20170609Kinney 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-17-01 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)
2015 Electric Integrated Resource Plan
August 31, 2015
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 1 of 212
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-17-01 S. Kinney, Avista
Schedule 1, Page 2 of 212
Table of Contents

Avista Corp 2015 Electric IRP i
Table of Contents

1. Executive Summary ...................................................................................................... 1-1 Resource Needs ....................................................................................................................... 1-1
Modeling and Results ............................................................................................................... 1-2 Electricity and Natural Gas Market Forecasts .......................................................................... 1-2
Energy Efficiency Acquisition ................................................................................................... 1-3 Preferred Resource Strategy ................................................................................................... 1-4
Energy Independence Act Compliance .................................................................................... 1-6 Greenhouse Gas Emissions .................................................................................................... 1-6
Action Items .............................................................................................................................. 1-8
2. Introduction and Stakeholder Involvement ................................................................ 2-1
IRP Process ............................................................................................................................. 2-1 2015 IRP Outline ...................................................................................................................... 2-4
Regulatory Requirements ........................................................................................................ 2-6
3. Economic & Load Forecast .......................................................................................... 3-1
Introduction & Highlights .......................................................................................................... 3-1
Economic Characteristics of Avista’s Service Territory ............................................................ 3-1 IRP Long-Run Load Forecast ................................................................................................ 3-14 Monthly Peak Load Forecast Methodology ............................................................................ 3-21
Simulated Extreme Weather Conditions with Historical Weather Data ................................. 3-22 Testing for Changes in Extreme Temperature Behavior ........................................................ 3-26
4. Existing Supply Resources .......................................................................................... 4-1 Introduction & Highlights .......................................................................................................... 4-1 Spokane River Hydroelectric Developments ........................................................................... 4-2 Clark Fork River Hydroelectric Development ........................................................................... 4-4
Total Hydroelectric Generation ................................................................................................ 4-4 Thermal Resources .................................................................................................................. 4-4
Power Purchase and Sale Contracts ....................................................................................... 4-6 Customer-Owned Generation ................................................................................................ 4-10 Solar ....................................................................................................................................... 4-11
5. Energy Efficiency & Demand Response ..................................................................... 5-1
Introduction ............................................................................................................................... 5-1 The Conservation Potential Assessment ................................................................................. 5-2
Overview of Energy Efficiency Potential .................................................................................. 5-4
Conservation Targets ............................................................................................................... 5-7 Energy Efficiency-Related Financial Impacts ........................................................................... 5-8 Integrating Results into Business Planning and Operations .................................................... 5-8
Demand Response ................................................................................................................. 5-11 Generation Efficiency Audits of Avista Facilities .................................................................... 5-15
6. Long-Term Position ....................................................................................................... 6-1 Introduction & Highlights .......................................................................................................... 6-1
Reserve Margins ...................................................................................................................... 6-1 Energy Imbalance Market ........................................................................................................ 6-8
Balancing Loads and Resources ............................................................................................. 6-9
Washington State Renewable Portfolio Standard .................................................................. 6-12
7. Policy Considerations ................................................................................................... 7-1 Environmental Issues ............................................................................................................... 7-1
Avista’s Climate Change Policy Efforts .................................................................................... 7-3
8. Transmission & Distribution Planning ........................................................................ 8-1
Introduction ............................................................................................................................... 8-1
FERC Transmission Planning Requirements and Processes.................................................. 8-1 BPA Transmission System ....................................................................................................... 8-4
Avista’s Transmission System ................................................................................................. 8-4
Transmission System Information ............................................................................................ 8-5
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP ii
Distribution System Efficiencies ............................................................................................... 8-8
9. Generation Resource Options...................................................................................... 9-1
Introduction ............................................................................................................................... 9-1 Assumptions ............................................................................................................................. 9-1
Natural Gas-Fired Combined Cycle Combustion Turbine ........................................................ 9-3 Hydroelectric Project Upgrades and Options ......................................................................... 9-12
Thermal Resource Upgrade Options ..................................................................................... 9-15 Ancillary Services Valuation ................................................................................................... 9-16
10. Market Analysis ........................................................................................................... 10-1 Introduction ............................................................................................................................. 10-1
Marketplace ............................................................................................................................ 10-1 Fuel Prices and Conditions .................................................................................................... 10-6
Greenhouse Gas Emissions and the Clean Power Plan ..................................................... 10-10 Risk Analysis ........................................................................................................................ 10-12
Market Price Forecast .......................................................................................................... 10-19 Scenario Analysis ................................................................................................................. 10-25
11. Preferred Resource Strategy ...................................................................................... 11-1 Introduction ............................................................................................................................. 11-1
Supply-Side Resource Acquisitions ....................................................................................... 11-1 Resource Deficiencies............................................................................................................ 11-2
Preferred Resource Strategy ................................................................................................. 11-7 Efficient Frontier Analysis ..................................................................................................... 11-15
Determining the Avoided Costs of Energy Efficiency ........................................................... 11-19 Determining the Avoided Cost of New Generation Options ................................................. 11-20
12. Portfolio Scenarios ...................................................................................................... 12-1 Introduction ............................................................................................................................. 12-1
Other Resource Scenarios ................................................................................................... 12-11 Resource Tipping Point Analyses ........................................................................................ 12-13
13. Action Items ................................................................................................................. 13-1 Summary of the 2013 IRP Action Plan................................................................................... 13-1
2013 Action Plan and Progress Report – Supplemental ........................................................ 13-3 2015 IRP Two Year Action Plan ............................................................................................. 13-5
Production Credits .................................................................................................................. 13-6

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 4 of 212
Table of Contents

Avista Corp 2015 Electric IRP iii
Table of Figures

Figure 1.1: Load-Resource Balance—Winter Peak Load & Resource Availability ...................... 1-1 Figure 1.2: Average Mid-Columbia Electricity Price Forecast ...................................................... 1-2
Figure 1.3: Stanfield Natural Gas Price Forecast ......................................................................... 1-3 Figure 1.4: Annual and Cumulative Energy Efficiency Acquisitions ............................................. 1-4
Figure 1.5: Efficient Frontier ......................................................................................................... 1-5
Figure 1.6: Avista’s Qualifying Renewables for Washington State’s EIA ..................................... 1-6
Figure 3.1: MSA Population Growth and U.S. Recessions, 1971-2014 ....................................... 3-2 Figure 3.2: MSA Population Growth, 2007-2014 .......................................................................... 3-3
Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2014 .............................. 3-4 Figure 3.4: MSA Non-Farm Employment Growth, 2007-2014 ..................................................... 3-4
Figure 3.5: MSA Personal Income Breakdown by Major Source, 2013 ....................................... 3-5 Figure 3.6: MSA Real Personal Income Growth, 1970-2013 ....................................................... 3-6
Figure 3.7: Forecasting IP Growth.............................................................................................. 3-10 Figure 3.8: Industrial Load and Industrial (IP) Index .................................................................. 3-10
Figure 3.9: Population Growth vs. Customer Growth, 2000-2014 ............................................. 3-11 Figure 3.10: Forecasting Population Growth .............................................................................. 3-12 Figure 3.11: Long-Run Annual Residential Customer Growth ................................................... 3-16 Figure 3.12: Load Scenarios with PV Shocks ............................................................................ 3-17
Figure 3.13: Load Growth Scenarios with PV Shocks................................................................ 3-17 Figure 3.14: Average Megawatts, High/Low Economic Growth Scenarios ................................ 3-19
Figure 3.15: UPC Growth Forecast Comparison to EIA ............................................................. 3-20 Figure 3.16: Load Growth Comparison to EIA ........................................................................... 3-20 Figure 3.17: Peak Load Forecast 2015-2035 ............................................................................. 3-24 Figure 3.18: Peak Load Forecast with 1 in 20 High/Low Bounds, 2015-2035 ........................... 3-25
Figure 4.1: 2016 Avista Capability & Energy Fuel Mix ................................................................. 4-1
Figure 4.2: Avista’s Net Metering Customers ............................................................................. 4-10
Figure 5.1: Historical and Forecast Conservation Acquisition (system) ....................................... 5-2 Figure 5.2: Analysis Approach Overview ..................................................................................... 5-3 Figure 5.3: Cumulative Conservation Potentials CPA versus PRiSM .......................................... 5-7 Figure 5.4: Existing & Future Energy Efficiency Costs and Energy Savings ............................... 5-8
Figure 6.1: 2020 Market Reliance & Capacity Cost Tradeoffs ..................................................... 6-4 Figure 6.2: Planning Margin Survey Results ................................................................................ 6-5
Figure 6.3: Single Largest Contingency Survey Results (2014 Peak Load) ................................ 6-6
Figure 6.4: 95th Percentile Capacity Requirements ..................................................................... 6-7 Figure 6.5: 99th Percentile Capacity Requirements ..................................................................... 6-8 Figure 6.6: Winter 1 Hour Capacity Load and Resources .......................................................... 6-10
Figure 6.7: Summer 18-Hour Capacity Load and Resources .................................................... 6-11 Figure 6.8: Annual Average Energy Load and Resources ......................................................... 6-12
Figure 7.1: Draft Clean Power Plan 2030 Emission Intensity Goals ............................................ 7-7 Figure 8.1: NERC Interconnection Map ....................................................................................... 8-2
Figure 9.1: Northwest Wind Project Levelized Costs per MWh ................................................... 9-6 Figure 9.2: Solar Nominal Levelized Cost ($/MWh) ..................................................................... 9-8
Figure 9.3: Historical and Planned Hydro Upgrades .................................................................. 9-13
Figure 9.4: Storage’s Value Stream ........................................................................................... 9-17
Figure 9.5: Avista’s Monthly Up/Down Regulation Surplus ........................................................ 9-18 Figure 10.1: NERC Interconnection Map ................................................................................... 10-2
Figure 10.2: 20-Year Annual Average Western Interconnect Energy ........................................ 10-3 Figure 10.3: Resource Retirements (Nameplate Capacity) ....................................................... 10-4
Figure 10.4: Cumulative Generation Resource Additions (Nameplate Capacity) ...................... 10-5
Figure 10.5: Henry Hub Natural Gas Price Forecast .................................................................. 10-7 Figure 10.6: Northwest Expected Energy ................................................................................... 10-9 Figure 10.7: Regional Wind Expected Capacity Factors .......................................................... 10-10
Figure 10.8: 2030 Adjusted State Carbon Intensity CPP Goals ............................................... 10-11
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP iv
Figure 10.9: Historical Stanfield Natural Gas Prices (2004-2015) ........................................... 10-12 Figure 10.10: Stanfield Annual Average Natural Gas Price Distribution .................................. 10-13
Figure 10.11: Stanfield Natural Gas Distributions .................................................................... 10-14 Figure 10.12: Wind Model Output for the Northwest Region ................................................... 10-18
Figure 10.13: 2014 Actual Wind Output BPA Balancing Authority ........................................... 10-18 Figure 10.14: Mid-Columbia Electric Price Forecast Range .................................................... 10-21
Figure 10.15: Western States Greenhouse Gas Emissions ..................................................... 10-22
Figure 10.16: EPA’s CPP Annual Emissions Intensity for the West ........................................ 10-23
Figure 10.17: EPA’s CPP 2030 State Goal vs. Modeling Result ............................................. 10-23 Figure 10.18: Base Case Western Interconnect Resource Mix ............................................... 10-24
Figure 10.19: Annual Mid-Columbia Flat Price Forecast Benchmark Scenario ....................... 10-25 Figure 10.20: Benchmark Scenario Annual Western U.S. Greenhouse Gas Emissions ......... 10-26
Figure 10.21: Annual Mid-Columbia Flat Price Forecast Colstrip Retires Scenario ................ 10-27 Figure 10.22: No Colstrip Scenario Annual Western U.S. Greenhouse Gas Emissions ......... 10-27
Figure 10.23: Social Cost of Carbon Scenario Emission Prices .............................................. 10-28 Figure 10.24: Annual Mid-Columbia Flat Price Forecast Social Cost of Carbon Scenario ...... 10-29
Figure 10.25: Social Cost of Carbon Scenario Western US Greenhouse Gas Emissions ...... 10-29 Figure 10.26: Draft CPP as Proposed Scenario Flat Mid-Columbia Electric Prices ................ 10-30
Figure 10.27: Draft CPP as Proposed Scenario Western Greenhouse Gas Emissions .......... 10-31 Figure 10.28: Draft CPP as Proposed Scenario 1941 Water Year Annual Costs .................... 10-32
Figure 10.29: CPP as Proposed 1941 Water Year Scenario Mid-Columbia Electric Prices .... 10-33 Figure 11.1: Resource Acquisition History ................................................................................. 11-2
Figure 11.2: Physical Resource Positions (Includes Energy Efficiency) .................................... 11-3 Figure 11.3: REC Requirements vs. Qualifying RECs for Washington State EIA ..................... 11-4
Figure 11.4: Conceptual Efficient Frontier Curve ....................................................................... 11-6 Figure 11.5: New Resources Meets Winter Peak Loads............................................................ 11-8
Figure 11.6: Energy Efficiency Annual Expected Acquisition Comparison .............................. 11-10 Figure 11.7: Load Forecast with and without Energy Efficiency .............................................. 11-10
Figure 11.8: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions ............. 11-12 Figure 11.9: Power Supply Expense Range ............................................................................ 11-14
Figure 11.10: Expected Case Efficient Frontier ........................................................................ 11-16 Figure 11.11: Risk Adjusted PVRR of Efficient Frontier Portfolios ........................................... 11-17
Figure 11.12: Risk Adjusted PVRR of Efficient Frontier Portfolios ........................................... 11-18 Figure 12.1: Linear versus Integer Efficient Frontier Difference ................................................. 12-2
Figure 12.2: Colstrip Retires Scenario Efficient Frontier Analysis .............................................. 12-5 Figure 12.3: Colstrip Retires in 2026 Scenario Power Supply Cost Impact ............................... 12-6
Figure 12.4: Colstrip Retires in 2027 Emissions ........................................................................ 12-6 Figure 12.5: High-Cost Colstrip Retention Scenario Efficient Frontier ....................................... 12-8
Figure 12.6: High-Cost Colstrip Scenarios Annual Cost ............................................................ 12-8 Figure 12.7: Social Cost of Carbon Impact to Efficient Frontier ................................................. 12-9
Figure 12.8: Colstrip Retires in 2027 Portfolio Efficient Frontier .............................................. 12-10 Figure 12.9: Colstrip Retires in 2027 Portfolio Emissions ........................................................ 12-10
Figure 12.10: Other Resource Strategy Portfolio Cost and Risk (Millions) .............................. 12-11 Figure 12.11: Risk Adjusted PVRR (2016- 2035) ..................................................................... 12-13
Figure 12.11: Utility Scale Solar Tipping Point Analysis (2014 $) ............................................ 12-14 Figure 12.13: Utility Scale Storage Tipping Point Analysis (2014 $) ........................................ 12-15

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 6 of 212
Table of Contents

Avista Corp 2015 Electric IRP v
Table of Tables

Table 1.1: The 2015 Preferred Resource Strategy ...................................................................... 1-4 Table 2.1: TAC Meeting Dates and Agenda Items ....................................................................... 2-2
Table 2.2: External Technical Advisory Committee Participating Organizations ......................... 2-3 Table 2.3: Idaho IRP Requirements ............................................................................................. 2-6
Table 2.4: Washington IRP Rules and Requirements .................................................................. 2-6 Table 3.1: UPC Models Using Non-Weather Driver Variables ..................................................... 3-9
Table 3.2: Customer Growth Correlations, January 2005-December 2013 ............................... 3-11 Table 3.3: Average Annual PV Scenario Load Growth for Selected Periods ............................ 3-18
Table 3.4: High/Low Economic Growth Scenarios (2015-2035) ................................................ 3-18 Table 3.5: Load Growth for High/Low Economic Growth Scenarios (2015-2035) ..................... 3-19
Table 3.6: Forecasted Winter and Summer Peak Growth, 2015-2035 ...................................... 3-24 Table 3.7: Energy and Peak Forecasts ...................................................................................... 3-25
Table 4.1: Avista-Owned Hydroelectric Resources ...................................................................... 4-4 Table 4.2: Avista-Owned Thermal Resources .............................................................................. 4-5
Table 4.3: Mid-Columbia Capacity and Energy Contracts ........................................................... 4-8 Table 4.4: PURPA Agreements .................................................................................................... 4-9 Table 4.5: Other Contractual Rights and Obligations ................................................................... 4-9 Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ...................... 5-5
Table 5.2: Annual Achievable Potential Energy Efficiency (Megawatt Hours) ............................. 5-7 Table 5.3: Commercial and Industrial Demand Response Achievable Potential (MW) ............. 5-13
Table 6.1: Washington State EIA Compliance Position Prior to REC Banking .......................... 6-13 Table 8.1: 2015 IRP Requested Transmission Upgrade Studies ................................................. 8-7 Table 8.2: Third-Party Large Generation Interconnection Requests ............................................ 8-7 Table 8.3: Completed and Planned Feeder Rebuilds ................................................................ 8-10
Table 9.1: Natural Gas-Fired Plant Levelized Costs per MWh .................................................... 9-3 Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics................................... 9-5
Table 9.3: Solar Capacity Credit by Month ................................................................................... 9-7 Table 9.5: Storage Power Supply Value .................................................................................... 9-17 Table 9.6: Natural Gas-Fired Facilities Ancillary Service Value ................................................. 9-18 Table 10.1: AURORAXMP Zones ................................................................................................. 10-2
Table 10.2: Added Northwest Generation Resources ................................................................ 10-6 Table 10.3: Natural Gas Price Basin Differentials from Henry Hub ........................................... 10-8
Table 10.4: Monthly Price Differentials for Stanfield from Henry Hub ........................................ 10-8
Table 10.5: January through June Load Area Correlations ..................................................... 10-15 Table 10.6: July through December Load Area Correlations ................................................... 10-15 Table 10.7: Area Load Coefficient of Determination (Standard Deviation/Mean) .................... 10-15
Table 10.8: Area Load Coefficient of Determination (Standard Deviation/Mean) .................... 10-16 Table 10.9: Annual Average Mid-Columbia Electric Prices ($/MWh) ....................................... 10-21
Table 11.1: Qualifying Washington EIA Resources ................................................................... 11-4 Table 11.2: 2015 Preferred Resource Strategy .......................................................................... 11-8
Table 11.3: 2013 Preferred Resource Strategy .......................................................................... 11-9 Table 11.4: PRS Rate Base Additions from Capital Expenditures ........................................... 11-13
Table 11.5: Avista Medium-Term Winter Peak Hour Capacity Tabulation ............................... 11-15
Table 11.6: Avista Medium-Term Summer 18-Hour Sustained Peak Capacity Tabulation ..... 11-15 Table 11.7: Alternative Resource Strategies along the Efficient Frontier (MW) ....................... 11-19 Table 11.8: Updated Annual Avoided Costs ($/MWh).............................................................. 11-21
Table 12.1: Efficient Frontier with Linear Programming ............................................................. 12-2 Table 12.2: Load Forecast Scenarios (2016-2035) .................................................................... 12-3
Table 12.3: Resource Selection for Load Forecast Scenarios ................................................... 12-3
Table 12.4: Colstrip Retires in 2026 Scenario Resource Strategy ............................................. 12-5 Table 12.5: Colstrip Retires in 2022 Scenario Resource Strategy ............................................. 12-7

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 7 of 212
Avista Corp 2015 Electric IRP
2015 Electric IRP Introduction

Avista has a 125-year tradition of innovation and a commitment to providing safe,
reliable, low-cost, clean energy to our customers. We meet this commitment
through a diverse mix of generation resources.

The 2015 Integrated Resource Plan (IRP) continues this legacy by looking 20 years into
the future to determine the energy needs of our customers. The IRP, updated every two years, analyzes and outlines a strategy to meet the projected demand and renewable portfolio standards through energy efficiency and a diverse mix of renewable and
traditional energy resources.

Summary The 2015 IRP shows Avista has adequate resources between owned and contractually controlled generation, combined with conservation and market purchases, to meet
customer needs through 2020. In the longer term, plant upgrades, energy efficiency
measures, and additional natural gas-fired generation are integral parts of Avista’s 2015
Preferred Resource Strategy.
Changes
Major changes from the 2013 IRP include:
 Average annual load growth reduced to 0.6 percent from just over 1 percent in
2013. This combined with a short term purchase power agreement delays the need for a new natural gas-fired resource by one year.
 Less contribution from natural gas-fired peakers due to lower projected loads.
 The elimination of demand response (temporarily reducing the demand for energy) due to higher estimated costs.

Highlights
Some highlights of the 2015 IRP include:
 Population and employment growth is starting to recover from the Great
Recession.
 Natural gas-fired plants represent the largest portion of generation potential.
 The first anticipated resource acquisition is a natural gas-fired peaker by the end
of 2020 to replace expiring contracts and to serve load growth.
 Colstrip remains a cost effective and reliable source of power to meet future
customer needs.
 Energy efficiency offsets more than half of projected load growth through the 20-
year IRP timeframe.

IRP Process Each IRP is a thoroughly researched and data-driven document that identifies and
describes a Preferred Resource Strategy to meet customer needs while balancing costs
and risk measures with environmental mandates. Avista’s professional energy analysts
use sophisticated modeling tools and input from over 75 invited participants to develop
each plan. The participants in the public process include customers, academics,
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 8 of 212
Avista Corp 2015 Electric IRP
environmental organizations, government agencies, consultants, utilities, elected officials, state utility commission stakeholders and other interested parties.

Conclusion
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 2017 IRP in early 2016. Stakeholder involvement is
encouraged and interested parties may contact John Lyons at [phone] or
[e-mail] for more information on participating in the IRP process.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 9 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-1

1. Executive Summary

Avista’s 2015 Electric Integrated Resource Plan (IRP) guides its resource strategy over
the next two years and resource procurements over the next 20-years. It provides a
snapshot of existing resources and loads and evaluates acquisition strategies over expected and possible future conditions. The 2015 Preferred Resource Strategy (PRS)
includes energy efficiency, generation upgrades, and new natural gas-fired generation.

PRS development depends on modeling techniques to balance cost, reliability, rate
volatility, and renewable resource requirements. Avista’s management and the Technical Advisory Committee (TAC) guide its development and the IRP document by
providing input on modeling and planning assumptions. TAC members include
customers, Commission staff, the Northwest Power and Conservation Council,
consumer advocates, academics, environmental groups, utility peers, government
agencies, and other interested parties.

Resource Needs
Under extreme weather conditions, Avista experiences its highest peak loads in the
winter. Its peak planning methodology includes operating reserves, regulation, load
following, wind integration, and a 14 percent planning margin over winter-peak load
levels. The company has adequate resources, combined with conservation and market purchases, to meet peak load requirements through 2020. Figure 1.1 shows Avista’s
resource position through 2035.

Figure 1.1: Load-Resource Balance—Winter Peak Load & Resource Availability

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Case No. AVU-E-17-01 S. Kinney, Avista
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Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-2

A short-term capacity need exists in the winter of 2015-2016, but is short-lived due to a 150 MW capacity sale contract ending in 2016. Avista addressed this deficit with market
purchases; so, the first long-term capacity deficit begins in 2021. Resources acquired to
meet projected winter deficiencies will provide capacity in excess of summer needs.
Chapter 6 – Long Term Position details Avista’s resource needs.
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. This Western Interconnect-wide study determines the impact of extra-
regional markets on the Northwest electricity marketplace of which Avista is a part. It
then maps existing Avista resources to the transmission grid in a model simulating
hourly operations for the Western Interconnect from 2016 to 2035, the IRP study timeframe. The model adds new resources and transmission to the Western Interconnect as regional loads grow and older resources are retired. Monte Carlo-style
analyses vary hydroelectric and wind generation, loads, forced outages and natural gas
price data over 500 iterations of potential future market conditions to develop the Mid-
Columbia electricity marketplace through 2035.
Electricity and Natural Gas Market Forecasts
Figure 1.2 shows the 2015 IRP Mid-Columbia electricity price forecast for the Expected Case, including the range of prices resulting from 500 Monte Carlo iterations. The levelized price is $38.48 per MWh in nominal dollars over the 2016-2035 timeframe.

Figure 1.2: Average Mid-Columbia Electricity Price Forecast

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Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 11 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-3

Electricity and natural gas prices are highly correlated because natural gas fuels marginal generation in the Northwest during most of the year. Figure 1.3 presents
nominal 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 Expected Case. The average is $4.97 per dekatherm over the next 20 years. See Chapter 10 – Market Analysis for details on the natural gas and electricity price forecasts.

Figure 1.3: Stanfield Natural Gas Price Forecast

Energy Efficiency Acquisition
Avista commissioned a 20-year Conservation Potential Assessment in 2015. The study
analyzed over 3,000 equipment and 2,300 measure options for residential, commercial,
and industrial energy efficiency applications. Data from this study formed the basis of
the IRP conservation potential evaluation. Figure 1.4 shows how historical efforts in energy efficiency have decreased Avista’s load requirements by 127 aMW, or
approximately eleven percent of its total load in 2014. The cumulative line shows the
summation of all efficiency acquisitions and the online dashed line shows the amount of
energy efficiency still reducing loads due to the 18-year assumed measure life. See
Chapter 5 – Energy Efficiency and Demand Response for details.
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 12 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-4

Figure 1.4: Annual and Cumulative Energy Efficiency Acquisitions

Preferred Resource Strategy
The PRS results from careful consideration by Avista’s management and the TAC of
information gathered and analyzed in the IRP process. It meets future load growth with
upgrades at existing generation facilities, energy efficiency, and natural gas-fired
technologies, as shown in Table 1.1.
Table 1.1: The 2015 Preferred Resource Strategy
Resource By the End of
Year
ISO Conditions
(MW)
Winter Peak
(MW)
Energy
(aMW)
Natural Gas Peaker 2020 96 102 89
Thermal Upgrades 2021-2025 38 38 35
Combined Cycle CT 2026 286 306 265
Natural Gas Peaker 2027 96 102 89
Thermal Upgrades 2033 3 3 3
Natural Gas Peaker 2034 47 47 43
Total 565 597 524
Efficiency
Improvements
Acquisition
Range
Winter Peak
Reduction
(MW)
Energy
(aMW)
Energy Efficiency 2016-2035 193 132
Distribution Efficiencies <1 <1
Total 193 132

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 13 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-5

The 2015 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 2013 IRP include a reduced contribution from natural gas-fired peakers and the
elimination of demand response because of lower projected load growth, more thermal
plant upgrades and higher demand response costs. Each new resource and energy efficiency option is valued against the Expected Case
Mid-Columbia electricity market to identify its future value, 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
11 provides a detailed discussion of the efficient frontier concept.

The PRS provides a least reasonable-cost portfolio minimizing future costs and risks
within actual and 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. Conversely, reducing risk generally reduces overall returns. Figure 1.5
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 such as wind and hydroelectric upgrades. The PRS is the portfolio selected on the
efficient frontier where reduced risk justifies the increased cost.

Figure 1.5: Efficient Frontier

$20 Mil
$30 Mil
$40 Mil
$50 Mil
$60 Mil
$70 Mil
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$350 Mil $400 Mil $450 Mil $500 Mil $550 Mil
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Preferred Resource Strategy
Least Risk
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 14 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-6

Chapter 12 – Portfolio Scenarios, includes several scenarios identifying tipping points where the PRS could change under different conditions from the Expected Case. It also
evaluates the impacts of, among others, varying load growth, resource capital costs,
and greenhouse gas policies.

Energy Independence Act Compliance
Washington voters approved the Energy Independence Act (EIA) through Initiative 937
in the November 2006 general election. The EIA requires utilities with over 25,000 customers to meet three percent of retail load from qualified renewable resources by 2012, nine percent by 2016, and 15 percent by 2020. The initiative also requires utilities
to acquire all cost-effective conservation and energy efficiency measures. Avista will
meet or exceed its EIA requirements through the IRP timeframe with a combination of
qualifying hydroelectric upgrades, the Palouse Wind project, Kettle Falls Generating Station output and renewable energy certificate (REC) purchases. Figure 1.6 shows Avista’s EIA-qualified generation; Chapter 6 – Long-Term Position includes a more in-
depth discussion of this topic.

Figure 1.6: Avista’s Qualifying Renewables for Washington State’s EIA

Greenhouse Gas Emissions
The regulation of greenhouse gases, or carbon emissions, is in various stages of
development and implementation throughout the country. Some states have active cap
and trade programs, emissions performance standards, renewable portfolio standards,
or a combination of active and proposed regulations affecting emissions from electric generation resources. The Environmental Protection Agency’s (EPA) June 2014 Clean Power Plan (CPP) draft proposal aimed to reduce greenhouse gas emissions from
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Requirement
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 15 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-7

existing fossil-fueled electric generating units by establishing state-by-state emission rate targets calculated based on four building blocks. The EPA issued the final CPP rule
on August 3, 2015, which was after modeling for this IRP was completed. The analysis
of the final CPP rule, and subsequent state implementation plans, will occur in the 2017
IRP. The 2015 IRP reduces emissions consistent with the EPA draft rule. All active regulations affecting generation in the Western Interconnect are included in the IRP, including a $12 per metric ton carbon cost that escalates over time. Figure 1.7 shows
Avista’s projected greenhouse gas emissions for its existing and new generation assets.

Figure 1.7 shows that Avista emissions will increase modestly over the IRP timeframe. Figure 1.8 shows that, unlike Avista, western-region emissions likely will fall from historic levels. This discrepancy occurs because Avista does not own any of the less-
cost-effective coal and natural gas-fired plants projected to retire over the IRP
timeframe. More details on state and federal greenhouse gas policies are in Chapter 7.
Results of greenhouse-gas policy scenarios are in Chapter 12.

Figure 1.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 16 of 212
Chapter 1- Executive Summary
Avista Corp 2015 Electric IRP 1-8

Figure 1.8: U.S. Western Interconnect Greenhouse Gas Emissions

Action Items
The 2015 Action Items chapter updates progress made on Action Items in the 2013 IRP
and outlines activities Avista intends to perform between the publication of this report
and publication of the 2017 IRP. It includes input from Commission Staff, Avista’s
management team, and the TAC. Action Item categories include generation resource-related analysis, energy efficiency, and transmission planning. Refer to Chapter 13 –
Action Items for details about each of these categories.

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 17 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
2. Introduction and Stakeholder Involvement

Avista submits an IRP to the Idaho and Washington public utility commissions
biennially.1 Including its first plan in 1989, the 2015 IRP is Avista’s fourteenth 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 safe and 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 a mix of resources meeting resource adequacy requirements and optimizing the value
of its current portfolio. The IRP is a resource evaluation tool, not a plan for acquiring a
particular set of assets. Actual resource acquisition generally occurs through
competitive bidding processes.

IRP Process
The 2015 IRP is developed and written with the aid of a public process. Avista actively
seeks input from a variety of constituents through the TAC. The TAC is a mix of more
than 75 invited participants, including staff from the Idaho and Washington
commissions, customers, academics, environmental organizations, government
agencies, consultants, utilities, and other interested parties, who joined the planning process.

Avista sponsored six TAC meetings for the 2015 IRP. The first meeting was on May 29,
2014; the last occurred on June 24, 2015. Each TAC meeting covers different aspects
of IRP planning activities. At the meetings, members provide contributions to, and assessments of, modeling assumptions, modeling processes, and results of Avista
studies. Table 2.1 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. The website link
contains all past IRPs and TAC meeting presentations back to 1989.

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-17-01 S. Kinney, Avista
Schedule 1, Page 18 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
Table 2.1: TAC Meeting Dates and Agenda Items
Meeting Date Agenda Items
TAC 1 – May 29, 2014  TAC Meeting Expectations
 2013 IRP Commission Acknowledgements
 2013 Action Plan Update
 Energy Independence Act Compliance
 Pullman Energy Storage Project
 Demand Response Study Discussion
 Draft 2015 Electric IRP Work Plan
TAC 2 – September 23, 2014  Introduction & TAC 1 Recap
 Conservation Selection Methodology
 Load and Economic Forecast
 Shared Value Report
 Generation Options
 Clean Power Plan Proposal Discussion
TAC 3 – November 21, 2014  Introduction & TAC 2 Recap
 Planning Margin
 Colstrip Discussion
 Cost of Carbon
 IRP Modeling Overview
 Conservation Potential Assessment
TAC 4 – February 24, 2015  Introduction & TAC 3 Recap
 Demand Response Study
 Natural Gas Price Forecast
 Electric Price Forecast
 Resource Requirements
 Interconnection Studies
 Market Scenarios and Portfolio Analysis
TAC 5 – May 19, 2015  Introduction & TAC 4 Recap
 Review of Market Futures
 Ancillary Services Valuation
 Conservation Potential Assessment
 Draft 2015 PRS & Portfolio Analysis
TAC 6 – June 24, 2015  Introduction & TAC 5 Recap
 Avista Community Solar
 2015 Action Plan
 Final 2015 PRS
 2015 IRP Document Introduction

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 19 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
Avista greatly appreciates the valuable contributions of its TAC members and wishes to acknowledge and thank the organizations that allow their attendance. Table 2.2 is a list
of the organizations participating in the 2015 IRP TAC process.

Table 2.2: External Technical Advisory Committee Participating Organizations
Organization
AEG
As You Sow
Birch Energy Economics
City of Spokane
Clearwater Paper
Earth Justice
Eastern Washington University
Eugene Water & Electric Board
GE Energy
Gonzaga University
Grant PUD
Idaho Department of Environmental Quality
Idaho Public Utilities Commission
Inland Empire Paper
Montana Environmental Information Center
NW Energy Coalition
PacifiCorp
Pend Oreille PUD
Puget Sound Energy
Pullman City Council
Renewable Northwest
Residential and Small Commercial Customers
Resource Development Associates
Sierra Club
Spokane Neighborhood Action Partners
The Energy Authority
Washington State Office of the Attorney General
Washington Department of Enterprise Services
Washington State Department of Commerce
Washington Utilities and Transportation Commission
Whitman County Commission

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

Energy Efficiency Advisory Group
The energy efficiency Advisory Group provides stakeholders and public groups biannual
opportunities to discuss Avista’s energy efficiency efforts.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 20 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
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 the 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. Avista received a 50-year license for the Spokane
River Project following a multi-year collaborative process involving 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 quarterly reviews ensure
changing administrative issues and needs are met.

Regional Planning The Pacific Northwest generation and transmission system operates in a coordinated
fashion. Avista participates in the efforts of many regional planning processes.
Information from this participation supplements Avista’s IRP process. A partial list of the
regional organizations Avista participates in includes:

 Western Electricity Coordinating Council
 Peak Reliability
 Northwest Power and Conservation Council
 Northwest Power Pool
 Pacific Northwest Utilities Conference Committee
 ColumbiaGrid
 Northern Tier Transmission Group
 North American Electric Reliability Corporation

Future Public Involvement
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.

2015 IRP Outline
The 2015 IRP consists of 13 chapters plus an executive summary and this introduction.
A series of technical appendices supplement this report.

Chapter 1: Executive Summary
This chapter summarizes the overall results and highlights of the 2015 IRP.

Chapter 2: Introduction and Stakeholder Involvement
This chapter introduces the IRP and details public participation and involvement in the
IRP planning process.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 21 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
Chapter 3: Economic and Load Forecast This chapter covers regional economic conditions, Avista’s energy and peak load
forecasts, and load forecast scenarios.

Chapter 4: Existing Supply Resources This chapter provides an overview of Avista-owned generating resources and its contractual resources and obligations.

Chapter 5: Energy Efficiency and Demand Response
This chapter discusses Avista energy efficiency programs. It provides an overview of the conservation potential assessment and summarizes energy efficiency modeling results.

Chapter 6: Long-Term Position
This chapter reviews Avista reliability planning and reserve margins, resource
requirements, and provides an assessment of its reserves and flexibility.
Chapter 7: 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 8: Transmission & Distribution Planning
This chapter discusses Avista distribution and transmission systems, as well as regional
transmission planning issues. It includes detail on transmission cost studies used in IRP
modeling and provides a summary of our 10-year Transmission Plan. The chapter
concludes with a discussion of distribution efficiency and grid modernization projects.

Chapter 9: Generation Resource Options
This chapter covers the costs and operating characteristics of the generation resource
options modeled for the IRP.

Chapter 10: Market Analysis
This chapter details Avista IRP modeling and its analyses of the wholesale market.

Chapter 11: Preferred Resource Strategy
This chapter details the resource selection process used to develop the 2015 PRS, including the efficient frontier and resulting avoided costs.

Chapter 12: Portfolio Scenarios
This chapter discusses the portfolio scenarios and tipping point analyses.

Chapter 13: Action Items
This chapter discusses progress made on Action Items contained in the 2013 IRP. It
details the action items Avista will focus on between publication of this plan and the next
one.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 22 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
Regulatory Requirements
The IRP process for Idaho has several requirements documented in IPUC Orders Nos.
22299 and 25260. Table 2.3 summarizes them.
Table 2.3 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 4- Existing Supply 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 3- Economic & Load Forecast Chapter 12- Portfolio Scenarios
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 11- Preferred Resource
Strategy
Identify energy efficiency resources and costs. Chapter 5- Energy Efficiency & Demand Response
Provide opportunities for public participation and involvement.Chapter 2- Introduction and Stakeholder Involvement

The IRP process for Washington has several requirements documented in Washington
Administrative Code (WAC). Table 2.4 summarizes where in the document Avista
addressed each requirement.

Table 2.4 Washington IRP Rules and Requirements

Rule and Requirement Plan Citation
–

–
–
–
–

–

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 23 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
WAC 480-100-238(2)(b) – LRC analysis
considers resource costs. Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis
considers market-volatility risks. Chapter 10- Market Analysis
Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis
considers demand side uncertainties. Chapter 5- Energy Efficiency & Demand
Response Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis
considers resource dispatchability. Chapter 9- Generation Resource Options
Chapter 10- Market Analysis
WAC 480-100-238(2)(b) – LRC analysis
considers resource effect on system operation. Chapter 10- Market Analysis
Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis
considers risks imposed on ratepayers. Chapter 7- Policy Considerations
Chapter 9- Generation Resource Options Chapter 10- Market Analysis
Chapter 11- Preferred Resource Strategy
Chapter 12- Portfolio Scenarios
WAC 480-100-238(2)(b) – LRC analysis
considers public policies regarding resource preference adopted by Washington state or
federal government.
Chapter 3- Economic & Load Forecast
Chapter 4- Existing Supply Resources Chapter 7- Policy Considerations
Chapter 11- 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 7- Policy Considerations
Chapter 11- Preferred Resource Strategy
Chapter 12- Portfolio Scenarios
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 5- Energy Efficiency & Demand Response Chapter 11- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan includes a range of forecasts of future demand. Chapter 3- Economic & Load Forecast Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(a) – Plan develops forecasts using methods that examine the effect of economic forces on the consumption of
electricity.
Chapter 3- Economic & Load Forecast Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(a) – Plan develops
forecasts using methods that address changes in the number, type and efficiency of end-uses.
Chapter 3- Economic & Load Forecast
Chapter 5- Energy Efficiency & Demand Response
Chapter 8- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan includes an assessment of commercially available
conservation, including load management.
Chapter 5- Energy Efficiency & Demand Response
Chapter 8- 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 5- Energy Efficiency & Demand
Response Chapter 8- 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 9- Generation Resource Options Chapter 11- Preferred Resource Strategy
Chapter 12- Portfolio Scenarios
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 24 of 212
Chapter 2- Introduction and Stakeholder Involvement
Avista Corp 2015 Electric IRP
WAC 480-100-238(3)(d) – Plan includes an
assessment of transmission system capability and reliability (as allowed by current law).
Chapter 8- 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 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution

WAC-480-100-238(3)(f) – Demand forecasts and resource evaluations are integrated into the long range plan for resource acquisition.
Chapter 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution
Chapter 9- Generation Resource Options Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(g) – Plan includes a two-year action plan that implements the long range plan.
Chapter 13- Action Items
WAC 480-100-238(3)(h) – Plan includes a progress report on the implementation of the
previously filed plan.
Chapter 13- Action Items
WAC 480-100-238(5) – Plan includes
description of consultation with commission staff and public participation
Chapter 2- 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 10- Preferred Resource Strategy
RCW 19.280.030-1(e) – An assessment of
methods, commercially available technologies,
or facilities for integrating renewable resources, and addressing overgeneration events, if
applicable to the utility's resource portfolio;
Chapter 9- Generation Resource Options
Chapter 10- Market Analysis

RCW 19.280.030-1(f) – The integration of the
demand forecasts and resource evaluations into
a long-range assessment describing the mix of supply side generating resources and
conservation and efficiency resources that will
meet current and projected needs, including mitigating overgeneration events, at the lowest
reasonable cost and risk to the utility and its ratepayers.
Chapter 9- Generation Resource Options
Chapter 10- Market Analysis

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 25 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-1
3. Economic & Load Forecast

Introduction & Highlights
An explanation and quantification of Avista’s loads and resources are integral to the
IRP. This chapter summarizes Expected Case customer and load projections, load
growth scenarios, and recent enhancements to our forecasting models and processes.

Economic Characteristics of Avista’s Service Territory
Avista’s core service area for electricity includes a population of more than a half million
people residing in Eastern Washington and Northern Idaho. Three metropolitan
statistical areas (MSAs) dominate its service area: the Spokane-Spokane Valley, WA
MSA (Spokane-Stevens counties); the Coeur d’Alene, ID MSA (Kootenai County); and
the Lewiston-Clarkson ID-WA, MSA (Nez Perce-Asotin counties). These three MSAs account for just over 70 percent of both customers (i.e., meters) and load. The
remaining 30 percent are in low-density rural areas in both states. Washington accounts
for about two-thirds of customers and Idaho one-third.

Population Population growth is increasingly a function of net migration within Avista’s service area.
Net migration is strongly associated with both service area and national employment
growth through the business cycle. The regional business cycle follows the U.S.
business cycle, meaning regional economic expansions or contractions follow national trends.1 Econometric analysis explains that when regional employment growth is stronger than U.S. growth over the business cycle, its cause is increased in-migration.
The reverse holds true. Figure 3.1 shows annual population growth since 1971. During
all deep economic downturns since the mid-1970s, reduced population growth rates in
Avista’s service territory led to lower load growth.2 The Great Recession reduced population growth from nearly two percent in 2007 to less than one percent from 2010
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. 2 Data Source: Bureau of Economic Development, U.S. Census, and National Bureau of Economic Research
Chapter Highlights
 Population and employment growth are recovering from the Great Recession.
 The 2015 Expected Case energy forecast grows 0.6 percent per year, replacing the 1.0 percent annual growth rate in the 2013 IRP.
 Peak load growth is higher than energy growth, at 0.74 percent in the winter
and 0.85 percent in the summer.
 Retail sales and residential use per customer forecasts continue to decline
from 2013 IRP projections.
 Testing performed for this IRP shows that historical extreme weather events are valid for peak load modeling.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 26 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-2
to 2013. Accelerating service area employment growth in 2013 helped push population growth above one percent in 2014.

Figure 3.1: MSA Population Growth and U.S. Recessions, 1971-2014

Figure 3.2 shows population growth since the start of the Great Recession in 2007.3 Service area population growth over the 2010-2012 period was weaker than the U.S.; it
was closely associated with the strength of regional employment growth relative to the
U.S. over the same period. The same can be said for the increase in population growth
in 2014 relative to the U.S. The association of employment growth to population growth has a one year lag. That is, the relative strength of service area population growth in
year “y” is positively associated with service area population growth in year “y+1”.
Econometric estimates based on historical data show that, holding U.S. employment-
growth constant, every one percent increase in service area employment growth is
associated with a 0.4 percent increase in population growth in the next year.

3 Data Source: Bureau of Economic Analysis and U.S. Census.
-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
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5
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7
19
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3
20
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 27 of 212
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Avista Corp 2015 Electric IRP 3-3
Figure 3.2: MSA Population Growth, 2007-2014

Employment It is useful to examine the distribution of employment and employment performance
since 2007 given the correlation between population and employment growth. The
Inland Northwest has transitioned from a natural resources-based manufacturing
economy to a services-based economy. Figure 3.3 shows the breakdown of non-farm employment for all three MSAs.4 Approximately 70 percent of employment in the three MSAs is in private services, followed by government (18 percent) and private goods-
producing sectors (13 percent). Farming accounts for one percent of total employment.

Spokane and Coeur d’Alene MSAs are major providers of health and higher education services to the Inland Northwest. A recent addition to these sectors is approval from
Washington’s legislature for Washington State University to open a medical school in
Spokane, Washington.

Between 1990 and 2007 non-farm employment growth averaged 2.7 percent per year. However, Figure 3.4 shows that service area employment lagged the U.S. recovery from the Great Recession for the 2010-2012 period.5 Regional employment recovery did
not materialize until 2013, when services employment started to grow. Prior to this,
reductions in federal, state, and local government employment offset gains in goods
producing sectors. By the fourth quarter 2014, service area employment growth began
exceeding U.S. growth rates.
4 Data Source: Bureau of Labor and Statistics 5 Data Source: Bureau of Labor and Statistics.
1.8%
1.4%
1.1%
0.7%
0.6%0.6%
0.8%
1.2%
1.0%1.0%0.9%0.8%
0.7%0.7%0.7%0.7%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2.0%
2007 2008 2009 2010 2011 2012 2013 2014
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Avista WA-ID MSAs
U.S.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 28 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-4
Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2014

Figure 3.4: MSA Non-Farm Employment Growth, 2007-2014

Figure 3.5 shows the distribution of personal income, a broad measure of both earned
income and transfer payments, for Avista’s Washington and Idaho MSAs.6 Regular
income includes net earnings from employment, and investment income in the form of
6 Data Source: Bureau of Economic Analysis.
Private Goods Producing, 13%
Private Service
Producing, 69%
Federal Government, 2%
State Government,
4%
Local Government, 12%
2.2%
0.5%
-4.6%
-1.6%
0.4%0.7%
2.1%
1.7%
1.1%
-0.6%
-4.3%
-0.7%
1.2%
1.7%1.7%1.9%
-5.5%
-4.5%
-3.5%
-2.5%
-1.5%
-0.5%
0.5%
1.5%
2.5%
3.5%
2007 2008 2009 2010 2011 2012 2013 2014
An
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Avista WA-ID MSAs
U.S.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 29 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-5
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 3.5: MSA Personal Income Breakdown by Major Source, 2013

Transfer payments in Avista’s service area in 1970 accounted for 12 percent of the local economy. The income share of transfer payments has nearly doubled over the last 40 years, to 22 percent. The relatively high regional dependence on government
employment and transfer payments means continued federal fiscal consolidation and
transfer program reform may reduce future growth. Although roughly 60 percent of
personal income is from net earnings, transfer payments account for more than one in every five dollars of personal income. Recent years have seen transfer payments become the fastest growing component of regional personal income. This growth
reflects an aging regional population, a surge of military veterans, and the Great
Recession; the later significantly increased payments from unemployment insurance
and other low-income assistance programs. Figure 3.6 shows the real (inflation adjusted) average annual growth per capita income
for Avista’s service area and the U.S. Note that in the 1980-90 period the service area
experienced significantly lower income growth compared to the U.S. as a result of the
back-to-back recessions of the early 1980s.7 The impacts of these recessions were more negative in the service area compared to the U.S. as a whole. As a result, the ratio of service area per capita income to U.S. per capita income fell from 93 percent in
the previous decade to around 85 percent. The income ratio has not since recovered.

7 Data Source: Bureau of Economic Analysis.
Net Earnings, 56%
Dividends,
Interest, and Rent, 22%
Transfer Receipts, 22%
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 30 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-6
Figure 3.6: MSA Real Personal Income Growth, 1970-2013

Five-Year Load Forecast Methodology In non-IRP years, the retail and native load forecasts have a five-year time horizon.
Avista conducts the forecasts each spring with the option of second forecast in the
winter if changing economic conditions warrant a new forecast. The results are fed into
Avista’s revenue model, which converts the load forecast into a revenue forecast. In
turn, the revenue forecast feeds Avista’s earnings model. In IRP years, the long-term forecast boot-straps off the five-year forecast by applying a set of growth assumptions
beyond year five.

Overview of the Five-Year Retail Load Forecast
The five-year retail load forecast is a two-step process. For most schedules in each class, there is a monthly use per customer (UPC) forecast and a monthly customer
forecast.8 The load forecast is generated by multiplying the customer and UPC
forecasts. The UPC and customer forecasts are generated using time-series
econometrics, as shown in Equation 3.1.

8 For schedules representing a single customer, were there is no customer count and for street lighting, total load is forecast directly without first forecasting UPC.
2.3%
1.4%
2.5%
0.7%
1.4%
2.1%
2.3%2.4%
0.7%
1.8%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
1970 to 1980 1980 to 1990 1990 to 2000 2000 to 2010 2010 to 2013
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Avista WA-ID MSAs
U.S.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 31 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-7
Equation 3.1: Generating Schedule Total Load

Where:

 = the forecast for month t, year j = 1,…,5 beyond the
current year, yc ,for schedule s.
 = the UPC forecast.
 = the customer forecast.

UPC Forecast Methodology
The econometric modeling for UPC is a variation of the “fully integrated” approach
expressed by Faruqui (2000) in the following equation:9

Equation 3.2: Use Per Customer Regression Equation

The model uses actual historical weather, UPC, and non-weather drivers to estimate the
regression in Equation 3.2. To develop the forecast, normal weather replaces actual
weather (W) along with the forecasted values for the Z variables (Faruqui, pp. 6-7).
Here, W is a vector of heating degree day (HDD) and cooling degree day (CDD)
variables; Z is a vector of non-weather variables; and εt,y is an uncorrelated N(0,σ) error term. For non-weather sensitive schedules, W = 0.

The W variables will be HDDs and CDDs. Depending on the schedule, the Z variables
may include real average energy price (RAP); average household size (AHS); the U.S. Federal Reserve industrial production index (IP); non-weather seasonal dummy
variables (SD); trend functions (T); and dummy variables for outliers (OL) and periods of
structural change (SC). RAP is measured as the average annual price (schedule total
revenue divided by schedule total usage) divided by the consumer price index (CPI),
less energy. For most schedules, the only non-weather variables are SD, SC, and OL.
If the error term appears to be non-white noise, then the forecasting performance of
Equation 3.3 can be improved by converting it into an ARIMA “transfer function” model
such that Єt,y = ARIMAЄt,y(p,d,q)(pk,dk,qk)k. The term p is the autoregressive (AR) order,
d is the differencing order, and q is the moving average (MA) order. The term pk is the order of seasonal AR terms, dk is the order of seasonal differencing, and qk is the seasonal order of MA terms. The seasonal values relate to “k,” or the frequency of the
data. With the current monthly data set, k = 12.

9 Faruqui, Ahmad (2000). Making Forecasts and Weather Normalization Work Together, Electric Power Research Institute, Publication No. 1000546, Tech Review, March 2000.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 32 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-8
For certain schedules, such as those related to lighting, simpler regression and smoothing methods are used because they offer the best fit for irregular usage without
seasonal or weather related behavior, is in a long-run steady decline, or is seasonal and
unrelated to weather.
Normal weather for the forecast is defined as a 20-year moving average of degree-days taken from the National Oceanic and Atmospheric Administration’s Spokane
International Airport data. Normal weather updates only when a full year of new data is
available. For example, normal weather for 2015 is the 20-year average of degree-days
for the 1995 to 2014 period; and 2016 is the 1996 to 2015 period. The choice of a 20-year moving average for defining normal weather reflects several
factors. First, recent climate research from the National Aeronautic and Space
Administration’s (NASA) Goddard Institute for Space Studies (GISS) shows a shift in
temperature starting about 20 years ago. The GISS research finds that summer
temperatures in the Northern Hemisphere have increased about one degree Fahrenheit above the 1951-1980 reference period; the increase started roughly 20 years ago in the
1981-1991 period.10 An in-house analysis of temperature in Avista’s Spokane-Kootenai
service area, using the same 1951-1981 reference period, also shows an upward shift
in temperature starting about 20-years ago. A detailed discussion of this analysis is in
the peak-load forecast section of this chapter.
The second factor in using a 20-year moving average is the volatility of the moving
average as function of the years used to calculate the average. Moving averages of 10
and 15 years showed considerably more year-to-year volatility than the 20-year
average. This volatility can obscure longer-term trends and lead to overly sharp changes in forecasted loads when the updated definition of normal weather is applied
each year. These sharp changes would also cause excessive volatility in the revenue
and earnings forecasts.

As noted earlier, if RAP, AHS, and IP appear in Equation 3.2, then they must also be forecasted for five years to generate the UPC forecast. The assumption in the five-year
forecast for this IRP is that RAP will increase two percent annually. This rate reflects the
average annual real growth rate for the 2005-2013 period. AHS is constant at the 2012
level.11 This reflects the relative stability of AHS over the 2006-2013 period. Table 3.1
shows the schedules using these three drivers.

10 See Hansen, J.; M. Sato; and R. Ruedy (2013). Global Temperature Update Through 2012,
http://www.nasa.gov/topics/earth/features/2012-temps.html 11 AHS only appears in the forecast equation for Washington Schedule 1 UPCAHS is not a statistically
significant predictor of UPC and the sign on the estimated regression coefficient is not stable for Idaho Schedule 1.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 33 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-9
Table 3.1: UPC Models Using Non-Weather Driver Variables
Schedule Variables Comment
Washington:
Residential Schedule 1 RAP, AHS
Commercial Schedule 31 RAP Commercial pumping schedule
Industrial Schedule 31 RAP
Industrial Schedules 11, 21, and 25 IP
Idaho:
Residential Schedule 1 RAP AHS not a statistically significant or stable driver
Commercial Schedule 31 RAP Commercial pumping schedule
Industrial Schedules 11 and 21 IP

IP forecasts generate from a regression using the GDP forecast. Equation 3.3 and Figure 3.7 describes this process.
Equation 3.3: IP Regression Equation

Where:

 GIPy,US = the annual growth in IP in year y.
 GGDPy,US= the annual growth in real GDP in year y.
 εy= a random error term.
Equation 3.3 uses historical data and incorporates forecasts for GDP to forecast GIP
over five years. GIP is an input for the generation of a forecast for the level of the IP index. The forecasts for GGDP reflect the average of forecasts from multiple sources.
Sources include the Bloomberg survey of forecasts, the Philadelphia Federal Reserve
survey of forecasters, the Wall Street Journal survey of forecasters, and other sources.
Averaging forecasts reduces the systematic errors of a single-source forecast. This
approach assumes that macroeconomic factors flow through UPC in the industrial schedules. This reflects the relative stability of industrial customer growth over the
business cycle.

Figure 3.8 shows the historical relationship between the IP and industrial load for
electricity.12, The load values have been seasonally adjusted using the Census X12 procedure. The historical relationship is positive for both loads. The relationship is very
strong for electricity with the peaks and troughs in load occurring in the same periods as
the business cycle peaks and troughs.

12 Data Source: U.S. Federal Reserve and Avista records. 13 Figure 3.8 excludes one large industrial customer with significant load volatility.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 34 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-10
Figure 3.7: Forecasting IP Growth

Figure 3.8: Industrial Load and Industrial (IP) Index

Customer Forecast Methodology
The econometric modeling for the customer models range from simple smoothing
models to more complex autoregressive integrated moving average (ARIMA) models. In
some cases, a pure ARIMA model without any structural independent variables is used.
For example, the independent variables are only the past values of the schedule customer counts, the dependent variable. Because the customer counts in most
schedules are either flat or growing in stable fashion, complex econometric models are
generally unnecessary for generating reliable forecasts. Only in the case of certain
residential and commercial schedules is more complex modeling required.
For the main residential and commercial schedules, the modeling approach needs to
account for customer growth between these schedules having a high positive
correlation over 12-month periods. This high customer correlation translates into a high
70
80
90
100
110
120
70 GWh
80 GWh
90 GWh
100 GWh
110 GWh
120 GWh
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Industrial, SA Industrial, Trend-Cycle Industrial Production
Average GDP Growth Forecasts:
 IMF, FOMC, Bloomberg, etc.
 Average
forecasts out 5-yrs.
U.S Industrial Production
Index (IP) Growth Model:
 Model links year y GDP growth year y IP growth.
 Federal Reserve
industrial production index is measure of IP growth.
 Forecast out 5-yrs.
Generate Average, High, and Low IP Forecast:
 Forecast annual IP growth using the GDP forecast average.
 Convert annual growth scenario to a monthly basis to project out the monthly level of the IP
index.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 35 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-11
correlation over the same 12-month periods. Table 3.2 shows the correlation of customer growth between residential, commercial, and industrial users of Avista
electricity and natural gas. To assure this relationship in the customer and load
forecasts, the models for the Washington and Idaho Commercial Schedules 11 use
Washington and Idaho Residential Schedule 1 customers as a forecast driver. Historical and forecasted Residential Schedule 1 customers become drivers to generate customer forecasts for Commercial Schedule 11 customers.

Table 3.2: Customer Growth Correlations, January 2005-December 2013
Customer Class
(Year-over-Year)
Residential,
Year-over-
Year
Commercial,
Year-over-
Year
Industrial,
Year-over-
Year
Streetlights,
Year-over-Year
Residential 1
Commercial 0.892 1
Industrial -0.285 -0.167 1
Streetlights -0.273 -0.245 0.209 1

Figure 3.9 shows the relationship between annual population growth and year-over-year customer growth.14 For the last 15 years electricity customer growth has closely followed population growth in the combined Spokane-Kootenai MSAs. Both population
and customer growth have averaged 1.2 percent annually over the 2000-14 period.

Figure 3.9: Population Growth vs. Customer Growth, 2000-2014

Figure 3.9 demonstrates that population growth can be used as a proxy for customer
growth. As a result, forecasted population is an adjustment to Expected Case forecasts
of Residential Schedule 1 customers in Washington and Idaho. That is, for schedule 1
14 Data Source: Bureau of Economic Analysis, U.S. Census, and Avista records.
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 36 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-12
in Washington and Idaho, an Expected Case forecast is made using an ARIMA times-series model. If the growth rates generated from this approach differ from forecasted
population growth, the Expected Case forecasts are adjusted to match forecasted
population growth. Figure 3.10 summarizes the forecasting process for population
growth for use in Residential Schedule 1 customers.
Figure 3.10: Forecasting Population Growth

Forecasting population growth is a process that links U.S. GDP growth to service area
employment growth and then links regional and national employment growth to service
area population growth.

The forecasting models for regional employment growth are:

Equation 3.4: Spokane Employment Forecast

Equation 3.5: Kootenai Employment Forecast

Where:
 SPK = the Spokane, WA MSA.
 KOOT = the Kootenai, ID MSA.
 GEMPy = employment growth in year y.
 GGDPy,US, GGDPy-1,US, and GGDPy-2,US = U.S. real GDP growth in
years y, y-1, and y-2.
Average GDP
Growth Forecasts:
 IMF, FOMC, Bloomberg, etc.
 Average
forecasts out 5-yrs.
Non-farm Employment Growth Model:
 Model links year y, y-1, and y-2 GDP growth to year y regional employment growth.
 Forecast out 5-yrs.
 Averaged with GI
forecasts.
Regional Population Growth Models:
 Model links regional, U.S.
growth to Spokane and Kootenai population growth.
 Forecast out 5-yrs for Spokane, WA; and Kootenai,
ID
 Averaged with IHS forecasts.
 Growth rates used to adjust Expected Case ARIMA
customer forecasts for WA-ID Residential Schedule 1
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 37 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-13
 DKC and DHB = structural change (SC) dummy variables for the closing
of Kaiser Aluminum in Spokane.
 For the housing bubble, specific to each region.
 D1994=1 and D2009=1 = outlier (OL) dummy variables for 1994 and 2009
in Kootenai.
 εy= a random error term.
The same average GDP growth forecasts used for the IP growth forecasts are inputs to
generate five-year employment growth forecasts. Employment forecasts are averaged
with IHS Connect’s (formerly Global Insight) forecasts for the same counties. Averaging
reduces the systematic errors of a single-source forecast. The averaged employment
forecasts become inputs to generate population growth forecasts. The forecasting models for regional population growth are:

Equation 3.6: Spokane Population Forecast

Equation 3.7: Kootenai Population Forecast

Where:

 SPK = the Spokane, Washington MSA.
 KOOT = the Kootenai, Idaho MSA.
 GPOPy = employment growth in year y.
 GEMPy-1 and GEMPy-2 = employment growth in y-1 and y-2.
 D1994=1, D2001=1, and D2002=1 = outlier (OL) dummy variables for recession impacts
 DHB,2007=1 = structural change (SC) dummy variable that adjusts for the
after effects of the housing bubble collapse in the Kootenai, Idaho MSA.
Equations 3.6 and 3.7 are estimated using historical data. Next, the GEMP forecasts (the average of Avista and HIS forecasts) become inputs to Equations 3.6 and 3.7 to
generate population growth forecasts. These forecasts, averaged with IHS’s forecasts
for the same MSAs, produce a final population forecast. This population growth forecast
is used to adjust the Expected Case ARIMA generated forecasts for Residential
Schedule 1 customers. This adjustment reconciles forecasted growth with forecasted population growth.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 38 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-14
IRP Long-Run Load Forecast

The Basic Model The long-run load forecast extends the five-year projection out to 2035. It includes the impacts from a growing electric vehicle (EV) and residential rooftop photovoltaic solar
(PV) fleets. The long-run modeling approach starts with Equation 3.8.

Equation 3.8: Residential Long-Run Forecast Relationship

Where:
 ℓy = residential load growth in year y.
 cy = residential customer growth in year y.
 uy = UPC growth in year y.

Equation 3.8 sets annual residential load growth equal to annual customer growth plus
the annual UPC growth.15 Cy is not dependent on weather, so where uy values are weather normalized, ℓy results are weather-normalized. Varying cy and uy generates
different long-run forecast simulations. This IRP pays attention to varying cy for
economic reasons and uy due to increased PV penetration.

Expected Case Assumptions The Expected Case forecast makes assumptions about the long-run relationship
between residential, commercial, and industrial classes, as documented below.

1. Long-run residential and commercial customer growth rates are the same for 2020 to
2040, consistent with historical growth patterns over the past decade. Figure 3.11 shows the Expected Case time path of residential customer growth. The average
annual growth rate after 2019 is approximately 1 percent, assuming a gradual
decline starting in 2020. This value was generated with the Employment and
Population forecast Equations 3.4, 3.5, 3.6, and 3.7 in conjunction with IHS
Connect’s employment and population forecasts for the 2020-2024 period. The Expected Case assumes long-run U.S. employment growth of approximately 1.4
percent and service area employment growth of approximately 1.5 percent. These
numbers result from assumed U.S. long-run GDP growth of approximately 2.4
percent. The annual industrial customer growth rate assumption is zero, matching
historical patterns for the past decade. 2. Commercial load growth follows changes in residential load growth, but with a
spread of 0.5 percent. This assumption of high correlation is consistent with the high
historical correlation between residential and commercial load growth. The 0.5
15 Since UPC = load/customers, calculus shows the annual percentage change UPC ≈ percentage change in load - percentage change in customers. Rearranging terms, the annual percentage change in
load ≈ percentage change in customers + percentage change in UPC.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 39 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-15
percent spread is in the range of historical norms and the forecasted growth spread from the five-year model.

3. Consistent with historical behavior, industrial and streetlight load growth projections
are not correlated with residential or commercial load. For 2020-2035, annual industrial load growth is set at 0.5 percent and streetlight load growth at 0.1 percent. Both growth rates are in the range of historical norms and forecasted growth trends
from the five-year model.

4. The real residential price per kWh increases at 2 percent per year until 2026. Up to 2026, this is the same as the nominal price increasing 4 percent a year assuming a non-energy inflation rate of 2 percent. The real price increase assumption is zero
starting in 2026. This assumption means the nominal price is increasing at the same
rate as consumer inflation, excluding energy. This assumption relies on historical
trends in residential prices and current capital spending plans.
5. The own-price elasticity of UPC is set at -0.20. Own price elasticity was estimated
from the five-year UPC forecast equations for Residential Schedule 1 in Washington
and Idaho. Specifically, the own-price elasticity calculation uses the customer-
weighted average between Washington and Idaho.
6. The AHS-elasticity of UPC is set at 2.3. This assumes AHS is constant up to 2025,
then starts to slowly decline through 2040. AHS-elasticity estimates are from the
five-year UPC forecast equations for Residential Schedule 1 in Washington and
Idaho, using the customer-weighted average between Washington and Idaho.
7. From 2020 to 2023, depressed UPC growth results from new lighting and other
efficiency standards. The impact is more gradual than the Energy Information
Administration’s (EIA) modeling assumptions in its 2014 Annual Energy Outlook.
The EIA assumes a large decline in UPC growth in 2020 with a subsequent sharp
rebound in 2021 that Avista believes is too volatile.
8. Electric vehicles grow at a rate consistent with present adoption rates. Using Electric
Power Research Institute data, Avista estimates that as of 2015 there are around
400 EVs registered in its service area. The forecasted rate of adoption over the
2020-2035 period is a function of forecasted residential customer growth over the same period. The EV adoption rate assumption uses historical data for the 2010-
2013 period to establish the relationship between residential customers and EVs.
This analysis shows that for every 100 residential customers added, approximately
three new registered EVs are added to the Avista service area. However, since
Avista does not serve 100 percent of all loads in the counties it serves, so this adoption rate is reduced by 50 percent. Each EV uses 2,500 kWh per year in the
forecast.

9. Rooftop PV penetration, measured as the share of PV residential customers to total
residential customers, continues to grow at present levels in the forecast. The
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 40 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-16
average PV system is forecast at the current median of 3.0 kilowatts and a 13 percent capacity factor. As of 2014, residential PV penetration was about 0.06
percent. The growth assumption is approximately 0.01 percent per year to 2040,
resulting in a 2035 penetration rate of 0.29 percent. This slow rate of PV penetration
growth is consistent with recent history.
Figure 3.11: Long-Run Annual Residential Customer Growth

Load Scenarios with PV
In addition to the Expected Case forecast, three alternatives illustrate the impacts of
varying PV penetration by 2025: 1 percent (low shock scenario); 5 percent (medium shock scenario); and 10 percent (high shock scenario). In each scenario, the penetration rate is constant after 2025. Each shock case assumes that the PV system
size grows each year so that by 2035 the typical system size equals 5 kilowatts. All
remaining assumptions in the PV penetration cases remain unchanged from the
Expected Case. Figure 3.12 presents results of the Expected Case and shock scenarios. Figure 3.13 shows the annual growth rate in the load shown in Figure 3.12. In all PV scenarios, load growth returns to the Expected Case by 2026 when the
penetration rate stabilizes. Table 3.3 shows the average annual PV scenario growth
rates in native load for the five-year forecast and long-run forecast.

0.7%
0.8%
0.9%
1.0%
1.1%
1.2%
1.3%
20
1
4
20
1
5
20
1
6
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1
7
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1
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1
9
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An
n
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G
r
o
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t
h
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 41 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-17
Figure 3.12: Load Scenarios with PV Shocks

Figure 3.13: Load Growth Scenarios with PV Shocks

1,000
1,050
1,100
1,150
1,200
1,250
1,300
20
1
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1
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5
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e
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Expected Case
Exponential Low Shock
Exponential Medium Shock
Exponential High Shock
-2.0%
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
20
1
5
20
1
6
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1
7
20
1
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1
9
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2
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2
2
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5
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G
r
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h
Expected Case
Exponential Low Shock
Exponential Medium Shock
Exponential High Shock
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 42 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-18
Table 3.3: Average Annual PV Scenario Load Growth for Selected Periods
PV Scenario 2015-2019
(Percent)
2020-2035
(Percent)
2015-2035
(Percent)
Expected Case (0.1%) 0.73 0.47 0.53
Low Shock (1%) 0.73 0.46 0.52
Medium Shock (5%) 0.73 0.38 0.46
High Shock (10%) 0.73 0.28 0.39

The model suggests that with PV penetration between 0.3 percent and 1 percent, load growth after 2020 averages around 0.5 percent, a slight decrease from the 0.6 percent assumption in the Expected Case. Penetration rates 5.0 percent and higher result in
noticeable load growth declines.

Native Load Scenarios with Low/High Economic Growth Native load changes in the PV scenarios because of varying PV growth assumptions. For load growth scenarios, Expected Case PV assumptions remain constant while
regional economic growth levels vary. The high and low scenarios use population
growth Equations 3.6 and 3.7, holding U.S. employment growth constant at 1.4 percent,
but varying MSA employment growth at higher and lower levels gauges the impacts on population growth and utility loads. See Table 3.4. The high/low range for service area employment growth reflects historical employment growth variability. Simulated
population growth is a proxy for residential and customer growth in the long-run forecast
model, and produces the high and low native load forecasts shown in Figure 3.14.

Table 3.4: High/Low Economic Growth Scenarios (2015-2035)
Economic
Growth
Annual U.S.
Employment Growth
(percent)
Annual Service Area
Employment Growth
(percent)
Annual Population
Growth
(percent)
Expected Case 1.4 1.5 1.0
High Growth 1.4 2.3 1.6
Low Growth 1.4 0.7 0.8

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 43 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-19
Figure 3.14: Average Megawatts, High/Low Economic Growth Scenarios

Table 3.5 is the average annual load growth rate over the 2015-2035 period. The low growth scenario predicts a slight load decline over 2020-2022 due to the impact of the
phased-in efficiency standards discussed in Item 7 of the Expected Case Assumptions
listed above.

Table 3.5: Load Growth for High/Low Economic Growth Scenarios (2015-2035)
Economic Growth Average Annual Native Load
Growth
(percent)
Expected Case 0.53
High Growth 0.83
Low Growth 0.23

Long-Run Forecast Residential Retail Sales
Focusing on residential kWh sales, Figure 3.15 is the Expected Case residential UPC
growth plotted against the EIA’s annual growth forecast of U.S. residential use per
household growth. The EIA’s forecast is from the 2014 Annual Energy Outlook. Avista’s
forecast never shows positive UPC growth; in contrast, the EIA forecasts positive UPC
growth returning in 2033. The EIA forecast reflects a population shift to warmer-climate
states where air conditioning is typically required most of the year.

1,000
1,050
1,100
1,150
1,200
1,250
1,300
20
1
4
20
1
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1
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Av
e
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Expected Case
High Economic Growth
Low Economic Growth
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 44 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-20
Figure 3.15: UPC Growth Forecast Comparison to EIA
Figure 3.16 shows the EIA and Expected Case residential load growth forecasts of
residential load growth. Avista’s forecast is higher in the 2015-2020 period, reflecting an
assumption that service area population growth will be stronger than the U.S. average.

Figure 3.16: Load Growth Comparison to EIA

-2.0%
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
20
1
5
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EIA Refrence Case Use Per Household Growth
Expected Case's UPC Growth
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
1
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EIA Purchased Residential Load Growth
Expected Case's Load Growth
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 45 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-21
Monthly Peak Load Forecast Methodology

The Peak Load Regression Model The peak load forecast helps Avista determine the amount of resources necessary to meet peak demand. In particular, Avista must build generation capacity to meet winter
and summer peak periods. Looking forward, the highest peak loads are most likely to
occur in the winter months, although in some years a mild winter followed by a hot
summer could find the annual maximum peak load occurring in a summer hour. This said, on a planning basis where extreme weather is expected to occur in the winter, peak loads occur in the winter throughout the IRP timeframe. Equation 3.9 shows the
current peak load regression model.

Equation 3.9: Peak Load Regression Model

Where:

= metered peak hourly usage on day of week d, in month t, in
year y and excludes two large industrial producers. The data series starts
in June 2004.
 and = heating and cooling degree days the day before the
peak.
 = squared value of HDDd,t,y. and = heating
and cooling degree days the day before the peak.
 = maximum peak day temperature minus 65 degrees. This term
provides a better model fit than the square of CDD.
 = level of real GDP in quarter q covering month t in year y-1.
 ωWDDd,t,y = dummy vector indicating the peak’s day of week.
 ωSDDt,y = seasonal dummy vector indicating the month; and the other
dummy variables control for outliers in March 2005 and February 2012.
 εd,t,y = uncorrelated N(0, σ) error term.

Generating Weather Normal Growth Rates Based on a GDP Driver Equation 3.9 coefficients identify the month and day most likely to result in a peak load
in the winter or summer. By assuming normal peak weather and switching on the
dummy variables for day (dMAX) and month (tMAX) that maximize weather normal peak
conditions in winter and summer, a series of peak forecasts from the current year, yc, are generated out N years by using forecasted levels of GDP as shown in Equation
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 46 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-22
3.3.16 All other factors besides GDP remain constant to determine the impact of GDP on peak load. For winter, this is defined as the forecasted series W:

For summer, this is defined as the forecasted series S:

Both S and W are convertible to a series of annual growth rates, GhMW. Peak load
growth forecast equations are shown below as winter (WG) and summer (SG.)

In Equation 3.10, holding all else constant, growth rates are applied to simulated peak loads generated for the current year, yc, for each month, January through December.
These peak loads are generated by running actual extreme weather days observed
since 1890. The following section describes this process.

Simulated Extreme Weather Conditions with Historical Weather Data Equation 3.10 generates a series of simulated extreme peak load values for heating
degree days.

Equation 3.10: Peak Load Simulation Equation for Winter Months

Where:

 = simulated winter peak megawatt load using historical weather
data.
 HDDt,y,MIN = heating degree days calculated from the minimum (MIN)
average temperature (average of daily high and low) on day d, in month t,
in year y if in month t the maximum average temperature (average of daily high and low) is less than 65 degrees.
 a = aggregate impact of all the other variables held constant at their
average values. Similarly, the model for cooling degree days is:
16 Forecasted GDP is generated by applying the averaged GDP growth forecasts used for the employment and
industrial production forecasts discussed previously.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 47 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-23
Equation 3.11: Peak Load Simulation Equation for Summer Months

Where:

 = simulated winter peak megawatt load using historical weather
data.
 CDDt,y,MAX = cooling degree days calculated from the maximum (MAX) average temperature. The average of daily high (H) and low (L) on day d,
in month t, in year y if in month t if the maximum average temperature
(average of daily high and low) is greater than 65 degrees.
 a = aggregate impact of all the other variables held constant at their average values.
Given over 100 years of average maximum and minimum temperature data, Equations
3.10 and 3.11 applied to each month t will produce over 100 simulated values of peak
load that can be averaged to generate a forecasted average peak load for month t in the current year, yc. The average for each month are shown by Equations 3.12 and 3.13
Equation 3.12: Current Year Peak Load for Winter Months

Equation 3.13: Current Year Peak Load for Summer Months

Forecasts beyond yc are generated using the appropriate growth rate from series WG
and SG. For example, the forecasts for yc+1 for winter and summer are:

The peak load forecast is finalized when the loads of two large industrial customers
excluded from the Equation 3.12 and 3.13 estimations are added back in.

Table 3.6 shows estimated peak load growth rates with and without the two large
industrial customers. Figure 3.17 shows the forecasted time path of peak load out to
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 48 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-24
2040, and Figure 3.18 shows the high/low bounds based on a one in 20 event (95 percent confidence interval) using the standard deviation of the simulated peak loads
from Equations 3.12 and 3.13.

Table 3.6: Forecasted Winter and Summer Peak Growth, 2015-2035
Category Winter
(Percent)
Summer
(Percent)
Excluding Large Industrial Customers 0.74 0.85
Including Large Industrial Customers 0.68 0.79

Table 3.6 shows the summer peak is forecast to grow faster than the winter peak.
Under current growth forecasts, the orange summer line in Figure 3.17 will converge
with the blue winter line in approximately year 2100. Figure 3.18 shows that the winter high/low bound considerably larger than summer, and reflects a greater range of
temperature anomalies in the winter months. Table 3.7 shows the energy and peak
forecasts.

Figure 3.17: Peak Load Forecast 2015-2035

1,000
1,200
1,400
1,600
1,800
2,000
2,200
19
9
7
19
9
9
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g
a
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s
Winter Peak
Summer Peak
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 49 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-25
Figure 3.18: Peak Load Forecast with 1 in 20 High/Low Bounds, 2015-2035

Table 3.7: Energy and Peak Forecasts
Year
Energy
(aMW)
Winter Peak
(MW)
Summer Peak
(MW)
2016 1,074 1,718 1,582
2017 1,084 1,731 1,596
2018 1,091 1,744 1,610
2019 1,097 1,756 1,623
2020 1,099 1,768 1,635
2021 1,102 1,780 1,648
2022 1,105 1,792 1,661
2023 1,110 1,804 1,674
2024 1,115 1,816 1,686
2025 1,120 1,828 1,699
2026 1,125 1,840 1,713
2027 1,131 1,853 1,726
2028 1,137 1,865 1,739
2029 1,143 1,878 1,753
2030 1,150 1,891 1,766
2031 1,156 1,903 1,780
2032 1,163 1,916 1,794
2033 1,169 1,929 1,808
2034 1,176 1,942 1,822
2035 1,183 1,955 1,836

1,000
1,200
1,400
1,600
1,800
2,000
2,200
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19
9
9
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3
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3
5
Me
g
a
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a
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s
Winter Peak Summer Peak
Winter- High Winter- Low
Summer- High Summer- Low
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 50 of 212
Chapter 3: Economic & Load Forecast
Avista Corp 2015 Electric IRP 3-26
Testing for Changes in Extreme Temperature Behavior The impacts of global warming and the relevance of historical temperature data when
forecasting future peak loads, drives much of the recent load forecasting debates. To
validate the use of historical temperatures in the peak load forecast, an analysis was
conducted using the same GISS methodology and reference period referenced in the UPC forecast methodology section. In particular, using 1951-1981 as the reference period, Avista examined daily temperature anomalies using daily temperature data from
the Spokane International Airport going back to 1947. The analysis focused on the core
summer months (June, July, and August) and winter months (December, January, and
February). The GISS study only considered summer months and found, in addition to an increase in the average temperature in the summer, the variance around the average increased. Specifically, the frequency of extreme temperature anomalies three
or more standard deviations above the summer average increased compared to the
1951 to 1981 reference period. In contrast, while Avista analysis shows increased
average temperatures compared to the reference period, there was no significant shift
in the frequency of extreme temperature events. This finding supports continued use of historical temperature extremes for peak load forecasting.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 51 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-1
4. Existing Supply Resources

Introduction & Highlights
Avista relies on a diverse portfolio of assets to meet customer loads, including owning
and operating eight hydroelectric developments on the Spokane and Clark Fork rivers.
Its thermal assets include partial ownership of two coal-fired units, five natural gas-fired
projects, and a biomass plant. Avista purchases energy from several independent
power producers (IPPs), including Palouse Wind and the City of Spokane.
Figure 4.1 shows Avista capacity and energy mixes. Winter capability is the share of
total capability of each resource type the utility can rely upon to meet peak load (absent
outages). The annual energy chart represents the energy as a percent of total supply;
this calculation includes fuel limitations (for water, wind, and wood), maintenance and
forced outages. Avista’s largest supply in the peak winter months is hydroelectric at 51 percent, followed by natural gas. On an energy capability basis, natural gas-fired
generation can produce more energy, at 42 percent, than hydroelectric at 37 percent,
because it is not constrained by fuel limitations. In any given year, the resource mix will
change depending on streamflow conditions and market prices.

Figure 4.1: 2016 Avista Capability & Energy Fuel Mix

Owned Hydro40%
Contracted
Hydro11%
Natural Gas37%
Coal9%
Biomass & Wind3%
Winter Capability
Owned Hydro28%
Contracted Hydro10%
Natural Gas42%
Coal13%
Biomass & Wind
7%
Annual Energy
Section Highlights
Hydroelectric represents about half of Avista’s winter generating capability.

Seven percent of Avista’s generating


Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 52 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-2
Avista reports its fuel mix annually in the Washington State Fuel Mix Disclosure. The State calculates the resource mix used to serve load, rather than generation potential,
by adding regional estimates for unassigned market purchases and Avista-owned
generation stripped of environmental attributes from renewable energy credit (REC)
sales.

Spokane River Hydroelectric Developments
Avista owns and operates six hydroelectric developments on the Spokane River. Five
operate under 50-year FERC operating licenses issued in June 2009. The sixth, Little
Falls, operates under a separate license authorized by the U.S. Congress. This section
describes the Spokane River developments and provides the maximum on-peak and
nameplate capacity ratings for each plant. The maximum on-peak capacity of a generating unit is the total amount of electricity it can safely generate with its existing
configuration and state of the facility. This capacity is often higher than the nameplate
rating for hydroelectric developments because of plant upgrades. The nameplate, or
installed capacity, is the capacity of a plant as rated by the manufacturer. All six
hydroelectric developments on the Spokane River connect directly to the Avista transmission grid.

Post Falls
Post Falls is the facility furthest upstream on the Spokane River. It is located several miles east of the Washington/Idaho border. It began operating in 1906, and during summer months maintains the elevation of Lake Coeur d’Alene. Post Falls has a 14.75-
MW nameplate rating and is capable of producing up to 18.0 MW with its six generating
units.

Upper Falls The Upper Falls development sits within the boundaries of Riverfront Park in downtown
Spokane. It began generating in 1922. The 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 in downtown Spokane near Riverfront Park. Rebuilt in 1992, the single generating
unit has a 14.8-MW nameplate rating and a 15.0-MW maximum capacity rating. Avista
redeveloped the Huntington Park area around this facility in 2014 in honor of the
company’s 125th anniversary.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 53 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-3
Huntington Park, Downtown Spokane, WA

Nine Mile A private developer built the Nine Mile development in 1908 near Nine Mile Falls, Washington. Avista purchased the project in 1925 from the Spokane & Inland Empire
Railroad Company.

Nine Mile is undergoing substantial upgrades scheduled for completion in 2016. Two 8-MW units will replace its existing 3-MW units. Once operational, the new units will add 1.4 aMW of energy beyond the plant’s original configuration and bring total operating
capability to 32 MW. The nameplate rating of the facility will rise to 36 MW. In addition to
capacity upgrades, the facility will receive new hydraulic governors, static excitation
systems, switchgear, station service, control and protection packages, ventilation, rehabilitation of intake gates and sediment bypass system, and other investments.
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, bringing the project’s four units to a nameplate rating of 81.6 MW and 88.0 MW
of combined capacity.

Little Falls
The Little Falls development, completed in 1910 near Ford, Washington, is the furthest downstream hydroelectric facility on the Spokane River. A new runner upgrade in 2001
added 0.6 aMW of energy generation to the project. 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
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 54 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-4
completed, replacing generators, turbines, and unit protection and control systems on the four units will start.

Clark Fork River Hydroelectric Development
The Clark Fork River Development 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 the Avista transmission system.
Cabinet Gorge
Cabinet Gorge started generating power in 1952 with two units, and added two
additional generators the following year. The current maximum on-peak plant capacity is
270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades to units 1 through 4 occurred in 1994, 2004, 2001, and 2007, respectively.
Noxon Rapids
The Noxon Rapids development includes four generators installed between 1959 and
1960, and a fifth unit entered service in 1977. Avista completed major turbine upgrades on units 1 through 4 between 2009 and 2012. The upgrades increased the capacity of each unit from 105 MW to 112.5 MW and added 6.6 aMW of additional energy.

Total Hydroelectric Generation
Avista’s hydroelectric plants have 1,065.4 MW of on-peak capacity. Table 4.1
summarizes the location and operational capacities of Avista’s hydroelectric projects
and the expected energy output of each facility based on the 80-year hydrologic record.

Table 4.1: Avista-Owned Hydroelectric Resources

Monroe Street Spokane Spokane, WA 14.8 15.0 11.2
Post Falls Spokane Post Falls, ID 14.8 18.0 9.4
Nine Mile Spokane Nine Mile Falls, WA 36.0 32 15.7
Little Falls Spokane Ford, WA 32.0 35.2 22.6
Long Lake Spokane Ford, WA 81.6 89.0 56.0
Upper Falls Spokane Spokane, WA 10.0 10.2 7.3
Cabinet Gorge Clark Fork Clark Fork, ID 265.2 270.5 123.6
Noxon Rapids Clark Fork Noxon, MT 518.0 610.0 196.5

Thermal Resources
Avista owns seven thermal generation assets located across the Northwest. Based on
IRP analyses, Avista expects each plant to continue operation through the 20-year IRP
horizon. The resources provide dependable energy and capacity serving base- and
peak-load obligations. A summary of their capabilities is in Table 4.2.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 55 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-5
Table 4.2: 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 176.0 130.0 166.5
Northeast Spokane, WA Gas 1978 66.0 42.0 61.2
Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6
Coyote Springs 2 Boardman, OR Gas 2003 312.0 277.0 287.3
Kettle Falls Kettle Falls, WA Wood 1983 47.0 47.0 50.7
Kettle Falls CT1 Kettle Falls, WA Gas 2002 11.0 8.0 7.5

Colstrip Units 3 and 4
The Colstrip plant, located in eastern Montana, consists of four coal-fired steam plants connected to a double-circuit 500 kV BPA transmission line under a long-term wheeling
agreement. Talen Energy Corporation operates the facilities on behalf of the six owners.
Avista has no ownership interest in Units 1 or 2, but owns 15 percent of Units 3 and 4.
Unit 3 began operating in 1984 and Unit 4 was finished in 1986. The Avista share of
Colstrip has a maximum net capacity of 222.0 MW, and a nameplate rating of 247.0 MW.

Rathdrum
Rathdrum consists of two simple-cycle combustion turbine (CT) units. This natural gas-
fired plant near Rathdrum, Idaho connects to the Avista 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, has two aero-derivative simple-cycle CT units completed in 1978. It 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 limited to run no more than
approximately 550 hours per year.
Boulder Park
The Boulder Park project entered service in the Spokane Valley in 2002 and connects
directly to the Avista 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.
1 The Kettle Falls CT numbers include output of the natural gas-fired turbine plus the benefit of its steam
to the main unit’s boiler.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 56 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-6
Coyote Springs 2 Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine (CCCT)
located near Boardman, Oregon. The plant connects to the BPA 500 kV transmission
system under a long-term agreement. The plant began service in 2003 with a maximum
capacity of 285 MW in the winter and 250 MW in the summer, with duct burners providing additional capacity of up to 27 MW. The plant nameplate rating of the plant is 287.3 MW.

Recent upgrades to Coyote Springs 2 include cooling optimization and cold day
controls. 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 upgrades allows Avista to maintain high reliability,
reduce future O&M costs, maintain compliance with WECC reliability standards, and
help prevent damage to the machine during electrical system disturbances.

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 on its 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 7.5 MW 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 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 55.0 to 58.0 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 can be limited in
the winter when the natural gas pipeline is capacity constrained. For IRP modeling, the
CT does not run when temperatures fall below zero. This operational assumption
reflects natural gas availability limits on the plant when local natural gas distribution demand is highest.

Power Purchase and Sale Contracts
Avista uses purchase and sale arrangements of varying lengths to meet a portion of its
load requirements. Contracts provide many benefits, including environmentally low-
impact and low-cost hydroelectric and wind power. This chapter describes the contracts
in effect during the timeframe of the 2015 IRP. Tables 4.3 through 4.5 summarize
Avista’s contracts.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 57 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-7
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 originally entered into long-term contracts for the output of four of these projects
“at cost.” Avista now competes in capacity auctions to retain the rights of these expiring contracts. The Mid-Columbia contracts in Table 4.3 provide energy, capacity, and reserve capabilities; in 2015, the contracts provide approximately 160 MW of capacity
and 96 aMW of energy. The Douglas PUD (2018) and Chelan PUD (2020) contracts
expire over the next five years. Avista may extend these contracts or even gain
additional capacity in auctions; however, there are no guarantees to extend 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 a result of
agreements including the 1961 Columbia River Treaty and the 1964 Pacific Northwest
Coordination Agreement (PNCA). Both agreements optimize hydroelectric project operations in the Northwest U.S. and Canada. In return for these benefits, Canada
receives return energy under the Canadian Entitlement. The Columbia River Treaty and
the PNCA manage storage water in upstream reservoirs for coordinated flood control
and power generation optimization. On September 16, 2024, 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 reached. This IRP
does not model alternative outcomes for the treaty negotiations, because it will not likely
affect long-term resource acquisition and we cannot speculate on future wholesale electricity market impacts of the treaty.

Lancaster Power Purchase Agreement
Avista acquired output rights to the Lancaster CCCT, located in Rathdrum, Idaho, as part of the sale of Avista Energy in 2007. Lancaster directly interconnects with the
Avista transmission system at the BPA Lancaster substation. Under the tolling contract,
Avista pays a monthly capacity payment for the sole right to dispatch the plant through
October 2026. In addition, Avista pays a variable energy charge and arranges for all of
the fuel needs of the plant.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 58 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-8
Table 4.3: 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-2001 Dec-2052 34.8 16.9
Grant PUD Wanapum 3.7 Dec-2001 Dec-2052 34.5 27.2
Chelan PUD Rocky Reach 5.0 Jan-2016 Dec-2020 58.1 18.4
Chelan PUD Rock Island 5.0 Jan- 2016 Dec-2020 20.1 25.7
Douglas PUD Wells 3.3 Feb-1965 Aug-2018 27.9 16.5
Canadian Entitlement -10.1 -5.7
2016 Total Net Contracted Capacity and Energy 155.3 99.0

Public Utility Regulatory Policies Act (PURPA)
The passage of PURPA by Congress in 1978 required utilities to purchase power from
resources meeting certain size and fuel criteria. Avista has many PURPA contracts, as
shown in Table 4.4. The IRP assumes renewal of these contracts after their current terms end.

Bonneville Power Administration – WNP-3 Settlement
Avista signed settlement agreements with BPA and Energy Northwest on September 17, 1985, ending its nuclear plant 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.
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 contained in Chapter 6.
Palouse Wind – Power Purchase Agreement
Avista signed a 30-year power purchase agreement in 2011 with Palouse Wind for the
entire output of its 105-MW project. Avista has the option to purchase the project after
10 years. Commercial operation began in December 2012. The project is EIA-qualified
and directly connected to Avista’s transmission system.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 59 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-9
Table 4.4: PURPA Agreements

Meyers Falls Hydro
Technology Systems Inc.
Hydro Kettle Falls,
WA
12/2013 1.30 1.05
Spokane Waste to Energy
City of Spokane Municipal Waste Spokane, WA 12/2017 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
Clark Fork LLC. Hydro Clark Fork, ID 12/2017 0.22 0.12
Upriver Dam2 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

Table 4.5: Other Contractual Rights and Obligations

PGE Capacity Exch. Exchange System 12/2016 -150 -150 0
Douglas Settlement Purchase Hydro 9/2018 2 2 3
Energy America Sale CEC RECs3 12/2019 50 50 50
WNP-3 Purchase System 6/2019 82 0 42
Lancaster Purchase Natural Gas 10/2026 279 228 215
Palouse Wind Purchase Wind 12/2042 0 0 40
Nichols Pumping Sale System n/a -1 -1 -1
2 Energy estimate is net of the city’s pumping load. 3 CEC RECs are renewable resources based on approval of the California Energy Commission. Kettle Falls, Palouse Wind, Nine Mile Falls, Post Falls, Monroe Street, and Upper Falls are CEC certified.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 60 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-10
Customer-Owned Generation
A small but growing number of customers install their own generation systems. In 2007
and 2008, the average number of new net-metering customers added was 10 yearly; and between 2009 and 2014, the average increased to 38 per year. The increase likely was in response to generous federal and new state tax incentives. Certain renewable
projects qualify for the federal government’s 30 percent tax credit and Washington tax
incentives of up to $5,000 per year through 2020. The Washington utility taxes credit
finances these incentives that rise to as much as $1.08 per kWh. Avista had 208 customer-installed net-metered generation projects on its system at the
end of 2014 representing a total installed capacity of 1.8 MW. Eighty-four percent of
2014 installations are in Washington, with most located in Spokane County. In that year,
Avista credited customers $245,884 for the energy created via the Washington state tax incentive–an average of $281 per MWh. Figure 4.2 shows annual net metering customer additions. Solar is the primary 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 at less
than a 10 percent capacity factor, depending on location. Given current tax incentives are nearing optimal payback, the number of new net-metered systems rose in 2014. If 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 4.2: Avista’s Net Metering Customers

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 61 of 212
Chapter 4: Existing Supply Resources
Avista Corp 2015 Electric IRP 4-11
Solar
As solar equipment and installation prices have decreased, the nation’s interest and
development of the technology has increased dramatically. Avista has three small projects of its own. The first was three kilowatts on its corporate headquarters as part of the Solar Car initiative. The solar production helped power two electric vehicles in the
corporate fleet. Avista installed a 15-kilowatt solar system in Rathdrum, Idaho to supply
Buck-A-Block, a program allowing customers to purchase green energy. The 423-kW
Avista Community Solar project entered service in 2015. The project takes advantage of federal and state subsidies. The $1,080/MWh Washington solar subsidy allows customers to purchase individual solar panels within the facility and receive payments
that more than offset their upfront investment. The program will utilize approximately
$600,000 each year in state tax incentives.

Boulder Park Community Solar Project

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 62 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
5. Energy Efficiency & Demand Response

Introduction
Avista began offering energy efficiency programs to its customers in 1978. Recent
programs include the distribution in the summer of 2011 of 2.3 million compact
fluorescent lights (CFLs) to residential and commercial customers for an estimated
energy savings of 39,005 MWh. The Opower Home Energy Report program began
sending peer-comparison reports to participating customers every two months beginning in June 2013. Conservation programs regularly meet or exceed regional
shares of the energy efficiency gains outlined by the Northwest Power and
Conservation Council (NPCC).

Figure 5.1 illustrates Avista’s historical electricity conservation acquisitions. Avista has acquired 197 aMW of energy efficiency since 1978; however, the 18-year average
measure life of the conservation portfolio means some measures no longer are reducing
load. The 18-year assumed measure life accounts for the difference between the
cumulative and online trajectories in Figure 5.1. Currently 127 aMW of conservation
serves customers, representing nearly 11 percent of loads.
Avista energy efficiency programs provide conservation and education options to the
residential, low income, commercial, and industrial customer segments. Program
delivery includes prescriptive, site-specific, regional, upstream, behavioral, market transformation, and third-party direct install options. Prescriptive programs, or standard offerings, provide cash incentives for standardized products such as the installation of
qualifying high-efficiency heating equipment. Prescriptive programs work in situations
where uniform products or offerings are applicable for large groups of homogeneous
customers and primarily occur in programs for 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. Other delivery methods build off
these approaches but may include upstream buy downs of low cost measures, free-to-
customer direct install programs, and coordination with regional entities for market transformation efforts.

Section Highlights
 Current Avista-sponsored conservation reduces retail loads by nearly 11
percent, or 127 aMW.
 This IRP evaluated over 3,000 equipment options and over 2,300 measure
options covering all major end use equipment, as well as devices and actions
to reduce energy consumption for this IRP.
 This 2015 IRP is the first to co-optimize conservation and demand response options with generation resource options using our PRiSM model.

 Bas
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 63 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
Figure 5.1: Historical and Forecast Conservation Acquisition (system)

Efficiency programs with economic paybacks of less than one year are not eligible 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.

The Conservation Potential Assessment
Avista retained Applied Energy Group (AEG) to develop an independent Conservation
Potential Assessment (CPA) for this IRP. The study forms the basis for the conservation
portion of this plan. 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 resource selection process, in accordance with the EIA’s 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.
AEG took the following steps to assess and analyze energy efficiency and potential within Avista’s service territory. Figure 5.2 illustrates the steps of the analysis.
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 64 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
Figure 5.2: Analysis Approach Overview

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’ electricity usage behavior in
Avista’s service territory. AEG uses this assessment to develop energy market
profiles describing energy consumption by market segment, vintage (existing or new
construction), end use, and technology.
2. Baseline Projection: Develops a projection of energy and demand for electricity,
absent the effects of future conservation by sector and by end use for the entire 20-
year study.
3. Measure Assessment: Identifies and characterizes energy efficiency measures
appropriate for Avista, including regional savings from energy efficiency measures acquired through Northwest Energy Efficiency Alliance efforts.
4. Potential: Analyzes measures to identify technical, economic, and achievable
conservation potential.

Market Segmentation The CPA divides Avista customers by state and class. The residential class segments
include single-family, multi-family, manufactured home, and low-income customers.1
AEG incorporated information from the Commercial Building Stock Assessment to break
out the commercial sector by building type. Avista analyzed the industrial sector as a
whole for each state. AEG characterized energy use by end use within each segment in each sector, including space heating, cooling, lighting, water heat or motors; and by
technology, including heat pump and resistance-electric space heating.

1 The low-income threshold for this study is 200 percent of the federal poverty level. Low-income
information is available from census data and the American Community Survey data.
Avista data
Avista data Avista data/secondary data

Energy market profiles by end
use, fue/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
Avista data
Avi 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-17-01 S. Kinney, Avista
Schedule 1, Page 65 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
The baseline projection is the “business as usual” metric without future utility conservation programs. It estimates annual electricity consumption and peak demand
by customer segment and end use absent future efficiency programs. The baseline
projection includes the impacts of known building codes and energy efficiency
standards as of 2013 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;
 trends in end use and technology saturations;
 equipment purchase decisions;
 consumer price elasticity;
 income; and
 persons per household.

For each customer class, AEG compiled a list of electrical energy efficiency measures and equipment, drawing from the NPCC’s Sixth Power Plan, the Regional Technical
Forum, and other measures applicable to Avista. The approximately 6,000 individual
measures included in the CPA represent a wide variety of end use applications, as well
as devices and actions able to reduce customer energy consumption. The CPA includes
measure costs, energy and capacity 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 of Avista’s service territory. Many measures initially do not pass the economic
screen of supply side resource options, but some measures may become part of the
energy efficiency program as contributing factors evolve during the 20-year planning horizon.

Avista supplements energy efficiency activities by including potentials for distribution
efficiency measures consistent with EIA conservation targets and the NPCC Sixth
Power Plan. Details about the distribution efficiency projects are in Chapter 8 – Transmission and Distribution Planning.

Overview of Energy Efficiency Potential
AEG’s approach adhered to the conventions outlined in the National Action Plan for
Energy Efficiency Guide for Conducting Potential Studies.2 The guide represents the
most credible and comprehensive national industry standard practice for specifying
energy efficiency potential. Specifically, three types of potential are in this study, as
discussed below. Table 5.1 shows the CPA results for technical, economic, and achievable potential.

2 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-17-01 S. Kinney, Avista
Schedule 1, Page 66 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years)
2016 2017 2020 2025 2035
Cumulative (GWh)
Achievable Potential 34 74 236 575 1,090
Economic Potential 68 138 360 733 1,292
Technical Potential 173 344 837 1,581 2,506

Cumulative (aMW)
Achievable Potential 3.9 8.5 26.9 65.6 124.5
Economic Potential 7.7 15.9 41.1 83.7 147.5
Technical Potential 19.8 39.3 95.5 180.5 286.1

Technical Potential
Technical potential finds the most energy-efficient option commercially available for
each purchase decision, regardless of its cost. This theoretical case provides the broadest and highest definition of savings potential 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 in
the CPA is a “phased-in technical potential,” meaning the only considered portion of
current equipment stock is that reaching the end of its useful life and changed out with 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.

Economic Potential
Economic potential includes the purchase of the most efficient cost-effective option available for each given equipment or non-equipment measure.3 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.4 Measures passing 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, accounting for expected program
participation, customer preferences, and budget constraints. It estimates achievable savings attainable through Avista energy efficiency programs when considering market
3 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”. 4 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-17-01 S. Kinney, Avista
Schedule 1, Page 67 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
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, AEG applied market acceptance rates based upon NPCC-defined
ramp rates from the Sixth Power Plan, taking into account market barriers and measure lives. However, AEG adjusted the ramp rates for the measures and equipment to reflect
Avista’s market-specific conditions and program history. In some cases Avista ramp
rates exceed the NPCC’s, illustrating a mature energy efficiency program reaching a
greater percentage of the market than estimated by the now five-year-old 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 the additional design and implementation time necessary to launch a new program. Other examples of ramp rate
changes include measures or equipment where the regional market shows lower
adoption rates than historically estimated by the NPCC, such as heat pump water
heaters. AEG’s CPA forecasts incremental annual achievable potential for all sectors at
3.9 aMW (34,106 MWh) in 2016, increasing to cumulative savings of 124.5 aMW through 2035.

PRiSM Co-Optimization
For the first time, this IRP used a second methodology to identify achievable conservation potential. This method selects conservation measures concurrently with
supply side resources in Avista’s PRiSM model. This methodology was the result of a
2013 IRP Action Item to streamline the process of selecting conservation in conjunction
with the efficient frontier modeling process. See Chapter 11 for more details about the
PRiSM model. The method inputs all measures with TRCs less than 130 percent of the avoided cost rate, adjusted for ramp rates used for achievable potential. The 130-
percent threshold ensures that conservation options are available in the lower-risk
region of the efficient frontier, just as PRiSM includes higher-cost supply-side options
that help mitigate risk. The conservation resources compete with supply- and demand
response options to meet Avista resource deficits. Each conservation program’s winter and summer peak contribution, plus the value of its energy savings are considered.

Given the change to evaluating conservation directly in PRiSM, results were also
compared to the historical method. Figure 5.3 shows both CPA and PRiSM
conservation estimates. The results were very similar, with PRiSM selecting 0.4 aMW more conservation than the CPA over the 20-year horizon. The similar result is
evidence that the avoided cost method used for previous IRPs was accurate. However,
using PRiSM for program selection allows conservation selections to change with
differing resource strategies across the efficient frontier.5 Previously a change in
resource selection required a feedback loop with AEG to re-run the CPA with new avoided costs. With the new approach, no feedback loop is required. Given the results
of this methodology, Avista will likely use this method in future IRPs for conservation
selection.

5 For example, pursuing a least-cost strategy might have less conservation resource than pursuing a
least-cost strategy where more costly supply-side resources are being avoided through conservation.
Exhibit No. 4
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Avista Corp 2015 Electric IRP
Figure 5.3: Cumulative Conservation Potentials CPA versus PRiSM

Conservation Targets
The IRP process provides conservation targets for the EIA Biennial Conservation Plan.
Other components, including conservation from distribution and transmission efficiency
improvements, combine with energy efficiency targets to arrive at the full Biennial
Conservation Plan target for Washington. Table 5.2 contains achievable conservation
potential for 2016-2017 using both the AEG and PRiSM methodologies. Also included is the energy savings expected from the 2016 and 2017 feeder upgrade projects. See
Chapter 8 – Transmission and Distribution Planning for more information.

Table 5.2: Annual Achievable Potential Energy Efficiency (Megawatt Hours)
Year Methodology Washington Idaho
2016 AEG CPA 22,863 11,243
2016 PRiSM Selection 22,747 11,213

2017 AEG CPA 26,930 13,217
2017 PRiSM Selection 26,799 13,186

2016 WA Feeder Upgrades 485 1,118
2017 WA Feeder Upgrades 0 0

2016 Facility Efficiencies 0 300
2017 Facility Efficiencies 151 0
4
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2016 2020 2025 2030 2035
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e
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AEG's CPA
PRiSM Selection
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
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 acquire all cost-effective and achievable energy conservation.6 For the first 24-month period under the law, 2010-2011, this equaled a ramped-in share of the regional 10-year conservation target
identified in the Sixth Power Plan. Penalties of at least $50 per MWh exist for utilities not
achieving Washington EIA targets.
The EIA requirement to acquire all cost-effective and achievable conservation may pose significant financial implications for Washington customers. Based on CPA results, the
projected 2016 conservation acquisition cost to electric customers is $11.6 million. This
amount grows by 224% to $26 million by 2026, a total of $186 million over this 10-year
period. Costs continue increasing after 2026 to more than $31 million in 2035. Figure 5.4 shows the annual cost in millions of nominal dollars for the utility to acquire the projected electric achievable potential.

Figure 5.4: 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 conservation cost-effectiveness and acquisition opportunities. Results establish
baseline goals for continued development and enhancement of energy efficiency
programs, but the results are not detailed enough to form an actionable plan. Avista
uses both processes’ results to establish a budget for energy efficiency measures, help
6 The EIA defines cost effective as 10 percent higher than the cost a utility would otherwise spend on
energy acquisition.
0
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Energy Savings (aMW)
Spending (millions $)
Levelized Cost ($/MWh)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
determine the size and skill sets necessary for future operations, and identify 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.
The CPA is useful for implementing energy efficiency programs in the following ways:
 Identifying conservation resource potentials by sector, segment, end use, and
measure of where energy savings may come from. Energy efficiency staff uses
CPA results to determine the segments and end uses/measures to target.
 Identifying measures with the highest TRC benefit-cost ratios, resulting in the
lowest cost resources, brings the greatest amount of benefits to the overall
portfolio.
 By identifying measures with great adoption barriers based on the economic
versus achievable results by measure, staff can develop effective programs for
measures with slow adoption or significant barriers.
 By improving 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. Additional consideration for lost opportunities can lead to offering
greater incentives on measures with higher benefits and lower incentives on
measures with lower benefits.

The CPA 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 both residential and non-residential program concepts, and their sensitivity to more
detailed assumptions, feeds into program planning.
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 2014 included space and water heating conversions, ENERGY STAR® homes, space and water equipment upgrades, and home
weatherization. The appliance programs offered by ENERGY STAR® phased 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. Other non-appliance ENERGY STAR®
programs continue.
Avista offers its remaining residential energy efficiency programs through other
channels. For example, JACO, a third party administer, operates a refrigerator/freezer
recycling program. UCONS administers a manufactured home duct-sealing program.
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. ARRA funds also helped support another program aimed
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 71 of 212
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Avista Corp 2015 Electric IRP
at helping to remove the financial roadblocks to implementing energy efficiency for customers. This program used ARRA funds to buy down the interest rate on loans
geared directly towards installing energy efficiency measures in the home. This loan
program ended December 31, 2014, after helping fund 269 projects.
Avista processed 5,300 residential energy efficiency rebates in 2014, benefiting approximately 4,000 households. Rebates of over $2.3 million offset customer
conservation-implementation costs. 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 to provide customers reduced cost lighting and showerheads through participating retailers. Finally, Avista distributed over 7,700 CFLs, and provided expert
advice, at various community events throughout the service territory. Residential
programs contributed 25,397 MWh and 355,443 therms of energy savings in 2014.

Avista successfully launched a three-year cost-effective behavioral program in June 2013 using the Opower Home Energy Report platform, where participating customers
receive a peer-comparison report in the mail every two months. Since launch of the
program, Avista has seen a higher than expected ramp rate of energy savings for
participating customers as measured in the statistically valid Randomized Control Trial
method. Uptake in other energy efficiency programs increased as well. The Opower Home Energy Report contributed 8,131 MWh of savings in 2014.

Low-Income Sector Overview
During 2014, six community action agencies administered Avista low-income programs,
targeting a range of end-uses including space and water heating conversions, ENERGY STAR® refrigerators, and weatherization improvements. Beyond direct energy
efficiency measures, Avista funding goes towards health and safety improvements
considered necessary to ensure the habitability of low-income homes and protect the
efficiency measures. The funding also allows the agencies to receive an administration
fee for program delivery.
Avista processed approximately 1,400 low-income sector rebates in 2014, benefitting
360 households.7 During 2014, Avista reimbursed the six agencies over $2.6 million for
energy efficiency upgrades where some measures were fully subsidized and others
capped based on avoided costs. The agencies spent nearly $394,000 on health and human safety, or 13 percent of their total expenditures–within their 15 percent
allowance for this spending category. The low-income energy efficiency programs
contributed 400 MWh of electricity savings and 14,944 therms of natural gas savings in
2014.

Non-Residential Sector Overview
Marketing and the new energy efficiency program development starts with measures
highlighted in the CPA. All electric-efficiency measures with simple paybacks exceeding
one year, but less than eight years for lighting measures or 13 years for other
7 Washington agencies had up to $2.0 million available for energy efficiency improvements. Idaho had
$700,000 available for energy efficiency improvements and $50,000 for conservation education.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
measures, automatically qualify for the non-residential portfolio. The IRP provides account executives, program managers/coordinators, and energy efficiency engineers
to support program implementation. However, characteristics of a non-residential facility
override any high-level program prioritization.
For the non-residential sectors, including multi-family, Avista offers energy efficiency programs on a site-specific or custom basis. Avista offers prescriptive approaches when
treatments result in similar savings and the technical potential is high. As an example,
the prescriptive lighting program is not purely prescriptive in the traditional sense, such
as with residential applications where homogenous programs are provided for all residential customers. It is a more prescriptive approach applied for these similar applications.

Non-residential prescriptive programs offered by Avista include, but are not limited to,
space and water heating conversions and equipment upgrades, appliance and 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, including site-specific multi-family measures
and multi-family market transformation.

Avista processed 1,100 energy efficiency projects resulting in the payment of over $4.6 million in rebates paid directly to non-residential customers to offset the cost of their
energy efficiency projects in 2014. These projects contributed 24,400 MWh of electricity
and 262,000 therms of natural gas savings.

PECI’s Energy Smart Grocer is a regional turnkey program administrated for several years in the Avista service territory. It will approach saturation levels during the early
part of the IRP 20-year planning horizon. The Energy Smart Grocer program contributed
3,275 MWh of the 24,400 MWh of non-residential program savings in 2014.

After years of review, Avista began converting a large portion of its high-pressure sodium (HPS) street light system to LED units in 2015. Advancements in LED
technology and lower product costs make early replacements cost effective. LEDs
consume about half of the energy as their conventional counterparts for the same light
output. Other non-energy benefits include improved visibility and color rendering relative
to HPS lighting, and longer product life. The initial focus of the program is replacing 26,000 100-watt cobra-head style streetlights. Avista intends to study converting
decorative lighting and larger-wattage (200 watt and 400 watt) streetlights in the future.

Demand Response
Over the past decade, demand response (DR) gained growing attention as an alternative for meeting peak load growth. Demand response reduces load to specific customers during peak demand periods. Enrolling customers allows the utility to modify
their usage pattern in exchange for bill discounts. National attention focuses on
residential programs to control water heaters, space heating, and air conditioners. A
2013 Action Item suggested further study of the DR potential based on its selection as a
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 73 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
PRS resource from 2022 to 2027 in that plan. Avista retained AEG to study the potential of future commercial and industrial programs.

Past Programs
Avista’s experience with DR dates back to the 2001 Energy Crisis. Avista responded with an all-customer and irrigation customer buy-back programs and bi-lateral agreements with its largest industrial customers. These programs, along with enhanced
commercial and residential energy efficiency programs, reduced the need for purchases
in very high-cost wholesale electricity markets. A July 2006 multi-day heat wave again
led Avista to rely on DR through a media request for customers to conserve and short-term agreements with large industrial customers. During the 2006 event, Avista estimates DR reduced loads by 50 MW.

Avista conducted a two-year residential load control pilot between 2007 and 2009 to
study specific technologies and examine cost-effectiveness and customer acceptance.
The pilot tested scalable Direct Load Control (DLC) devices based on installation in approximately 100 volunteer households in Sandpoint and Moscow, Idaho. The sample
allowed Avista to test DR with the benefits of a larger-scale project, but in a controlled
and customer-friendly manner. Avista installed DLC devices 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 to four hours. A separate group within the same communities participated in an in-home-display device study as part of the
pilot. The program provided Avista and its customers experience with “near-real time”
energy-usage feedback equipment. Information gained from the pilot is in the report
filed with the Idaho Public Utilities Commission.
Avista engaged in a DR program as part of the Northwest Regional Smart Grid
Demonstration Project (SGDP) with Washington State University (WSU) and
approximately 70 residential customers in Pullman and Albion, Washington. Residential
customer assets including forced-air electric furnaces, heat pumps, and central air-
conditioning units received a Smart Communicating Thermostat provided and installed by Avista. The control approach was non-traditional in several ways. First, the DR
events were not prescheduled, but Avista controlled customer loads defined by pre-
defined customer preferences (no more than a two degree offset for residential
customers and an energy management system at WSU with a console operator). More
importantly, the technology used in the DR portion of the SGDP predicted if equipment was available for participation in the control event. Lastly, value quantification extended
beyond demand and energy savings and explored bill management options for
customers with whole house usage data analyzed in conjunction with smart thermostat
data. Inefficient homes identified through this analysis prompted customer engagement.
For example, an operational anomaly prompted an investigation that uncovered a control board in a customer’s heat pump that caused the system to draw warm air from
inside the home during the heating season. This in turn caused the auxiliary heat to
come on prematurely and cycle too frequently, resulting in high customer bills. The
repair saved the customer money and allowed them to be more comfortable in their
home. Lessons learned from the STP program helped craft Avista’s new Smart Thermostat rebate program (an efficiency-only program) implemented in October 2014.
The Smart Grid demonstration project concluded December 31, 2014.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 74 of 212
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Avista Corp 2015 Electric IRP
Experiences from 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 high natural gas penetration for typical DLC
space and water heat applications. Customers who have interest may not have
qualifying equipment, making them ineligible for participation in the program. Secondly, customers did not seem overly interested in the DLC program offerings. BPA has found similar challenges in gaining customer interest in their recent regional DLC programs.
Finally, Avista is unable at this time to offer pricing strategies other than direct
incentives to compensate customers for participation in the program, which might limit
customer interest.
Demand Response Potential Assessment Study
Avista retained AEG to study the potential for commercial and industrial DR in Avista’s
service territory for the 20-year planning horizon of 2016–2035. It primarily sought to
develop reliable estimates of the magnitude, timing, and costs of DR resources likely
available to Avista for meeting winter peak loads. The study focuses on resources assumed achievable during the planning horizon, recognizing known market dynamics
that may hinder acquisition.

The IRP incorporates DR study results, and the study will affect subsequent DR
planning and program development efforts. A full report outlining the DR potential for commercial and industrial customers is in Appendix C. Table 5.3 details achievable
demand response potential for the programs studied by AEG.

Table 5.3: Commercial and Industrial Demand Response Achievable Potential (MW)

Program 2016 2020 2025 2030 2035
Direct Load Control 0.6 6.5 6.7 6.9 7.2
Firm Curtailment 5.8 17.5 17.4 17.4 17.5
Opt-in Critical Peak Pricing 0.1 1.4 4.3 4.3 4.4
Opt-out Critical Peak Pricing 6.3 4.4 12.9 13.0 13.1

Direct Load Control A DLC program targeting Avista General and Large General Service customers in
Washington and Idaho would directly control electric space heating load in winter,
and water heating load throughout the year, through a load control switch or
programmable thermostat. Central electric furnaces, heat pumps, and water heaters
would cycle on and off during high-load events. Typically, DLC programs take five years to ramp up to maximum participation levels.

Firm Curtailment
Customers participating in a firm curtailment program agree to reduce demand by a
specific amount or to a pre-specified consumption level during the event. In return,
they receive fixed incentive payments. Customers receive payments even if they
never receive a load curtailment request. The capacity payment typically varies with the firm reliability-commitment level. In addition to fixed capacity payments,
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
participants receive compensation for reduced energy consumption. Because the program includes a contractual agreement for a specific level of load reduction,
enrolled loads have the potential to replace a firm generation resource. Penalties are
a possible component of a firm curtailment program.
Industry experience indicates that customers with loads greater than 200 kW participate in firm curtailment programs. However, there are a few programs where
customers with 100-kW maximum demand participate. In Avista’s case, the study
lowered the demand threshold level to include Large General Service customers with
an average demand of 100 kW or more. Customers with operational flexibility are attractive candidates for firm curtailment
programs. Examples of customer segments with high participation possibilities
include large retail establishments, grocery chains, large offices, refrigerated
warehouses, water- and wastewater-treatment plants, and industries with process
storage (e.g. pulp and paper, cement manufacturing). Customers with operations requiring continuous processes, or with obligations such as schools and hospitals,
generally are not good candidates.

Third parties generally administer firm curtailment programs for utilities and are
responsible for all aspects of program implementation, including program marketing and outreach, customer recruitment, technology installation and incentive payments.
Avista could contract with a third party to deliver a fixed amount of capacity reduction
over a certain specified timeframe. The contracted capacity reduction and the actual
energy reduction during DR events is the basis of payment to the third party.

Critical Peak Pricing Critical peak pricing programs set prices much higher during short critical peak periods
to encourage lower customer usage at those times. Critical peak pricing is usually
offered in conjunction with time-of-use rates, implying at least three periods: critical
peak, on-peak and off-peak. Utilities offer heavy discounts to participating customers
during off-peak periods, even relative to a standard time-of-use rate program. Event days generally are a day ahead or even during the event day. Over time, establishment
of event-trigger criteria enables customers to anticipate events based on hot weather or
other factors. System contingencies and emergencies are candidates for Critical peak
pricing. Critical peak pricing differentials between on-peak and off-peak in the AEG
study are 6:1, and available to all three commercial and industrial classes.
There are two ways to offer critical peak pricing. An opt-in rate that allows voluntary
enrollment in the program or the utility enrolls all customers in an opt-out program,
requiring them to select another rate program if they do not want to participate.
Studies show that dynamic pricing programs such as critical peak pricing vary
according to whether customers have enabling technology to automate their response.
For General and Large General Service customers, the enabling technology is a
programmable communicating thermostat. For Extra Large General Service customers,
the enabling technology is automated demand response implemented through energy management and control systems.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
Critical peak pricing programs require formal rate design based on customer billing data to specify peak and off-peak price levels and periods the rates are available. Rate
design was outside the scope of the AEG study. Further, new metering technology is
required. Given these requirements, critical peak pricing was not an option for the IRP.

Standby Generation Partnership Few utilities have contracted with large industrial customers to use their standby
generation resources during peak hours. The AEG DR study included standby
generation in its firm curtailment section. Avista studied a standby generation option
similar to the Portland General Electric program where existing customers use their standby generation. Portland General Electric dispatches, tests, and maintains the customer generation resources in exchange for their use during peak hours. It uses
customer generators for limited hours for peak requirements, operating reserves, and
potentially for voltage support on certain distribution feeders.

Environmental regulations limit the use of backup generation facilities unless they meet strict emission guidelines. To provide more operating hours a program could introduce
natural gas blending to improve the emissions and operating costs.

Avista estimates approximately 20 MW of standby generation resources are available
for utility use over a five-year acquisition period. To test the concept, a pilot using Avista backup generation facilities is likely. The pilot would provide a cost estimate and
illustrate the engineering necessary to bring a standby generation program to fruition.
The IRP assumes a standby generation program would cost $50 to $85 per kW in
upfront investments, plus $10 to $15 per kW-year in O&M costs.
In May 2015, the federal courts overturned rules limiting the availability of standby
generation resources. This ruling creates uncertainty around using standby generation
to serve utility requirements. The ruling requires new rules to be developed to determine
the amount of hours and environmental conditions these units could be used.

Generation Efficiency Audits of Avista Facilities
A 2013 IRP Action Item was the study of potential for energy efficiency opportunities at company generation facilities. During 2015, Avista performed preliminary energy efficiency audits at all of its hydroelectric dams and most thermal generation facilities
Avista owns or is a partial owner in, excluding Colstrip. The preliminary scoping audits
focused on lighting, shell, heating ventilation and air conditioning (HVAC), and motor
controls on processes. Table 5.4 summarizes these potential projects, Table 5.5
summarizes the planned projects for 2016 – 2017, and Appendix D contains a complete description of the study findings. A discussion of some of the major identified categories
follows. Studies will continue into 2016 and the findings reported in the 2017 IRP.

Lighting Projects
Avista’s generation facilities have a mixture of T12, T8 and some T5 linear fluorescent fixtures as well as many incandescent bulbs. The proposed replacement fixtures from
the lighting audits are primarily linear, high bay, and screw in LED fixtures. Noxon
Exhibit No. 4
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Avista Corp 2015 Electric IRP
Rapids is the only facility that has completed a lighting retrofit. Little Falls, Nine Mile, Cabinet Gorge and Long Lake lighting upgrades are planned in 2016 and 2017.

Shell Projects
Shell projects include measures keeping conditioned air within buildings. A generation facilities review found no capital shell measures with significant savings potential. However, small maintenance weatherization efforts could improve occupant comfort.

Table 5.4: Preliminary Generation Facility Efficiency Upgrade Potential
Facility Description Measure
Life
(years)
Electric
Savings
(kWh)
Boulder Park

Control Room Lighting 15 3,931
Generating Floor Lighting High Bays 15 16,099
Replacing Engine Bay Lights 15 6,736
Replace Exterior Wall Packs 15 16,054
Instrument Air Cycling Air-Dryers 12 10,074
Oil Reservoir Heater Fuel Conversion8 15 525,600
Coyote Springs

Control Room Lighting 15 6,368
Generating Floor Lighting High Bays 15 85,778
Roadway Lighting 15 1,085
Air-Compressor VFD 12 130,000
Retrofit Air-Dryer with Dew-Point Controls 12 25,000
Kettle Falls

Plant Lighting 15 150,190
Plant Lighting Controls 15 183,058
Yard Lighting 15 48,180
Forced Draft Boiler Fan VSD 12 700,000
Little Falls Speed Controls Cooling/Exhaust Fans 12 247,909
Long Lake Variable Speed Stator Cooling Blowers 12 135,000
Northeast CT Halogen Pole Lights 15 5,146
Noxon Rapids Full LED Lighting Upgrade (Completed) 15 382,115
Post Falls Control Room T12s 15 1,776
Generating Floor HPS 15 3,312
Upper Falls

Utility Men Break Room Lighting 15 2,151
Control Room Lighting 15 4,340
Network Feeder Tunnel Lighting 15 8,344
Rathdrum CT Roadway Lighting 15 16,273
Halogen Pole Lights 15 3,200

8 Also saves 23,911 therms of natural gas per year.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 78 of 212
Chapter 5–Energy Efficiency & Demand Response
Avista Corp 2015 Electric IRP
Table 5.5: Planned Generation Facility Efficiency Upgrades 2016 – 2017
Facility Description Measure
Life
(years)
Electric
Savings
(kWh)
Cabinet Gorge Lighting Retrofit 15 300,000
Little Falls Lighting Retrofit 15 62,266
Long Lake Lighting Retrofit 15 17,441
Nine Mile Lighting Retrofit 15 71,455

HVAC Projects Noxon Rapids is the only hydroelectric project with heating and cooling equipment. Its water-source heat pump system includes air handlers and hydronic unit heaters. In
addition to efficiency gains, replacing this system would reduce annual maintenance.

Cabinet Gorge does not have active heating or cooling systems. Ducted hydronic coils
flush air outside during spring and summer nights. A water-source heat pump would increase overall heating and cooling efficiency.

In most cases waste heat from the hydroelectric generating equipment supplies heat to
facilities in winter months. When idle, facilities typically motor a unit during the winter
months to keep the facility above freezing. Unit heaters could provide a more efficient heat source, and the control room could be thermally isolated from the rest of the plant
to ensure only required areas are heated.

Given the relative efficiency of existing thermal facilities heating systems, HVAC
equipment improvements make sense only when each unit reaches the end of its useful life.

Controls on Process Motors
Most motor loads at the hydroelectric facilities operate limited hours, often less than 30
hours per year. They do not consume enough electricity to justify the cost of installing new variable speed drives. Coyote Springs 2 has potential for variable-speed motors in
its compressed-air systems. The Little Falls exhaust fan could benefit from the
installation of variable speed drives.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 79 of 212

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 80 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-1
6. Long-Term Position

Introduction & Highlights
This chapter describes the analytical framework used to develop Avista’s net position. It
describes reserve margins held to meet peak loads, risk-planning metrics used to meet
hydroelectric variability, and plans to meet renewable goals set by Washington’s Energy
Independence Act.
Avista has unique attributes affecting its ability to meet peak load requirements. It
connects to several neighboring utility systems, but is only 5 percent of the regional
load. Annual peaks can occur either in the winter or in the summer; but on a planning
basis using extreme weather conditions, Avista is winter peaking. The winter peak
generally occurs in December or January, but may happen in November or February where weather events occur in these months. As described in Chapter 4 – Existing Resources, Avista’s resource mix contains roughly equal splits between hydroelectric
and thermal generation. Hydroelectric resources meet most of Avista’s flexibility
requirements for load and intermittent generation, though thermal generation is playing
a larger role as load growth and intermittent generation increase flexibility demands.

Reserve Margins
Planning reserves accommodate situations when load exceeds and/or resource output falls below expectations due to adverse weather, forced outages, poor water conditions, or other contingencies. Reserve margins, on average, increase customer rates when
compared to resource portfolios without reserves because of the additional cost of
carrying rarely used generating capacity. Reserve resources have the physical
capability to generate electricity, but most have high operating costs that limit their dispatch and revenues.
There is no industry standard reserve margin level; standardization across systems with
varying resource mixes, system sizes, and transmission interconnections, is difficult.
NERC defines reserve margins as follows:
Generally, the projected demand is based on a 50/50 forecast. Based on
experience, for Bulk Power Systems that are not energy-constrained, reserve
margin is the difference between available capacity and peak demand,
normalized by peak demand shown as a percentage to maintain reliable
operation while meeting unforeseen increases in demand (e.g. extreme weather)
Section Highlights
 Avista’s first long-term capacity deficit net of energy efficiency is in 2021; the first energy deficit is in 2026.
 Including operating reserves, Avista plans to a 22.6 percent planning margin.
 The 2015 IRP meets all EIA mandates over the next 20 years with a combination of qualifying hydroelectric upgrades, purchased RECs, Palouse
Wind, and Kettle Falls.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 81 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-2
and unexpected outages of existing capacity. Further, from a planning
perspective, planning reserve margin trends identify whether capacity additions
are keeping up with demand growth. As this is a capacity based metric, it does
not provide an accurate assessment of performance in energy limited systems,
e.g., hydro capacity with limited water resources. Data used here is the same
data that is submitted to NERC for seasonal and long-term reliability
assessments. Figures above shows forecast net capacity reserve margin in US
and Canada from 2008 to 2017.

NERC's Reference Reserve Margin is equivalent to the Target Reserve Margin
Level provided by the Regional/subregional’s own specific margin based on load,
generation, and transmission characteristics as well as regulatory requirements.
If not provided, NERC assigned 15 percent Reserve Margin for predominately
thermal systems and 10 percent for predominately hydro systems. As the
planning reserve margin is a capacity based metric, it does not provide an
accurate assessment of performance in energy limited systems, e.g., hydro
capacity with limited water resources.1
Avista’s hydroelectric system is energy constrained, so the 10 or 15 percent metrics
from NERC do not adequately define our planning margin. Beyond planning margins as
defined by NERC, a utility must maintain operating reserves to cover forced outages on
the system. Avista therefore includes operating reserves in its definition of planning
margin. Per Western Electric Coordinating Council (WECC) requirements, Avista must maintain 1.5 percent of current load and 1.5 percent of on-line generation as spinning
reserves and 1.5 percent of current load and 1.5 percent of on-line generation as
standby reserves.2 Avista must also hold load regulation reserves to meet load following
and regulation requirements of within-hour load and generation variability.
Avista participates in regional Energy Imbalance Market (EIM) studies and committees.
An EIM, where adopted, would create a trading market for regulation services, among
other products. While the new market may not reduce the amount of required capacity,
it may lower customer rates by providing Avista another market to buy and sell short-
term capacity products and services.
Planning Margin
Utility capacity planning begins with identifying the broader regional capacity position,
as regional surpluses can offset utility investments. The Northwest has a history of
capacity surpluses and energy deficits because of its hydroelectric generation base. Since the 2000-2001 energy crisis the Northwest added nearly 6,000 MW of natural
gas-fired generation, about 3,500 MW was constructed immediately after the crisis.
During this same time, Oregon and Washington added 7,850 MW of wind generation.
With recent wind additions in the mix, due to wind’s lack of on-peak capacity
contribution, the region is approaching load-resource capacity balance, while retaining an energy surplus.
1 http://www.nerc.com/pa/RAPA/ri/Pages/PlanningReserveMargin.aspx 2 Spinning reserves sync to the system while stand-by reserves must be available within 10 minutes.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 82 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-3
Given the interconnected landscape of the Northwest power market, selecting a planning margin target is not straightforward. One approach is to conduct a regional
loss of load probability (LOLP) study calculating the amount of capacity required to meet
a 5 percent LOLP threshold. Five percent LOLP means utilities meet all customer
demand in all hours of the year in 19 of 20 years; one loss-of-load event is allowed in a 20-year period. Regional LOLP analysis is beyond the scope of an IRP. Fortunately, the NPCC conducts regional LOLP studies. Based on their work, the Northwest begins to
fail the five-percent LOLP measure in the winter of 2020-21 when three major coal
generators retire.3 The NPCC identifies a need of 1,150 MW of natural gas-fired
capacity to eliminate potential 2021 resource shortfalls. The projected shortages occur primarily in the winter, with a small chance of shortage in the summer. At the time of writing, the NPCC had not translated its LOLP study results into a regional planning
margin statistic. Absent NPCC translation to planning margin level, Avista made its own
estimate using NPCC data and historical methodology to perform the translation.
Including operating reserves, the Northwest planning margin is between 23 and 24
percent.
Avista is an interconnected utility, an advantage over its sister utility Alaska Electric
Light & Power (AELP). AELP is an electrical island and must meet all loads with its own
resources without relying on its neighbors. AELP retains large reserve margins to
account for avalanche danger – typically 115 percent of peak load. Avista, as an interconnected utility, can rely on its neighbors and target a lower planning margin. The
harder question is how much reliance it should place on the wholesale market. Previous
IRPs have shown charts like Figure 6.1, the tradeoff between added resources, i.e.,
planning margin, and higher system costs and wholesale market reliance. For example,
were Avista an electrical island like AELP, a 5 percent LOLP would require a 31 percent planning margin, adding nearly $40 million annually to rates. On the opposite end of the
spectrum, if the marketplace had 275 megawatts available, a 12 percent planning
margin would meet the 5 percent LOLP for no added cost. Figure 6.1 also explains that
in 2020, absent any resource additions or market reliance, Avista projects a 12 percent
reserve margin.

3John Fazio, NPCC, http://www.nwcouncil.org/media/7149183/may-1-2015-raac-steer-2020-21-
adequacy-assessment.pdf. The 8.3 percent LOLP result primarily is due to the retirements of the Boardman and Centralia coal-fired plants, and to a lesser extent regional load growth.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 83 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-4
Figure 6.1: 2020 Market Reliance & Capacity Cost Tradeoffs
Avista reviewed planning margins used by transmission organizations and utilities
across the country. The results varied depending on the depth and breadth of their
interconnections and the types and quantities of resources within their systems. One
challenge in comparing planning margins across utilities is determining whether they
include ancillary service, or operating reserve, obligations in their planning margins. Figure 6.2 illustrates the findings of our review of utility planning margins. Utilities with
minimal interconnections, or a large hydroelectric system, have higher planning margins
than better-interconnected and/or thermal-based systems. Avista and its neighbors
generally meet a large portion of their load obligations with hydroelectric resources,
implying that their planning margins might need to be higher than NERC’s 15 percent recommendation.

Another metric to consider when selecting the appropriate planning margin is the utility’s
largest single contingency relative to peak load. Avista’s largest single unit contingency
is Coyote Springs 2. This plant met 16 percent of weather-adjusted peak load in 2014, a high statistic relative to our Western Interconnect peers. Figure 6.3 illustrates the single
largest contingencies for selected utilities in the West. Excluding Avista, the average
percentage of peak load is 11 percent; the high is 33 percent for Sierra Pacific (553 MW
Tracy CCCT), and the low is 5 percent for BC Hydro.
Some resource planners argue planning margins should be no smaller than a utility’s
single largest contingency on the basis that where your largest resource fails, other
resources may not be able to replace it. Given the Northwest’s contingency reserve
sharing agreement, lower reserve levels are required for the first hour following a
qualifying generation outage. Signatories to the contingency reserve sharing agreement
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 84 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-5
can call on assistance from neighboring utilities for up to 60 minutes to help meet shortages. Beyond the first hour, utilities are responsible for replacing the lost power
themselves, either from other utility resources, from purchases from other generators, or
load reductions.

Figure 6.2: Planning Margin Survey Results

0%
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NorthwesternHydro QuebecFortisIdaho PowerMinnesota PowerEntergy-New OrleansSunflower CoopKansas City B of PUOklahoma Gas & ElectricSalt River ProjectNevada PowerPGEIndianoplis Light & PowerPublic Service Co of NMPacifiCorpSPPXCEL-New MexicoERCOTDuke-IndianaPSE (2018-19)Duke-Carolina'sMISOTVAISO New EnglandCalifornia PUCBasin ElectricSan Diego Gas & ElectricRoseville ElectricPlatte River Power AuthorityAPSUNS ElectricEl Paso ElectricSierra PacificTri-State G&TDominionPJMPSE (2020+)XCEL-ColoradoEWEBNYISOColorado Springs UtilitiesClark PUDNova Scotia PowerHydro OneFPLProgress EnergyBC HydroNew Brunswick PowerCowlitz PUDLADWP
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 85 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-6
Figure 6.3: Single Largest Contingency Survey Results (2014 Peak Load)
Flexibility Requirements Renewable portfolio standards, large federal and state subsidies, high feed-in tariff and
PUPRA prices, and falling equipment and installation costs have led to more intermittent
wind and solar generation installations in the Northwest. Unlike traditional generation
resources, intermittent generation variability consumes system capacity. This is similar
to holding generation capacity for unknown changes in load, but differs because changes in renewable generation output are much larger and more volatile than load
changes on a per-MW of capacity basis. Avista and many of its peer utilities have
conducted studies to ensure they have enough flexible capacity to support intermittent
resources. However, analytical methods contained in these studies are not fully mature
because it is a relatively new concept for the industry.
Avista has identified an initial analytical process to study flexibility requirements for this
IRP. The first step looks at system variation on different time horizons. The analysis
looks at the five-, 10-, 15- and 60- minute periods in calendar year 2013. The study
estimated the amounts of capacity reserves required in the 95th and 99th percentile, or 8,322 and 8,672 hours of the 8,760 hours of a year. While Avista will need to meet all needs during the calendar year, some reliance on the wholesale marketplace is
appropriate. Figures 6.4 and 6.5 outline the amount of capacity required to meet load
and wind variation, and operating reserve requirements, at the 95th and 99th percentiles.
Over the five-minute time range, Avista needs 100 MW to 107 MW of flexible resources. Extending the time horizon to 10 minutes, 110 MW to 122 MW are required. Between 120 MW and 137 MW are required for 15-minute interval variation. Over an hour, total
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Sierra Pacific (Tracy CCCT-553)
Avista-Winter (Coyote Springs 2-312)
Portland General Electric (Boardman-517)
Avista-Summer (Coyote Springs 2-277)
PacifiCorp-West (Chehalis-477)
Public Service of NM (San Juan-248)
El Paso Electric (Palo Verde-207)
Nevada Power (Lenzie-551)
Idaho Power (Langley Gultch-318)
Public Service of CO (Comanche-525)
PacifiCorp-East (Lake Side 2-628)
LADWP (Scattergood-450)
Arizona Public Service (Redhawk-500)
Bonneville Power Admin (Coulee-805)
Salt River Project (Springerville-415)
Puget Sound Energy (Mint Farm-297)
BC Hydro (Various-500)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 86 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-7
needs are 196 MW to 260 MW. Regulation-capable resources are required to meet much of the variation under 15 minutes, though the 44 MW of non-spinning reserve can
be met with stand-by ready resources. For the hour, incremental capacity requirements
over the five- to 15-minute intervals increases, but standby resources meet the
requirement. Figures 6.4 and 6.5 identify the requirements for flexible resources on the system, but
they do not identify the resources available to meet them. Avista outlines in Chapter 4
resources currently meeting its flexibility requirement. We typically use a combination of
Mid-Columbia contracts and Clark Fork generators to provide regulation and load following services, but natural gas-fired peaking resources sometimes meet non-spin or supplemental operating requirements. Recently added controls at Coyote Springs 2
allow it to provide regulation services, taking advantage of its flexibility when online.
Figure 9.5 in Chapter 9 shows the excess reserves by month available to meet flexibility
requirements.

Figure 6.4: 95th Percentile Capacity Requirements

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Total Up Reg
Regulation Load Following
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 87 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-8
Figure 6.5: 99th Percentile Capacity Requirements

Avista’s Planning Margin and Flexibility Reserve Levels The NPCC Draft Seventh Power Plan finds the region is surplus capacity through 2020. Avista will not acquire additional capacity until its expected peak loads, plus reserve
margins, exceed resources beyond 2020 either on a single-hour or on a sustained 3-
day basis. To meet customer loads in a reliable and cost-effective manner, Avista
retains resources capable of a minimum of 114 percent of its one-in-two winter peak load forecast.4 Further, it plans to meet spin- and non-spin requirements, as set by the WECC. Lastly, Avista retains an additional 16 MW of regulation to serve load and wind
generation variation within the peak hour. The winter total requirement equates to a
22.6 percent planning margin. This level is in line with NPCC estimates for an adequate
supply, as described earlier in this chapter. The NPCC study shows the region has a minimal chance of a load loss event in
summer months. Given this low probability, Avista’s summer planning margin is
comprised only of balancing area reserve requirements and 16 MW of regulation. Avista
will monitor the summer market depth and will revise its planning margin assumption if regional capacity surpluses fall due to load growth or exports.
Energy Imbalance Market
Avista is participating in a regional effort to evaluate the viability of an intra-hour Energy Imbalance Market (EIM) in the Northwest Power Pool area. The Market Coordination
4 One-in-two load is the peak load day during an average coldest winter day.
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 88 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-9
(MC) Initiative officially launched on March 19, 2012 to explore alternatives to address the growing operational and commercial challenges to integrate variable energy
resources affecting the regional power system.

The MC Initiative’s core goal is to lower overall load serving costs by voluntarily re-dispatching resources. Balancing Authorities (BA) can collectively reduce within-hour balancing resources and maintain their systems if the EIM captures regional load and
resource diversity and BAs agree on protocols for allocating reserves and ramping
capability obligations among participants. The EIM does this by executing a security-
constrained economic dispatch process every five minutes instead of the current one- hour term. The process accounts for the capabilities and prices of the volunteered and committed generating resources for re-dispatch, and the real-time capability of the
transmission system to accommodate flows resulting from a central market-instructed
re-dispatch.

The name “energy imbalance market” implies the core function is managing intra-hour imbalances – such as load forecast error, generator station error – particularly from
variable energy resources – or both. While covering these imbalances is an integral part
of the EIM, it is not the main objective of the overall economic optimization process. The
market allows BAs to use lower-cost third-party generation when sufficient real-time
transmission exists available to replace their higher-cost generation resources.

The MC Initiative formed an Analytical Team to evaluate the potential production cost
savings within the Northwest Power Pool area. An Executive Committee instructed the
Analytical Team to identify a minimum high-confidence range of potential savings, using
a production cost model with updated grid assumptions provided by members. The base case results range from approximately $40 million to $90 million per year in
regional gross annual savings. Additional sensitivities resulted in savings of $70 to $80
million dollars to the region. This analysis indicates Avista would conservatively observe
approximately 5 percent of the total regional benefits, or $2 to $5 million. The Executive
Committee currently is evaluating implementation costs to determine if they are lower than expected savings.

Savings estimates do not reflect significant additional benefits of reducing reserve
requirements in the region. These benefits may add $100 million or more to expected
annual benefit.
Balancing Loads and Resources
Both single-hour and sustained-peaking requirements compare future load and resource projections to identify any shortages. The single peak hour is a larger concern
in the winter months than is the three-day sustained 18-hour peak. During winter
months, the hydroelectric system can sustain generation levels for longer periods than
in the summer due to higher inflows. Figure 6.6 illustrates the winter balance of loads
and resources; the first year Avista identifies a significant winter capacity deficit is January 2021. The load resource comparison removes conservation from the load
forecast to show the total resource need. Conservation will lower this need, but the plan
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 89 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-10
requires new generating resources to meet remaining shortfalls. At the time of the IRP analysis, Avista had small short-term deficits in 2015 and 2016, but those positions
have been filled with market purchases. Chapter 11 – Preferred Resource Strategy
provides more details about the short-term position.

Figure 6.6: Winter 1 Hour Capacity Load and Resources
Avista plans to meet its summer peak load with a smaller planning margin than in the
winter. During summer months, only operating reserve and regulation obligations are
included in the planning margin. Market purchases in the deep regional market will
satisfy any weather-induced load variation or generation forced outage that otherwise would be included in the planning margin. Resource additions serving winter peaks
meet smaller summer deficits as well.

Figure 6.7 shows Avista’s summer resource balance. This chart differs from the winter
load and resource balance by using an 18-hour sustained peak rather than the single-hour peak. Longer-term sustained peaks are more constraining in summer months due
to reservoir restrictions and lower river flows, reducing the amount of continuous
hydroelectric generation available to meet loads.

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 90 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-11
Figure 6.7: 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 a sustained outage limits the contribution
of a resource. Where generation capability is not adequate to meet these variations,
customers and the utility must rely on the short-term electricity market. In addition to
load variability, Avista holds energy-planning margins accounting for variations in month-to-month hydroelectric generation.
As with capacity planning, there are differences in regional opinions 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 1936/37.5 The critical water year of 1936/37 is low on an annual basis, but it does not represent a low water condition 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 capacity planning margins included in the Expected Case of the 2015 IRP to cover a one-in-one-hundred year event. Investments to support this high level of
reliability would increase pressure on retail rates for a modest benefit. Avista instead
plans to the 90th percentile for hydroelectric generation. Using this metric, there is a
one-in-ten-year chance of needing to purchase energy from the market in any given month over the IRP timeframe.
5 The critical water year represents the lowest historical generation level in the streamflow record.
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 91 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-12
Beyond load and hydroelectric 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 this contract
risk, the energy contingency increases by 32 aMW until the contract expires in 2019. With the addition of WNP-3 contract contingency to load and hydroelectric variability, the total energy contingency amount equals 194 aMW in 2016. See Figure 6.8 for the
summary of the annual average energy load and resource net position.

Figure 6.8: 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 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 output from the Palouse Wind project through a 30-year
power purchase agreement to help meet the EIA goal. In 2012, an amendment to the
EIA allowed some 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 help meet EIA goals.

Table 6.1 shows the forecast amount of RECs Avista needs to meet Washington state
law and the amount of qualifying resources already in Avista’s generation portfolio.
Without the ability to roll RECs from previous years, Avista would require additional
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 92 of 212
Chapter 6: Long-Term Position
Avista Corp 2015 Electric IRP 6-13
renewables in 2030. With this ability, Avista does not need additional EIA resources over the planning horizon of this IRP. It may have surplus renewables depending upon
the qualifying output of Kettle Falls. Kettle Falls qualifying output may vary depending
upon the quantity of fuel meeting the EIA old growth provision, the availability of fuel,
and economics of the facility. Given its expected renewables surplus until 2020, Avista will market the excess RECs until 2019. Beginning in 2019, surplus RECs will roll into 2020, allowing the banking provision to delay additional renewable resource investment.

Table 6.1: Washington State EIA Compliance Position Prior to REC Banking
2016 2020 2025 2030 2035
Percent of Washington Sales 9% 15% 15% 15% 15%
2-Year Rolling Average Washington Retail Sales Estimate 645 662 671 682 696

Renewable Goal -58 -99 -101 -102 -104
Incremental Hydroelectric 23 23 23 23 23
Net Renewable Goal -35 -77 -78 -79 -82

Other Available REC's
Palouse Wind with Apprentice Credits 48 48 48 48 48
Kettle Falls (67% Capacity Factor) 31 31 31 31 31
Net Renewable Position (before rollover RECs) 44 3 1 0 -2

Net Renewable Position with Kettle Falls at
90% Capacity Factor 55 14 12 11 8

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 93 of 212

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 94 of 212
Chapter 7–Policy Considerations
Avista Corp 2015 Electric IRP
7. Policy Considerations

Public policy affects Avista’s current generation resources and the resources it can
pursue. Each resource option presents different cost, environmental, operational,
political, regulatory, and siting challenges. Regulatory environments continue to evolve since publication of the last IRP; most recently, EPA released the Clean Power Plan in
August 2015. Current and proposed regulations by the EPA, among other agencies,
coupled with political and legal efforts, have particular implications for coal generation,
as they involve regional haze, coal ash disposal, mercury emissions, water quality, and
greenhouse gas emissions. This chapter discusses pertinent public policy issues relevant to the IRP.

Environmental Issues
The evolving nature of environmental regulation creates unique resource planning
challenges. If avoiding certain air emissions were the only issue facing 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 changing
environmental requirements sometimes creates conflict. Each generating resource has distinctive operating characteristics, cost structures, and environmental regulatory challenges that can change significantly based on timing and location.

Traditional thermal generation technologies, like coal and natural gas-fired plants,
provide reliable capacity and energy. Mine-mouth coal-fired units, like Avista’s shares in Colstrip Units 3 and 4, have high capital costs and long permitting and construction lead times, and relatively low and stable fuel costs. New coal plants are difficult, if not
impossible, to site today due to state and federal laws and regulations, local opposition,
their relatively high costs when compared to natural gas-fired plants, and additional
environmental concerns. Remote locations increase costs from either the transportation of coal to the plant or the transportation of the generated electricity by the plant to load
centers.

Compared to coal, natural gas-fired plants have low capital costs, can typically be
located closer to load centers, can be constructed in relatively short time frames, emit less than half the greenhouse gases of conventional coal generation, have fewer other
emissions and waste product issues, and are often the only utility-scale baseload
resource available. Higher fuel price volatility has historically affected the economics of
Chapter Highlights


Avista’s Climate Policy Council monitors greenhouse gas legislation and
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natural gas-fired plants, their performance 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, including 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 resources have 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. Even with significant decreases in equipment and installation costs, renewables are high-cost and suffer from integration challenges.
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 often located to maximize their capability rather than to
be near 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. Some of these issues may
be alleviated with distributed resources, but the price differentials of distributed
resources make them more difficult to develop at utility scale. 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. Transportation costs and logistics also complicate the
location of biomass plants.
The long-term economics of renewable resources is uncertain for several reasons.
Federal investment and production tax credits begin expiring for projects starting
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 technologies. Many relatively unpredictable
factors affect the costs of renewable technologies, such as renewable portfolio standard
goals, construction and component prices, international trade issues, and currency
exchange rates. Capital costs for wind and solar have decreased over the last several
IRPs, but future costs remain uncertain.
Uncertainty still exists about final design and scope of greenhouse gas regulation.
Pockets of strong regional and national support to address climate change exist, but
little political will at the national level to implement significant new laws exists beyond
the regulations proposed by the EPA and is unpredictable going forward. However, since the 2013 IRP publication, changes in the approach to greenhouse gas emissions
regulation have occurred, including:

 The EPA proposed actions to regulate greenhouse gas emissions under the CAA through the proposed CPP; and
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 California’s cap and trade regulation continues scheduled expansion throughout
the economy and includes new linkages with Quebec, and an October 2013
compact to link future programs with British Columbia, Oregon, and Washington.

Avista’s Climate Change Policy Efforts
Avista’s Climate Policy Council is an interdisciplinary team of management and other
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 on certain
topics as needed. 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 and regulation, 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 main vehicle to engage in federal-
level climate change dialog, supplemented by other industry affiliations. Avista monitors
regulations affecting hydroelectric and biomass generation through its membership in
other associations.

Greenhouse Gas Emissions Concerns for Resource Planning
Resource planning in the context of greenhouse gas emissions regulation raises the
relationships between Avista’s obligations for environmental stewardship and cost
implications for customers. Resource planning considers the cost effectiveness of
resource decisions, as well as the need to mitigate the financial impact of potential future emissions risks. Although some parties 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 among concerns related to pursuing
this type of policy. Technologically, it is possible to replace fossil-fueled generation with
renewables, but this approach results in increased cost to customers and results in reliability challenges.

State and Federal Environmental Policy Considerations
The CPP is the focus of federal greenhouse gas emissions policies in the 2015 IRP. In
the 2013 plan, Avista did not include a specific dollar amount for cap and trade or a
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carbon tax on the modeling of the Western Interconnect. Modeling for jurisdictions with existing costs, such as California and British Columbia, included the appropriate costs.
The 2013 IRP had an implied cost from the replacement of retired coal capacity. The
Expected Case in this IRP includes the probability of a cost of carbon. Details about the
cost of carbon and the modeling results are in Chapter 10 – Market Analysis. The Expected Case also includes proposed regulatory mechanisms through sections 111(b) for new sources and 111(d) for existing sources of the Clean Air Act (CAA) as described
below.

The President’s Climate Action Plan, released on June 25, 2013, outlined the Obama administration’s three pillars of executive action regarding climate change. The pillars include:
 Reducing U.S. carbon emissions through the regulation of emissions from power
plants, increased use of renewables and other clean energy technologies, and
stronger energy efficiency standards (reflected in the CPP);
 Making infrastructure preparations to mitigate the impacts of climate change; and
 Working on efforts to reduce international greenhouse gas emissions and
prepare for the impacts of climate change.
A presidential memo with several climate related policies went to the EPA Administrator
on the same day as the Climate Action Plan. It directed the EPA to:
 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 EPA answered the administration by issuing a new proposal to limit carbon dioxide
emissions from new and modified coal and natural gas-fired electric generating units in
late 2013, and from existing sources in June 2014. Details of these proposals are later in this chapter.
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 non-solar projects that began construction before the end of 2013 and for solar projects before the end of 2016. Avista did not model an extension of these tax incentives because of the
uncertainty of their continuation. This situation may change and would affect modeling
assumptions for the 2017 IRP. 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.

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EPA Regulations EPA regulations, or the States’ authorized versions, directly, or indirectly, affecting
electricity generation include the CAA, along with its various components, including the
Acid Rain Program, the National Ambient Air Quality Standard, the Hazardous Air
Pollutant rules, and Regional Haze Programs. The U.S. Supreme Court ruled that the EPA has authority under the CAA to regulate greenhouse gas emissions from new motor vehicles and the EPA 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. EPA proposed a rule in early 2012, and
modified in 2013, setting standards of performance for greenhouse gas emissions from
new and modified fossil fuel-fired electric generating units and for existing sources
through the draft CPP in June 2014.
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 Operating Permits The 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. Title V
operating permits are required for our largest generation facilities and are renewed
every five years. The Title V operating permit for Colstrip Units 3 and 4 expires in 2017. The Coyote Springs 2 permit expires in 2018. A new Title V operating permit for the
Kettle Falls generating station is expected in 2016, and the Rathdrum CT expires in
2016. Boulder Park, Northeast CT, and other small facilities require only minor source
operating or registration permits based on their limited operation and emissions.
Discussion of some major CAA programs follows.
New Source Proposal
After receiving over 2.5 million comments on the April 2012 proposal for new resources
under section 111(b) of the CAA, the EPA withdrew that proposal and submitted a new
proposal on September 20, 2013. This proposal covers new fossil fuel-fired resources larger than 25 MW for the following resource types:

 Natural gas-fired stationary combustion turbines: 1,000 pounds CO2 per MWh for units burning greater than 850 mmBtu/hour and 1,100 pounds CO2 per MWh units burning less than or equal to 850 mmBtu/hour.
 Fossil fuel-fired utility boilers and integrated gasification combined cycle (IGCC)
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units: 1,100 pounds CO2 per MWh over a 12-operating month period or 1,000–1,500 pounds CO2 per MWh over a seven-year period.

The EPA finalized the new source standard on August 3, 2015. The final rule differs
from the proposal, which was the basis for the development of this IRP. The final rule will guide modeling assumptions for the 2017 IRP.

Clean Power Plan Proposal
The EPA issued the draft CPP on June 2, 2014. The modeling for this IRP was based
on the CPP proposal. This plan aims to reduce national greenhouse gas emissions from covered fossil-fueled electric generating units by 30 percent by 2030 from a 2005 baseline, with an interim goal in 2020. The draft rule calculated emission rate targets for
each state using a combination of four building blocks:

1. Heat rate improvements at coal plants up to 6 percent;
2. Displacement of coal-fired and oil-fired steam generation by increasing utilization of natural gas-fired combined cycle plants up to a 70 percent capacity
factor;
3. Use of more low- or zero-carbon emitting generation resources (including 6
percent of nuclear capacity); and
4. Increase demand side efficiency by 1.5 percent per year between 2020 and 2029.

The EPA used 2012 data for the baseline for each state. The building blocks could
constitute the best system of emission reduction a state could propose in its compliance
plan. However, states might also propose to comply through other measures, including a cap and trade form of regulation. The state of Washington, through the provisions of
the EIA (Chapter 19.285 RCW), currently applies renewable energy and energy
efficiency standards to Avista’s electric operations. The state also imposes an
emissions performance standard under Chapter 80.80 RCW to long-term financial
commitments made by electric utilities when acquiring new baseload generation or upgrading existing fossil-fueled baseload generation.

Several aspects of the proposed CPP are problematic. The TAC discussed these issues
in several of its meetings. Issues include the impact of the 2012 baseline year on
hydroelectric generation, the affect on combined cycle resources in Idaho, the immediate impact of the first two building blocks on the 2020 interim goal, and the short
time to develop regional solutions in light of the interim goal and legislation that may be
required from some of the states. Some adjustments to modeling for the 2015 IRP
attempt to alleviate some of these issues to make them into a workable plan. Updates to
2017 IRP modeling assumptions will account for changes made in the final CPP and subsequent state implementation plans. The EPA issued the final CPP on August 3,
2015. The final rule differs from the proposed rule in many ways including the removal
of the fourth building block (energy efficiency), movement of the start date from 2020 to
2022, and adjusted goals for many states. The 2017 IRP will account for these changes,
since modeling for the 2015 concluded in early 2015.
Figure 7.1 includes the IRP’s adjusted 2030 goal in comparison to the 2012 baseline.
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The orange portion of the bar shows the proposed reduction. Washington State has the highest percentage reduction, followed by Arizona. Idaho has the lowest reduction after
an assumed adjustment for 2012 partial year of operations at Langley Gulch.

Figure 7.1: Draft Clean Power Plan 2030 Emission Intensity Goals

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.

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 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 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 finalized the Mercury Air Toxic Standards (MATS) for the
coal and oil-fired source category in 2012. Colstrip Units 3 and 4’s existing emission
control systems should be sufficient to meet mercury limits. For the remaining portion of the rule specifically addressing air toxics (including metals and acid gases), the joint owners of Colstrip are currently evaluating what type of new emission control systems
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will be required to meet MATS compliance in 2016. 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.

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 currently
report 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. The state of
Washington requires mandatory greenhouse gas emissions reporting similar to the EPA
requirements. Oregon has similar reporting requirements.

Coal Ash Management and Disposal
On December 19, 2014, the EPA issued a final rule regarding coal combustion residuals
(CCR). This will affect Colstrip since it produces CCR. The rule establishes technical
requirements for CCR landfills and surface impoundments under Subtitle D of the
Resource Conservation and Recovery Act, the nation’s primary law for regulating solid waste. The final rule has not yet been published in the Federal Register. The owners of
Colstrip are developing a multi-year plan to comply with the new CCR standards. Any
financial or operational impacts to Colstrip from the CCR are still estimates at this time.

State and Regional Level Policy Considerations The lack of a comprehensive federal greenhouse gas policy encouraged states, such as
California, to develop their own climate change laws and regulations. Climate change
legislation takes many forms, including economy-wide regulation under a cap and trade
system, a carbon tax, and an emissions performance standard for power plants.
Comprehensive climate change policy can include multiple 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,
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with active renewable portfolio standards, and eight additional states have adopted voluntary standards.1

Idaho Policy Considerations
Idaho 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 beyond the CPP. The Idaho Department of Environmental
Quality will 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
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 5 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 the end of 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.
1 http://www.dsireusa.org/rpsdata/index.cfm
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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 its scheduled closure. The state of Washington enacted several fossil-fueled generation emissions and resource diversification measures. A 2004 law requires new
fossil-fueled thermal electric generating facilities of more than 25 MW of generation
capacity to offset 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 avoided cost. Additional details about the energy efficiency portion of the EIA are in Chapter 6 – Long-Term Position.
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 its Kettle Falls generation facility beginning in
2016. The 2015 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.
The Washington Department of Ecology 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
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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 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 adopt a lower emissions performance standard in
2013; a new standard would not be applicable until at least 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, 2013.2
April 29, 2014, Washington Governor Jay Inslee issued Executive Order 14-04,
“Washington Carbon Pollution Reduction and Clean Energy Action.” The order created
a “Climate Emissions Reduction Task Force” tasked with providing recommendations to
the Governor on designing and implementing a market-based carbon pollution program
to inform possible legislative proposals in 2015. The order also called on the program to
“establish a cap on carbon pollution emissions, with binding requirements to meet our
statutory emission limits.” The order also states that the Governor’s Legislative Affairs
and Policy Office “will seek negotiated agreements with key utilities and others to
reduce and eliminate over time the use of electrical power produced from coal.” The
Task Force issued a report summarizing its efforts, which included a range of potential carbon-reducing proposals. Subsequently, in January 2015, at Governor Inslee’s
request, the Carbon Pollution Accountability Act was introduced as a bill in the
Washington legislature. The bill includes a proposed cap and trade system for carbon
emissions from a wide range of sources, including fossil-fired electrical generation,
“imported” power generated by fossil fuels, natural gas sales and use, and certain uses of biomass for electrical generation. The bill did was not enacted during the 2015
legislative session. After the conclusion of the 2015 legislative sessions, Governor
Inslee directed the Department of Ecology to commence a rulemaking process to
impose a greenhouse gas emission limitation and reduction mechanism under the
agency’s CAA authority to meet the future emissions limits established by the Legislature in 2008. This regulatory program will not itself include the establishment of
an emissions trading market, but other entities could develop such a system to facilitate
trading.

2 http://www.commerce.wa.gov/Programs/Energy/Office/Utilities/Pages/EmissionPerfStandards.aspx
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8. Transmission & Distribution Planning

Introduction
Avista delivers electricity from generators to customer meters through a network of
conductors and ancillary equipment. Avista categorizes its energy delivery systems
between transmission and distribution voltages. Avista’s transmission system operates
at 115 and 230 kV nominal voltages; the distribution system operates between 4.16 and
34.5 kV, but typically at 13.2 kV in 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 reliable and economic transmission service for our
customers. Transmission providers and interested stakeholders coordinate regional planning, construction, and operations under Federal Energy Regulatory Commission
(FERC) rules and guidance from state and local agencies. 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 feeder upgrade
program, the transmission system, completed and planned upgrades, and estimated
costs and issues of new generation resource integration.

FERC Transmission Planning Requirements and Processes
Avista coordinates its transmission planning activities on a voluntary basis with neighboring interconnected transmission operators. Avista complies with a number of
FERC requirements related to both regional and local area transmission planning. This
section describes several of these processes and forums important to Avista
transmission planning.

Local Transmission Planning Report
Avista’s local planning report is the product of both a local transmission planning
process and an annual planning assessment. Attachment K to Avista’s Open Access
Transmission Tariff (OATT) FERC Electric Volume No. 8 outlines the local transmission
Chapter Highlights
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planning process. This process identifies single-system projects needed to mitigate future reliability and load-service requirements for the Avista transmission system.

The annual planning assessment is outlined by North American Electric Reliability
Corporation (NERC) Reliability Standard TPL-001-4. The planning assessment determines where the system may have the inability to meet performance requirements as defined in the NERC Reliability Standards and identifies corrective action plans
addressing how to meet the performance requirements. The planning assessment
includes performing steady state contingency analysis, voltage collapse, and transient
technical studies. The local planning report supports compliance with the local transmission planning
process and applicable NERC reliability standards. The local planning report, with its
associated collection of single-system projects and corrective Action Plans, provides a
10-year transmission system expansion plan by including all transmission system facility
improvements.

Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) is the group responsible for
promoting bulk electric system reliability, compliance monitoring, and enforcement in the
Western Interconnection. This group also facilitates development of reliability standards and helps coordinate operating and planning among its membership. WECC is the
largest geographic territory of the regional entities with delegated authority from the
NERC and the FERC. It covers all or parts of 14 Western states, the provinces of
Alberta and British Columbia, and the northern section of Baja, Mexico.1 See Figure
8.1.

Figure 8.1: NERC Interconnection Map

1 https://www.wecc.biz/Pages/About.aspx
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Peak Reliability The Peak Reliability (Peak) organization took over the role of reliability coordinator from
WECC on February 12, 2014. Peak is wholly independent of WECC, performing the
reliability coordinator and interchange authority functions for the Western
Interconnection.2
Northwest Power Pool
Avista is a member of the Northwest Power Pool (NWPP), an organization formed in
1942 when the federal government directed utilities to coordinate operations in support
of wartime production. The NWPP serves as a northwest 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.
The NWPP operates a number of committees, including its 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.

ColumbiaGrid
ColumbiaGrid began on March 31, 2006. Its membership includes Avista, BPA, Chelan
County PUD, Grant County PUD, Puget Sound Energy, Seattle City Light, Snohomish County PUD, and Tacoma Power. ColumbiaGrid aims 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 provides an open and transparent process to develop sub-regional
transmission plans, assess 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.
2 https://www.peakrc.com/aboutus/Pages/History.aspx

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 109 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-4

BPA Transmission System
BPA owns and operates over 15,000 miles of transmission-level facilities and owns over
three-quarters 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, and
its WNP-3 settlement contract. Avista also contracts for BPA transmission to transfer
power to several delivery points on the BPA system serving portions of our retail load
and for selling surplus power 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 works with BPA and other regional utilities to coordinate
major transmission facility outages. Future electric grid expansion likely will require transmission expansion by federal and
other entities. BPA is developing several transmission projects in the Interstate-5
corridor and in southern Washington to maintain reliable system operation and integrate
regional wind generation resources. Each project has the potential to increase BPA
transmission rates and thereby affect Avista’s costs.
Avista’s Transmission System

Reliability and Operations
Avista plans and operates its transmission system pursuant to applicable criteria
established by the 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 provides reliable and efficient transmission service from
the company’s generation resources to its retail and wholesale customers.
Transmission capacity surplus to retail load service needs is available to other parties
pursuant to FERC regulations and the terms and conditions of Avista’s OATT. Avista
markets its unsold surplus transmission capacity on a long-term (greater than one year) basis and short-term basis to other parties as part of Avista’s overall resource optimization efforts.

System Topology
Avista owns and operates 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 8.2 illustrates Avista’s transmission system.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 110 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-5

Figure 8.2: Avista Transmission Map
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 has network interconnections with
the following utilities:

 BPA
 Chelan County PUD
 Grant County PUD
 Idaho Power Company
 NorthWestern Energy
 PacifiCorp
 Pend Oreille County PUD

Transmission System Information
Since the 2013 IRP, Avista completed several transmission projects to support new
generation, increase reliability, and provide system voltage support.

Transmission Line Upgrades
 Chelan – Stratford 115 kV: line reconductor
 Garden Springs to Hallet & White section of South Fairchild 115 kV Tap: line reconductor
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 111 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-6

 Irvin – Opportunity 115 kV line: new line section
 Burke to Montana border section of Burke – Thompson Falls A&B 115 kV lines
 Southern half of Bronx – Cabinet Gorge 115 kV line: line reconductor
Stations
 Stratford 115 kV – station rebuild
 Odessa 115 kV – capacitor bank installed
 Lancaster 230 kV station interconnection
 Lind 115 kV – capacitor bank installed
 Moscow 230/115 kV – station rebuild
 Blue Creek 115 kV – station rebuild
 Beck Road 115 kV – new station
 Clearwater 115 kV – station upgrade
 Lewiston Mill Road 115 kV – new station
 North Lewiston 115 kV Distribution Substation

Planned Projects
Avista plans to complete several re-conductor projects throughout its transmission system over the next decade. These projects focus on replacing decades-old small
conductor with new conductor capable of greater load-carrying capability and fewer
electrical losses. The following list gives an example of planned transmission projects:

Transmission Lines
 Addy – Devil’s Gap 115 kV
 Bronx – Cabinet Gorge 115 kV (2011-2017)
 Burke – Pine Creek 115 kV (2012-2015)
 Benton – Othello 115 kV (2014-2016)
 Devils Gap – Lind 115 kV (2014-2016)
 Devil’s Gap – Stratford 115 kV (2019)
 Coeur d’Alene – Pine Creek 115 kV (2014-2018)
 Spokane Valley Reinforcement Project (2011-2016)
Stations
 Irvin 115 kV Switching Station [Spokane Valley Reinforcement] (2016)
 Millwood 115 kV Distribution Substation [Spokane Valley Reinforcement] (2013)
 Harrington 115 kV Distribution Substation (2014)
 Noxon 230 kV Switching Station (2013-2018)
 9th & Central 115 kV Distribution Substation (2015)
 Greenacres 115 kV Distribution Substation (2014)
 Beacon 230/115 kV Station Partial Rebuild (2017+)
 Saddle Mountain 115 kV Station (new, 2018)
 Westside 230/115 kV transformer (2016)

IRP Generation Interconnection Options
Table 8.1 shows the projects and cost information for each of the IRP-related locational
studies where Avista evaluated new generation options. The study details for each
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 112 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-7

project, including cost and integration options, are in Appendix E. These studies provide a high-level view of the generation interconnect requests, and are similar to third-party
feasibility studies performed under Avista’s generator interconnection process. Because
the FERC does not allow complete charging of integration costs benefiting the overall
transmission system to the new generator, it is unlikely that the entirety of these figures will actually be charged to a new interconnected generator. There are cost ranges for each proposed generation project because there are alternate solutions to reinforce the
transmission system to support the proposed interconnected generation levels.

Table 8.1: 2015 IRP Requested Transmission Upgrade Studies
Project Size (MW) Cost Estimate (Millions)3

Large Generation Interconnection Requests
Third-party generation companies may request transmission studies to understand the
cost and timelines for integrating potential new generation projects. These requests
follow a strict FERC process, including three study steps to estimate the feasibility, system impact, and facility requirement costs for project integration. The studies
typically take at least one year to complete. After this process is completed, a contract
offer to integrate the project may occur and negotiations can begin to enter into a
transmission agreement if necessary. Each of the proposed projects becomes public to
some degree, but customer names remain anonymous. Table 8.2 lists major projects currently in Avista’s interconnection queue.

Table 8.2: Third-Party Large Generation Interconnection Requests

Project Size (MW) Type Interconnection
#43 150 Wind Lind 115 kV Substation
#44 600 Pumped Hydro Colstrip 500 kV System

3 Cost estimates are in 2014 dollars and use engineering judgment with a 50 percent margin for error.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 113 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-8

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

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

Grid Modernization
Building on a 2009 effort, a 2013 study assessed the benefits of distribution feeder
automation for increased efficiency and operability. The Grid Modernization Program (GMP) combines the work from these system performance studies and provides
Avista’s customers with refreshed system feeders with new automation capabilities
across the company’s distribution system. Table 8.3 contains a list of completed and
planned feeder upgrades.
The GMP charter ensures a consistent approach to how Avista addresses each project.
This program integrates work performed under various Avista operational initiatives,
including the Wood Pole Management Program, the Transformer Change-Out Program,
the Vegetation Management Program, and the Feeder Automation Program. The work
of the Distribution Grid Modernization Program includes replacing undersized and deteriorating conductors, and replacing failed and end-of-life infrastructure materials
including wood poles, cross arms, fuses, and insulators. It addresses inaccessible pole
alignment, right-of-way, under-grounding, and clear-zone compliance issues for each
feeder section, as well as regular maintenance work including leaning poles, guy
anchors, unauthorized attachments, and joint-use management. This systematic overview enables Avista to cost-effectively deliver a modernized and robust electric
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 114 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-9

distribution system that is more efficient, easier to maintain, and more reliable for our customers.

Figure 8.3 illustrates the reliability advantages and reasons for the Grid Modernization
Program. Prior to the 2009 feeder rebuild pilot program, 39 outages per year were expected. After the project, outages declined significantly to an average of 20 unique outages. In the past two years, only one outage occurred. The program is in its second
year of regular funding and is realizing its intended purpose of capturing energy savings
through reduced losses, increased reliability, and decreased O&M costs. Table 8.3
shows the feeders addressed through this program to date and projects currently in progress. The total energy savings from both re-conductor and transformer efficiencies for all completed feeders is approximately 7,479 MWh annually.

Figure 8.3: Spokane’s 9th and Central Feeder (9CE12F4) Outage History

0
10
20
30
40
50
60
70
2006 2007 2008 2009 2010 2011 2012 2013 2014
Nu
m
b
e
r

o
f

O
u
t
a
g
e
s
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 115 of 212
Chapter 8 – Transmission & Distribution Planning
Avista Corp 2015 Electric IRP 8-10

Table 8.3: Completed and Planned 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
OTH502 Othello, WA 2014 21
RAT231 Rathdrum, ID 2014 0
M23621 Moscow, ID 2015 413
WIL12F2 Wilbur, WA 2015 1,403
WAK12F2 Spokane, WA (Waikiki) 2016 175
RAT233 Rathdrum, ID 2019 471
SPI12F1 Northport, WA (Spirit) 2019 127
Total 7,479

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 116 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
9. 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 to meet its load obligations. This section describes resources Avista
considered in the 2015 IRP to meet future needs. The resources described in this
chapter are mostly generic, as actual resources identified through a competitive process may differ in size, cost, and operating characteristics due to siting or engineering
requirements.

Assumptions
Avista only considers commercially available resources with well-known costs,
availability, and generation profiles priced as if Avista developed and owned the generation. Resource options include natural gas-fired combined cycle combustion
turbines (CCCT), simple cycle combustion turbines (SCCT), natural gas-fired
reciprocating engines, large-scale wind, energy storage, photovoltaic solar,
hydroelectric upgrades, and thermal unit upgrades. Several other resource options
described later in the chapter were not included in the PRS analysis, but discussed as potential resource options that may respond to a future RFP. The IRP excludes
potential contractual arrangements with other energy companies as an option in the
plan, but such arrangements may be an option when Avista seeks new resources
through a competitive acquisition process.
The resource costs of each resource option include transmission expenses, as
described in Chapter 8 – Transmission & Distribution Planning. Levelized costs result
from discounting nominal cash flows by a 6.58 percent-weighted average cost of capital
approved by the states of Idaho and Washington in recent rate case filings. All costs in
this section are in 2015 nominal dollars unless otherwise noted. Many renewable resources are eligible for federal and state tax incentives. Federal
solar tax benefits fall by two-thirds after 2016; federal production tax credits (PTCs) are
no longer available unless meeting certain provisions. Incentives, to the extent they are
Section Highlights


Upgrades to Avista’s


Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 117 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
available, are included in IRP modeling. The IRP amortizes investment tax credits over the life of the asset per regulatory accounting rules.

Avista relies on several sources including the NPCC, press releases, regulatory filings,
internal analysis, developer estimates, and Avista’s experience with certain technologies for its resource assumptions. The natural gas-fired plants use operating characteristic and cost information from Thermoflow.

Levelized resource costs illustrate the cost differences between generator types. The
values show the cost of energy if the plants generate electricity during all available hours of the year. In reality, plants do not operate to their maximum generating potential because of market and system conditions. Costs are separated between energy in
$/MWh, and capacity in $/kW-year, to better compare the facilities. Without this
separation of costs, resources operating very infrequently during peak-load periods
would appear more expensive than base-load CCCTs, even though peaking resources
are lower cost when planned to operate only a few hours each year. Levelized energy costs fairly compare renewable resources to the energy component of natural gas-fired
resources because renewable technologies are not dispatchable.

The following cost items are in the levelized cost calculations for both the capacity and
energy cost components.
 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 federal tax incentive in the form of a PTC, a cash
grant, or an investment tax credit (ITC), available to qualified generation options.
 Fuel Costs: The average cost of fuel such as natural gas, coal, or wood per MWh of generation. Additional fuel price 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.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 118 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
 Other Overheads: Includes miscellaneous charges for non-capital expenses such
as un-collectibles, excise taxes, and commission fees.

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.1 Table 9.1 compares the levelized costs of different resource types.

Table 9.1: Natural Gas-Fired Plant Levelized Costs per MWh

Advanced Large Frame CT $58 $130 220
Modern Large Frame CT $57 $124 186
Advanced Small Frame CT $64 $151 102
Frame/Aero Hybrid CT $46 $164 106
Small Reciprocating Engine Facility $41 $159 93
Modern Small Frame CT $59 $188 49
Aero CT $54 $202 45
1 x 1 Advanced CCCT $37 $211 362
1 x 1 Modern CCCT $37 $210 306

Natural Gas-Fired Combined Cycle Combustion Turbine Natural gas-fired CCCT plants provide reliable capacity and energy for a relatively
modest capital investment. The main disadvantage of a CCCT is generation cost
volatility due to reliance on natural gas, unless utilizing hedged fuel prices. CCCTs
modeled in the IRP are “one-on-one” (1x1) configurations, using hybrid air/water cooling
technology and zero liquid discharge. The 1x1 configuration consists of a single gas turbine with a heat recovery steam generator (HRSG) and a duct burner to gain more
generation from the steam turbine. The plants have nameplate ratings between 250 MW
and 350 MW each depending on configuration and location. A two-on-one (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 Avista’s needs.

Cooling technology is a major cost driver for CCCTs. Depending on water availability, lower-cost wet cooling technology could be an option, similar to Avista’s Coyote Springs 2 plant. However, if no water rights are available, a more capital-intensive and less
efficient air-cooled technology may be used. For this IRP, Avista assumes some water
is available for plant cooling, but only enough for a hybrid system utilizing the benefits of
combined evaporative and convective technologies.
1 Peak credit is the amount of capacity a resource contributes at the time of system peak load.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 119 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
This IRP models two types of CCCT plants, first a smaller 285 MW machine, and a larger advanced 341 MW plant. Avista reviewed many CCCT technologies and sizes,
and selected these plants due to their being commonly used technologies in the
Northwest. Where Avista pursues a CCCT, a competitive acquisition process will allow
analysis of other CCCT technologies and sizes. The most likely location is in Idaho,
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 state taxes on the
emission of carbon dioxide.2 CCCT site or sites likely would be on or near our
transmission system to avoid third-party wheeling costs. Another advantage of siting a
CCCT resource in Avista’s Idaho service territory is access to relatively low-cost natural gas on the GTN pipeline.
The smaller machine’s heat rate is 6,720 Btu/kWh in 2016.3 The larger machine is 6,631
Btu/kWh. The plants include duct firing for 7 percent of rated capacity at a heat rate of
7,912 and 7,843 Btu/kWh, respectively.
The IRP includes a 3 percent forced outage rate for CCCTs and 14 days of annual plant
maintenance. The smaller plant can back down to 62 percent of nameplate capacity,
while the larger plant can ramp down to 30 percent of nameplate capacity. The
maximum capability of each plant is highly dependent on ambient temperature and plant
elevation.
The anticipated capital costs for the two CCCTs, located in Idaho on Avista’s
transmission system with AFUDC on a green field site, are $1,177 per kW for the
smaller machine and $1,120 per kW (2016$) for the larger machine. These estimates
exclude the cost of transmission and interconnection. Table 9.1 shows levelized plant cost assumptions split between capacity and energy. The costs include firm natural gas
transportation, fixed and variable O&M, and transmission. Table 9.2 summarizes key
cost and operating components of natural gas-fired resource options.

Natural Gas-Fired Peakers Natural gas-fired SCCTs 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 frame, hybrid-intercooled, reciprocating engines, and aero-derivative
peaking resource options. The peaking technologies have different load following
abilities, costs, generating capabilities, and energy-conversion efficiencies. Table 9.2
shows cost and operational estimates based on internal engineering estimates. All
2 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 for new plants. 3 Heat rates shown are the higher heating value.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 120 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
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 9.1.

Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics

Advanced Large
Frame CT
$638 $2.08 9,931 $3.65 1 203 203 $129
Modern Large
Frame CT
$667 $2.08 10,007 $2.60 1 170 170 $114
Advanced Small Frame CT $853 $3.13 11,265 $2.60 1 96 96 $82
Frame/Aero Hybrid CT $1,016 $3.13 8,916 $3.13 1 101 101 $103
Small Reciprocating
Engine Facility
$546 $8.33 7,700 $3.13 10 9.3 93 $51
Modern Small
Frame CT
$1,265 $4.17 10,252 $2.60 1 45 45 $57
Aero CT $1,316 $6.25 9,359 $2.60 1 42 42 $56
1 x 1 Modern
CCCT
$1,120 $18.7
5
6,771 $3.91 1 341 341 $382
1 x 1 Advanced
CCCT
$1,177 $15.6
3
6,845 $3.13 1 286 286 $336

Firm natural gas fuel transportation is an electric reliability issue with FERC and the
subject of 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 evaluated sites are not presently full or expected
to become full in the near future. Where non-firm transportation options become
inadequate for system reliability, three options exist: contracting for firm natural gas transportation rights, on-site oil, or liquefied natural gas storage.

Wind Generation
Governments promote wind generation with tax benefits, 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 if
construction began in 2013. This IRP does not assume the PTC extends beyond this
term, but does assume the preferential five-year tax depreciation remains.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 121 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Wind resources benefit from having no emissions 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 2016, including AFUDC,
are $2,234 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 balancing authority and the market price of power. Wind integration in
this IRP is $4.30 per kW-year in 2016. These estimates come from Avista’s experience
in the market and results from Avista’s 2007 Wind Integration Study.
Wind capacity factors in the Northwest range between 25 and 40 percent depending on
location. This plan assumes Northwest wind has a 35 percent average 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 details). The expected capacity factor impacts 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.

As discussed above, levelized costs change substantially due to capacity factor, but can
change more from tax incentives. Figure 9.1 shows nominal levelized prices with different start dates, capacity factors, and availability of the ITC. For a plant installed in
2016, the estimated “all-in” cost is $102 per MWh; but, direct cost to customers would
be $70 per MWh with the ITC. This plan assumes wind resources selected in the PRS
include the 20 percent REC apprenticeship adder for the EIA. Qualification for the adder
requires 15 percent of construction labor by state-certified apprentices.

Figure 9.1: Northwest Wind Project Levelized Costs per MWh

102 109
116
124
131
70 71 75 80 86
60 61 65 69 74
$0
$20
$40
$60
$80
$100
$120
$140
2016 2020 2025 2030 2035
No
m
i
n
a
l

L
e
v
e
l
i
z
e
d

$
/
M
W
h
Expected Case 30% ITC 30% ITC + 40% CF
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 122 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Photovoltaic Solar Photovoltaic (PV) solar generation technology costs have fallen substantially in the last
several years partly due to low-cost imports and from demand driven by renewable
portfolio standards and tax incentives. Even with large cost reductions, IRP analyses
shows that PV solar facilities still are uneconomic for winter-peaking utilities in the Northwest compared to other renewable and non-renewable generation options. This is due to its low capacity factor and lack of output during winter-peak periods. PV solar
provides predictable daytime generation complementing the loads of summer-peaking
utilities, though panels typically do not produce at full output during peak hours.
Where a substantial amount of PV solar is added to a summer peaking utility system, such as one located in the Desert Southwest, the peak hour recorded prior to the
installation will be reduced, but the peak hour will shift toward sundown when PV solar
output is lower. As more PV solar enters a system, the on-peak resource contribution
falls precipitously. Table 9.3 presents the peak credit by month with different amounts of
solar using output from the Rathdrum Solar Project. This table illustrates that solar does
not reduce Avista’s winter peak, reduces the summer peak, and is less effective at
reducing peak as more solar is installed.

Table 9.3: Solar Capacity Credit by Month

Month 5 MW 25 MW 50 MW 100 MW 150 MW 200 MW 300 MW
Jan 0% 0% 0% 0% 0% 0% 0%
Feb 0% 0% 0% 0% 0% 0% 0%
Mar 0% 0% 0% 0% 0% 0% 0%
Apr 28% 15% 11% 8% 6% 5% 3%
May 46% 46% 37% 26% 17% 13% 9%
Jun 39% 39% 36% 31% 25% 22% 19%
Jul 52% 49% 45% 43% 33% 27% 22%
Aug 40% 40% 40% 34% 32% 30% 24%
Sep 0% 0% 0% 0% 0% 0% 0%
Oct 0% 0% 0% 0% 0% 0% 0%
Nov 0% 0% 0% 0% 0% 0% 0%
Dec 0% 0% 0% 0% 0% 0% 0%

Solar-thermal technologies can produce capacity factors as much as 30 percent higher
than PV solar projects and can store energy for several hours for later use in reducing
peak loads. However, solar thermal technologies do not lend themselves well to the
Northwest due to their lack of significant generation in the winter and higher overall installation and operation costs; therefore, only PV solar systems are considered for the
IRP.

Utility-scale PV solar capital costs in the IRP, including AFUDC, are $1,500 per kW for
fixed panel and $1,600 per kW for single-axis tracking projects. A well-placed utility-scale single-axis tracking PV system located in the Pacific Northwest would achieve a
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 123 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
first-year capacity factor of approximately 18 percent and a fixed panel system would achieve 15 percent. PV solar output degrades over time. The IRP de-rates solar
generation output by one-half percent each year to account for panel degradation.

Figure 9.2 shows the levelized costs of solar resources, including applicable federal and state incentives, on-line dates, and capacity factors. The costs are specific to Avista acquisition and ownership. The State of Washington offers a number of incentives for
solar installations. First, plants less than five megawatts count double toward
Washington’s EIA. The state also offers substantial financial incentives for consumer-
owned solar. Consumer-owned solar counts in reductions in Avista’s retail load forecast.
Figure 9.2: Solar Nominal Levelized Cost ($/MWh)

Energy Storage
Increasing solar and wind generation on the electric grid makes energy storage
technologies attractive from an operational perspective. Storage could be an ideal way
to smooth out renewable generation variability, oversupply, and assist in load following and regulation needs. The technology could help meet peak demand, provide voltage
support, relieve transmission congestion, take power during over supply events, and
supply other non-energy needs for the system. The IRP considered several storage
technologies, including pumped hydroelectric, lead-acid batteries, lithium ion batteries,
flow batteries, flywheels, and compressed air.

Storage may become an important part of the nation’s electricity grid if the technology
overcomes a number of large physical, technical, and economic barriers. First, existing
technologies consume a significant amount of electricity relative to their output through
conversion losses. Second, equipment costs are high, at near $3,455 per kW, or nearly
150
137 141 148 155
138
129 133 139 145
94 88 91 95 99
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
2016 2020 2025 2030 2035
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Expected Case 30% ITC 30% ITC + 20% CF
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 124 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
three times the initial cost of a natural gas-fired peaking plant that can provide many of the same capabilities without the electricity consumption characteristics of storage.
Storage costs will 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 relatively small, limiting their applicability to utility-scale deployment. Finally, early technology adoption can be risky,
with industry examples of battery fires and financial issues.

To learn more about storage technology and its potential, Avista recently installed a vanadium flow battery in Pullman, Washington. This installation, known as the Turner Energy Storage Project, will provide insight about the technology’s reliability, its
potential benefit to the transmission and/or distribution systems, and potential power
supply benefits including oversupply events. The battery has one megawatt of power
capability and three megawatt-hours of energy storage. A Washington state grant for
research and development partially funded this storage project.
Turner Energy Storage Project, Pullman, WA

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

In addition to capital costs, storage projects O&M costs are $20 per kW-year, and recharge costs use off-peak Mid-Columbia energy prices. Levelized storage project
costs are highly inaccurate as storage projects do not create megawatt hours; in fact,
they consume megawatt hours with 15 to 20 percent or more of their charge being lost.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 125 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
The nominal levelized capacity cost for storage is approximately $580 per kW-year and energy costs $35/MWh.

Other Generation Resource Options
A thorough IRP analyzes generation resources not readily available in large quantities, not commercially available, not economically ready for utility-scale development, or prohibited by state policy. Several emerging technologies, like energy storage, are
attractive from an operational or environmental perspective, but are significantly higher-
cost than other technologies providing similar capabilities at lower cost. The resources
include biomass, geothermal, co-generation, nuclear, landfill gas, and anaerobic digesters. This plan does not model these resource options explicitly, but continues to monitor their viability.

Exclusion from the PRS is not the last opportunity for non-modeled technologies to be
part of Avista’s future portfolio. The resources compete with those included in the PRS
through competitive acquisition processes. Competitive acquisition processes identify technologies that might displace resources otherwise included in the IRP strategy.
Another possibility is acquisition through federal PURPA mandates. PURPA provides
non-utility developers the ability to sell qualifying power to Avista at set prices and
terms.4

Woody Biomass Generation
Woody biomass generation projects use waste wood from lumber mills or forest
restoration processes. In the generation process, 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 megawatt-hour of electricity; the ratio varies with
the moisture content of the fuel. The viability of another Avista biomass project depends
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.

Geothermal Generation
Northwest utilities have shown increased interest in geothermal energy over the past
several years. It provides predictable capacity and energy with minimal carbon dioxide emissions (zero to 200 pounds per MWh). Some forms of geothermal technology
extract steam from underground sources to run through power turbines on the surface
while others utilize an available hot water source to power an Organic Rankine Cycle
installation. Due to the geologic conditions of Avista’s service territory, no geothermal
projects are likely to be developed.
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
4 Rates, terms, and conditions are available at www.avistautilities.com under Schedule 62.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 126 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
cost over $3 million. Ongoing geothermal costs are low, but the capital required locating and proving a viable site is significant. Costs shown in this section do not account for
the dry-hole risk associated with sites that do not prove to be viable after drilling has
taken place.

Landfill Gas Generation Landfill gas projects generally use reciprocating engines to burn methane gas collected
at landfills. The Northwest has developed many landfill gas resources. The costs of a
landfill gas project depend 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. Much of the Spokane area no longer landfills its waste and instead uses the Spokane Waste to Energy Plant. Nearby in Kootenai County, Idaho, the
Kootenai Electric Cooperative has developed the 3.2 MW Fighting Creek Project. Using
publically available costs and the NPCC estimates, landfill gas resources are
economically promising, but are limited in their size, quantity, and location.

Anaerobic Digesters (Manure or 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, at fewer than five megawatts. Most facilities are located at large dairies and 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 system configuration. Retrofits to existing
wastewater treatment facilities are possible, but tend to have higher costs. Many
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.

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 efficiency
targets.

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.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 127 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
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
during the retrofit of an industrial process, but the retrofit may not occur when the utility
needs new capacity. 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 or if cost effective small-scale nuclear plants
become a reality.

The viability of nuclear power could change as national policy priorities focus attention on de-carbonizing the nation’s energy supply. The lack of recent nuclear construction
experience in the U.S. makes estimating construction costs difficult. Cost projections in
the IRP are from industry studies, recent nuclear plant license proposals, and the 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, and make these traditionally large projects better fit the needs of
smaller utilities.

Coal
The coal generation industry is at a crossroads. In many states, like Washington, new coal-fired plants are unlikely due to emission performance standards and the shortage
of utility scale carbon capture and storage projects. Federal guidelines under section
111(b) of the CAA and the CPP likely prevent or restrict the construction of new coal
generation. The final rule was not available at the time this section’s drafting. The risks
associated with future carbon legislation and projected low natural gas costs make investments in this technology challenging.

Hydroelectric Project Upgrades and Options
Avista continues to upgrade its hydroelectric facilities. The latest hydroelectric upgrade
added nine megawatts to the Noxon Rapids Development in April 2012. Figure 9.3
shows the history of upgrades to Avista’s hydroelectric system. Avista added 40.1 aMW
of incremental hydroelectric energy between 1992 and 2012. Upgrades completed after
1999 can qualify for the EIA, thereby reducing the need for additional renewable energy options.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 128 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Figure 9.3: Historical and Planned Hydro Upgrades

Avista is currently upgrading the Nine Mile powerhouse, replacing two of its four turbine generator units. Avista removed the last two original 1908 units in 2013 and began a
project to replace the 107-year old technology with new turbine generators, generator
step-up transformer, switchgear, exciters, governors and controls in 2014. Avista
expects to complete the project in 2016.
The Spokane River hydroelectric construction occurred in the late 1800s and early
1900s, when the priority was to meet then-current loads. The developments currently do
not capture a majority of the river flow as their original designs only met then-current
loads and not river capacity. In 2012, Avista reassessed its Spokane River
developments to evaluate opportunities to take advantage of more of the streamflow. 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 and 2013 IRP Action Plans and results appear below. Each of these upgrades are major engineering projects, taking several years to complete and requiring major
changes to the FERC licenses and project water rights. A summary of the upgrade
options is in Table 9.4. The upgrades will compete against other renewable options
when more renewables are required in future.

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 129 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Table 9.4: Hydroelectric Upgrade Options
Resource Post
Falls
Monroe
Street/Upper
Falls
Long
Lake
Cabinet
Gorge
Incremental Capacity (MW) 22 80 68 110
Incremental Energy (MWh) 90,122 237,352 202,592 161,571
Incremental Energy (aMW) 10.3 27.1 23.1 9.2
Peak Credit (Winter/ Summer) 24/0 31/0 100/100 0/0
Capital Cost ($ Millions) $136 $193 $179 $286
Levelized Energy Cost ($/MWh) $159 $93 $112 $197

Long Lake Second Powerhouse Avista studied adding a second powerhouse at Long Lake over 20 years ago by using
the small arch or saddle dam located on the south end of the project site. This project
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 levels by reducing spill at the project and provide incremental capacity to meet peak
load growth.

The 2012 study focused on three alternatives. The first replaces the existing four-unit powerhouse with four larger units to total 120 MW, increasing capacity by 32 MW. The other two alternatives develop a second powerhouse with a penstock beginning from a
new intake structure just downstream of 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 9.4 shows upgrade costs and characteristics.
Post Falls Refurbishment
The Post Falls hydroelectric development is 109 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 replaces 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. Studies of alternatives to address the aging infrastructure of the plant will continue over the next decade.
Monroe Street/Upper Falls Second Power House
Avista replaced the powerhouse at its Monroe Street development on the Spokane
River in 1992. There are three options to increase its capacity. Each would be a major undertaking requiring substantial cooperation with the City of Spokane to mitigate disruption in Riverfront and Huntington parks and downtown Spokane during
construction. The upgrade could increase plant capacity by up to 80 MW. To minimize
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 130 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
impacts on the downtown area and the park, a tunnel drilled on the east side of Canada Island could avoid excavation of the south channel. A smaller option would add a
second 40 MW Upper Falls powerhouse, but this option would require south channel
excavation. A final option would add a second Monroe Street powerhouse for 44 MW.

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 110 MW underground powerhouse would benefit from an existing diversion tunnel
around the dam built during original 1952 construction.
Thermal Resource Upgrade Options
The 2013 IRP identified several thermal upgrade options for Avista’s fleet. This plan contains new ideas to increase generating capability at Avista’s thermal generating resources. No costs are presented in this section, as pricing is sensitive to third-party
suppliers.

Northeast CT Water Injection This is a water injected NOx control system allowing the firing temperature to increase and thereby increasing the capacity at the Northeast CT by 7.5 MW.

Rathdrum CT Supplemental Compression
Supplemental compression is a new technology developed by PowerPhaseLLC, the technology increases airflow through a combustion turbine compressor increasing machine output. This upgrade increases Rathdrum CT capacity by 24 MW.

Rathdrum CT 2055 Uprates
By upgrading certain combustion and turbine components, the firing temperature can increase to 2,055 degrees from 2020 degrees corresponding to a five MW increase in output.

Rathdrum CT Inlet Evaporation
Installing a new inlet evaporation system will increase the Rathdrum CT capacity by 17 MW on a peak summer day, but no additional energy is expected during winter months.

Kettle Falls Turbine Generator Upgrade
The Kettle Falls plant began operation in 1983. In 2025, the generator and turbine will
be 42 years old and will be at the end of its expected life. At this time, Avista could
spend additional capital and upgrade the unit by 12 megawatts rather than replace it with in kind technology.

Kettle Falls Fuel Stabilization
The wood burned at Kettle Falls varies in moisture content, and dryer fuel burns more
efficiently. A fuel drying system added to the fuel handling system would allow the boiler to operate at a higher efficiency point, increasing plant capability by three megawatts.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 131 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Ancillary Services Valuation
IRPs traditionally model the value of resources using hourly models. This method
provides a good approximation of resource value, but it does not provide a value for the intra-hour or ancillary services needs of a balancing area. Ancillary services modeled in the IRP include spinning and non-spinning reserves, regulation, and load following.
Spinning and non-spinning reserve obligations together equal 3 percent of load and 3
percent of on-line generation, as required by regional standards. Half of the reserves
must synchronize to the system and half must be capable of synchronizing within 10 minutes. Regulation meets instantaneous changes in load or resources with plants responding to the change using automatic generating control. Load following covers
load changes within the hour, but for movements occurring across a timeframe greater
than 10 minutes.
Avista developed a new tool, called the Avista Decision Support System (ADSS), for use in operations and long-term planning. This model is a mixed-integer linear program
simulating Avista’s system. It optimizes a set of resources to meet system load and
ancillary services requirements using real-time information. The tool uses both actual
and forecasted information regarding the surrounding market and operating conditions to provide dispatch decisions, but can also use historical data to simulate benefits of certain system changes. ADSS uses historical data sets to estimate ancillary services
values for storage and natural gas-fired resources.

Storage As intermittent resources grow in size, there is potential for the existing system not being robust enough to integrate the resources and handle oversupply of renewable
energy. To address this concern, governments and utilities are investing in storage
technology. Today storage has a limited role due to cost and technology infancy. This
analysis studies the potential financial value storage brings to Avista’s power supply costs based on 2012 actual data and average hydroelectric conditions. The study includes several storage capacities with storage to peak ratio of three to one and 85
percent efficiency. Table 9.5 is the value brought to the power supply system for each
storage capacity size. These values are to the Avista system only and do not represent
the value to other systems or non-power supply benefits. Avista has a deep resource stack of flexible resources and adding additional flexible resources do not necessarily add value unless sold to third parties.

The values shown in Table 9.5 include margin from several value streams including
operating reserves, regulation, load following, and arbitrage. Arbitrage is optimizing the
battery to charge in low prices and discharging when prices are higher. Of the values shown in Table 9.5, arbitrage represents the largest value stream. Figure 9.4 shows the
five value streams for power supply benefits. Load following and arbitrage represent 92
percent of the value to Avista.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 132 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Table 9.4: Storage Power Supply Value
Storage
Capacity
(MW)
Annual
Value
Annual $/kW
Value
35 $1,201,590 $34
30 $1,024,569 $34
25 $923,291 $37
10 $381,407 $38
5 $189,000 $38
1 $36,862 $37

Figure 9.4: Storage’s Value Stream

Natural Gas-Fired Facilities Natural gas-fired facilities can provide energy and ancillary services. This study looks at
their incremental ancillary services value to the system. The values do not represent the
value for current resources of similar technology, but only the incremental value of a
new facility. This study assumes 100 MW resource increments in 2020. Table 9.6
shows the results of the analysis. The incremental values for these resources are marginal due to the limited need for this type of resource. The study assumes each facility has different operating capabilities. For example, diesel back-up can only provide
non-spin reserves as it is for emergency use only, while the LMS 100 may provide non-
spinning reserves, spinning reserves, regulation, and load following if operating.

Arbitrage, 64%
Load Following,
28%
Spin & Non-Spin Reserves, 5%
Regulation, 2%
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 133 of 212
Chapter 9- Generation Resource Options
Avista Corp 2015 Electric IRP
Table 9.5: Natural Gas-Fired Facilities Ancillary Service Value
Resource Type Capabilities Annual $/kW
Value
CCCT Load Following/ Spin5, Regulation $0.00
LMS 100 Load Following/ Spin, Non-Spin/ Regulation $1.12
Reciprocating Engines Load Following/Spin/Non-Spin $0.61
Diesel Back-Up Non-Spin $0.00

Currently, there is not a mature ancillary services market in the Northwest, so ancillary
service values are the costs of operating Avista’s system differently to provide more
ancillary services relative to traditional wholesale energy sales. The ancillary service
values of both storage and natural gas-fired technology were less than expected prior to the analysis. Avista concluded that the results were reasonable for one primary reason: having a large hydroelectric system, Avista’s system has a significant amount of
flexibility relative to its load variability in most periods. With as the addition of more
variable generation resources, the value of ancillary services capacity should rise.
Figure 9.5 details the significant surplus of ancillary service generation Avista’s system contains. While the system can become constrained during peak load periods, the large value in these periods is not as significant when averaged over the entire year.

Figure 9.5: Avista’s Monthly Up/Down Regulation Surplus

5 Fast start CCCTs may have some non-spin reserve capability.
0
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Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
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Up Capacity Down Capacity
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 134 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
10. Market Analysis

Introduction
This section describes the electricity, natural gas, and other markets studied in the 2015
IRP. It contains price risks Avista considers to meet customer demands at the lowest
reasonable cost. The analytical foundation for the 2015 IRP is a fundamentals-based
electricity model of the entire Western Interconnect. The market analysis evaluates potential resource options on their net value within the wholesale marketplace, rather
than the summation of their installation, operation, maintenance, and fuel costs. The
PRS analysis uses these net market values to select future resource portfolios.

Understanding market conditions in the Western Interconnect is important because regional markets are highly correlated due to 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 an electricity market model. The model, AURORAXMP, 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.

Marketplace
AURORAXMP is a fundamentals-based modeling tool used by Avista to simulate the
Western Interconnect electricity market. The Western Interconnect includes states west
of the Rocky Mountains, the Canadian provinces of British Columbia and Alberta, and
the Baja region of Mexico as shown in Figure 10.1. The modeled area has an installed
resource base of approximately 240,000 MW.

Section Highlights
 Natural gas, solar, and wind resources dominate new generation additions in the Western Interconnect.
 Clean Power Plan regulation could cause large price and costs swings, but
without a final rule and state compliance plans, the impacts are unknown at
this time.
 The Expected Case forecasts a continuing reduction of Western Interconnect
greenhouse gas emissions due to coal plant closures brought on by federal
and state regulations and low natural gas prices.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
Figure 10.1: NERC Interconnection Map

The Western Interconnect is separate from the Eastern and ERCOT interconnects to
the east except for eight DC inverter stations. It follows operation and reliability
guidelines administered by WECC. Avista modeled the WECC electric system as 17
zones based on load concentrations and transmission constraints. After extensive study in prior IRPs, Avista models the Northwest region as a single zone because this
configuration dispatches resources in a manner consistent with historical operations.
Table 10.1 describes the specific zones modeled in this IRP.

Table 10.1: 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, MexicoUtah

Western Interconnect Loads
The 2015 IRP relies on a load forecast for each zone of the Western Interconnect.
Avista uses other utilities’ resource plans and regional plans to quantify load growth
across the west. These estimates include energy efficiency, customer-owned generation, plug-in electric vehicles, and demand response reductions within the
trajectory. Forecasting future energy use is difficult because of large uncertainties with
the long-term drivers of future energy use.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 136 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.2 shows regional load growth estimates. The total of the forecasts show Western Interconnect loads rising nearly 1.1 percent annually over the next 20 years.
On a regional basis, the Northwest will grow at 0.73 percent, California at 1 percent, the
Rocky Mountain States at 1 percent, and the desert Southwest region is lower than
previous forecasts at 0.75 percent. The strongest projected growth area in the region comes from Canada at 2 percent. From a system reliability perspective, regional peak loads grow at similar levels.

Figure 10.2: 20-Year Annual Average Western Interconnect Energy

Resource Retirements
The resource mix constantly changes as new resources start generating and older
resources retire. In prior IRPs, much of the existing fleet continued to serve future loads
in combination with new resources. Many companies are now choosing to retire older
plants to comply with environmental regulations and economic changes. Most plant closures are once-through-cooling (OTC) facilities in California and older coal
technology throughout North America that cannot economically meet stricter air
emissions standards and compete with lower-cost natural gas-fired facilities.

Several states are developing rules to restrict or eliminate certain generation technologies. In California, all OTC facilities require retrofitting to eliminate OTC technology or the plant must retire. Over 14,200 MW of OTC natural gas-fired
generators in California likely will retire and need replacement in the IRP timeframe.
Remaining OTC natural gas-fired and nuclear facilities with more favorable economics
are candidates for retrofitting with new cooling technology. The IRP models the closure of OTC plants with identified shutdown dates from their utility owners’ IRPs and news releases. Elimination of OTC plants in California will eliminate older technology
California
Northwest
Desert SW
Rocky Mountains
Canada
aGW
20 aGW
40 aGW
60 aGW
80 aGW
100 aGW
120 aGW
140 aGW
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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presently used for reserves and high demand hours. Replacement plants will be expensive for California customers, but a more modern and efficient generation fleet will
serve customers.

Coal-fired facilities face increasing regulatory scrutiny. In the Northwest, the Centralia and Boardman coal plants will retire by the end of calendar years 2020 and 2025 respectively, for a reduction of 1,961 megawatts. Other coal-fired plants throughout the
Western Interconnect have announced plant closures, including Four Corners, Carbon,
Arapahoe, San Juan, Reid Gardner, and Corette. The Nevada legislature successfully
placed into law a plan to retire all in-state coal plants, and PacifiCorp appears poised to retire many plants as indicated in its most recent IRP. Over the next 20 years, roughly 45 percent of the Western Interconnection coal fleet retires in the Expected Case. In
total, announced retirements for all generation technologies, as shown in Figure 10.3,
equal approximately 29 gigawatts by 2035. Avista does not forecast any additional large
coal facility retirements in its Expected Case.

Figure 10.3: Resource Retirements (Nameplate Capacity)

New Resource Additions
New resource capacity is required to meet future load growth and replace retired power
plants over the next 20 years. To fill the gap, the model adds new resources in each region to maintain a 5 percent Loss of Load Probability (LOLP). This means meeting all
system demand in 95 percent of simulated forecasts. The generation additions meet
capacity, energy, ancillary services, and renewable portfolio mandates. Only natural
GW
5 GW
10 GW
15 GW
20 GW
25 GW
30 GW
35 GW
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Oil
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Natural Gas
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 138 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
gas-fired peaking and CCCT plants, solar plants, and wind plants are in the plan. The IRP does not include new nuclear or coal plants over the forecast horizon.

Many states have RPS requirements promoting renewable generation to reduce
greenhouse gas emissions, provide jobs, and diversify their energy mixes. 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 based on resource selection trends. Figure 10.4 illustrates new capacity and RPS additions made in the modeling process. Nearly 112 GW will be required to meet the renewable and capacity requirements for the system. Wind and solar facilities meet
most renewable energy requirements.

Geothermal, biomass, and hydroelectric resources provide limited RPS contributions.
Due to its low capacity factor, large quantities of solar capacity are necessary to make a meaningful contribution. 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 given policy choices by those states. The Northwest will
use a combination of wind, solar, and hydroelectric upgrades because the costs of
these resources are the lowest for the region. Rocky Mountain States will meet RPS requirements predominately with wind.

Figure 10.4: Cumulative Generation Resource Additions (Nameplate Capacity)

In total, 45,000 MW of new utility and consumer-owned renewable generation will put
downward pressure on afternoon peak pricing and move peak load requirements later in
the day. Potential for oversupply in shoulder months in California will increase imports to
GW
20 GW
40 GW
60 GW
80 GW
100 GW
120 GW
140 GW
160 GW
GW
2 GW
4 GW
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8 GW
10 GW
12 GW
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 139 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
the Northwest and other markets. The forecast finds wind generation is no longer the largest contributor of new renewable resources in the Western Interconnect; it
represents 6,000 MW, or 13 percent, of new renewable capacity. The largest resource
addition expected in the west is natural gas-fired generation. The technology likely will
be a combination of peakers and flexible combined cycle plants. A new entrant into the resource forecast is storage technology. Given increasing government intervention in the energy storage market in California, 1,300 MW of storage capacity is included in the
forecast. Avista will continue to monitor this technology to determine if a larger level of
market penetration is likely.
The Northwest market needs new capacity resources in 2021. Utility resource size requirements determine if the new plants are CCCTs or peakers. Based on market
simulation results, a 24 percent regional planning margin (including operating reserves)
is necessary to meet the 5 percent LOLP. The Northwest likely will continue to develop
wind to meet RPS requirements, but given the lower cost of solar, Avista expects some
utilities to move to solar to meet renewable requirements beginning in 2020. Table 10.2 shows the amount of new renewables added to the Northwest by the end of 2035 in the
Expected Case.

Table 10.2: Added Northwest Generation Resources
Resource Type Capacity (MW)
Wind 2,340
Utility- Solar 1,140
Customer- Solar 1,884
Other Renewables 225

Fuel Prices and Conditions
Fuel cost and availability are some of the most important drivers of the wholesale
electricity marketplace and resource values. Some resources, including geothermal and
biomass, have limited fuel options or sources, while natural gas has greater potential.
Hydroelectric, wind, and solar resources benefit from free fuel, but are highly dependent on weather and limited siting opportunities.
Natural Gas
The natural gas industry continues its fundamental shift away from conventional gas to
hydraulic fracturing, or fracking. As fracking continues to become more efficient,
production increases at record pace. At the same time, growth in the residential, commercial, and industrial markets is flat. Natural gas used for power generation is
growing due to its flexibility to support the variable output from renewable energy and as
a replacement resource for coal plant retirements caused by state and federal
regulations. Additionally, forecast adoption of natural gas for transportation and LNG
exports increases demand in later years of the forecast.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 140 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
The fuel of choice for new base-load and peaking generation continues to be natural gas. Natural gas has a history of significant price volatility. Unconventional sources
reduce overall price levels and volatility, although it is unknown how much volatility will
exist in the future, 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 forecasts from prominent energy industry consultants to develop the natural gas price forecast for this IRP. Based on these forecasts, the
levelized nominal price is $5.13 per dekatherm (Dth) at Henry Hub (shown in Figure
10.5 as the green bars). The pricing methodology to create a fundamental price forecast
is below, as follows:
 2016: 100 percent market;
 2017: 75 percent market, 25 percent consultant average;
 2018: 50 percent market, 50 percent consultant average; and
 2019-21: 25 percent market, 75 percent consultant average.

Figure 10.5: Henry Hub Natural Gas Price Forecast

Price differences across North America depend on demand at the major trading hubs
and pipeline constraints existing between them. One change in recent years is the new
Ruby pipeline. It provides the west coast access to historically cheaper natural gas supplies located in the Rocky Mountains. Table 10.3 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
$/Dth
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IRP Forecast
Consultant 1
Consultant 2
Forwards (12/04/14)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 141 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
natural gas prices, monthly Stanfield price shapes are in Table 10.4 for selected forecast years.

Table 10.3: Natural Gas Price Basin Differentials from Henry Hub

Stanfield 93% 94% 95% 97% 100%
Malin 98% 98% 98% 99% 101%
Sumas 90% 93% 93% 97% 100%
AECO 81% 83% 87% 92% 94%
Rockies 97% 96% 97% 98% 99%
Southern CA 103% 102% 102% 102% 103%

Table 10.4: Monthly Price Differentials for Stanfield from Henry Hub

Jan 97% 97% 98% 99% 103%
Feb 97% 96% 97% 98% 102%
Mar 96% 95% 96% 98% 101%
Apr 92% 94% 95% 96% 100%
May 91% 92% 93% 95% 99%
Jun 87% 88% 92% 94% 98%
Jul 87% 90% 93% 93% 98%
Aug 91% 93% 94% 95% 99%
Sep 93% 95% 95% 97% 100%
Oct 93% 95% 96% 98% 100%
Nov 95% 97% 97% 100% 102%
Dec 96% 97% 96% 99% 102%

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 3.6 percent based on data from the Energy Information Administration. 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 hydroelectric generation is its
variable and limited fuel supply.

This IRP uses an 80-year hydroelectric data record from the 2014 BPA rate case. The study provides monthly energy levels for the region over an 80-year hydrological record
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 142 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
spanning 1928 to 2009. This IRP also includes BPA hydroelectric estimates for the 80-year record for British Columbia and California.

Many IRP studies use an average of the hydroelectric record, whereas stochastic
studies randomly draw from the record, as the historical distribution of hydroelectric generation is not normally distributed. Avista does both. Figure 10.6 shows the average hydroelectric energy of 17,370 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 13,735 aMW (-21 percent) and a 90th
percentile water year of 20,340 aMW (+17 percent). AURORAXMP maps each hydroelectric plant to a load zone, creating a similar energy
shape for all plants in that load zone. For Avista’s hydroelectric plants, AURORAXMP
uses the output from its own proprietary software with a better representation of
operating characteristics and capabilities. 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 load hours; this maximizes the
value of the system consistent with actual operations.

Figure 10.6: Northwest Expected Energy

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 143 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Wind New wind resources satisfy renewable portfolio standards over the IRP timeframe.
These additions increase competition for the remaining higher-quality wind sites. Similar
to how AURORAXMP maps each hydroelectric plant to a load zone, the capacity factors
in Figure 10.7 are averages for each zone. The IRP uses capacity factors from a review of the BPA and the National Renewable Energy Laboratory (NREL) wind data sets.
Figure 10.7: Regional Wind Expected Capacity Factors

Greenhouse Gas Emissions and the Clean Power Plan
Greenhouse gas, or carbon emissions, regulation is a significant risk for the electricity
industry because of its reliance on carbon-emitting power generation. Regulation may
require the reduction of carbon emissions at existing power plants, the construction of low- and non-carbon-emitting technologies, and changes to existing resource operations. Between 2008 and 2012, carbon emissions from electricity generation have
fallen by nearly 12 percent due to reduced loads and lower coal generation levels.

Future carbon emissions could fall due to fundamental market changes. In 2014, the EPA released the draft CPP under section 111(d) of the CAA to reduce emissions from existing plants. A description of the draft CPP is in Chapter 7 – Policy Considerations.
Use of compliance measures that do not rely on emission reductions solely from
covered fossil-fueled electric generating units, such as renewable energy and energy
efficiency standards, would not necessarily preclude emission increases from certain sources, just an overall reduction in a statewide emission rate. If emissions from plants covered under section 111(d) and newly constructed plants subject to section 111(b)
are not both subjected (at some point) to the same emission rate target established
31%33%35%
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NW BC AB CA MT WY SW UT CO
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 144 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
under section 111(d), then newly constructed thermal facilities may increase emissions even when complying with 111(b)’s emission performance standard.

The Expected Case makes assumptions about state and federal greenhouse gas
emissions policies. Avista’s 2013 IRP acknowledgement from the WUTC directed the company to include a non-zero cost of carbon in the 2015 IRP. The acknowledgement indicated that by not including a risk factor for this potential cost, the portfolio decision
does not include the potential risk of the added costs. The Expected Case in this IRP
includes a 10 percent probability of $12 per metric ton beginning in 2020. Beyond 2020,
the price increases 5 percent per year. This results in a levelized 2016-2035 cost of $11.45 per metric ton, applied randomly in 10 percent of the modeled iterations.
The second carbon reduction assumption in the Expected Case is the Western
Interconnect meeting draft CPP goals by 2030. The CPP proposal was in draft form at
the time of IRP development. This regulation received the most comments on a
proposed rule in EPA history. The final rule, issued after the modeling was complete for this IRP, differs from the draft. The IRP assumes meeting CPP state-by-state goals as a
whole in the Western Interconnect by 2030. The IRP assumes certain modifications to
the goals to conform to this modeling effort, including adjustments for plants located
outside the Western Interconnect, and adjusting Idaho’s goal to account for partial-year
operation of the Langley Gulch plant. The IRP assumes the Western Interconnect must be below 801 pounds per MWh by 2030. Figure 10.8 shows adjusted state and regional
carbon intensity goals for CPP-regulated plants compared to the 2012 baseline.

Figure 10.8: 2030 Adjusted State Carbon Intensity CPP Goals

0
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1,000
1,500
2,000
2,500
West AZ CA CO ID MT NM NV OR UT WA WY
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 145 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Risk Analysis
A stochastic analysis, using the variables discussed earlier in this chapter, evaluates the
market to account for future uncertainty. It is better to represent the electricity price forecast as a range because point estimates are unlikely to reflect underlying assumptions perfectly. Stochastic price forecasts develop more robust resource
strategies by accounting for tail risk. The IRP developed 500 distinct 20-year market
futures, providing a large distribution of the marketplace illustrating 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 $24.36 per Dth between 2004 and 2014. Figure 10.9 shows average Stanfield monthly prices since January 2004. Prices retreated from 2008 highs to a monthly price of $2.26 per Dth in April 2015. Prices since 2009 are lower than
the previous five years, but continue to show volatility.

There are several methods to stochastically model natural gas prices. This study retains the method from the 2011 IRP, with mean prices shown in Figure 10.5 as the starting
point. Prices vary using historical month-to-month volatility and a lognormal distribution.

Figure 10.9: Historical Stanfield Natural Gas Prices (2004-2015)

$/Dth
$2/Dth
$4/Dth
$6/Dth
$8/Dth
$10/Dth
$12/Dth
1/
1
/
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 146 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.10 shows Stanfield natural gas price duration curves for 2016, 2025, and 2035. The chart illustrates a larger price range in the later years of the study, reflecting
less forecast certainty over time. Shorter-term prices are more certain due to additional
market information and the quantity of near term natural gas trading. Figure 10.11
shows another view of the forecast. The mean price in 2016 is $3.47 per Dth, represented by the horizontal bar, and the levelized price over the 20 years is $4.97 per MWh. The bottom and top of the bars represent the 10th and 90th percentiles. The bar
length indicates price uncertainty.

Figure 10.10: Stanfield Annual Average Natural Gas Price Distribution

0
100
200
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 147 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.11: Stanfield Natural Gas Distributions
Regional Load Variation
Several factors drive load variability. The largest short-run driver is weather. Long-run
economic conditions like the recent Great Recession tend to have a larger impact 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 with its previous practice of modeling load variation using FERC Form
714 data from 2007 to 2013 for the Western Interconnect as the basis for its analysis. Correlations between the Northwest and other Western Interconnect load areas
represent how electricity demand changes together across the system. This method
avoids oversimplifying Western Interconnect loads. Absent the use of correlations,
stochastic models may offset changes in one variable with changes in another, virtually
eliminating the possibility of broader excursions witnessed by the electricity grid. The additional accuracy from modeling loads this way is crucial for understanding wholesale
electricity market price variation. It is vital for understanding the value of peaking
resources and their use in meeting system variation.

Tables 10.5 and 10.6 present load correlations for the 2015 IRP. Statistics are relative to the Northwest load area (Oregon, Washington, and Idaho). “NotSig” indicates that no
statistically valid correlation existed in the data. “Mix” indicates the relationship was not
consistent across the 2007 to 2013 period. For regions and periods with NotSig and Mix
results, the IRP does not model correlations between the regions. Tables 10.7 and 10.8
provide the coefficient of determination values by zone.1
1 The coefficient of determination is the standard deviation divided by the average.
$/Dth
$2/Dth
$4/Dth
$6/Dth
$8/Dth
$10/Dth
$12/Dth
$14/Dth
20
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Table 10.5: January through June Load Area Correlations
Area Jan Feb Mar Apr May Jun
Alberta Not Sig Not Sig Not Sig Mix Mix Mix
Arizona 14% 34% Mix Not Sig Mix 7%
Avista 89% 82% 81% 80% 43% 51%
British Columbia 87% 86% 72% 78% 50% 31%
California Not Sig Not Sig Mix Mix Mix 30%
CO-UT-WY -16% Mix Mix -24% -3% -6%
Montana 50% 43% 65% 57% Mix 7%
New Mexico Not Sig Mix Mix Mix Mix Not Sig
North Nevada 62% 22% 7% Not Sig Mix 25%
South Idaho 77% 75% 67% Mix Mix 32%
South Nevada 37% 59% Mix Not Sig Mix 7%

Table 10.6: July through December Load Area Correlations
Area Jul Aug Sep Oct Nov Dec
Alberta Not Sig Not Sig Not Sig Not Sig Not Sig Not Sig
Arizona Not Sig Not Sig Mix -7% Mix 8%
Avista 66% 75% 65% 77% 92% 92%
British Columbia 67% 47% 18% 80% 89% 84% California 5% Not Sig Mix Not Sig Mix Not Sig CO-UT-WY -9% Mix -2% -1% 19% Mix
Montana 14% 15% 8% 7% 76% 76%
New Mexico Not Sig Not Sig Mix -21% 36% Not Sig
North Nevada 48% 61% 32% Not Sig 75% 63%
South Idaho 40% 63% 32% Mix 86% 88%
South Nevada 7% 37% Mix -22% Mix 63%

Table 10.7: Area Load Coefficient of Determination (Standard Deviation/Mean)
Area Jan Feb Mar Apr May Jun
Alberta 5.4% 4.6% 5.2% 5.0% 5.5% 6.1%
Arizona 8.8% 8.3% 8.1% 12.3% 16.5% 18.6%
Avista 10.1% 8.8% 10.2% 9.8% 9.7% 11.1%
British Columbia 9.7% 8.7% 9.4% 9.3% 9.7% 9.9%
California 10.6% 10.5% 10.5% 10.8% 12.5% 14.2%
CO-UT-WY 8.6% 8.1% 8.6% 8.6% 10.0% 14.8%
Montana 8.5% 7.3% 8.0% 7.9% 8.2% 10.5%
New Mexico 9.4% 9.1% 9.3% 10.9% 14.5% 15.9%
Northern Nevada 6.3% 6.2% 6.3% 6.4% 7.6% 10.2%
Pacific Northwest 11.0% 9.8% 10.6% 10.1% 9.6% 9.9%
South Idaho 9.5% 8.6% 9.9% 10.5% 11.6% 16.3%
South Nevada 7.3% 6.6% 7.2% 12.5% 17.8% 20.1%

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 149 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Table 10.8: Area Load Coefficient of Determination (Standard Deviation/Mean)
Area Jul Aug Sep Oct Nov Dec
Alberta 6.5% 6.2% 5.8% 5.6% 5.6% 5.5%
Arizona 16.4% 16.9% 18.1% 15.0% 8.7% 8.3%
Avista 13.9% 13.6% 11.5% 10.1% 11.1% 10.7%
British Columbia 10.8% 10.6% 10.3% 10.3% 11.3% 10.3%
California 14.9% 15.9% 16.0% 12.7% 11.2% 11.0%
CO-UT-WY 14.7% 14.3% 13.1% 9.5% 9.1% 9.3%
Montana 11.1% 10.9% 9.3% 8.4% 8.9% 9.0%
New Mexico 15.0% 14.7% 15.7% 12.2% 10.3% 10.0%
Northern Nevada 11.3% 10.9% 9.8% 6.8% 6.9% 7.3%
Pacific Northwest 11.8% 11.7% 10.8% 10.5% 12.0% 12.0%
South Idaho 12.2% 12.9% 13.5% 9.6% 10.4% 9.9%
South Nevada 17.9% 18.3% 20.0% 14.1% 7.8% 7.8%

Hydroelectric Variation Hydroelectric generation is the most commonly modeled stochastic variable in the
Northwest because historically it has a larger impact on regional electricity prices than
other variables. The IRP uses an 80-year hydroelectric record starting with the 12-
month water year beginning October 1, 1928. Every iteration starts with a randomly drawn water year from the historical record, so each water year repeats 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 does not model year-to-year correlation after studying the data and
finding a modest 35 percent year-to-year correlation over the 80-year record.
Wind Variation
Wind has the most volatile short-term generation profile of any utility-scale resource.
This makes it necessary to capture wind volatility in the power supply model to
determine the value of non-wind resources able to follow loads when wind production is varying. 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 an individual wind plant, but it
closely represents the diversity of a large number of wind farms located across a zone. 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 PRS. Therefore individual wind farm shapes form the
basis of wind resource options for Avista.
Fifteen potential 8,760-hour annual wind shapes represent each geographic region or
facility. Each year contains a wind shape drawn from these 15 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.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 150 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Avista believes an accurate representation of a wind shape across the West requires meeting several conditions:

1. Data correlated between areas using historical data.
2. Data within load areas is auto-correlated.2
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.
5. Hourly capacity factors for a diversified wind region are never greater than 90
percent due to turbine outages and wind diversity within the area.

Absent these conditions, it is unlikely any wind study provides a level of accuracy
adequate for planning efforts. Avista’s methodology, first developed for its 2013 IRP, attempts to adhere to the five conditions 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 accounts four hours with
generation levels exceeding a 90 percent capacity factor. Figure 10.12 shows a
Northwest example of an 8,760-hour wind generation profile. This example, shown in
blue, has a 31 percent capacity factor. Figure 10.13 shows actual 2014 generation
recorded by BPA Transmission; in 2014, the average wind fleet in BPA’s balancing authority had a 28.1 percent capacity factor.

2 Adjoining hours or groups of hours are correlated to each other.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 151 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.12: Wind Model Output for the Northwest Region

Figure 10.13: 2014 Actual Wind Output BPA Balancing Authority3

There is speculation a correlation exists between wind and hydroelectric generation,
especially outside of the winter months where storm events bring both rain to the river
3 Chart data is from the BPA at: http://transmission.bpa.gov/Business/Operations/Wind/default.aspx.
0%
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
system and wind to the wind farms. This IRP does not correlate wind and hydroelectric generation due to a lack of any historical wind data set large enough to test this
hypothesis. If correlation exists, it would be optimal to run the model using a large
dataset of historical wind and water years.

Forced Outages Most deterministic market modeling represents generator-forced outages with an
average reduction to maximum capability. This over simplification represents expected
values well; however, it is better to represent the system more accurately in stochastic
modeling by randomly placing non-hydroelectric units out of service based on a mean time to repair and on an average forced outage rate. Internal studies show 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 under 100 MW on forced outage do
not have a material impact on market prices and therefore their outages do not require
stochastic modeling. Forced outage rates and mean time to repair data for the larger
units in the Western Interconnect come from analyzing the North American Electric
Reliability Corporation’s Generating Availability Data System database, also known as
GADS.

Market Price Forecast
An optimal resource portfolio cannot ignore the extrinsic value inherent in its resource
choices. The 2015 IRP simulation compares each resource’s expected hourly output
using forecasted Mid-Columbia hourly prices over 500 iterations of Monte Carlo-style scenario analysis.
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 another zone to
the modeled zone. 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 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 Avista, 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 different assumptions
from the Expected Case or with changes to 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, and the resultant impact on individual and portfolios of resources. These
analyses include 500 iterations of varying natural gas prices, loads, hydroelectric
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
generation, thermal outages, and wind generation shapes. The IRP includes three stochastic studies—the Expected Case, a case with the social cost of carbon, and a
benchmarking case excluding a cost of carbon.

Mid-Columbia Price Forecast The Mid-Columbia market is Avista’s primary electricity trading hub. The Western Interconnect also has major trading hubs at the California/Oregon Border (COB), Four
Corners, in the northwestern corner of New Mexico, Palo Verde in central Arizona, SP-
15 in southern California, NP-15 in northern California, and Mead in southern Nevada.
The Mid-Columbia market is usually the lowest cost because of the significant amount of hydroelectric generation assets at the hub, 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 study 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 2016 and 2035. The analysis used 29 central processing units (CPUs) linked to a SQL server, creating over 45 GB of data in 3,000
CPU-hours.

Figure 10.14 shows the Mid-Columbia stochastic market price results with horizontal
bars representing the 10th to 90th percentile range for annual prices, the diamonds show the average prices, and the arrows represents the 95th percentile. The 20-year nominal
levelized price is $38.48 per MWh. Table 10.9 shows the annual averages of the
stochastic case on-peak, off-peak, and levelized prices. Spreads between on- and off-
peak prices average $7.78 per MWh over 20 years. The 2013 IRP annual average
nominal price was $44.08 per MWh. The reduction in pricing is a result of lower natural gas prices, lower loads, and higher percentages of new lower-heat-rate natural gas
plants.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 154 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.14: Mid-Columbia Electric Price Forecast Range

Table 10.9: Annual Average Mid-Columbia Electric Prices ($/MWh)

2016 25.87 21.62 29.05
2017 27.27 23.03 30.47
2018 29.59 25.18 32.90
2019 31.40 26.83 34.82
2020 33.25 28.94 36.48
2021 34.54 30.21 37.79
2022 36.05 31.70 39.30
2023 36.43 32.17 39.64
2024 38.60 34.27 41.85
2025 39.42 35.18 42.59
2026 43.12 38.80 46.36
2027 44.72 40.23 48.08
2028 46.48 42.09 49.79
2029 48.01 43.51 51.39
2030 48.79 44.32 52.14
2031 51.23 46.52 54.76
2032 53.90 48.98 57.58
2033 54.98 49.95 58.74
2034 57.77 52.65 61.64
2035 59.33 54.12 63.24
$/MWh
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
Greenhouse Gas Emission Levels Greenhouse gas levels decline as natural gas prices decrease and coal plants react by
dispatching for fewer hours in the year or retire. This IRP includes a 10 percent
probability of a carbon price and includes reductions consistent with EPA’s CPP goal for
2030. This forecast also includes cap-and-trade costs in California and carbon taxes in the Canadian provinces. Further discussion of carbon policy is in Chapter 7 – Policy Considerations. Figure 10.15 shows historic and expected greenhouse gas emissions
for the Western Interconnect. Greenhouse gas emissions from electricity generation
decrease 6.4 percent between 2016 and 2035, and 2016 is 12 percent lower than 2012.
The figure also includes 10th and 90th percentile statistics from the 500-iteration dataset. The higher and lower bands show where emissions could land depending on changes in hydroelectric generation, load, resource availability, and other factors. The reduction
drivers are lower load forecasts, lower natural gas prices, higher RPS requirements in
some states, and forecasted coal-fired generation retirements due to federal and state
regulations, and carbon pricing. Further, emissions from plants covered under the CPP
fall by 28 percent as shown in the green line, but new plants emissions covered under the CPP offset much of this reduction.

Figure 10.15: Western States Greenhouse Gas Emissions
Figure 10.16 illustrates the Expected Case emissions rate for EPA regulated plants
compared to EPA’s draft CPP goal for each year. The Expected Case estimates the
west will meet the 2030 goal by 2026; by 2035, the 681 lbs/MWh result is well below the
801 lbs/MWh CPP draft goal. Certain states, including Arizona, Colorado, Washington,
and Wyoming, likely will exceed the goal while other states witness falling emissions. See Figure 10.17. If the final rule implements as the draft proposal, these state will need
to take additional action, as described later in this chapter.

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.16: EPA’s CPP Annual Emissions Intensity for the West

Figure 10.17: EPA’s CPP 2030 State Goal vs. Modeling Result

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 157 of 212
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Avista Corp 2015 Electric IRP
Resource Dispatch State-level RPS goals and greenhouse gas regulations change resource dispatch
decisions and affect future power prices. The Northwest already is witnessing the
market-changing effects of a more than 7,750 MW wind fleet. Figure 10.18 illustrates
how natural gas will increase its contribution as a percentage of Western Interconnect generation, from 28 percent in 2016 to 42 percent 2035. The increase offsets coal-fired generation, with coal dropping from 22 percent in 2016 to 10 percent in 2035. Utility-
owned solar and wind generation increase from 9 percent in 2016 to 14 percent by
2035. New renewable generation sources also reduce coal-fired generation, but natural
gas-fired generation is the primary resource meeting load growth. Public policy changes encouraging renewable energy development may reduce
greenhouse gas emissions on a market scale, 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). Stranded coal plant investments may increase the
overall cost of electricity. 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 higher than otherwise retail rates absent
greenhouse gas reduction policies.

Figure 10.18: Base Case Western Interconnect Resource Mix

Nuclear
Hydro
Other
Coal
Wind
Solar
Natural Gas
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 158 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Scenario Analysis
Scenario analysis evaluates the impact of changes in underlying market assumptions,
Avista’s generation portfolio and new generation resource options’ values. In addition to the Expected Case, this IRP includes three stochastic analyses. The Benchmark Case removes the carbon price and relaxes assumptions on meeting draft CPP goals. This
scenario provides data to calculate the impact of the environmental policies in the
Expected Case. The second scenario assumes all four Colstrip units retire by the end of
2026. This scenario uses a portfolio study to estimate impacts of an early closure at Colstrip. The third scenario looks at the added costs and associated reductions in greenhouse gas emissions if the social cost of carbon was included in the market price
analysis. Deterministic studies model impacts of state-by-state draft CPP compliance.

Benchmark Scenario The Benchmark Scenario removes the carbon adder in 2020 and relaxes assumptions in meeting the draft CPP targets. The flat levelized price for this scenario is $38.12 per
MWh, or a reduction of $0.39 per MWh from the Expected Case. Figure 10.19 shows
annual flat prices compared to the Expected Case. This scenario’s prices are similar to
the Expected Case. The levelized cost of the carbon adder in the Expected Case is $1.15 per metric ton. While the emissions penalty was small in this case, Western Interconnect emissions increase 2.3 percent by 2035. This scenario shows that the
lower emissions of the Expected Case are relatively modest, at a levelized $30 million
each year for the Western Interconnect. Figure 10.20 shows annual greenhouse gas
emissions for the Western Interconnect in the Benchmark Scenario.

Figure 10.19: Annual Mid-Columbia Flat Price Forecast Benchmark Scenario

$/MWh
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
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Avista Corp 2015 Electric IRP
Figure 10.20: Benchmark Scenario Annual Western U.S. Greenhouse Gas Emissions

No Colstrip Scenario
The No Colstrip Scenario models the implications of retiring Colstrip. The scenario
values new resource options and the remaining portfolio in a marketplace without Colstrip. In addition, this scenario provides data about the regional financial impacts of a
Colstrip closure, rather than just the impact to Avista from divestment of its share. This
scenario assumes the site redevelops with several large CCCT plants upon retirement
in 2026. It does not attempt to represent the feasibility of this assumption, but rather
helps understand the impacts to the overall market place by replacing Colstrip with a CCCT. Without Colstrip, regional market prices increase slightly as shown in Figure
10.21. There are small differences beginning in 2027 with a $0.93 per MWh annual
average price difference. While these price changes are not large, it assumes the
average price over a year in average water conditions. At times, the price impacts are
much greater. Further, without replacement capacity, price impacts and reliability concerns increase. Beginning in 2027, the annual cost to all western customers
increases by $651 million with the closure of Colstrip, or 2.6 percent, in the No Colstrip
scenario. Without Colstrip, greenhouse gas emissions should decrease; in 2035
emissions in this scenario were 3.2 percent lower, or nearly 9.3 million metric tons per
year, as shown in Figure 10.22. Given the increased cost and associated emissions reductions, the implied price of carbon reduction at Colstrip is $74.17 per metric ton in 2027; the average price between 2027 and 2035 is $73.18 per metric ton.

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 160 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.21: Annual Mid-Columbia Flat Price Forecast Colstrip Retires Scenario

Figure 10.22: No Colstrip Scenario Annual Western U.S. Greenhouse Gas Emissions

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Colstrip Retires
Expected Case
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 161 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Social Cost of Carbon Scenario For the past several IRPs Avista has conducted carbon emission pricing scenarios. For
this IRP, the TAC recommended a Social Cost of Carbon case. The Social Cost of
Carbon study uses data from an EPA study. The prices from this study have different
ranges depending on the discount rate assumed and the point on the probability curve. Avista chose the 5 percent discount rate study with a starting price of $11 per metric ton in 2010 (2007 dollars). Figure 10.23 shows the nominal prices per metric ton. The
levelized price is $19.31 per metric ton, approximately 18 times the carbon cost
assumed in the Expected Case. These prices do not vary in each of the 500 iterations.
With a Social Cost of Carbon adder, the impact to Mid-Columbia prices is more apparent. The levelized price increases to $45.46 per MWh, or 18 percent higher than
the Expected Case, as shown in Figure 10.24. The added pricing to emissions also
increases power costs by $3.6 billion annually (17.2 percent) across the U.S. west. In
exchange for the added costs, emissions fall 9.6 percent or 25 million metric tons by
2035. See Figure 10.25.

Figure 10.23: Social Cost of Carbon Scenario Emission Prices

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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 162 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.24: Annual Mid-Columbia Flat Price Forecast Social Cost of Carbon Scenario

Figure 10.25: Social Cost of Carbon Scenario Western US Greenhouse Gas Emissions

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Social Cost of Carbon
Expected Case
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 163 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Clean Power Plan Scenarios The 2015 IRP analyzes implications of the draft CPP by first looking at its requirements
on a state-by-state compliance basis instead of a regional basis as is assumed in the
Expected Case. This scenario was studied on a deterministic basis rather than the full
500 stochastic iterations, because some of the stochastic variables have a large impact on emissions. Because emissions are highly dependent on some of the stochastic assumptions – for example, streamflows affect hydroelectric generation – a low water
year is tested. To meet the 2020 draft CPP goal, each state would have to change its
system. Any planned coal retirement beyond 2020 would accelerate to 2019. Some
states would need to increase conservation and renewable resource acquisitions. Many states may need to implement a carbon emissions price. Northwest states would require a carbon price of $1.25 per short ton in an average water year to reduce emissions,
even with the early closure of Centralia 1 & 2 and Boardman by the end of 2019. Other
states, such as Colorado and Arizona, would require prices near $20 per short ton.

Figure 10.26 shows the Mid-Columbia flat annual price in the state-by-state compliance scenario. The levelized price is $39.06 per MWh, 1.6 percent higher than the Expected
Case’s deterministic study. This is not a large increase because the average price of
carbon across the west is actually lower than in the Expected Case, but since fewer
coal resources are available, the price is higher. In 2020, the year with the largest price
change, the difference is $1.59 per MWh, an increase of 4.7 percent.
Figure 10.26: Draft CPP as Proposed Scenario Flat Mid-Columbia Electric Prices

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111(d)
Expected Case (Deterministic)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 164 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
The cost of the Western electrical system requires review to understand the impacts of a state-by-state draft CPP scenario. Levelized cost increases $342 million per year (1.7
percent), and cost is $1.2 billion (7.6 percent) in 2020. This added cost reduces
emissions from the Expected Case by 19 percent in 2020 and 9 percent in 2035, as
shown in Figure 10.27. The reduction from the Expected Case comes from earlier retirement of coal resources. Reductions toward the end of the study are from additional renewable resources and higher carbon emission prices. Emissions increase because
increased conservation offsets the need to reduce emissions from generation.
The draft CPP significantly affects the timing of new resources to replace retired coal plants. It would require carbon pricing unless using other CPP building blocks. These
issues are minimal compared to a low water year in the Northwest. In low water years,
decreased hydroelectric production requires the region’s natural gas and coal-fired
resources to dispatch more and reduces regional exports and associated revenues.

Figure 10.27: Draft CPP as Proposed Scenario Western Greenhouse Gas Emissions

A low water year environment requires higher carbon prices to reduce emissions
compared to the average water year. To test this hypothesis, this study uses the water conditions from 1941 to represent a lower 10th percentile water year. In this case, the
carbon prices required for the Northwest states are:

 Washington: $18/ton (2020), $18/ton (2030)
 Oregon: $19/ton (2020), $15/ton (2030)
 Idaho: $23/ton (2020), $14/ton (2030)
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111d Proposed
Expected Case
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 165 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
The required carbon price changes as the amount of conservation increases, lowering the reliance on the remaining generating fleet to meet the draft CPP goal. The cost
impact of this regulation in a lower water year can also be very high if the water
conditions are less than average beginning in 2020. For example, Figure 10.28
demonstrates the financial impact of the low water year; in 2020, the costs are $1.6 billion higher, or 9 percent, as compared to a low water year without the draft CPP requirement. In 2030, as conservation ramps up and if a poor water year occurs, the
added costs decrease to $137 million or 0.4 percent higher. Electricity market prices at
the Mid-Columbia also have similar impacts. Figure 10.29 illustrates the increases of the
draft CPP in the 1941 water year and illustrates increases in prices compared to the average water year from the Expected Case. In 2020, the added regulation increases prices by $6.10 per MWh, or 17 percent, compared to the case without the regulation in
the poor water year. The impact decreases to approximately 5 percent in 2035. Given
that the future timing of low water years is unknown, the levelized price impact of $4.76
per MWh (10.3 percent) is the best indicator of the added price to the Northwest market.

Figure 10.28: Draft CPP as Proposed Scenario 1941 Water Year Annual Costs

$1.6 $1.3 $1.2 $1.1 $1.1 $0.9 $0.6 $0.6 $0.3 $0.3 $0.3 $0.2 $0.1 $0.1 $0.1 $0.1
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Expected Case Water Year 1941
111(d) as Proposed Water Year 1941
Cost Difference
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 166 of 212
Chapter 10- Market Analysis
Avista Corp 2015 Electric IRP
Figure 10.29: CPP as Proposed 1941 Water Year Scenario Mid-Columbia Electric Prices

$/MWh
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Expected Case (Deterministic)
Expected Case (1941)
111d Proposal (1941)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 167 of 212

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 168 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-1

11. Preferred Resource Strategy

Introduction
This chapter describes potential costs and financial risks of the new resource and
conservation strategy Avista plans to meet future requirements over the next 20 years.
It explains the decision making process used to select the PRS, and the resulting
avoided costs used to target future conservation.
The 2015 PRS describes a reasonable low-cost plan along the efficient frontier of
potential resource portfolios accounting for fuel supply, regulatory, and price risks. Major
changes from the 2013 plan include modestly less energy efficiency, the elimination of
demand response, and the elimination of a natural gas-fired peaking plant. The plan
also calls for upgrades to Avista’s thermal generating fleet. The strategy’s lower energy efficiency acquisition is due to lower market prices and increased codes and standards reducing some of the need for utility-sponsored acquisition. The reduction in natural
gas-fired resources results primarily from a lower retail load forecast. Demand response
is no longer in the PRS, as a third-party study found costs to be much higher than
estimated in the 2013 IRP. Like the prior plan, upgrades at certain existing facilities look attractive as a resource alternative. Overall, the 2015 PRS performs better against the efficient frontier than the 2013 strategy.

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. Natural gas-fired plants replaced it. See Figure 11.1. Since the Centralia sale, Avista has made several generation acquisitions and
upgrades, including:

 25 MW Boulder Park natural gas-fired reciprocating engines (2002);
 7 MW Kettle Falls natural gas-fired CT (2002);
 35 MW Stateline wind power purchase agreement (2004 – 2014);
 56 MW (total) hydroelectric upgrades (through 2012);
 270 MW natural gas-fired Lancaster Generation Station tolling agreement
(2010 – 2026);
 105 MW Palouse Wind power purchase agreement (2012 – 2042); and
 16 MW Nine Mile Falls Upgrade (2016)
Section Highlights




Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 169 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-2

Figure 11.1: Resource Acquisition History

Resource Deficiencies
Avista uses a single-hour and an 18-hour peak event methodology to measure resource
adequacy. The 18-hour methodology assures energy-limited hydroelectric resources
can meet multiday extreme weather events.
Avista considers the regional power surplus in its planning, consistent with the NPCC’s
forecast, and does not intend to acquire long-term generation assets while the region is
significantly surplus. Current NPCC research indicates the region is long on capacity
through 2020 during the winter and forecasts no summer resource deficits.
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 2021.1 See Figure 11.2 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.

1 Chapter 6 – Long-Term Position contains details about Avista’s peak planning methodology.

1,100
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 170 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-3

Figure 11.2: 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.

Avista expects to meet or exceed its EIA 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 REC purchases.2 Table 11.1
provides a list of the qualifying generation projects and the associated expected output.
Figure 11.3 shows the forecast REC positions. The flexibility included in the EIA to use
RECs from the current year, from the previous year, or from the following year for
compliance, mitigates year-to-year variability in the output of qualifying renewable resources.

2 The RECs from Wanapum are not in WREGIS and are currently ineligible under the EIA requirements
for investor-owned utilities, but Avista is working with Grant County PUD to qualify the energy.
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Summer 18 Hour Peak (MW)
Annual Energy (aMW)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 171 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-4

Table 11.1: Qualifying Washington EIA Resources

Kettle Falls GS3 Biomass 1983 47.0 374,824 281,118 Long Lake 3 Hydro 1999 4.5 14,197 14,197
Little Falls 4 Hydro 2001 4.5 4,862 4,862
Cabinet Gorge 3 Hydro 2001 17.0 45,808 45,808
Cabinet Gorge 2 Hydro 2004 17.0 29,008 29,008
Cabinet Gorge 4 Hydro 2007 9.0 20,517 20,517
Wanapum Hydro 2008 0.0 22,206 22,206
Noxon Rapids 1 Hydro 2009 7.0 21,435 21,435
Noxon Rapids 2 Hydro 2010 7.0 7,709 7,709
Noxon Rapids 3 Hydro 2011 7.0 14,529 14,529 Noxon Rapids 4 Hydro 2012 7.0 12,024 12,024 Palouse Wind Wind 2012 105.0 349,726 419,671 Nine Mile 1 & 2 Hydro 2016 4.0 11,826 11,826

Figure 11.3: REC Requirements vs. Qualifying RECs for Washington State EIA

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
3 The Kettle Falls Generation Station becomes EIA qualified beginning in 2016. Clarification about old
growth fuel is required to determine the amount of energy to qualify for the law.
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Requirement
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 172 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-5

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 generation portfolio. 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 PRiSM in 2002 to support resource decision
making in the 2003 IRP. Various enhancements over the years have improved the
model. PRiSM uses a mixed integer programming routine to support complex decision
making with multiple objectives. These 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 EIA requirements
2. Costs to serve future retail loads 3. Existing resource and conservation contributions
o Operating margins
o Fixed operating costs
4. Resource and conservation 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 25 years more than the later years to highlight the importance
of nearer-term decisions. Equation 11.1 shows a simplified view of the PRiSM linear
programming objective function.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 173 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-6

Equation 11.1: PRiSM Objective Function
Minimize: (X1 * NPV2016-2040) + (X2 * NPV2016-2065)

Where: X1 = Weight of net costs over the first 25 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.4

An efficient frontier captures the optimal resource mix graphically given varying levels of cost and risk. Figure 11.4 illustrates the efficient frontier concept.
Figure 11.4: Conceptual Efficient Frontier Curve

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. No best point on the curve exists, but Avista prefers points where small incremental cost additions
offer large risk reductions. Portfolios to the left of the curve are more desirable, but do
not meet the planning requirements or resource constraints. Examples of these
constraints include environmental costs, regulation, and the availability of commercially
viable technologies limit utility-scale resource options. 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.5 Instead, it uses the market to balance short-term
gaps and adds resources in sizes equal to the project sizes Avista could actually obtain.
4 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. 5 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-17-01 S. Kinney, Avista
Schedule 1, Page 174 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-7

Constraints As discussed earlier in this chapter, reflecting real-world constraints in the model is
necessary to create a realistic representation of the future. Some constraints are
physical and others are societal. The major resource constraints are capacity and
energy needs, Washington’s EIA, and greenhouse gas emissions performance standard.
The PRiSM model selects from conservation, combined- and simple-cycle natural gas-
fired combustion turbines, natural gas-fired reciprocating engines, wind, solar, storage
batteries, and upgrades to existing thermal and hydroelectric resources. 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 consists of natural gas-fired
peaking resources. Portfolios with less risk replace some of the natural gas-fired peaking resources with wind generation, other renewables, combined cycle natural gas-
fired plants and/or coal-fired resources. Past IRPs identified resource strategies
including all of these risk-reducing resources. Added environmental and legislative
constraints reduce the number of resource choices available to reduce future costs
and/or risks.
Preferred Resource Strategy
The 2015 PRS consists of existing thermal resource upgrades, energy efficiency, natural gas-fired peakers, and a natural gas-fired CCCT. A list of planned acquisitions is
in Table 11.2 and a graphic is in Figure 11.5. The first resource acquisition is 96 MW of
natural gas-fired peaking technology by the end of 2020. This resource acquisition fills
the capacity deficit created by the expiration of the 82-MW WNP-3 contract with the BPA, the expiration of a 28 MW Douglas County PUD contract for a portion of its Wells hydroelectric facility, and load growth. In this IRP evaluation, frame technology CTs are
the preferred gas-fired peaking technology. Given the relatively small cost differences
between the evaluated natural gas-fired peaker technologies, the future technology
decision will be determined in an RFP. Technological changes in efficiency and flexibility may mean the Avista will need to revisit this resource choice closer to the actual need. Since the long-term need is more than five years out, Avista will not
release an RFP in the next two years, but will begin a process to evaluate technologies
and potential locations prior to a RFP release, likely following the 2017 IRP.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 175 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-8

Table 11.2: 2015 Preferred Resource Strategy
Resource By the End of
Year
ISO Conditions
(MW)
Winter Peak
(MW)
Energy
(aMW)
Natural Gas Peaker 2020 96 102 89
Thermal Upgrades 2021-2025 38 38 35
Combined Cycle CT 2026 286 306 265
Natural Gas Peaker 2027 96 102 89
Thermal Upgrades 2033 3 3 3
Natural Gas Peaker 2034 47 47 43
Total 565 597 524
Efficiency
Improvements
Acquisition
Range
Winter Peak
Reduction
(MW)
Energy
(aMW)
Energy Efficiency 2016-2035 193 132
Distribution Efficiencies <1 <1
Total 193 132

Figure 11.5: New Resources Meets Winter Peak Loads
The next resource acquisitions in the PRS are upgrades to Avista’s thermal fleet. These
upgrades may be cost effective earlier depending upon negotiations with vendors. The
proposed 286 MW CCCT replaces the Lancaster tolling agreement expiring in October
2026. Avista could renegotiate the current agreement or find other mutual terms to
retain the plant for customers. If Avista does not retain Lancaster, it would need to build or procure a similar-sized natural gas-fired unit. The new plant size could meet future
-
500
1,000
1,500
2,000
2,500
20
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6
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9
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0
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20
3
5
Me
g
a
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a
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s
Thermal Plant Upgrade NG Peaker
NG Combined Cycle CT Existing Resources
Load w/ Conservation + Cont.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 176 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-9

load growth needs and delay or eliminate the need for later 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. More information and
replacement costs will be discussed in future IRPs as 2026 approaches.
The 2015 PRS is moderately different from the 2013 resource strategy shown in Table 11.3. Avista’s capacity needs have changed since the prior plan. The first need for new
resources has moved out one year, as Avista won an auction to purchase a share of the
output from Chelan County PUD’s hydroelectric projects. Lower loads compared to the
prior plan and new upgrade options eliminate the need for one of the peakers forecasted in the prior plan.
Table 11.3: 2013 Preferred Resource Strategy

Resource By the End of
Year
ISO Conditions
(MW)
Winter Peak
(MW)
Energy
(aMW)
Simple Cycle CT 2019 83 86 76 Simple Cycle CT 2023 83 86 76
Combined Cycle CT 2026 270 281 248
Simple Cycle CT 2023 83 86 76
Rathdrum CT Upgrade 2028 6 2 5
Simple Cycle CT 2032 50 52 46
Total 575 594 527
Efficiency
Improvements
Acquisition
Range
Winter 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

Energy Efficiency
Energy efficiency is an integral part of the PRS. It also is a critical component of the EIA
requirement for utilities to obtain all cost effective energy efficiency at below 110 percent
of generation alternative costs. Avista now models energy efficiency and supply side
options in a single optimization, a change from prior practice. This enhancement allows PRiSM to select different conservation amounts along the efficient frontier instead of
one acquisition strategy across the entire curve.

Figure 11.6 shows the annual PRS conservation additions from the optimization
compared to the third party CPA. The PRiSM model selected nearly identical conservation quantities each year and in total (132.5 aMW with PRiSM versus 132.1
with the CPA). Figure 11.7 shows the difference between the load forecast with and
without conservation. The 132 aMW of energy savings (including losses) represents 52
percent of potential load growth. Please refer to Chapter 5 – Energy Efficiency and
Demand Response for a detailed discussion of energy efficiency resources. That chapter identifies 124.5 aMW, which is the 132 aMW minus 6 percent for losses.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 177 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-10

Figure 11.6: Energy Efficiency Annual Expected Acquisition Comparison6

Figure 11.7: Load Forecast with and without Energy Efficiency

6 Figure 11.6 includes 6.1 percent energy losses.
0
15
30
45
60
75
90
105
120
135
150
0
1
2
3
4
5
6
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8
9
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PRiSM
CPA
Cumulative PRiSM
-
200
400
600
800
1,000
1,200
1,400
20
1
6
20
1
7
20
1
8
20
1
9
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2
0
20
2
1
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2
2
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2
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2
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2
6
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2
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8
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2
9
20
3
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20
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1
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20
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20
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4
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M
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Net Load Forecast w/ Conservation
Expected Case Load Forecast w/o Conservation
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 178 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-11

Grid Modernization Distribution feeder upgrades entered the PRS for the first time in the 2009 IRP. The grid
modernization process began with the Ninth and Central feeder in Spokane. The
decision to rebuild a feeder considers energy, operation and maintenance savings, the
age of installed equipment, reliability indexes, and the number of customers on the feeder. System reliability, instead of energy savings, generally drives feeder rebuild decisions. Therefore, feeder upgrades are no longer included as resource option in
PRiSM. A broader discussion of Avista’s feeder rebuild program is in Chapter 8.

Natural Gas-Fired Peakers Avista plans to locate 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 for gas-fired generation. Locations in
Washington have higher generation costs because of natural gas fuel taxes and carbon
mitigation fees. However, Washington locations may benefit from their proximity to
natural gas pipelines and Avista’s transmission system, lower project elevations with higher on-peak capacity contributions per investment dollar, and potential for water
rights to cool the facility more efficiently relative to air-cooled options. 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 rights for cooling water. A 2013 IRP Action Item was identification of a location for a future natural gas resource. Avista has studied
potential locations and concluded a site in Northern Idaho best fits customer needs.
Avista has yet to determine if a brownfield or a greenfield site is best. Given Avista’s
extended surplus position until the end of 2020, it will defer the decision while continuing
to pursue and evaluate sites.
Avista is not specifying a preferred peaking technology until a competitive bidding
process is completed. Given current assumptions, the resource strategy would include a
Frame CT machine. Tradeoffs will occur between capital costs, size, operating
efficiency, and flexibility. Relative to other natural gas-fired peaking facilities, 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. Advances in natural gas-fired reciprocating engines are
also of interest. These resources utilize a group of smaller units to reduce the risk of a
larger single plant breaking down, have low heat rates, and are highly flexible, but they can be more expensive than other technologies. Given the expected number of
operating hours, 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 plant or reciprocating engines preferable. Avista has enough resource flexibility
to meet customer needs to drive the strategy towards a lower cost peaker option, but energy imbalance markets may provide enough revenues for a flexible peaker to offset
the higher costs.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 179 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-12

Greenhouse Gas Emissions Chapter 10 – Market Analysis, discusses how greenhouse gas emissions decrease due
to coal plant retirements across the Western Interconnect. Avista’s projected resource
mix does not include any retirements due to current or proposed environmental
regulations. The only significant carbon emitting lost resource is the expiration of the Lancaster PPA in 2026. Figure 11.8 presents Avista’s expected greenhouse gas emissions (excluding Kettle Falls Generating Station) with the addition of 2015 PRS
resources. Emissions should not change significantly prior to 2019 other than from year-
to-year fluctuations resulting from maintenance outages, market fluctuations, and
regional hydroelectric generation levels. Beginning in 2019, additional emissions will come from new peaking resources, but these resources will not affect overall emissions levels much due to low projected use. The estimates in Figure 11.8 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 remain around 0.27 metric tons per MWh with the current resource mix
and the new generation identified in the PRS.

Figure 11.8: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions

Capital Spending Requirements
This IRP assumes Avista will finance and own all new resources. This may or may not
be the result of competitive acquisition processes, but the overall result is unchanged by
assumed ownership structure. Using this assumption, and the resources identified in the
2015 PRS, the first capital addition to rate base is in 2021 for the first natural gas-fired peaker. The development is likely to begin years earlier, but would likely enter rate base
-
0.13
0.25
0.38
0.50
Mil
1 Mil
2 Mil
3 Mil
4 Mil
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
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4
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20
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20
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20
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20
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20
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Expected Total
Metric Tons per MWh
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 180 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-13

January 1, 2021. Avista may begin making major capital investments for the addition in 2018 or earlier. The capital cash flows in Table 11.4 include AFUDC, transmission
investments for generation, tax incentives, and sales taxes. Over the 20-year IRP
timeframe, $682 million (nominal) in generation and related transmission expenditure is
required to support the PRS. A separate tariff rider funds energy efficiency.

Table 11.4: PRS Rate Base Additions from Capital Expenditures
(Millions of Dollars)
Year Investment Year Investment
2016 0.0 2026 8.2
2017 0.0 2027 398.9
2018 0.0 2028 98.7
2019 0.0 2029 0.0
2020 0.0 2030 0.0
2021 89.4 2031 0.0
2022 0.0 2032 0.0
2023 0.0 2033 0.0
2024 3.0 2034 4.2
2025 12.1 2035 68.1
2016-25 Total 104.5 2026-35 Totals 578.0

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 provide a range of expected costs to serve future
loads. Figure 11.9 shows expected PRS costs through 2035 as the blue bar. In 2016,
costs are $26 per MWh. The chart shows a two-sigma cost range. Yellow diamonds represent the lower range and orange triangles represent the upper range. The main
driver increasing power supply costs and volatility in future years is natural gas prices
and weather, which affects both hydroelectric generation levels and load variability.
Avista increases the volatility assumption of future natural gas prices, as the commodity
price has unknown future risks and a history of volatility.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 181 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-14

Figure 11.9: Power Supply Expense Range

Near Term Load and Resource Balance
Under Washington regulation (WAC 480-107-15), utilities expecting supply deficits
within three years of an IRP filing must file a RFP with the WUTC within 135 days after
filing the IRP. After WUTC approval, bids to meet the anticipated capacity shortfall are
issued within 30 days. In the 2013 IRP, an Action Item committed Avista to develop a short-term capacity load and resource balance tool to monitor temporarily short
positions. Shortly after the filing of the 2013 plan, a Capacity Report was completed and
is consulted prior to the heating and cooling seasons. Chapter 6 – Long-term Position
discussed small deficits in 2015 and 2016. The company’s power supply department
filled those deficits due to monitoring of the Capacity Report. Table 11.5 shows the latest position with the 2016 short-term capacity positions closed with market
purchases. In Table 11.6, the summer position is long in each of the next four years. As
described in Chapter 6, the region is long on summer capacity. Given this circumstance,
Avista is not planning to hold capacity for a planning margin and will utilize the surplus
in the wholesale market to meet load in extreme weather conditions or extended plant outages.
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
6
20
1
7
20
1
8
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20
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20
2
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 182 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-15

Table 11.5: Avista Medium-Term Winter Peak Hour Capacity Tabulation
2016/17 2017/18 2018/19 2019/20 Load Obligations 1,718 1,725 1,737 1,748
Other Firm Requirements 239 89 59 8
Reserves Planning 376 374 376 381
Total Obligations 2,333 2,188 2,172 2,137

Firm Power Purchases 206 164 162 31
Owned & Contracted Hydro 1,014 1,029 996 1,001
Thermal & Storage Resources 1,137 1,142 1,142 1,141 Wind (at Peak) 0 0 0 0
Total Resources 2,357 2,335 2,300 2,173

Net Position 24 147 128 36

Table 11.6: Avista Medium-Term Summer 18-Hour Sustained Peak Capacity Tabulation
2016 2017 2018 2019 Load Obligations 1,515 1,529 1,542 1,554
Other Firm Requirements 189 89 89 59
Reserves Planning 165 164 166 166
Total Obligations 1,869 1,782 1,797 1,779

Firm Power Purchases 68 68 51 49
Owned & Contracted Hydro 823 818 806 781
Thermal Resources 984 988 988 988
Wind (at Peak) 0 0 0 0
Total Resources 1,875 1,874 1,845 1,818

Net Position 6 92 48 39

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 range of risk
levels. The PRS analyses examined the following portfolios.
 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 year-on-year portfolio cost variability.
 Efficient Frontier: Meets all capacity, energy, and RPS requirements met with
sets of intermediate portfolios between the least risk and least cost options.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 183 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-16

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 given current information.

Figure 11.10 presents the Efficient Frontier in the Expected Case. 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 2027. It is necessary to move far enough into the future so load growth
provides PRiSM the opportunity to make new resource decisions. The year 2027 is far
enough into the future to account for the risk tradeoffs of several resource decisions.
Using an earlier year to measure risk would have too few new resource decisions
available to distinguish between portfolios.
Avista is not choosing to pursue the absolute least cost strategy in this IRP, as it relies
exclusively on natural gas-fired peaking facilities. A peakers-only strategy would include
more market risk than exists in the present portfolio because the portfolio would trade
diversity of the Lancaster CCCT for another peaker. Selecting the appropriate point on the efficient frontier is not solvable through a mathematical formula.

Figure 11.10: Expected Case Efficient Frontier

$20 Mil
$30 Mil
$40 Mil
$50 Mil
$60 Mil
$70 Mil
$80 Mil
$90 Mil
$350 Mil $400 Mil $450 Mil $500 Mil $550 Mil
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Least Cost
Preferred Resource Strategy
Least Risk
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 184 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-17

In the WUTC’s 2013 IRP acknowledgement, the Commission asked Avista to evaluate the value of risk mitigation among competing resource strategies and provide
justification for its selection of the PRS over other portfolios along the efficient frontier.
Avista investigated several methods of measuring the benefits and costs of each
portfolio along the efficient frontier. Economic theory indicates all points on the curve are the best portfolio for a given level of risk. Academic research suggests users of efficient frontiers develop indifference curves to overlay against the efficient frontier to
help select the appropriate portfolio strategy. After researching this concept, it is no
different from finding what level of risk reduction a manager is accepting for each level
of risk. Avista investigated two other analytical methodologies to evaluate each portfolio along the efficient frontier: risk adjusted PVRR and point-to-point derivatives.
The first step calculates risk adjusted PVRR for each portfolio. This calculation is the net
present value of the future revenue requirements, plus the present value of taking each
of the future year’s tail risk, calculated by 5 percent of the 95th percentile’s increase in
costs. This methodology assumes the lowest NPV should yield the best strategy. Figure 11.11 shows the results of this study of the efficient frontier. The lowest cost scenario,
including tail risk, is the Least Cost portfolio. This Risk-Adjusted PVRR methodology
suggests the Least Cost strategy would be the best choice. Before making this decision,
Avista considered additional analyses, given that this strategy built 527 MW of 11,000
Btu/kWh heat rate peakers. The strategy increases exposure to a potentially volatile power and natural gas market as compared to today’s portfolio.

Figure 11.11: Risk Adjusted PVRR of Efficient Frontier Portfolios

$ Bil
$1 Bil
$2 Bil
$3 Bil
$4 Bil
$5 Bil
$6 Bil
Le
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Efficient Frontier Porfolios
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 185 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-18

To illustrate this risk and the benefits of the PRS, Avista employed a second method. It calculates point-to-point derivatives by analyzing the slope of the change in cost relative
to the change in costs. In this case, a greater slope indicates increasing benefits for
trading off risk reduction for higher portfolio costs; a higher slope indicates a better
tradeoff between cost and risk. Figure 11.12 illustrates the results of this study. The PRS selected by PRiSM falls between Portfolios 3 and 4, indicating its results are valid. Avista prefers the PRS relative to Portfolio 4 because it includes more efficiency
upgrades to its generation assets and a CCCT technology more closely aligned with our
expiring Lancaster CCCT facility contract.

Figure 11.12: Risk Adjusted PVRR of Efficient Frontier Portfolios

Other Efficient Frontier Portfolios
In addition to the PRS, the efficient frontier contains 16 additional resource portfolios.
The lower cost and higher risk portfolios contain primarily natural gas peakers, as
portfolio risk decreases, CCCT capacity increases. The amount of conservation varies in these portfolios as it lowers risk, and as it fills deficiency gaps depending on the
resource selection. For example, the model must select a resource size actually
available in the marketplace. Given this “lumpiness”, it may be more efficient to meet
some larger needs with conservation in order to meet the load requirement. This
discussion continues in Chapter 12 – Portfolio Scenarios. Toward the middle of the efficient frontier, PRiSM favors wind and solar to reduce risk
as additional conservation resources become more expensive. The lower half of the
efficient frontier includes portfolios with large capacity surpluses and renewable
-
1.00
2.00
3.00
4.00
5.00
6.00
Le
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t

C
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t
2 3 4 5 6 7 8 9 10 11 12 13 14 15
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Efficient Frontier Portfolios
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 186 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-19

resources, meanwhile maxing out the amount of conservation included in the model. The least risk portfolio has no financial objective and selects as many resources as
possible given the model’s constraints to lower risk.

Table 11.7: Alternative Resource Strategies along the Efficient Frontier (MW)
Portfolio
NG
Peaker
NG
CCCT Wind Solar
Thermal
Upgrade
Energy
Efficiency
Least Cost 527 - - - 38 128
2 524 - - - 41 135
3 239 286 - - 38 128
PRS 239 286 - - 41 132
4 143 341 - - 38 138
5 189 341 50 10 41 139
6 140 341 100 20 41 143
7 189 341 200 - 38 141
8 140 341 250 20 41 142
9 186 341 300 70 38 141
10 186 341 400 30 38 141
11 140 341 450 80 38 144
12 140 341 500 150 41 142
13 186 341 500 290 38 143
14 93 627 500 270 38 140
15 93 627 500 480 38 141
Least Risk 186 683 500 600 23 144

Determining the Avoided Costs of Energy Efficiency
The efficient frontier methodology determines the avoided cost of 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 benefits beyond generation resource value.

Avoided Cost of Energy Efficiency
Since energy efficiency is within PRiSM, the prior IRP method of calculating avoided
costs is no longer required; but estimating these values is helpful in selecting conservation measures in future more detailed analysis between IRPs. The process
used to estimate avoided cost calculates the marginal cost of energy and capacity of the
resources selected in the PRS. The energy value uses an hourly energy price to ensure
matching between savings and value. If the savings were the same each hour of the
year, it would receive the flat energy price, but if it were only saving energy in on-peak hours, it would receive a higher price. In addition to energy prices, the 10 percent Power
Act adder and the value of loss savings are included.7 Reducing customer loads saves
future distribution and transmission capital and O&M costs, and is included in the
7 The Power Act adder refers to one aspect of federal law enacted in 1980 along with the creation of the
Northwest Power and Conservation Council.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 187 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-20

conservation-avoided cost calculation. The final component of avoided cost accounts for the savings from avoided new capacity. This capacity value is the difference between
the cost of a resource mix and the value the mix earns from commodity energy sales in
the wholesale marketplace.
Equation 11.2 describes the avoided costs to evaluate conservation measures. This equation is slightly different from the 2013 IRP. In prior IRPs, the capacity value
received the 10 percent Power Act benefit. Now with energy efficiency included in the
PRiSM model, the 10 percent adder cannot be included in the linear program as it
would create a non-linear solution. This change is consistent with the NPCC’s methodology.
Equation 11.2: Conservation Avoided Costs

{(E + (E * L) + DC) * (1 + P)} + PCR
Where:
E = Market energy price. The price calculated by AURORAXMP is $38.48
per MWh assuming a flat load shape.
PCR = New resource capacity savings for the PRS selection point is estimated to be $102 per kW-year (winter savings only).
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 $12.30 per
kW-Year

Determining the Avoided Cost of New Generation Options
Avoided costs change as market prices, loads, and resources change. Table 11.8
shows avoided costs derived from the 2015 PRS, but they will change as Avista’s loads
and resources change. The 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 a PURPA qualifying project, would not qualify for capacity payments until 2021. This is
because Avista does not need capacity resources until then. The capacity payments
included are tilted and levelized, meaning the actual capacity costs are linear and
increasing each year rather than the PRS’s actual declining cost curve for capacity. This
is similar to typical pricing in the marketplace.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 188 of 212
Chapter 11 – Preferred Resource Strategy
Avista Corp 2015 Electric IRP 11-21

Table 11.8: Updated Annual Avoided Costs ($/MWh)
Year Flat
Energy
$/MWh
On-Peak
Energy
$/MWh
Off-Peak
Energy
$/MWh
Capacity
$/kW-Yr
2016 25.87 29.05 21.62 0.00
2017 27.27 30.47 23.03 0.00
2018 29.59 32.90 25.18 0.00
2019 31.40 34.82 26.83 0.00
2020 33.25 36.48 28.94 0.00
2021 34.54 37.79 30.21 145.00
2022 36.05 39.30 31.70 148.32
2023 36.43 39.64 32.17 151.72
2024 38.60 41.85 34.27 155.19
2025 39.42 42.59 35.18 158.75
2026 43.12 46.36 38.80 162.38
2027 44.72 48.08 40.23 166.10
2028 46.48 49.79 42.09 169.90
2029 48.01 51.39 43.51 173.80
2030 48.79 52.14 44.32 177.78
2031 51.23 54.76 46.52 181.85
2032 53.90 57.58 48.98 186.01
2033 54.98 58.74 49.95 190.27
2034 57.77 61.64 52.65 194.63
2035 59.33 63.24 54.12 199.09

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 189 of 212

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 190 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-1

12. Portfolio Scenarios

Introduction
The PRS is Avista’s strategy to meet future loads. In case the future is different from the
IRP forecast, the strategy needs to be flexible enough to benefit customers under the
new future. This chapter investigates the cost and risk impacts to the PRS with different
futures the utility might face. It reviews the impacts of losing a major generating unit,
evaluates alternative load forecasts, determines the impact of unit sizing, and the selection of portfolios to the right of the efficient frontier. This chapter also identifies the
capital cost tipping points for solar, storage, and demand response options.

Mixed Integer versus Linear Programming
PRiSM is a mixed integer model that meets utility power supply deficits over the IRP
timeframe from a pre-defined set of resource options. The integer model selects only
commercially available resources. For example, if Avista is short 45.3 MW, the integer
model cannot select a 45.3 MW resource. Rather it must choose among unit sizes actually for sale in the marketplace. This methodology creates lumpy resource
additions, meaning that by selecting a commercially available resource capable of fully
meeting the deficit, Avista likely will have some level of surplus. Figure 12.1 shows the
impact of lumpy resource acquisitions on the efficient frontier relative to a linear solution
not requiring lumpy additions. In this case, costs in the integer model average 0.5 percent higher than were Avista able to purchase resources exactly matching its deficits
in a linear model. In addition to higher costs, resources mixes on the efficient frontier
change when choices must match actual resources available in the marketplace. The
resources selected across the efficient frontier under a linear programming model are in
Table 12.1. This methodology creates a smoother transition of peakers to CCCTs and energy efficiency increases at a smoother rate than the more realistic integer-based
model.

Chapter Highlights
 Lower or higher future loads do not materially change the resources strategy.
 Colstrip remains a cost-effective and reliable source of power to meet future customer loads.
 Without Colstrip in 2027, customer bills increase $58 million.
 A $19 per metric ton social cost of carbon scenario increases customers’ costs by $67 million per year levelized.
 Tipping point analysis suggests utility scale solar costs would need to decline
48 percent to be included in the PRS.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 191 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-2

Figure 12.1: Linear versus Integer Efficient Frontier Difference

Table 12.1: Efficient Frontier with Linear Programming

Portfolio NG
Peaker
NG
CCCT Wind Solar Thermal
Upgrade
Hydro
Upgrade
Energy
Efficiency
Least Cost 500 - - - 41 - 130
2 367 129 - - 41 - 133
3 222 274 - - 41 - 133
4 79 414 - - 41 - 135
5 58 429 60 - 41 - 139
6 56 431 132 - 41 - 139
7 48 439 202 - 41 - 139
8 41 445 276 - 41 - 139
9 41 445 352 - 41 - 140
10 30 456 400 46 40 - 140
11 29 458 478 50 38 - 141
12 6 480 500 143 38 - 141
13 - 515 500 282 38 - 141
14 - 549 500 446 38 - 141
15 - 674 500 523 12 - 144
Least Risk - 855 500 600 12 57 147

$ Mil
$10 Mil
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$60 Mil
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$80 Mil
$90 Mil
$350 Mil $400 Mil $450 Mil $500 Mil $550 Mil
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PRS
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 192 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-3

Load Forecast Scenarios The PRS meets the Expected Case energy load growth of 0.6 percent and winter peak
demand growth of 0.68 percent over the next 20 years. Chapter 3 – Economic and Load
Forecast provides details about three alternative load forecasts. Table 12.2 summarizes
the alternative growth assumptions. The high and low load scenarios use different population growth assumptions than the Expected Case. The Increased DG Solar scenario uses the same economic growth rate as the Expected Case, but assumes 10
percent of residential customers install rooftop solar with up to a 6 kW system by 2040.

Table 12.2: Load Forecast Scenarios (2016-2035)
Scenario Energy
Growth (%)
Winter
Peak
Growth (%)
Summer
Peak
Growth (%)
Expected Case 0.6 0.7 0.8
High Load 0.8 0.9 1.1
Low Load 0.2 0.6 0.7
Increased DG Solar 0.4 0.7 0.6
Table 12.3 shows changes to the PRS for each load scenario. In the High Load scenario, 97 MW of additional natural gas-fired peakers meet added load growth, while
the Low Load scenario reduces peakers by 46 MW. The changes between the High and
the Low Load scenarios are not significant because expiring contracts is more of a
driver of Avista’s resource needs than load growth.
Table 12.3: Resource Selection for Load Forecast Scenarios

Resource
Expected
Case's
PRS
High
Loads
Low
Loads
Increased
DG Solar
NG Peaker 239 335 192 239
NG Combined Cycle CT 286 286 286 286
Wind 0 0 0 0
Solar 0 0 0 0
Demand Response 0 0 0 0
Thermal Upgrades 41 41 41 41
Hydro Upgrades 0 0 0 0
Total 565 662 519 565

The Increased DG Solar scenario provides interesting results. In this scenario, where customer-supplied generation increases during summer peak-load periods, the PRS
does not change. The winter peak load drives Avista’s resource acquisition needs, so
this scenario does not change the resource strategy, as DG solar does not produce
energy between the hours of 5:00 pm and 7:00 pm in the winter. This results in the
same resource build, but with lower retail energy sales.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 193 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-4

Load forecast changes can also come in the form of new large loads or the loss of an existing large load. In both cases, the change will likely be short notice. Avista likely
would meet these events by utilizing the energy market.

Colstrip Retirement Scenarios The 2013 IRP acknowledgement letter from the Washington Commission (Docket UE-121421) requested Avista continue assessing the impacts of a hypothetical portfolio
without Colstrip and provide the overall impacts on rates. TAC members requested
another scenario to analyze higher operating costs and shorter EPA compliance
timelines. Avista evaluated both continued operation and retirement of Colstrip under each of these scenarios.
Modeling results for Colstrip in the Expected Case indicate Avista ownership interests in
the plant will remain cost effective for the next 20 years. The IRP assumes certain
capital investments will satisfy future state and federal regulations over the IRP
timeframe. The type, amount, and timing of capital expenditures are estimates used for modeling purposes because exact dates and costs are unknown at this time. Future
IRPs will update assumptions as more and better information is available. The potential
capital investments include emerging requirements related to coal combustion residuals
(CCR) and Regional Haze-related controls. Other environmental regulations may drive
future investment requirements, such as ash pond improvements and the installation of a system for NOX control. IRP modeling assumes that a default control system of a
selective catalytic reduction (SCR) will be required by the end of 2026, but the specific
target date or control type is unknown at this time.

Colstrip Retires in 2026 Scenario This scenario assumes plant closure at the end of 2026 under the Expected Case’s
market forecast. This closure date eliminates capital spending for the SCR, accelerates
ash pond decommissioning, and alters ongoing capital and O&M spending at the plant.
This scenario assumes all costs related to existing and future capital spending would
fully depreciate five years after closure. It also assumes capital spending for ash pond closure and no additional shutdown costs beyond the amount included in current
depreciation schedules for the plant. The scenario does not include any costs related to
employee retraining or relocation costs, payments to other owners, or costs to
decommission the plant beyond those included in current rates.
The results of the 2026 year-end closure scenario require 208 MW of new winter
capacity, assuming a replacement resource in Avista’s balancing area. Table 12.4
provides details about the resource strategy in this scenario. The strategy for this
scenario adds a second CCCT to replace the Colstrip capacity and serve future load
growth. Figure 12.2 shows a full efficient frontier analysis for this scenario. Levelized power supply costs increase by $13.2 million or 3.6 percent per year across all years of
the IRP study. Portfolio risk increases by $12 million in 2027, or 16.6 percent. While the
3.6 percent cost impact appears to be modest due to the IRP’s method of levelizing
large future costs across the 20-year study timeframe, the annual cost increases in
Figure 12.3 are significant beginning in 2027.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 194 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-5

Table 12.4: Colstrip Retires in 2026 Scenario Resource Strategy
Resource By End of
Year
ISO Conditions
(MW)
Natural Gas-Fired Peaker 2020 96
Thermal Upgrades 2021-2025 38
Natural Gas-Fired CCCTs 2026 627
Total 761

Conservation (w/ T&D losses) 2016-2035 130.7

Figure 12.2: Colstrip Retires Scenario Efficient Frontier Analysis
Between 2016 and 2021, customer costs increase due to accelerated recovery of existing capital investments in the plant. In 2022-2026, the model assumes spending to
maintain and improve the plant continues at a lower rate, but most costs typically
classified as capital spending are expensed, leading to an earlier recovery of spending.
The elimination of the SCR offsets and lowers recovered Colstrip costs as high cost investments are removed. The biggest cost to customers is replacement capacity. In 2027, this amounts to $58 million in added costs, or 13 percent. To put this into
perspective, Avista’s 2015 electric revenue requirement in that year is $900 million.
Assuming non-power supply costs increased at the rate of load growth, closing Colstrip
alone would increase customer rates by 5.7 percent the first year of closure.
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Levelized Annual Power Supply Cost (2016-40, Millions)
Efficient Frontier
Preferred Resource Strategy
Colstrip Retires 2026 Scenario- Efficient Frontier
Colstrip Replacement Resource Strategy
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 195 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-6

Figure 12.3: Colstrip Retires in 2026 Scenario Power Supply Cost Impact
Avista greenhouse gas emissions decline by an estimated 0.9 million metric tons per
year, or 32 percent. Figure 12.4 shows the change in emissions by year. In 2027, the
first year of closure in the scenario, the cost per saved metric ton of carbon is $66.

Figure 12.4: Colstrip Retires in 2027 Emissions

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Colstrip Retires Scenario Resource Strategy
Preferred Resource Strategy
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 196 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-7

High-Cost Colstrip Retention Scenario The TAC proposed a second Colstrip case. The High-Cost Colstrip Retention scenario
assumes replacing existing SO2 scrubbers, converting the plant to dry ash handling,
landfill replacement, acceleration of SCR installation to 2022, and added O&M costs
due to the assumed closure of Colstrip Units 1 and 2 in 2017. While offering to perform an analysis of High-Cost Colstrip Retention, Avista does not believe this scenario represents a likely future for Colstrip and therefore has not vetted these assumptions
closely. The scenario provides a very high and unlikely case to test the viability of the
plant under much higher costs. A third scenario evaluates closing the plant in 2022 to
avoid the higher ongoing costs associated with the High-Cost Colstrip Retention case. The resource strategy selected by PRiSM for this scenario is in Table 12.5; it is very similar to the portfolio scenario with the plant retiring in 2027, but the scenario offsets
other plant requirements differently causing a small increase in capacity need (770 MW
versus 761 MW).

The High-Cost Colstrip scenario in Figure 12.5 uses the efficient frontier methodology to measure cost and risk. It increases fixed costs by $18 million per year levelized
between 2016 and 2040 and risk levels do not change. Where Colstrip retires in 2022 to
avoid High-Cost Colstrip Retention costs, overall system cost increases $2 million per
year; risk increases by $11 million in 2027. The annual costs for the Colstrip scenarios
are in Figure 12.6 in 2023. The first year without Colstrip costs increase by $19 million compared to the plant operating with the higher costs. This scenario shows with higher
operating costs, the plant is still marginally economic to continue operating.

Table 12.5: Colstrip Retires in 2022 Scenario Resource Strategy
Resource By End of
Year
ISO
Conditions
(MW)
Natural Gas Peaker 2020 56
Thermal Upgrades 2021-2035 41
Combined Cycle CTs 2023-2026 627
Natural Gas Peaker 2035 47
Total 770

Conservation (w/ T&D losses) 2016-2035 131

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 197 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-8

Figure 12.5: High-Cost Colstrip Retention Scenario Efficient Frontier

Figure 12.6: High-Cost Colstrip Scenarios Annual Cost

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Annual Levelized Portfolio Cost (Millions)
Expected Case- Efficient FrontierHigh-Cost Colstrip Retention Scenario- Efficient FrontierColstrip Retires 2022 Efficient FrontierPreferred Resource StrategyPRS w/ High-Cost Colstrip Retention ScenarioColstrip Retires in 2022 Scenario Resource Strategy
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
PRS 252 276 288 298 313 331 341 348 366 382 399 454 484 487 488 504 523 523 545 564
PRS High Colstrip Costs 252 276 290 301 320 347 373 389 404 414 425 477 507 510 511 528 547 546 568 588
PRS Colstrip Retires 2022 260 284 299 325 333 336 351 408 425 432 444 490 498 500 501 514 534 536 551 572
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 198 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-9

Social Cost of Carbon Market Scenarios Chapter 10 describes alternative market scenarios. One modeled scenario was the
market impact of a social cost of carbon added to all carbon emissions. This section
describes the cost and portfolio impacts of such a market environment to Avista. Figure
12.7 is the efficient frontier of the Expected Case compared to the efficient frontier developed for the Social Cost of Carbon market scenario. With the social cost of carbon, the cost of the PRS increases by $67 million per year, or 17 percent. Risk also
increases by $4 million or 6 percent in 2027 for the same portfolio as the PRS.

Figure 12.7: Social Cost of Carbon Impact to Efficient Frontier

Colstrip Retires in 2027 with Social Cost of Carbon
Adding a fee to emit carbon will increase portfolio costs. This scenario analyzes the cost
effectiveness of keeping Colstrip open with the Social Cost of Carbon adder. The cost of
retiring Colstrip is approximately $6 million higher per year with the plant closed compared to operating with the additional carbon pricing. Not only are system costs
higher with the closure of Colstrip in this scenario, but risk increases by 15 percent. See
Figure 12.8. This indicates Colstrip is still economic even with carbon pricing
approximately 10 times higher than in the Expected Case. The combination of the
Social Cost of Carbon with the assumptions from the High-Cost Colstrip Retention scenario would find the plant marginally uneconomic, but as explained earlier, Avista
does not believe the assumptions of the High-Cost Colstrip Retention scenario are
realistic. The Social Cost of Carbon case reduces carbon emissions without Colstrip
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PRS (Expected Case)
Social Cost of Carbon Case- Efficient Frontier
PRS (Social Cost of Carbon)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 199 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-10

retiring. In this scenario, emissions decline by 12 percent; if Colstrip retires, emissions fall 24 percent in total (See Figure 12.9).

Figure 12.8: Colstrip Retires in 2027 Portfolio Efficient Frontier

Figure 12.9: Colstrip Retires in 2027 Portfolio Emissions

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Social Cost of Carbon Case- Efficient Frontier- Colstrip Retires 2026
Colstrip Retires PRS (Social Cost of Carbon)
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Social Cost of Carbon (PRS)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 200 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-11

Other Resource Scenarios
Several other resource portfolio studies using the Expected Case’s market forecast
formed the following analyses. The portfolios show the financial impact of different choices in meeting future resource deficits. They are similar to how Avista selected resource strategies prior to its 2003 IRP and the adoption of more sophisticated
modeling tools such as PRiSM and Monte Carlo risk analysis. Figure 12.10 shows the
levelized cost and 2027 risk compared to the efficient frontier.

Figure 12.10: Other Resource Strategy Portfolio Cost and Risk (Millions)
Market and Conservation
The Market and Conservation portfolio shows the cost and risk if the utility chose not to fill its capacity need with generation assets, instead dependeding on the wholesale
market for its future needs. This portfolio helps estimate the value of capacity in the
PRS. It assumes the same amount of conservation as the PRS. This portfolio’s cost is
$28 million per year levelized lower than the least cost portfolio, and the risk is $1
million higher in 2027. The cost difference between this portfolio and the least cost represents the cost of capacity or the added cost of reliability. Given this strategy does
not meet reliability targets, it is not an acceptable portfolio. Utilities may lean toward this
type of portfolio when the market place is long on resources, which is not the case
beginning in 2021.

2013 Preferred Resource Strategy
This portfolio emulates the strategy selected in the 2013 IRP. The 2013 PRS portfolio
includes the resources described in Chapter 11, predominantly natural gas-fired
Market &
Conservation
2013 PRS
Renewables Meet All Load Growth
Peakers & Hydro Total Portfolio
Colstrip Retires 2027
PRS
Hydro Upgrades & Peakers
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Least Risk
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 201 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-12

peakers, a CCCT, and demand response. The portfolio reflects the current lower load growth trajectory by eliminating a peaker from the previous strategy. This strategy’s
levelized cost is $3 million higher than the PRS, and risk is $1.5 million higher in 2027.
With the exception of the demand response, this portfolio is similar to the current PRS
results with similar metrics for cost and risk.

Renewables Meet All Load Growth
The Renewables Meet All Load Growth scenario is similar to a higher RPS scenario.
The objective is to meet all energy load growth with renewables along with meeting capacity requirements. This scenario meets energy needs with newly acquired renewable resources and natural gas-fired generation for capacity needs. The model
selected 250 MW of wind (87 aMW) with a 20 percent apprentice REC credit, plus an
upgrade to the Kettle Falls plant; with rollover ability, these renewables meet the 126
aMW requirement each year.
The added renewables, in addition to the capacity resources, add $18 million per year
to power supply expenses relative to the Expected Case, and lower risk in 2027 by $3
million. Avista could get the same amount of risk reduction by selecting a portfolio on
the efficient frontier with an annual $15 million reduction in cost.

Hydroelectric Upgrades and Peakers
This scenario uses a combination of peakers and hydroelectric upgrades to meet future
capacity needs. The scenario completes major upgrades at Long Lake and Monroe
Street during the IRP timeframe; natural gas-fired peakers meet all remaining capacity
needs. Costs increase by $6 million per year in this scenario, and risk increases by $4 million. An interesting result from the scenario is the increased risk metric. Typically,
more renewables reduce risk, but since hydro is highly correlated with the Northwest
marketplace, the upgrades actually increase risk relative to the PRS.

Peakers and Hydro Total Portfolio A future with no coal or baseload natural gas resources is the premise of this scenario.
It retires Avista’s CCCTs and coal by 2027, replacing them with upgrades at
hydroelectric facilities and the construction of natural gas-fired peaking plants. In 2027,
when the retirements occur, the risk metric increases by $27 million; costs are $80
million higher compared to the PRS.

Risk-Adjusted PVRR
Avista believes efficient frontier analysis paired with robust analytics and data is a
superior method to measure tradeoffs between average costs and risk. Chapter 11 details the risk-adjusted PVRR methodology used to analyze the efficient frontier. Risk-
adjusted PVRR is helpful with measuring risk in handpicked portfolios that that do not
fall on the efficient frontier, or where the efficient frontier is not part of the IRP process.
Figure 12.11 shows the risk-adjusted PVRR analysis results for the other resource
strategy scenarios in this section. The portfolio with the lowest cost is the Market and Conservation portfolio. This portfolio does not meet reliability objectives of the IRP, and
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 202 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-13

is not an acceptable option. The next lowest cost portfolio is the PRS, followed by the 2013 PRS.

Figure 12.11: Risk Adjusted PVRR (2016- 2035)
Resource Tipping Point Analyses
Recent Avista IRPs studied through tipping point analyses show how much capital costs
needed to change before different resource selections occurred in the PRS. The 2013 IRP included solar, nuclear, and IGCC coal tipping point analyses. This IRP includes
tipping point analyses for solar, energy storage, and demand response. As emerging
technology costs generally do not follow typical inflation, tipping point analyses are
important to understand at what point such technologies might affect the PRS.

Utility Scale Solar
The IRP assumes utility scale solar has a $1,500 per kW capital cost for fixed panel and
$1,600 per kW (2014 dollars) for single-axis tracking panel facilities. Avista estimates
solar costs will decline in real dollars by 27 percent over the 20-year planning horizon
and the 10 percent federal investment tax credit is available after 2016. Solar does not provide winter on-peak capability. Therefore, the resource must be cost competitive with
wholesale market commodity prices.

The analysis decreases single axis solar capital costs in PRiSM until the model selects
the resource in the PRS. PRiSM selects solar in 2023 when its price falls 47 percent below current projections, to $682 per kW in 2014-year dollars. Figure 12.11 shows the
solar cost curve and the point where solar becomes economic to Avista.

$3.8 Bil
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PRS
2013 IRP's
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Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 203 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-14

Figure 12.12: Utility Scale Solar Tipping Point Analysis (2014 $)

Utility Scale Energy Storage
Energy storage might become a commercial-scale resource for utilities and their
customers in the future. As the amount of intermittent generation grows, many believe energy storage will help integrate these resources into the electricity grid. There are many types of energy storage technologies, but this study remains agnostic to the
technology and only looks at how costs change, as long as each technology performs
similarly. Similar to solar generation, energy storage costs should decline as the
technology becomes more common. Unlike solar, energy storage can meet on peak needs, but it consumes significant amounts of energy in the form of losses in the
process. The Expected Case assumes storage at $4,000 per kW in 2014. By the first
capacity need in 2021, utility scale energy storage is expects to be $2,736 per kW
(2014$) or $3,201/kW nominal. PRiSM first selects storage in 2021 with a price $770
per kW in 2014-year dollars, a 72 percent reduction in capital costs.

$/ kW
$200/ kW
$400/ kW
$600/ kW
$800/ kW
$1,000/ kW
$1,200/ kW
$1,400/ kW
$1,600/ kW
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Selected ($2014)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 204 of 212
Chapter 12 – Portfolio Scenarios
Avista Corp 2015 Electric IRP 12-15

Figure 12.13: Utility Scale Storage Tipping Point Analysis (2014 $)

Demand Response
Demand response was part of the PRS in Avista’s 2013 IRP. At that time, the costs
were preliminary internal estimates; since then, Avista sponsored a study to determine the demand response costs and quantities available. The results of the study showed higher prices than the 2013 plan, and the higher costs meant demand response is not in
this plan. To make demand response attractive, costs must fall to $117 per kW-year
levelized between 2023 and 2035. This is a reduction of 46 percent.
$/ kW
$500/ kW
$1,000/ kW
$1,500/ kW
$2,000/ kW
$2,500/ kW
$3,000/ kW
$3,500/ kW
$4,000/ kW
$4,500/ kW
20
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Selected ($2014)
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 205 of 212

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 206 of 212
Chapter 13–Action Items
Avista Corp 2015 Electric IRP
13. 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 2013 IRP Action Plan and provides the 2015 Action Plan.

Summary of the 2013 IRP Action Plan
The 2013 Action Plan included three categories: generation resource related analysis,
energy efficiency, and transmission planning.

2013 Action Plan and Progress Report

Generation Resource Related Analysis
 Consider Spokane and Clark Fork River hydroelectric upgrade options in the next IRP as potential resource options to meet energy, capacity, and environmental
requirements.
o This IRP continues incorporating hydroelectric upgrades as resource
options in the PRS and scenario analysis. Chapter 9 – Generation
Resource Options provides details about the hydroelectric upgrades evaluated for this IRP.

 Continue to evaluate potential locations for natural gas-fired resources identified to
be online by the end of 2019, including environmental reviews, transmission studies, and potential land acquisition.
o The natural gas-fired peaker options included in this IRP assume both
greenfield and brownfield sites in Northern Idaho. Avista is currently
negotiating the purchase of property for a greenfield site. Information
about this site will not be available publically until after the close of the potential transaction.

 Continue participation in regional IRP and regional planning processes, monitor
regional surplus capacity, and continue to participate in regional capacity planning processes.
o Avista continues to monitor and review other Northwest IRP processes.
o The company continues to participate in regional processes including the
development of the Seventh Regional Power Plan, PNUCC studies, and
work by the Western Governors Association on energy issues.
 Commission a demand response potential and cost assessment of commercial and
industrial customers per its inclusion in the middle of the PRS action plan.
o Avista retained the services of AEG to study the amount and cost of different types of demand response programs available in the service
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 207 of 212
Chapter 13–Action Items
Avista Corp 2015 Electric IRP
territory. A discussion about the scope of this study occurred with the TAC during the first meeting on May 29, 2014, and the results presented at the
fourth TAC meeting on February 24, 2015. Both of these presentations are
available in Appendix A.
o The complete AEG demand response study is available in Appendix C.
 Continue monitoring state and federal climate change policies and report work from
Avista’s Climate Change Council.
o Several developments concerning state and federal climate change
policies have occurred since publication of the 2013 IRP. Most notably, the CPP at the federal level and Washington Governor Inslee’s Executive
Order 14-04 concerning climate change and subsequent proposed
legislation concerning a cap and trade program at the state level.
o Details about the CPP proposal and Governor Inslee’s Executive Order
are available in Chapter 7 – Policy Considerations. Studies concerning these areas are included in chapter 12 – Portfolio Scenarios. The original
presentations made to the TAC about these issues are in Appendix A.

 Review and update the energy forecast methodology to better integrate economic, regional, and weather drivers of energy use.
o Please refer to Chapter 3 – Economic and Load Forecast for a detailed
account of changes made to the energy forecast methodology to better
integrate economic, regional, and weather drivers of energy use. Avista’s chief economist presented the forecasting methodology updates at the second TAC meeting on September 24, 2014. The presentation is
available in Appendix A

 Evaluate the benefits of a short-term (up to 24-months) capacity position report.
o Avista implemented a short-term capacity model in late 2013. The tool
assists in closing short capacity positions. An updated version of this tool
added long-term functionality to develop resource positions for this plan.

 Evaluate options to integrate intermittent resources.
o Avista completed development of the Avista Decision Support System
(ADSS); this tool can model the costs and benefits of intermittent
resources. A presentation about the model and the results of the value of
thermal resources assisting with ancillary services study occurred at the May 19, 2015, Technical Advisory Committee meeting. This presentation
is located in Appendix A.

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.
o Avista hired AEG to conduct the biannual CPA. The study complied with
accepted NPPC methodologies where possible by using measure savings
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 208 of 212
Chapter 13–Action Items
Avista Corp 2015 Electric IRP
identified by the RTF or estimated by AEG. Where RTF unit energy savings are utilized those savings will be symmetrically applied when
Avista claims the energy savings for the biennium. AEG is currently in the
process of updating inputs for the CPA to include indexing the CPA to the
forecast and other economic factors to address changing market conditions.
 Study and quantify transmission and distribution efficiency projects as they apply to
EIA goals.
o Avista continues to invest in transmission and distribution projects including efficiency upgrades. Chapter 8 contains details about completed
and announced projects.

 Assess energy efficiency potential on Avista’s generation facilities.
o Avista completed an energy audit on owned generating facilities. Chapter
5 – Energy Efficiency and Demand Response summarizes the results and
Appendix D includes the audit reports.

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.

 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 participates in and leads many regional transmission efforts
including the Columbia Grid and the Northern Tier Transmission Group
Forums.

2013 Action Plan and Progress Report – Supplemental
Avista submitted eight updated Action Items on January 27, 2014 in response to
comments made at the January 9, 2014 hearing with the WUTC. This section highlights
the work done in this IRP concerning the additional Action Items.

Generation Resource Related Analysis – Additional Updates

 Continue to evaluate scenarios related to Colstrip and how each scenario may impact power supply costs.
o The 2015 IRP includes several Colstrip scenarios in Chapter 10 – Market
Analysis and Chapter 12 – Portfolio Scenarios.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 209 of 212
Chapter 13–Action Items
Avista Corp 2015 Electric IRP
 Evaluate and explicitly document various options for quantifying carbon costs in the
IRP.
o Avista discussed different options concerning the quantification of the cost
of carbon in the Expected Case and in scenarios for the 2015 IRP. The
presentations made to the TAC are in Appendix A and the results of the analyses are in chapters 10, 11 and 12.
 Work with TAC to determine which carbon quantification method should be
employed in the Expected Case of the 2015 IRP.
o Avista’s discussions with the TAC about different options for the quantification of the cost of carbon in the Expected Case for the 2015 IRP
are in the presentations made to the TAC in Appendix A. The Expected
Case analysis concerning carbon emissions are in chapters 10 and 11.
 Use Avista’s new modeling capabilities to further evaluate the benefits of storage resources to its generation portfolio, including the impacts on ancillary services
needs.
o Chapter 9 – Generation Resource Options and chapter 12 – Portfolio
Scenarios discuss the results of the evaluation of energy storage to
Avista’s generation portfolio.
 Revisit with the TAC the benefits and costs of the Company’s 2013 IRP planning
margin target to determine if a different level is warranted in the 2015 IRP.
o Avista discussed the planning margin target with the TAC. The
presentations concerning those discussions are in Appendix A. Chapter 6
– Long-Term Position has an extensive discussion about the choice of the
appropriate planning margin for the 2015 IRP.
 Evaluate with the TAC the impacts of different points along the efficient frontier.
o Avista discussed the evaluation of the impacts of choosing different points along the efficient frontier with the TAC. The presentations concerning
those discussions are in Appendix A and details about the results in this
IRP are located in chapters 11 – Preferred Resource Strategy and 12 –
Portfolio Scenarios.

Energy Efficiency – Additional Updates

 Evaluate the impacts of targeting individual or groups of energy efficiency options
within PRiSM instead of targeting quantities using avoided cost.
o Avista developed and used a secondary methodology for identifying the
amount of achievable conservation potential using the PRiSM model.
Details about PRiSM co-optimization are in Chapter 5 – Energy Efficiency
and Demand Response.
 Work with TAC to determine if 2015 IRP should continue the historical method of
conservation quantification or if PRiSM should be used instead.
o The TAC meetings included discussions about the PRiSM co-optimization
methodology for identifying the amount of energy efficiency potential for
the 2015 IRP. Appendix A contains the presentation materials.
Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 210 of 212
Chapter 13–Action Items
Avista Corp 2015 Electric IRP
2015 IRP Two Year Action Plan
Avista’s 2015 PRS provides direction and guidance for the type, timing, and size of
future resource acquisitions. The 2015 IRP Action Plan highlights the activities planned for possible inclusion in the 2017 IRP. Progress and results for the 2015 Action Plan items are reported to the TAC and the results will be included in Avista’s 2017 IRP. The
2015 Action Plan includes input from Commission Staff, Avista’s management team,
and the TAC.

Generation Resource Related Analysis
 Analysis of the continued feasibility of the Northeast Combustion Turbine due to its
age.
 Continue to review existing facilities for opportunities to upgrade capacity and efficiency.
 Increase the number of manufacturers and sizes of natural gas-fired turbines
modeled for the PRS analysis.
 Evaluate the need for, and perform if needed, updated wind and solar integration
studies.
 Participate and evaluate the potential to join a Northwest EIM.
 Monitor regional winter and summer resource adequacy.
 Participate in state level implementation of the CPP.

Energy Efficiency
 Continue to study and quantify transmission and distribution efficiency projects as
they apply to EIA goals.
 Complete the assessment of 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 facilitate long-term
economic expansion of the regional transmission system.

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 211 of 212
Chapter 13–Action Items
Avista Corp 2015 Electric IRP
Production Credits

Primary Avista 2015 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
Richard Maguire System Planning Engineer Transmission & Distribution

2015 Electric IRP Contributors

Name Title
Thomas Dempsey Manager, Generation Joint Projects
Leona Doege DSM Program Manager
Tom Pardee Natural Gas Planning Manager
Shane Pacini Manager Network Engineering
Eric Scott Natural Gas Resources Manager
Mike Dillon DSM Planning and Analytics Manager
Jeff Schlect Senior Manager of FERC Policy and Transmission Services Dave Schwall Senior Engineer
Darrell Soyars Manager of Corporate Environmental Compliance
Xin Shane Power Supply Analyst
Debbie Simock Senior External Communications Manager
Jason Graham Mechanical Engineer

Contact contributors via email by placing their names in this email address format: [e-mail]

Exhibit No. 4
Case No. AVU-E-17-01 S. Kinney, Avista
Schedule 1, Page 212 of 212
CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality
Avista Utilities Energy Resources Risk Policy
Pages 1 through 35
Exhibit No. 4 Case No. AVU-E-17-01
S. Kinney, Avista Schedule 2, p. 1 of 35
Business Case Name Page Number
Asset Condition
Automation Replacement 2
Cabinet Gorge Automation Replacement 5
Cabinet Gorge Station Service Replacement 12
Cabinet Gorge Unit 1 Refurbishment *
Generation DC Supplied System Upgrade 17
Kettle Falls CT Control Upgrade 22
Kettle Falls Stator Rewind 27
Little Falls Plant Upgrade 33
Long Lake Plant Upgrades 38
Nine Mile Rehab 45
Noxon Station Service 49
Peaking Generation 54
Post Falls Redevelopment 57
Purchase Certified Rebuilt Cat D10R Dozer 63
Replace Cabinet Gorge Gantry Crane 68
Failed Plant and Operations
Base Load Hydro 76
Base Load Thermal Plant 81
Regulating Hydro 85
Mandatory and Compliance
Colstrip Thermal Capital 90
Clark Fork Settlement Agreement 93
Hydro Safety Minor Blanket 97
Kettle Falls RO System 101
Spokane River License Implementation 106
* The transfers to plant associated with this business case represent investment
of four thousand dollars ($4,000) associated with trailing charges following the
completion of the project, which is not unusual for this type of major project.Given that the project is complete, with the exception of these trailingcharges, a business case justification narrative in the new format was not
completed for this project.
Generation / Production Capital Projects - Index of Business Case Justification Narratives
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 1 of 108
Autom ati on Repl acement
I GENERAL INFORMATION
Requested Spend Amount $650,000.00
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Kristina Newhouse
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Program
Driver Customer Service Quality & Reliability
l.l Steering Committee or Advisory Group lnformation
The controls engineering team identified the need to address the risk of aging and
failing control equipment. The Distributed Control Systems (DCS) and
Programmable Logic Controllers (PLC) are aging and are introducing an increase in
hardware and software failures. Discussions with the Director of GPSS, the Manager
of Operations Analytics, the Electrical Engineering Manager, and the Protection
Control Meter Technician Foreman concluded that a planned replacement program
was needed.
The controls engineering manager will provide ongoing oversight and monthly
tracking of the ongoing work within the program. The advisory group for ongoing
vetting includes the Director of GPSS, the Controls Engineering Manager, the
Protection Control Meter Technician Foreman, the Manager of Hydro Operations
and Maintenance, and the Manager of Thermal Operations and Maintenance.
2 BUS¡NESS PROBLEM
The major driver for the Automation Replacement business case is Reliability. This
program aligns with Avista's Safe & Reliable lnfrastructure strategy. Upgrading our
control systems within our generating facilities allows us to provide reliable energy.
The Distributed Controls Systems (DCS) and Programmable Logic Controllers
(PLC) are used to control and monitor Avista's generating units as well as each
generating facility. For many facilities the operation of the generating units is
performed remotely with the use of the DCSs and the PLCs. These aging devices
use unsupported operating systems and modules that are no longer available.
Failing software and hardware introduces risk and limits Avista's ability to operate
generating facilities reliably.
The DCS and PLC work is needed now to reduce the higher risk of failure due to the
aging equipment. The DCSs are no longer supported and spare modules are limited.
The modules in service have a high risk of failure as they are over 20 years old. The
computer drivers that are needed to communicate to the DCSs will not fit in new
computers with Windows 10 operating systems. This creates a Cyber Security issue.
Business Case Justification Narrative Page 1 of3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 2 of 108
A uto m ati o n Re p I ace m ent
The software needed to view and modify the logic programs only runs on Windows
95. Avista has a very limited supply of Windows 95 laptops and they also continue
to fail.
Replacing aging DCSs and PLCs will reduce unexpected plant outages that require
emergency repair with like equipment. A planned approach will allow engineers and
technicians to update logic programs more effectively and replace hardware with
current standards.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option 1 is to replace all aging DCSs and PLCs proactively on a schedule that takes
into account resources and outage availability. This option addresses aging
hardware and software concerns as well as the cyber security vulnerabilities.
Additional resources are required in order to maintain a schedule and consistently
meet the objectives. Engineering will require a designer to develop new logic
programs and designs for installations. The Protection Control Meter Shop will need
a resource to install and commission the PLC programs.
Option 2 is to maintain existing Bailey DCSs and Modicon PLCs as we currently do
today. This includes replacing modules as they fail with old spare parts or refurbish
third party parts. Maintaining spare parts allows us to continue using existing
infrastructure and logic programs but it does not resolve the long term issue which
is aging equipment that will eventually no longer be available. The risk of outages at
undesirable times to replace failed parts becomes more likely the longer the aging
hardware is in service. This alternative also does not resolve the issue with
computers that have unsupported operating systems and are considered a cyber-
security risk.
Option 3 is to upgrade software on the DCSs and PLCs. This would include replacing
each system's software that runs on Windows 95 and Windows XP with a separate
software for each platform that runs on Windows 7. This will mitigate the software
and cyber security issue but not the aging hardware issue. Outages would be
required and the new logic programs would need to be rewritten and fully
commissioned. Upgrading the Bailey software and the Modicon software do not align
with our standard PLC platform that our engineers and technicians are trained on.
This would introduce two new software applications. Efficiency to troubleshoot and
resolve issues in a timely manner could be impacted.
Option 1 is the proposed option because it addresses the issues with aging hardware
and software and it resolves the cyber security vulnerabilities. This option addresses
the identified issues in a more controlled and planned manner where designs can
be wellthought out and plant outages for construction can be scheduled and ideally
Option Capital Cost Sta¡t Complete
Option I - Upgrade DCS and PLCs $6.5M 1t2017 1212025
Option 2 - Spare Parts Refurbishment / Do nothing $1 00k/year 1t2017 NA
Option 3 - Software Upgrade $2.5M 1t2017 12t2025
Business Case Justification Narrative Page 2 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 3 of 108
A uto m ati o n Re p I ace m ent
limited. The requested spend amount is based on Option 1 and takes into account
resources needed to perform designs and installations. ls also takes into
consideration feasibility of plant outages as projects are spread out over time.
See attached timeline titled Timeline Estimate - Automation Replacement Busrness
Case.pdf
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Automation Replacement
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title;
Role:
Signature:
Print Name
Title:
Role:
1,7 -
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Template Version: 03107 12017
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5 VERSION HISTORY
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1.0 Kristina Newhouse 04t05t2017 Andy Vickers 04t11t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 4 of 108
Cabinet Gorge Automation
I GENERAL INFORMATION
Requested Spend Amount $2,941,000
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Gategory Project
lnvestment Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
As generating plants are managed by the Generation, Production, and Substation
support group, they provide energy and other services used by Power Supply. The
steering committee for this project includes members from both groups: Director
Power Supply; Director GPSS; Manager Hydro Ops and Manager Project Delivery.
This team receives monthly project status updates but meets only in the event that
a decision is needed.
The projecUstakeholder team meets on a more regular basis (at least monthly) to
work on the project's scope and planning. The project/stakeholder team is
comprised of representatives from the various engineering groups (electrical,
controls, mechanical) and plant operations.
2 BUSINESS PROBLEM
This plant was designed for base load operation. Today, Cabinet Gorge is called on
to not only provide load, but to quickly change output in response to the variability of
wind generation, to adjust to changing customer loads, and other regulating
services needed to balance the system load requirements and assure transmission
reliability. The controls necessary to respond to these new demands include speed
controllers (governors), voltage controls (automatic voltage regulator a.k.a. AVR),
primary unit control system (i.e. PLC), and the protective relay system. ln addition
to reducing unplanned outages, these systems will provide the ability for Avista to
Business Case Justification Narrative Page 1 of7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 5 of 108
Cabinet Gorge Automation
maximize these services from within the pool of its own assets on behalf of its
customers rather than having to procure them from other providers.
As part of the designated "Regulating Hydro" class of assets.
The key metric for these plants is their Equivalent Availability
Factor or EAF.
Chart 1 - Equivalent Availability Factor
Equivalent
Availability Factor
(EAF) measures the
amount of time that
the Unit is able to
produce electricity
in a certain period,
divided by the
amount of time in
that period. In this
case, Cabinet
Gorge has
averaged below
85% EAF for the
twelve month rolling
period ending
September 2016.
The internal
company target for
this measure is
85o/o
Some of the outages that cause the EAF to fall below the target include forced and
maintenance outages associated with the control and protection systems described.
Some recent events captured are attached to this document for referencel.
An additional problem with the existing speed controls (governors) is the lack of
response in a system frequency event. The graph below shows a significant
frequency "excursion" (the dark blue line) and the response of the machines at
Noxon Rapids HED to this excursion. Those are the lines that move upward on the
top of the chart. The response of the Cabinet Units is shown in the lines in the
I See "l8 Maximo Work Orders related to CG Controls."
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Business Case Justification Narrative Page 2 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 6 of 108
Cabinet Gorge Automation
middle of the chart should have bumped up like the Noxon, but instead were non-
responsive.
Chart 2 - Lack of Frequency Response
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A similar chart showing voltage control issues at Cabinet Gorge can be found in
Appendix A.
There are several NERC Reliability standards against which the existing equipment
performs at a sub-standard level. One of these standards involves frequency
response as describe above. The related NERC standards are attached to this
document along with some technical explanation if more information is needed.
Last, there have been several unit outages that were specifically taken to address
problems associated with the existing control and protection equipment. This
equipment is at the end of its intended life and there is an increased likelihood of
forced outages and subsequent loss of revenue and reliability. More details of
these events are can be found in the attached "18 Maximo Work Orders related to
CG Controls" document.
Business Case Justification Narrative Page 3 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 7 of 108
Cabi net Gorge Automation
3 PROPOSAL AND RECOMMENDED SOLUTION
Avista's Safe & Reliable lnfrastructure strategic initiative seeks to leverage
technology and innovative products and services offered to existing and new
customers. The work proposed for Cabinet Gorge will include equipment and
component replacement geared at increasing reliability and unit control/monitoring.
Customers benefit in that it will allow Avista to economically optimize an existing
asset to provide energy and other energy related products.
To accomplish project objectives to improve unit response, operating flexibility, and
reliability, the following components will be considered: governor and governor
controls, generator excitation system and AVR, protective relays, and unit controls.
The extended outage will provide an opportunity to address other issues including,
insulating the generator housing roof, cooling water upgrade, unit flow meter and
other items to improve overall reliability. The objective is to ensure system
compatibility with current standards and improve system reliability.
Do Nothing / Continue to Repair: While the generator is capable of producing
energy with existing systems, the present equipment does not provide the system
support abilities needed to meet today's requirements (see graph above). This
solution requires maintenance of old systems that are no longer supported by the
original manufacturer and there is some question on parts availability. Additionally,
trained personnel available to work on these older systems are becoming scarce
and formal training is no longer available. For reasons of obsolescence, inadequate
system performance, and increasing maintenance demands, this option is not the
preferred option.
Replace Unit Control, Monitorinq, and Protection Systems: ln addition to addressing
issues of obsolescence and increased likelihood of unplanned outages,
replacement of these key systems addresses the performance needs to work with
the new dynamics of the systems today. This includes integration of intermittent
resources, reserves, frequency and voltage response, and the ability to adapt these
controls and protection devices as the larger grid continues to evolve.
lnstallation of new controls and protection will also provide increased visibility into
the systems allowing better remote monitoring and troubleshooting. New systems
Option Capital Cost $tart Complete
Do nothing / Continue to Repair $0 ongorng ongorng
Replace Unit Control, Monitoring, and
Protection Systems
$2,136,194 12t2015 12t2018
Mechanical, Controls, Electrical upgrades
and Stator Re-wedging
$2,936,194 12t2015 12t2018
Business Case Justification Narrative Page 4 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 8 of 108
Cabi net Gorge Automation
are also configured so compliance with NERC standards is much easier to achieve.
As this option addresses the primary issues, this is considered the minimal preferred
option.
Mechanical. Controls. Electrical norades and Stator Re-wedoino:This option is
the same as the Replace Unit Controls, Monitoring, and Protection Sysfems
described above except this also includes addressing additional items related to the
reliability of the generating unit. This may include replacing the insulation system
on the generator rotor, re-wedging the generator stator, replacing and updating
auxiliary system motor controls, and other items identified as necessary to both
extend the life of the asset and improve the reliability. This option would allow for
work that would be necessary in the near future to be performed now therefore
avoiding future outages and improving the near and long term reliability of the units.
While this is the preferred option, it cannot be selected at this time due to the gantry
crane's limitations2.
P ram Cash Flows
2 The gantry crane is needed to pick the rotor in order to perfotm the re-wedging work. The gantry crane is in
a state ofdisrepair which is being addressed by a separate business case.
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$$ 2.439.üX)Total S ¿,¿z¿,ozs Ë
Business Case Justification Narrative Page 5 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 9 of 108
Cabinet Gorge Automation
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Automation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
rAAr-L Þ¿t/.
Business Case Owner
Date: Ztt+61¡y
Date
Template Version : 03107 12017
A¿o
erS
D ìrecfo. G Pg I
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Terri Echeooven 04t14t17 Steve Wenke 04t14t17 lnitialversion
Business Case Justification Narrative Page 6 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 10 of 108
Cabinet Gorge Automation
APPENDIX A
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Business Case Justification Narrative PageT of7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 11 of 108
Cabinet Gorge Station Seryice
1 GENERAL INFORMATION
Requested Spend Amount $4,275,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Gase Sponsors Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Project
lnvestment Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The advisory group for this project consists of members from the Generat¡on
Production and Substation support department including: Director - GPSS,
Manager Hydro Operations & Maintenance and Manager Electrical Engineering.
Steering committee members receive monthly project status update reports but are
convened only in the event of a decision point.
The projecUstakeholder team meets on a more regular basis (at least monthly) to
work on the project's scope and planning. The project/stakeholder team is
comprised of representatives from the various engineering groups (electrical,
controls, mechanical) and operations.
2 BUS¡NESS PROBLEM
All generation facilities require Station Service to provide electric power to the plant.
Station Service components include Transformers, Power Centers, Motor Control
Centers, Load Centers, Emergency Load Centers and various breakers. Station
Service is an elaborate system with multiple built-in redundancies designed to
protect the plant's electrical operation.
The Cabinet Gorge Station Service equipment is original from 1951. The station
service is a typical redundant Main-Tie-Main Service with some components added
over time to accommodate changes to the Units and Balance of Plant needs. The
Main-Tie-Main has multiple power sources which provides various switching
alternative to bypass systems so that power is never lost. Station Service
transformers no longer have the capacity to provide the needed load and could be
subject to overload. The current Motor Control Centers (MCC) lack monitoring and
indication. Replacement of these MCCs would create operational efficiencies by
providing visibility into how station service is pefforming. The cables require
evaluation due to age of insulation and the wet conditions they have been subject to
over the years. The weight due to the number of cables in the tray cause concern
for potentialfailure (see photo below). Due to control and other additions that have
occurred over time, the existing 26 year old Emergency Generator no longer meets
the load critical requirements for the plant. The only components of Station Service
Business Case Justification Narrative Page 1 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 12 of 108
Cabinet Gorge Station Seruice
that have been recently replaced are the lntake Motor Control Center in 2010 and
the single high voltage circuit breaker serving the plant in 2015.
lf no action is taken, there is a risk of individual component failure that could force
load shedding under certain operational scenarios. Should a catastrophic failure
occur with switchgear and/or power cables, it could result in generator unit and/or
plant wide forced outages potentially lasting as long as eight months. This is due to
the long manufacturing lead time for some types of specialized equipment.
3 PROPOSAL AND RECOMMENDED SOLUTION
Do Nothing: doing nothing is an option. However, if components do fail, due their
age, replacements are not available. Addressing such failures in an emergency/ad
hoc situation would increase the cost and extend the outage time. This option does
not provide any capacity for future loads.
Alternative #1 would replace the following components:
. Station Service Transformers 1 & 2
o Power Center A & B.
o Load Center 1,2 & 4 would be replaced with Motor Control Centers with
provisions for future capacity.
o Power cables
o Emergency Generator and controls to accommodate additional emergency
load.
o Address arc flash rating and improve load flow analysis and coordination.
. Add metering to each Station Service Power Center and Emergency
Generator.
Alternative #2: Add a second emergency generator with appropriate
transformation to add capacity in the event of a failed Station Service transformer.
This alternative would require the addition of another Power Center that when tied
in with the others would significantly increase the complexity of the system. The
additional environmental risk in the form of containment and risk of release of the
Emergency Generator fuel would need to be addressed. This alternative does not
address the risks associated with the overloaded cable trays and Motor Control
Centers. When the costs of procuring a new generator, power center and
associated cables are factored in, alternative #2 exceeds the cost of alternative #1
bv $4got.
Option Capital Coct $tart Gomplete
Do nothing $o
Alternative #1 - Replace identified
components
$4,275,000 02t2017 02r2020
Alternate #2 - New external source $4,765,381 02t2017 02t2020
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 13 of 108
Cabinet Gorge Station Seryice
The recommended approach is alternative #1. This project aligns with both Avista's
Safe and Reliable lnfrastructure goal through investment to achieve optimum life-
cycle performance and operational safety and Reliable Resources goal to control a
portfolio of resources that responsibly meet our long term energy needs.
Additionally, alternative #1 provides an avenue for prudent procurement of capital
components by engaging in the competitive bid process.
This project impacts our external customers by ensuring they have predictable,
affordable power. When units go offline unscheduled, we are forced to purchase
power on the open market and/or produce power with our less cost effective
generating facilities. These alternatives come at the risk of higher and/or
unpredictable power costs per MWH for both our customers and shareholders.
Finally, unscheduled outages force hydro plants to spill water which represents a
FERC license violation.
Overloaded Cable Trays
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 14 of 108
Cabinet Gorge Station Seryice
l/ar-Feh17
Design
Closeout Phase 1
Closeout Phase 2
hocurement
Nov-19 Dec-19: lan20, teb-205e¡19 0ct"Apr-19Apr-18, May{8 Jun;18 Jul-18 Aug-18Mar-Feb-18Dec-0d{7. ltiov-Jul-17 Aug-17Apr{7 May-Jun17 l/ay-l9 lrll-Jun-Nov;18 Mar-19Feb-
Construction Phase 1
Construction Phase 2
Alternative #1 Program Cost Flows
Approved
sS soo,oooS 2,1oo,ooo
S 1,475.000S 2oo,ooo
s
sS 4,z7s,oao
Other Costs
S
s
S
S
s
s
s
s
O&M Cost
s
s
s
s
s
s
s
s
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sS 5oo,ooo
s 2,100,000
S L,475,oooS 2oo,ooo
s
sS 4,z7s,oao
Year {¡omrl
2417
2018
2019
2020
Total
Previous
Year 1
Year 2
Year 3
Year 4
Year 5
Year 6
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 15 of 108
Cabinet Gorge Station Service
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Station
Service Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Andy Vickers
gr Contract & Project Mgmt
Date aftlr/r
Date
Tempfate Version: 03107 12017
Director, GPSS
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
EY
Approval
Date
Reason
1.0 Terri Echegoyen 4t14t17 Steve Wenke 4t14t17 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 16 of 108
Generation DC Supplied Sysúem Update
1 GENERAL INFORMATION
Requested Spend Amount $1 ,315,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Glen Farmer
Business Gase Sponsor Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Gommittee or Advisory Group lnformation
The Steering Committee for this project consists of members from the Generation
Production and Substation Support Department including the Hydro Operations &,
Maintenance Manager, the Thermal Operations &. Maintenance Manager, and the
Generation Electrical Engineering Manager. Steering committee members receive project
status updates when there are proposed changes to the program plan and are convened only
in the event of a decision point.
The project stakeholder teams meet on a regular basis to work on the project scope and
planning the project. The stakeholder teams are comprised of the representatives from
Project Management, Engineering (Electrical, Controls, Mechanical & Civil), Operations,
Maintenance and Compliance.
2 BUSINESS PROBLEM
This program supersedes a previous progrqm thqt wqs identifiedfor Battery Bank replacements only.
Traditionally, the Direct Current (DC) system, (aka Battery System) at each generation plant
is used for protection and monitoring of the plant. All the protection relays, breaker control
circuits and monitoring circuits are fed from this source. The source is assumed to always
be on-line and able to supply the critical load for a predetermined length of time.
As technology has evolved, other standalone DC systems that were installed at different
times. Typical plants now have standalone DC Systems for: general station, Uninterruptible
Power Supplies (UPS), governors (electronic turbine speed controllers), communications
and control systems. Each of these systems have a battery bank, battery charger, converters
to supply different voltages, and distribution panels and circuits. As things have changed on
the generating units or in the balance of plant systems, the DC load requirement has
significantly increased and the time dwation for the systems to supply this critical load has
increased. Our current practice is to replace the battery banks per manufactures life cycle
recommendations. This practice is not addressing the additional load added to the systems.
Some of the other issues we have had on the DC systems are the failing of battery cells due
to inconsistent temperature and environmental control needed to maintain these present
battery systems. The system life cycle is 20 years at its normal operating temperature of 77
degrees F. For temperatures fifteen degrees F over the normal operating temperature the life
Business Case Justification Narrative Page 1 of5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 17 of 108
Generation DC Supplied Sysúem Update
cycle is decreased by 50 percent. Component failure, utilization from multiple extended
outages and manufactures quality are other problems we have experienced on these systems.
Finally there are compliance requirements from the North American Electric Reliability
Corporation Q.IERC) for inspections, maintenance and testing of the battery banks to make
sure they are in good working order and will perform when called upon. In order to perform
these inspections and maintenance, and testing needs, it requires either unit or plant outages
to comply with the requirements for multiple DC systems that are now present in our
stations.
To address these multiple issues, a new Generation Plant DC Standard was developed by the
engineering group. The new Generation Plant DC Standard System provides for layers of
back up and redundancy to address current and future capacity needs as well as addressing
maintenance and testing requirements. This Program will replace existing DC systems at
Avista's owned and operated generation plants with a system that meets this new design
standard. The Generation Plant DC Standard will be used as a guide for defining the base
scope ofthe project.
The activity objectives is to order the plant replacements in a time line that will allow for
stages of a project to happen and use our engineering and construction staffing. At each plant
the DC System will be updated to meet the current Generation Plant DC System Standard
and the following:
1. Comply with NERC requirements for inspection and testing.
2. Address battery room environmental conditions to optimize battery life.
3. Replace any legacy UPS systems with an invertor system.
4. Address auxiliary equipment based on life cycle.
5. Hydrogen sensing and fire alarm, eyewash station and lighting.
6. Wall separation of batteries and auxiliary equipment.
7. Install Programmable logic controller monitoring and new operating screens to provide
visibility for operations and maintenance purposes.
8. Provide new distribution panels, disconnect switches, voltage conversion devices for
communications equipment that operate at different voltages.
9. Establish current drawings, construction documents, I/O list, plans, schedules, manuals
and as-builts.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
1. Do nothing - no action $0
2. Address the DC system standards as we
are doing other system or unit upgrades.
$1,315,000/yr 01t2017 12t2030
3. Replace parts as they fail with the goal
of making it like our standard over time.
$200,000/yr 01t2017 12t2037
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 18 of 108
Generation DC Supplied Sysfem Update
4. Establish an independent DC system
replacement program to bring plants to a
standard as quickly as possible.
1,315,000/yr 1120t2017 12120126
The "no action" alternative fails to address the issues associated with our current DC system.
It allows for the scope of any maintenance work to balloon into a large project so if a problem
arises there is not defined plan to address it. This can extend outages and leave the plant
exposed for extended time frames for repairs andlor replacement parts. Upon failure we
would temporarily restore the system back to working condition with the knowledge that we
have to address it later. It places plant equipment at risk if a key element of the DC system
were to fail, particularly the battery system. It also does not provide a means to perform
required NERC testing and does not provide a means to plan for replacements costly. Also,
critical AC loads served from the UPS have increased to the point where we can no longer
get a UPS that is of necessary size. We would have to install more UPS systems, creating
more maintenance work and increasing the NERC testing requirements. It also does not
address any other issues that our design standard is intending to address. V/hile it is a much
higher life cycle cost and operationally impactful option.
Alternative 2 is to address the DC system as part of another capital project. In this case the
scope of the DC system upgrade project is often a lower level effort and is subordinated to
the primary project. The table below shows the cunent upgrade plans. While planning and
scoping management can manage the concerns about making sure the DC Supplied Systems
can be fully addressed, we do not have plans to work through all of the plants. This would
leave the program incomplete.
Alternative 3 to replace parts as they fail doesn't address any of the requirements for
Standards, NERC inspection and testing, or the room itself. The parts fail at different time
and we are subject to more outages. This also requires reaction to a critical system failure.
Clearly replacing failed parts and components is a more costly item than performing planned
work and without a planned effort, deployment of that new Generation Plant DC Standard
would likely take decades. Replacing as components fail and gradually build out to our
standard has the benefit of minimizing the costs of this program. However, it would be
unpredictable would make labor planning impossible. This would also place the plant at a
higher likelihood of forced outages and equipment damages if we wait for failure.
Year Plant Comments Cost
2014 Little Falls DC system was built to our standard, example to follow $700k
20ts Nine Mile Being addressed by Units l&2 project $650k
20ts GCC Just baftery bank replacement.$250k
2016 Monroe Street Doing design in 2015. Basis of design done. Install in 2016 $700k
2017 Cabinet Gorge Address existing problems with UPS system.s700k
2018 Long Lake Do design in conjunction with Unit Upgrades.s700k
2019 Post Falls Do design with plant rebuild $700k
2020 Kettle Falls Steam Turbine & Gas Turbine DC System.$700k
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 19 of 108
Generation DC Supplied Sysfem Update
Alternative 4 is to construct new systems as part of a programmatic effort. This would allow
for prioritized and planned series of projects to upgrade the existing station DC systems to
the Generation Plant DC Standard. This will save time and expense over the life cycle of the
station with the flexibility it provides to address future capacity and maintenance needs, and
the ability to perform NERC required testing. It also has the benefit allowing a schedule to
be established for both the engineering and the installation. Both of these resources are
constrained and it would allow options of contracting or in-house consideration. A typical
schedule to execute is given below. Each planned project would take approximately 16 to
18 months. Added complexity, cost, and time may be needed if extensive work is required
to address the temperature and other environmental issues with the location of the new
battery system.
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Alternative 4 is the recommended approach. This program aligns with Avista's Safe and
Reliable Infrastructure goal through investment to achieve optimum life-cycle performance
and operational safety. In addition, it helps Avista meet its corporate compliance goals.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 20 of 108
Generation DC Supplied Sysfem Update
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Generation DC Supplied
System Update Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Date ?
Business Case Owner
(^
Ê^1
Signature:
Print Name
Title:
Role:Business Case Sponsor
A ire. /r"âPss
Date:
Template Version: 03107 12017
7
t^./I
5 VERSION HISTORY
Ve¡rion lmplemented Revlsion
Dats
Approved
By
Approval
Date
Rgaeon
1.0 Glen Farmer 4t7t2017 Steve Wenke 4t10t2017 lnitialVersion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 21 of 108
So/ar Combustion Turbine Controls Upgrade
I GENERAL INFORMATION
Requested Spend Amount $ 660,000
Req uesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Greg Wiggins
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
l.l Steering Committee or Advisory Group lnformation
The plant uses a plant Budget Committee to evaluate, prioritize, and oversee project
work at the station. This group consists of the Plant Manager, General Foreman,
Plant Mechanic and a Plant Technician.
This project was first identified by plant technicians and plant control operators.
Using past maintenance logs along with an assessment on the current status of the
controls system a Project Request was submitted to the plant Budget Committee for
a rebuild on the major components.
The plant Budget Committee utilizes an in-house Maintenance Project Review
scoring matrix. The review process focuses around Personnel and Public Safety,
Environmental Concerns, Regulatory/lnsurance Mandates, Ongoing Maintenance
lssues, Decreasing Future Operating Costs, lncreasing Efficiency, Managing
Obsolete Equipment and Assessing the Risk of Equipment Failure.
The Maintenance Project Review scoring matrix revealed risks around Ongoing
Maintenance, Decreasing Future Operating Costs, Obsolete Equipment and
Equipment Failure.
The project request and detailed estimate was brought fonruard to Corporate Finance
and Planning Analyst for further analysis. The project was then presented to the
Thermal Operations and Maintenance Manager for plant budget approval.
Approved projects are assigned a project Lead from the plant staff depending on
discipline. Large complex projects may be assigned Engineering staff and/or a
Project Manager from Generation Production and Substation Support Department
to oversee. Project status and updates are discussed at the weekly plant
maintenance meetings.
2 BUSINESS PROBLEM
ln 2002 Kettle Falls Generating Station added a second generating unit at the facility.
The new unit was a skid mounted package combustion turbine Solar Taurus 70 and
(HRSG) Heat Recovery Steam Generator, The 7MW natural gas fired turbine that can
be operated in simple cycle or combined cycle modes depending on energy supply needs.
Business Case Justification Narrative Page 1 ofS
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 22 of 108
Solar Combustion Turbine Controls Upgrade
When operating in simple cycle mode the unit can be started quickly and ramped up to
full load to help meet load demand within 30 minutes. When operating in combined cycle
mode the hot exhaust from the gas turbine is converted to steam by directing the exhaust
to a heat recovery steam generator (HRSG). The HRSG creates medium pressure steam
which is used to preheat water for the wood fired boiler. This increases overall plant by
a 3MW increase in power output on the wood fired steam turbine generator or through an
efficiency improvement by a reduction in wood consumption if the wood fired unit is
already operating at full load.
Operation of the combustion turbine, HRSG and fire protection for the combustion turbine
is done remotely through the Solar TTX controls system. The controls platform is legacy
equipment and the control program is no longer supported by Solar. Additionally, the
installed version of the Allen Bradley control network has not been supported for a number
of years. The Human Machine lnterface (HMl) control system used by operations
functions on Windows 2000 software, which is no longer available for replacement
equipment. The desktop operating computer recently failed and the plant is now
operating without a spare. With this failed HMl, the HRSG cannot be operated from the
local control panel at the turbine enclosure. lf the one remaining HMI were to fail, the
combustion turbine would only be able to be operated in the simple cycle mode as there
would not be any communication with the HRSG system.
The fire protection system is no longer supported from the vendor or Solar Turbines. The
unit will not operate without the fire protection system in service due to insurance
requirements. The unit posted its third and fourth highest forced outage rates in the past
15 years in2013 and 2014. The higher forced outage rate was mostly attributed to
components failing within the fire protection system. The trend to the higher forced
outage rate from the fire protection system is expected to continue higher.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Do nothing $o
1. Replace fire protection system $22e,000 04 201 I 06 2018
2. Replace turbine control hardware $74,000 04 201 B 06 2018
3. Upgrade turbine controls $400,000 04 201 I 06 2018
4. Replace turbine controls and fire protection $660,000 04 2018 06 2018
The Solar Taurus 70 combustion turbine has been in commercial operation for 15 years
and has run an average of 700 hours annually the past four years. The times in which
the unit operates is mostly during the high load demand times in the winter and
summer.
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 23 of 108
Solar Combustion Turbine Controls Upgrade
Solar Taurus Operating Hours
1.,000.00
800.00
600.00
400.00
200.00
0.00
2012 ?_01.3 20L4 20L5 20L6
With an increase in plant operations and increasing forced outage rate, mostly attributed
to control devices failing on the fire protection system, five options were discussed.
Doing nothing will eventually put the combustion turbine in an unreliable and unsafe
mode.
Option 1 to replace the fire protection system hardware and controls was identified as a
safety and reliability issue. The unit will not operate without the fire protection system in
service due to insurance requirements. While trying to work with the fire protection
system manufacture we have constantly been re-directed back to Solar for support as
the fire protection manufacture no longer supports the system. Solar has stated the fire
protection system upgrade would not integrate into the outdated control system without
significant programing. They estimate a cost savings of nearly $60,000 if the fire
protection system is upgraded with the controls system. Total estimated costs
$228,000
Option 2 to replace the HMI with new hardware and newer operating system. Solar has
known documented cases of our outdated operating system failing on newer than
Windows 2000 systems. Solar will not guarantee the controls system will operate if we
lose our only computer and try to deploy the system on a newer computer. Total
estimated cost $74,000
Option 3 to replace the turbine controls software and hardware. The Solar Taurus 70
utilizes proprietary turbine controls. We have reached out to a number of third party
vendors and have been told they can do controls upgrades on Solar units just not the
Taurus 70. The turbine controls inteface with the fire protection system and although
they are separate systems they are very much integrated with each other. Solar has
estimated an additional $60,000 in programing the new controls system to our fire
protection system. Total estimated cost $400,000
Option 4 is to install new software and hardware in conjunction with upgrading the fire
protection system with the newest turbine controls. Transfer to plant is scheduled to be
June 2018 with an estimated cost of $660,000. The project would be sole sourced to
Solar and would have minimal impact on internal resources.
I
20lL
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 24 of 108
Solar Combustion Turbine Controls Upgrade
It is recommended we pursue Option 4. Completion of the project would bring unit
reliability up while maintaining safe operations. Detailed scope of work and estimates
from Solar attached.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 25 of 108
Solar Combustion Turbine Controls Upgrade
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Solar Combustion Turbine
Controls Upgrade Business Case and agree with the approach it presents and that
it has been approved by the steering committee or other governance body identified
in SectÍon 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Date 3t29t17
Greg
Kettle Falls Plant Manager
Business Case Owner
Andy Vickers
Business Case Sponsor
Date:7 7
Template Version: 03107 12017
Director of GPSS
5 VERSION HISTORY
Vers¡ôn lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Greg Wiggins 04t12t2017 Steve Wenke 04112t2017 lnitial version
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 26 of 108
Kettle Falls Stator Rewind
1 GENERAL INFORMATION
Requested Spend Amount $7,930,000
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Steering Committee is comprised of the Manager of Thermal Operations &
Maintenance, the Kettle Falls Plant Manager, the Manager of Contracts & Project
Management, and the Manager of Electrical Engineering for GPSS.
Monthly project status updates will be distributed via email indicating the status of
the scope, schedule and budget of the project.
Steering committee meetings will be coordinated if decisions need to be made, due
to significant changes to the scope, schedule or budget based on unforeseen
circumstances and/or risk identification.
1.2 Gustomers & Stakeholders:
This projects impacts internally the Thermal Operations & Maintenance teams,
including the crews at Kettle Falls, Electrical Engineering and Power Supply. By
providing these stakeholders with a properly maintained generator we are providing
them with reliability of the system.
This project impacts our external customers by ensuring they have predictable,
affordable power. When units go offline unscheduled, we are forced to purchase
power on the open market and/or produce power with our less cost effective
generating facilities. These alternatives come at the risk of higher and/or
unpredictable power costs per MWH for both our customers and shareholders.
2 BUSINESS PROBLEM
Maior Driver:
The General Electric (GE) generator at the Kettle Falls Generating Station is 32
years old (as of 2015, the time of the original funding request) and near the end of
its design life. Field inspections performed by GE and by Avista using industry
standard megger tests have shown a decline in the winding insulation resistance.
These condition reports are attached to this document for information.
Business Case Justification Narrative Page 1 of6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 27 of 108
Kettle Falls Stator Rewind
A 2014 report prepared by the Asset Management group (attached to this
document) demonstrated the prudency of replacing the winding before it fails in
service. Failing in service would significantly extend the outage time and the cost
to repair. Scheduled work to rewind the stator is a proactive measure to ensure
uninterrupted and efficient operations.
Risks:
The consequences of a stator winding failure include lost generation, loss of
renewable energy creditsl, long term interruption of fuel supply, possible collateral
damage to the core and hydrogen cooling system with resulting safety hazards.
Drivinq Metrics:
During the outage of 2007, GE completed a "Generator Inspection Report"
(attached) that found through the High Voltage DC Leakage test:
o Excessive leakage in the "right phase"o The leakage had doubled from the year 2000 test to the year 2007
test.o lndustry analysis has found that when the current leakage more than
doubles in a particular step, it is considered a warning sign that the
leakage may be approaching the point of failure. The leakage jumped
from 4 micro Amps (pA) to 22 ¡tA between these test periods. (See
following graph.)
Figure 1
I We rely on the "green tags" produced from Kettle Falls to meet our l-937 "The Clean Energy lnitiative"
requirements. An unplanned outage due to a system failure could prolong the outage and put us at risk of having
to incrementally procure additional Renewable Energy Credits (REC's) to meet our l-937 energy targets.
Business Case Justification Narrative Page 2 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 28 of 108
Kettle Falls Stator Rewind
2007 GE Generator Megger Test Results
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GE recommended that further DC High Potential (Hi-Pot) testing should not be
conducted due to the risk of potential damage and no preparations made for the
repairs necessary if the unit were to fail the test.
During the outage of 2015 an industry standard Polarization lndex (Pl) "Megger" test
(attached) was conducted. The results shows the Pl falling below 2.0 indicating
problems of winding contamination, moisture ingress (leakage) and/or bulk
insulation damage (conduction).
Success Measures:
Replacement of the existing stator windings and generator wedge system (sketch
shown below) will improve the groundwall insulation resistance, reduce losses, and
will allow the generator stator to operate at a cooler temperature. This will be
validated by a successful completion of a Hi Pot test, and Pl readings in excess of
6.0 for all three phases of the generator during commissioning. In addition, the
Business Case Justification Narrative Page 3 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 29 of 108
Kettle Falls Stator Rewind
operating temperatures of the unit as measured by the generator stator temperature
monitors will show a lower average operating temperature.
Figure 2
Generator Coil lllustration show Winding and Camelback Wedge System
This is the general configuration for Kettle Falls.
Camelback
Wedge System
Stator Core
lnot beino reolaced)
¿*
ãt
Groundwall
nsulation
GE has been commissioned to conduct the work and guarantees the MVA rating at
a given power factor. This guarantee will be validated by a one-time test to be
performed at an appropriate time after completion of the stator rewind and the unit
is capable of full electrical production, but not less than 90 days after the completion
of the stator rewind.
3 PROPOSAL AND RECOMMENDED SOLUTION
Impacts:
The impacts are improved reliance on the system for the Kettle Falls operators and
the Power Supply department. No additional O&M costs will be incurred as a result
of this project nor will any O&M costs be reduced and/or eliminated.
Stator
Windings
(two stacked)Su
Option Capital Cost Start Completo
1. Do nothing $o
2. Stator Rewind (recommended)$7.93M 05 2015 06 2017
3. Generator Upgrade Unidentified 05 2015 06 2017
Business Case Justification Narrative Page 4 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 30 of 108
Kettle Falls Stator Rewind
Alternatives:
Option 1 to "do nothing" would increase our risk of an unplanned and potentially
catastrophic outage. As described, test results conducted over time show a
continuing decline in the winding condition and provides reasonable doubt about the
ability of the present stator winding to continue to operate reliably for any duration
of time.
Option 2 to perform a Stator Rewind has been demonstrated by a study from the
Asset Management group to be a preferred option. This alternative minimizes
outage time and removes the concerns of the failing stator insulation system and
the potential for a catastrophic failure of the generator'
The Option 3 alternative to "upgrade" the generator to produce additional MWH
output was determined to be unfeasible, based on a "Feasibility Analysis" (attached)
conducted by contractor H2E in May 2015.
Risk Mitisation:
This project significantly reduces our risk of an unplanned, and possible
catastrophic, outage by replacing the existing stator winding.
The risk of an unplanned outage increases the cost of the outage and the length of
the outage due to the long lead time for stator bar order, construction and delivery.
By proactively scheduling the rewind of the stator we are reducing the risk of an
unplanned and potentially catastrophic outage. Firm costs and schedules can be
achieved working with suppliers and installers to minimize the costs and time within
acceptable windows.
Timeline:
o Design -2015. Request For Proposal (RFP), Contract Awarded, Planning - 2016o Construction, ln Service -2017
Alisnment with Strateqic lnitiatives:
Safe and reliable infrastructure. This project will improve the ability to sustain safe
systems that deliver energy effectively and efficiently at all times. ln addition, the
Kettle Falls Generating Station, as a biomass fueled generating station, is one of
the responsible resources in Avista's diverse generating portfolio for our customers.
This project will allow for the safe and continued operation of this key resource.
Budqet:
The rough +l- 50o/o estimate for the project began at $7.93M. The current estimate
with +/- 10o/o àccuracy is $5.43M.
Business Case Justification Narrative Page 5 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 31 of 108
Kettle Falls Stator Rewind
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Stator Rewind
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Andy Vickers
dt
Mgr. Contracts & Project Management
Date: Z0t+0U IT
Date:
Tem plate Version : 0212412017
Director GPSS
Business Case Sponsor
5 VERSION HISTORY
Version lmplernented
BY
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Tara Moses 3t28t2017 Steve Wenke 4t6t2017 lnitial version
Business Case Justification Narrative Page 6 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 32 of 108
Little Falls Plant Upgrade
1 GENERAL INFORMATION
Requested Spend Amount $56,100,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
This program is comprised of two layers of Steering Committee Oversight. One
layer of oversight is at the program level and the other layer is at the project level.
The Program Steering Committee is responsible for vetting and approving the
objective, scope and priority of the program. The deliverables for the program are
then reviewed with the Program Steering Committee on a semi-annual basis. Any
significant changes to the program's scope, budget or schedule will be approved
by the Program Steering Committee. The Program Steering Committee is
composed of the Director of GPSS and the Director of Power Supply. This
committee meets semi-annually or as major events create a change order request.
The Project Steering Committee oversees the deliverables of the individual
projects. Each member of the steering committee represents a major stakeholder
in the project. The members are dependent on the respective project but will
include representatives from hydro operations, central shops and engineering. The
Project Steering Committee will approve and changes to the schedule, scope and
budget of the individual project. They also are responsible for approving the
necessary personnel for the completion of the project. This group is engaged on a
quarterly basis.
2 BUSINESS PROBLEM
The existing Little Falls equipment ranges in age from 60 to more than 100 years
old. Little Falls experienced an increase in forced outages over the past six years,
increasing from about 20 hours in 2004 to several hundred hours in the past
several years, due to equipment failures on a number of different pieces of
equipment.
The major drivers for the Little Falls Plant Upgrade are available and reliability. See
the graph below that illustrates the trend line for availability at Little Falls.
Page 1 of5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 33 of 108
Little Falls Plant Upgrade
Plant Availability
1
0.95
t.9
0.85
0.8
2001 2m2 2m3 2W4 2005 2006 2047 2008 2009 2010
Trend Line
Once the business case is complete, a study of forced outages at the plant over a
5 year period could be taken and measured against the pre-construction outage
numbers to determine if plant availability has increased and the business case
objective met.
3 PROPOSAL AND RECOMMENDED SOLUTION
Below is a breakdown of the capital construction cost associated with each
alternative and any ongoing maintenance costs associated with each alternative.
Capital Cost O&M Cost
Status Quo $o $150,000/yr +
Alternative 1 $5,000,000 $20,000/yr +
Alternative 2 $83,000,000 $0
Proposed Alternative $56,100,000 $o
Summarv of alternatives:
Status Quo: Forced outages and emergency repairs would continue to increase,
reducing the reliability of the plant. Each time a generator goes down for an
emergency repair, Avista is forced to replace this energy from the open market
which leads to higher energy costs.
It is expected that the O&M costs would continue to climb as more failures
occurred. This may also require personnel to be placed back in the plant to man
the plant 2417 in order to respond to failures. Again, increasing expenses for the
project with no benefit in performance.
Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 34 of 108
Little Falls Plant Upgrade
Alternative 1: Replace Switchgear and Exciter: This would replace the two items
that are currently responsible for the majority of the forced outages, and then
continue to use the remaining equipment.
This alternative is a temporary fix. One of the generators has a splice and is
expected to fail in the next few years. lf this generator fails before a new generator
is ordered, this generator will be out of service for 2 years. The control system is a
vintage system and is on the verge of a total failure and spare parts are not
available (a few minor system failures occurred in the past 2 years). lf a total
system failure is encountered, it is expected the plant to be down for a year as the
control system is designed, procured and installed.
Alternative 2: Replace all generating units with larger, vertical units capable of
additional output. Avista's Power Supply group evaluated the present value of
larger, vertical units at Little Falls. The increase in present value from larger units
was $20M over a 30 year analysis. The capital construction cost increase from in-
kind replacement to vertical units was $27M.
This present value calculation of benefit did not include risk. Installing new vertical
units would require modification of the powerhouse foundation and presents
serious construction risk. Due to the high construction costs, high risk, and low
payoff NPV, this alternative was abandoned.
Alternative 3 and Proposed Alternative: Replace nearly all of the older and less
reliable equipment with new equipment. This includes replacing two of the
turbines, all four generators, all generator breakers, three of the four governors, all
of the AVR's, removing all four generator exciters, replacing the unit controls,
replacing the unit protection system, and replacing and modernizing the station
service. All major equipment would be procured through a competitive bid process
to help keep construction costs low. Equipment would also be purchased for all
four units at once to help keep costs down.
Add itional J ustification Pronosed Alternati VE:
Because of the age and condition of all of the equipment at the plant, all of the
equipment has been qualified as obsolete in accordance with the obsolescence
criteria tool. The Asset Management tool has been applied to Little Falls and also
supports this project. The Asset Management studies that have been done to date
are still subject to further refinements, but the general conclusions support this
project. There are many items in this 100 year old facility which do not meet
modern design standards, codes, and expectations. This project will bring Little
Falls to a place where it can be relied on for another 50 to 100 years. Finally, this
project will need to be worked in coordination with our lndian Relations group as
the Little Falls project is part of a settlement agreement with the Spokane Tribe.
Milestone Schedule:
January 2010
March 2012
January 2014
January 2014
Program Begins
Exciter & Generator Breaker Replacement Complete
Warehouse Construction Complete
Bridge Crane Overhaul Complete
Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 35 of 108
Little Falls Plant Upgrade
February 2015 Station Service Replacement Complete
February 2016 Unit 3 Modernization Complete
April2017 Unit 1 Modernization Complete
October 2017 Backup Generator lnstall Complete
May 2018 Unit 2 Modernization Complete
May 2019 Unit 4 Modernization Complete
October 2019 Headgate Replacement Complete
Yearly Transfer to Plant:
2013 $3,100,000
2014 $2,000,000
2015 $4,000,000
2016 $16,300,000
2017 $10,400,000
2019 $9,000,000
2019 $13.000.000
Total $57,800,000
Strategic Aliqnment:
The Little Falls Plant Upgrade aligns with the Safe and Reliable lnfrastructure
company strategy. The program will address safety and reliability issues while
looking for innovative, economical ways to deliver the projects.
Customers and .Stakeholclers:
Manager, Hydro Operations and Maintenance
Manager, Spokane River Hydro Operations
Chief Operator, Long Lake and Little Falls HED
Mike Magruder
Alexis Alexander
Kevin Powell
Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 36 of 108
Little Falls Plant Upgrade
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Little Falls Plant Upgrade
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Andy Vickers
Mgr Contract & Project Mgmt
Date btY)Ylt
Date:2
Template Version: 0212412017
Dir Gen Prod Sub Support
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Brian
Vandenburq
02t14t2017 Steve
Wenke
04t10t2017 lnitialCreation
Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 37 of 108
Long Lake Plant Upgrade
I GENERAL INFORMATION
Requested Spend Amount $46,000,000
Req uesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
This program is comprised of two layers of Steering Committee Oversight. One layer
of oversight is at the program level and the other layer is at the project level.
The Program Steering Committee is responsible for vetting and approving the
objective, scope and priority of the program. The deliverables for the program are
then reviewed with the Program Steering Committee on a semi-annual basis.Any
significant changes to the program's scope, budget or schedule will be approved by
the Program Steering Committee. The Program Steering Committee is composed of
the Director of GPSS, Director of Environmental Affairs, and the Director of Power
Supply. This committee meets semi-annually or as major events create a change
order request.
The Project Steering Committee oversees the deliverables of the individualþrojects.
Each member of the steering committee represents a major stakeholder in the
project. The members are dependent on the respective project but will include
representatives from hydro operations, central shops and engineering. The Project
Steering Committee will approve and changes to the schedule, scope and budget of
the individual project. They also are responsible for approving the necessary
personnel for the completion of the project. This group is engaged on a quarterly
basis.
2 BUSINESS PROBLEM
The existing Long Lake equipment ranges in age from 20 to more than 100 years
old. We have experienced an increase in forced outages at Long Lake over the past
six years, almost zero in 2011 and increasing every year since then. This is caused
by equipment failures on a number of different pieces of equipment. Specifically, the
turbines are thrusting too much (a sign of significant wear), including a failure in
2015. The 1990 vintage control system isfailing and onlysecondary markets can
support this equipment.
The original generators consist of a stator frame, stator core, stator winding, and
rotorfield poles. Theywere originally rated at12 MW's. ln the late 1940's, the
height of the dam was raised 16 feet which resulted in more operating head for the
Business Case Justification Narrative Page 1 of y'
\
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 38 of 108
Long Lake Plant Upgrade
generating units. A forced air cooling system for the generators was added to the
plant at that time to accommodate the increase in output from 12to 17 MW's due to
the increased head. In the 1960's, the stator windings on all of the units were
replaced and the rating of the generators, along with the forced air system allowed
for the units to operate at the higher 17 MW output.
ln the 1990's, the original turbine runners were replaced and upgraded. The
improvement in turbine runner efficiency resulted in still another increase in unit
output. Since the mid-1990's, the generators have been operating with a maximum
output of 22 to 24 MW's. The generators are currently operated at their maximum
temperature which stresses the life cycle of the already 50+-year-old winding.
lnspections of other components of the generator show the stator core is "wavy".
The core lamination steel should be in straight. The "wave" pattern is a strong
indication of higher than expected losses are occurring in the generator. Finally,
maintenance reports have identified that the field poles on the rotor have shifted
from their designed position very slightly over the years. While there can be several
causes of this movement, it is speculated that it is due to the high operating
temperatures of the generator. This highlights the first driver for the program,
reliability.
With the increase in generator output, the output of the generator step up
transformer (GSU) has also increased to its rating. These GSU's are now running
at the high 65C temperature which is a concern. As these GSU's are more than 30
years old and operating at the high end of their design temperature, these are now
approaching their end of useful life and need to be replaced proactively rather than
wait for a failure.
The other major driver for the program is safety. The switching procedure for moving
station service from one generator to the other resulted in a lost time accident and a
near miss in the past 5 years. ln addition, the station service disconnects represent
the greatest arc-flash potential in the company. This area is roped off and substantial
safety equipment is required to operate the disconnects. This project will reconfigure
this system to eliminate requiring personnel to perform this operation and avoid the
arc-flash potential area.
Below is a graph of Forced Outage Factor for Long Lake HED from Avista's Asset
Management Plan.
Business Case Justification Narrative Page 2 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 39 of 108
Long Lake Plant Upgrade
Long Lake HED Forced Outage Factor
-leLong Lake HED Unit L
'rLong Lake HED Unit 3
+Long Lake HED Unit 2
** Long Lake HED Unit 4
3s%
30%
25%
20%
t5%
t0%
5%
o%
2009 20r0 20Lt 20L2 2013 20L4 2015
I
I
I
29MW & smaller ro units
The below graph shows the O&M cost at Long Lake for the past 11 years. The
trendline is increasing due to increasing repairs to aging equipment.
O&M Cost at Long Lake
1,000,000
900,000
800,000
700,000
600,000
500,000
400,000
300,000
200,000
r"00,000
0 lr
200s 2006
I
2009
ll
2007 2008
lr II
2010 2011 2012 2013 201,4 201-5
The above graph shows the O&M cost at Long Lake for the past 11 years. The trendline is
increasing due to increasing repairs to aging equipment.
Business Case Justification Narrative Page 3 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 40 of 108
Long Lake Plant Upgrade
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital
Goet
Requested
$tart
Roquested
Complete
Do nothing $o N/A
Recommended: Replace Units ln-Kind $46M 05t2018 06t2024
Alternative 1: lnstall four new 60MW vertical units $173M 05t2018 04t2023
Alternative 2: Construct one unit powerhouse $144M 05t2018 07t2021
Alternative 3: Construct two unit powerhouse $276M 05t2018 11t2021
Alternative 4: Replace Units ln-Kind $46M 05t2018 06t2024
Do Nothing: Continue to run plant and repair as necessary
The Long Lake powerhouse would continue to operate as it has for the past 10
years. O&M costs would continue to rise. ln an additional 10 years, if the trend
continues, average O&M costs will rise from $285k in 2005 to $590 in 2014 and
projected to be $900k in 2024. Due to the condition of the generators, it is likely that
one of the generators or another piece of major equipment will fail and permanently
disable equipment, increasing forced outage numbers.
Alternative 1: lnstall four new 30MW vertical units
This alternative would be to replace the four existing units in the powerhouse with
four new 30 MW Kaplin units. Significant civil, electrical and mechanicalwork would
be required, in addition to powerhouse access.
The increased yearly generation would be 114,000MWh. Using $30/MWh
(extremely conservative number) the rough yearly benefit to Avista is $3.4M. The
payoff period is greater than 30 years and therefore this alternative was abandoned.
Alternative 2: Construct one unit powerhouse
Instead of upgrading the current powerhouse, this alternative is to construct a new
powerhouse with a single, 68MW next to the existing powerhouse, using the saddle
dam (also referred to as the "arch dam") as an intake. This alternative would only
use the old powerhouse during high flows, when flows exceeded the new unit's
capacity. Additional funds would be required to upgrade, even at a minimum level,
to address some of the failing components.
The increased yearly generation would be 170,000MWh. Again, using $30/MWh the
rough yearly benefit to Avista is $5.1M. The payoff for this is 30 years. Again, since
this cost does not include the additional work required in the plant and the cost of
the risk associated with modifying the saddle dam, this alternative was abandoned.
Alternative 3: Construct two unit powerhouse
Another option to build a new powerhouse is to construct a new powerhouse with
two, 76MW units next to the existing powerhouse. This alternative would also use
the saddle dam as an intake. This alternative would only use the old powerhouse
Business Case Justification Narrative Page 4 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 41 of 108
Long Lake Plant Upgrade
during extreme high flows, minimizing the need to perform any upgrades to the old
plant.
The increased yearly generation would be 258,000MWh. Using $30MWh, the rough
yearly benefit to Avista is $7.7M. The payoff would be greater than 30 years and
therefore the alternative was abandoned.
Alternative 4 and Recommended Alternative: Replace units in-kind
This alternative would replace the existing major unit equipment (generator, field
poles, governors, exciters, generator breakers) with new equipment.
Over the past 11 years, the average O&M spend at Long Lake was $470k, with the
low being g262kand the high year being $944k. ln addition, the O&M cost is trending
upward. After the upgrade, the expected O&M cost is $200k/year, an average
reduction of $270klyear.
Milestone Schedule:
\llay 2017 Project Kickoff
Sept 2018 Vertical Elevator Replacement Complete
Dec 2018 Bridge Crane Replacement Complete
Nov 2018 Sewer System Overhaul
Oct 2019 Access Road Overhaul
Dec 2019 Facility Upgrades
Oct 2019 Station Service Replacement
Apr 2021 Unit 1 Overhaul
Oct2020 Air System Overhaul
Apr 2022 Unit 2 Overhaul
Apr 2023 Unit 3 Overhaul
Sep 2022 Sump System Overhaul
Sep 2022 Spillway Controls Replacement
Apr 2024 Unit 4 Modernization
Aug 2024 Control Room Remodel
Yearly Transfer to Plant:
2019 $3,750,000
2019 $5,500,000
2020 $250,000
2021 $21,100,000
2022 $8,050,000
2023 $7,600,000
2024 $8,300,000
Total $45,750,000
Strategic Alisnment:
Business Case Justification Narrative Page 5 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 42 of 108
Long Lake Plant Upgrade
The Long Lake Plant Upgrade aligns with the Safe and Reliable lnfrastructure
company strategy. The program will address safety and reliability issues while
looking for innovative, economical ways to deliver the projects.
Customers and Stakeholders:
Manager, Hydro Operations and Maintenance
Manager, Spokane River Hydro Operations
Chief Operator, Long Lake and Little Falls HED
Business Case Justification Narrative Page 6 of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 43 of 108
Long Lake Plant Upgrade
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Long Lake Plant Upgrade
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
b idt
Mgr Contract & Project Mgmt
Business Case Owner
Date: futf 0y th
Date e/
Template Version: 0212412017
Signature:
Print Name
Title:
Role:
Andy Vickers
Dir Gen Prod Sub Support
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Brian
Vandenburq
03t22t2017 Steve
Wenke
0411012017 lnitialCreation
Business Case Justification Narrative PageT of 7
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 44 of 108
N i ne M ile Rehabil itation
I GENERAL INFORMATION
Requested Spend Amount $ 1 19,044,755
Req uesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Failed Plant & Operations
1.1 Steering Committee or Advisory Group lnformation
The Steering Committee for the Nine Mile Rehabilitation governs the scope,
schedule, and budget requests made by the stakeholder group when creating the
deliverables and requirements for any sub projects. Each project may have the
same, partial, or different members as selected by the Program Steering Committee.
ln general, Power Supply is represented by its Direction, Generation is represented
by its Director, and Hydro Licensing & Environmental is represented by its Director.
2 BUSINESS PROBLEM
Both Units I and 2 at Nine Mile have mechanically failed, and are no longer able to
generate electricity per our FERC license. These issues are a result of aging
equipment, reservoir sedimentation, and damage to submerged equipment from the
sediment. A FERC license amendment has been received to replace these units. ln
addition to the loss of generation for customers, failure to return the units to service
may put the existing Spokane River License at risk. Requirements for Renewable
Energy Credits (RECs) as part of Avista's Resource portfolio make this an opportune
time increase REC availability, restore the powerhouse to full capacity and
rehabilitate the su rrou nding facility.
3 PROPOSAL AND RECOMMENDED SOLUTION
Following the failure of Unit 1, Unit 2, and the subsequent turbine failure in Unit 4,
an assessment of the Spokane River Plants was performed to establish the
prudency of work within the Spokane River, prior to commencing work at Nine Mile.
Many alternatives were generated, including:
. Rehabilitation or new construction of powerhouse at Post Falls. Construction of new powerhouse at Upper Fall. Construction of new powerhouse or spillway modification at Monroe Street. Rehabilitation or new construction of powerhouse at Nine Mile. Rehabilitation or new construction of powerhouse at Long Lake
Business Case Justification Narrative Page 1 of4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 45 of 108
Nine Mile Rehabilitation
A Likert Scale was developed by the team to evaluate each alterative against the
following criteria.
. AlternativeDevelopment. Financial. Energy. Regulatory lnfluences. Operation and Maintenance. Transmission System lmpact. Stakeholders. Risk ldentification. Customer and Community lmpact
Following the group evaluation of all proposed alternatives, the Project Team
determined the only plant that warranted further evaluation at that time was Nine
Mile due to the failed equipment, and ongoing operational and maintenance issues
at the 100 year old facility. Focusing on the Nine Mile plant allowed for further
evaluation of and reduced the number of fully evaluated alternatives to two:
Based on the criteria used by the Project Team to evaluate the Nine Mile
Alternatives, Replacement of Units 1 and 2, rehabilitation of Units 3 and 4, and
modify the Sediment Bypass System received the best score primarily due to project
economics and likelihood of regulatory agency approval. Do nothing was eliminated
due to the risk to our licenses.
The recommended alternative consists of a series of steps or phases, beginning in
November 2012 and continuing through2019. The key elements are:
Unit 1 and 2 Upgrade to Seagull Turbines:. Units, including Turbines, Bulkheads, Generators, Switchgear. Control and Protection Package including Excitation and Governors. Powerhouse including Station Service, Ventilation, lntakes. Substation and Communications work. Site Work including cottages and warehouse. Rehabilitate lntake Gates and Trash Rack
Unit3and4Overhaul:. Overhaul including Runners, Thrust Bearings, Switchgear
Option Gost 9tarl Complete
Do nothing $o
Replace Units 1 and 2, rehabilitate Units 3 and 4, and modify the
Sediment Bypass System $ 70.8 2012 2019
A new five'unit 60 MW powerhouse located on the same footprint
as the existing powerhouse, which would be demolished.$ 192.7 2012 2027
Business Case Justification Narrative Page 2 of 4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 46 of 108
N ine M i le Rehabilitation
. Control and Protection Package including Excitation and Governors. Rehabilitate Intake Gates and Trash Rack
Plant Rehab
. Sediment Bypass and Debris Handling System. Rehabilitation of the existing 100 year old Powerhouse Building
At completion, the powerhouse production capacity will be increased, units will
experience less outages and reduced damaged from the sediment, and the failing
control components will be replaced. Spending is expected to occur between 2012
and 2019.
2012 $10,758,313
2013 $10,794,355
2014 $26,059,264
2015 $26,890,094
2016 $13,628,862
2017 $11,800,000
2018 $8,575,000
2019 $7,322,000
A complete evaluation of this alternative's review, the analysis process, and the risks
associated with the each is available in the attached material. Construction of a new
powerhouse was eliminated due to lengthy permitting efforts, and increased risk
surrounding unknown construction efforts.
Business Case Justification Narrative Page 3 of 4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 47 of 108
Nine Mile Rehabilitation
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Rehabilitation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
b dt
Mgr Contract & Project Mgmt
Business Case Owner
Date: ZOtV0ytr
Date tu/
Tempfate Version: 0212412017
Signature:
Print Name
Title:
Role:
Andy Vickers
Dir Gen Prod Sub Support
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Nathan Fletcher 03128117 Steve Wenke 0410712017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 48 of 108
Noxon Station Serurce
1 GENERAL INFORMATION
Requested Spend Amount $3,810,118
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Gategory Project
lnvestment Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The advisory group for this project consists of members from the Generat¡on
Production and Substation support department including the Director of GPSS, the
Manager of Hydro Operations & Maintenance, and the Manager of Electrical
Engineering for GPSS. Advisors are provided with monthly project status reports
but, are only convened in the event of a necessary decision point.
The project/stakeholder team meets on a more regular basis (at least monthly) to
work on the project's scope, schedule and budget. The projecUstakeholder team is
comprised of representatives from the various engineering groups (electrical,
controls, mechanical) and operations.
2 BUSINESS PROBLEM
All generation facilities require Station Service to provide electric power to the
plant. Station Service components include Motor Controf Centers, Load Centers,
Emergency Load Centers and various breakers. Station Service is an elaborate
system with multiple built-in redundancies designed to protect the plant's electrical
operation.
Upgrades and replacement of some of the Noxon 480V Station Service equipment
have occurred since the late 1990s. However, some of the planned projects were
never completed. ln the fall of 2013, both an overcurrent coordination and load
flow studyl were completed for the Noxon 480V Station Service in response to an
electrical overcurrent coordination issue. These studies found that a majority of the
components require replacement due to electrical capacity and rating issues
stemming from the added loads at the plant and the growth of the electric system
in the 50 years of service.
l These studies can be made available upon request
Business Case Justification Narrative Page 1 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 49 of 108
Noxon Station Service
This project seeks to create a more reliable Station Service system in order to
avoid forced outages and to modernize the electrical delivery system in the plant.
Additionally, this effort will provide remote operation and monitoring capabilities,
incorporate previously incomplete service expansions, support future system
expansion, improve operator safety and ensure regulatory compliance.
lf no action is taken, there is a risk of catastrophic switch gear failure and generator
unit forced outages for up to a year. Additionally, forced load shedding under
certain operational scenarios could be necessary.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Gomplete
Do nothing $o
Alternative 1 - Replace overrated and
marginal function equipment and cables
$3,110,118 12t2013 10t2017
Alternative 2 lnstall Current Limiting
Reactors
$800,000 12t2013 10t2017
Alternative 3 lnstall a new station service
source from outside the plant (feeder
extension)
$4,000,000 12t2013 10t2017
Do Nothing: doing nothing is an option. However, if components do fail, due their
age, replacements are not available. Addressing such failures in an emergency/ad
hoc situation would increase the cost and extend the outage time. This option does
not provide any capacity for future loads.
Alternative #1 would replace the following components:
o Station Service Transformers A & B
o 20004 Bus Ducts from Station Service transformers to Power Distribution
Centers A & B
o Power Distribution Centers A & B
o Tie Bus that connects Power Distribution Centers A & B
o Main supply breakers to Motor Control Center 1, 2 and 3 and installing new
monitoring and control of Motor Control Center starters
. Complete replacement of Motor Control Center 4
o Install a Programmable Logic Controller (PLC) to monitor and control Station
Service from a central operating room.
. Integration of 1000 kVA Emergency Generator into Programmable Logic
Controller monitoring and control
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 50 of 108
Noxon Station Sen¡ice
. Upgrade the existing Emergency Load Center to integrate with the balance
of the station service system
o Address arc flash rating and improve load flow analysis and coordination Add
metering to each Station Service Power Center and Emergency Generator.
Alternative #2 involves the installation of current limiting reactors on the
transformers which would address the breaker sizing issues but, would not
address the reliability and expansion components required by the project
objectives. As such, it was dropped from consideration.
Alternative #3 would bring in an external source for Station Service which would
achieve the reliability objective, but would not address the anticipated future load
requirement on MCC4. As such, it was dropped from consideration.
The recommended approach is alternative #1. This project aligns with both Avista's
Safe and Reliable lnfrastructure goal through investment to achieve optimum life-
cycle performance and operational safety and Reliable Resources goalto control a
portfolio of resources that responsibly meet our long term energy needs.
Additionally, alternative #1 provides an avenue for prudent procurement of capital
components by engaging in the competitive bid process.
This project impacts our external customers by ensuring they have predictable,
affordable power. When units go offline unscheduled, we are forced to purchase
power on the open market and/or produce power with our less cost effective
generating facilities. These alternatives come at the risk of higher and/or
unpredictable power costs per MWH for both our customers and shareholders.
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 51 of 108
Noxon Station Seryice
Feb-15 lul-15'
Phase 2
0d-17lVlar-15,
Procurement
Mar-16 0d-lan-li FeþDec-Nov-Feb-Dec Janiul-Jun-Jan-16 Feb"16,Mlar-0d-15 Nov{5 Dec-
Construdion Phase 1
Phase 2
Phase 1
Alternative #1 Program Cash Flows
NOTE: $700k in additional funds requested in Q4 2016.
118,208s
s
s
3,LLO,LLgs
s
343,228s
r,477,LO6s
7,r7L,577s
s
s
s
s
s
s
s
s$
S
s
s
s
s
s
s
s
S 343,228
5 2,177,1065 t,ttt,s77
S 118,208
5
s
S 3,810,118
Previous
2015
20L6
20L7
20L8
20L9
2O2A+
Total
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 52 of 108
Noxon Station Service
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Station Service
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Mgr Contract & Project Mgmt
Date: 20/ \Ay/7
Date //
Template Version : 03107 12017
t
Andy Vickers
Director - GPSS
Business Case Sponsor
5 VERSION HISTORY
Jacob
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Terri Echeqoven 4t14t17 Steve Wenke 4t14t17 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 53 of 108
Peaking Generation Business Case
I GENERAL INFORMATION
Requested Spend Amount $500,000 per year
Req uesting Organization/Department Generation Production and Substation Support
Business Case Owner Thomas Dempsey
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Program
Driver Failed Plant & Operations
l.l Steering Committee or Advisory Group lnformation
This business case request is for Avista's Peaking Generation thermal plants,
Boulder Park Generating Station, Northeast Combustion Turbine and Rathdrum
Combustion Turbines. The purpose of this program is for these plants to keep their
operating expenses as low as possible and to ensure start and operating reliability
is achieved by providing funding for specific efforts to allow the plants to accomplish
that objective.
Smaller and emergent projects planned for these facilities are identified and
prioritized during monthly maintenance meetings, and approved by the Manager of
Thermal Operations and Maintenance.
2 BUSINESS PROBLEM
Various projects for Boulder Park Generating Station, Northeast Combustion
Turbine and Rathdrum Combustion Turbines are necessary to ensure continued
safe, low cost, reliable and compliant electrical generation for Avista's electric
customers. Work includes replacement of items identified through asset
management decisions and programs necessary to maintain reliable and low
operating costs of these plants. At times these plants are needed by Avista's Power
Supply and System Operations group to start and operate in an emergency
situation, where the electrical output is needed in a short amount of time. There
have been times that have been identified by plant operations and tracked by
Avista's asset management metrics reports, where start reliability and forced
outages occur on a higher than acceptable occurrance. Some projects under this
business case are completed to improve the start reliability of these facilities. As
this program proceeds, it is expected that forced outage rates and forced derates of
these facilities will decrease to a level one standard deviation less than the current
average resulting in more economic benefits for the project.
The projects that are opened under this business case are not known in advance.
Most of the individual projects are small in nature and are required due to regulatory
or environmental requirements, emergent safety items, or for continued reliable
operation. Examples of recent expenditures under this program include:
Business Case Justification Narrative Page 1 of3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 54 of 108
Peaking Generation Business Gase
o Boulder Park - Emission Programmable Logic Controller replacement -
allows remote monitoring of air emission to remain compliant with permit.
(regulatory or environmental)
o Boulder Park - Replace the start air compressors - air used for start up of
the engines (reliable operation)
o Northeast Combustion Turbine - Replace start system air compressors - air
used for start up of the turbine (reliable operation)
o Northeast Combustion Turbine - Add sewage holding tank - replace
antiquated sewage management system (regulatory or environmental)
o Rathdrum Combustion Turbines Replace the Carbon Dioxide fire
extinguishing system controllers - system utilized in case of an emergency
in the combustion turbine area (safety)
o Rathdrum Combustion Tur"bines - Continuous Emission Monitoring System
replacement - used to monitor and record air emission when the combustion
turbines are on line (regulatory or environmental)
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital
Coet
Start Complete Risk
Mitigation
As proposed $500,000 Ongoing, required for operation
Unfunded Program
This program is necessary to sustain or improve the existing operating costs for
Boulder Park Generating Station, Northeast Combustion Turbine and Rathdrum
Combustion Turbines. Work includes replacement of items identified through asset
management decisions and programs necessary to maintain reliable and low
operating costs of these plants. The Peaking Generation Business Case is
reassessed for adjustments on a 5 year cycle.
A 5 year historical graph of expenditures is attached to help assess future capital
funding for the Peaking Generation plants. This spending pattern indicates the
diligence that is applied to capital request as managed by the Peaking Generation
management team. As mentioned above, there is opportunity to adjust this amount
every five years.
Peaking Generation Capital Program
$s92,863 s488,646 S52o,B9L$s00,000 s
st,000,000
3s8,049I
20Í2
582,773 I$o
2014 20L6
Business Case Justifìcation Narrative
2013 2015
Page 2 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 55 of 108
Peaking Generation Business Case
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Peaking Generation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
áfu
Thomas oén6ev
Date
Date:7
Tempfate Version: 0212412017
(
Business Case Owner
Andy Vickers
Dìrucfèr 6Psç
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revieion
Date
Approved
By
ABproval
Date
Reason
1.0 Mike Mecham 04t07t2017 Jacob Reidt 04t17t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 56 of 108
Posf Falls HED Redevelopment Program
I GENERAL INFORMATION
Requested Spend Amount $58,100,000- +l- 30%
Req uesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Gase Sponsor Andy Vickers
S ponsor Organ ization/De partment Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Post Falls HED Redevelopment program is monitored by a steering committee
consisting of the Director of Environmental Affairs, the Director of Generation
Production and Substation Support, the Director of Power Supply, and the Vice
President of Energy Resources. This group is provided quarterly updates on project
cost and schedule status. This group is also included in decisions on significant
changes in scope.
The program is actively overseen by a stakeholder group that consists of
representatives from Power Supply, Ass6et Management, Licensing and
Environmental, and Generation & Production. This group meets at least monthly to
receive progress reports, cost and schedule updates, and is presented with project
risks and proposed mitigations to those risks. This group is also included on
decisions on significant and modest changes in scope.
The project is led by a Project Manager. The Project Manager (PM) has a team of
subject matter experts (SME) in a variety of areas to help them execute the project
plan. Under the management of the PM and SME's, weekly and daily decisions are
made to determine the most prudent course of action and to actively monitor
progress of the project.
This PM is also assisted by an Advisory Group consisting of GPSS Engineering
Managers, Maintenance Managers, and other administrative GPSS support
personnel.
2 BUSINESS PROBLEM
The Post Falls HED started operation in 1906 and has been operating continually
since that time. The generators, turbines, and governors (turbine speed controller)
are original equipment and are still in service. The brick powerhouse with riveted
steel superstructure is has not changed since the plant was constructed. Over
time, it has been re-roofed and the intake area has had some major work, but the
appearance of the project remains largely the same as when it started operation
more than 110 years ago.
Business Case Justification Narrative Page 1 of6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 57 of 108
Posú Falls HED Redevelopment Program
Photo showing interior of present Powerhouse
While the plant is still producing, the generating equipment, protective relaying, unit
controls, and many other components of the operating equipment are mechanically
and functionally failing. The turbines are estimated to be 50% efficient contrasted to
modern turbines which can exceed 90% efficient. The existing governors have had
patchwork repairs due to lack of replacement parts and while they do allow for unit
control, they are ineffective in their response to system disturbances. Generator
voltage controllers, protective relays, and unit monitoring systems all have a similar
story of marginal functionality.
The units are exhibiting signs of failure. Attached are recent reports for Unit 1, Unit
4 and Unit 6 that describe some of the problems encountered during last
maintenance on Unit 1, and the current operational directive to de-rate Unit 4 and
Unit 6 due to their mechanical condition.
Because of the age of the plant, it presents some safety issues that have evolved
over time. The access port for crews to access and maintain the turbine runners is
too small to allow for any type of backboard or stretcher to exit the turbine area in
the event a worker would be injured. The castings used to create the turbine water
case do not allow the opening to be increased without risk of permanently damaging
the water case and leaking. For this reason, crews can no longer access the
turbines to maintain the runners. This has been the case for nearly a decade.
Business Case Justification Narrative Page 2 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 58 of 108
Posú Falls HED Redevelopment
Photo showing safety issue due to restricted access to turbine area
The opening will not allow a backboard or stretcher to the area for emergency
evacuation
Additionally, control modifications done in the late 1940's place the primary
generator breakers inside the control room. This presents and unacceptable arc
flash hazard to operating and maintenance personnel. While either the operation
desk or the switchgear can be relocated to address this issue, this work would cost
several million dollars and would not address some of the other issues associated
with the plant.
Photo showing proximity of switchgear to Operators Station
(Operator Chair is indicated by arrow)
Business Case Justification Narrative Page 3 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 59 of 108
Post Falls HED Redevelopment Program
Finally, the Post Falls project has a number of critical operational requirements that
support key recreational facilities, fishery, and other FERC license requirements.
The Post Falls dam must provide minimum flows during summer months to support
fishery habitat downstream. lt is also subject to restrictions on how fast the flows
through the project can change in order to meet downstream flow requirements.
The present plant controls marginally provide the precision needed for this control.
To address water quality issues during high river flow seasons, unit and spillway
controls must follow certain procedures to minimize Total Dissolved Gas creation in
the river system. ln addition, flows through the project provide water at the
recreational site known as Trailer Park Wave. Upstream of the dam is the Spokane
River and Lake Coeur d'Alene which are significant regional recreational resources
that rely on the water control at Post Falls to maintain the water levels during the
summer months.
Finally, there is a City Park and boat launch that is integralwith the immediate
upstream reservoir. Safety requirements have been implemented that require all
spillgates at the project be closed before boaters are allowed to use the boat launch
and recreate in the reservoir immediately upstream. Flows that would normally go
through the plant need to be passed through the spillgates instead because of the
unreliability of the generating units, extended maintenance outages, unit de-rates,
and forced outages. This requires the boat launch opening to be delayed or in some
cases closed on an emergency basis until flows subside or the generating unit can
be returned to service.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital
CoEt
Start Complete Rlsk
Mitigatlon
1. Remove the existing six generating
units and equipment and replace
them with new units, control and
monitoring equipment, and balance
of plant equipment. This is to be
done within the present building
structure.
$58.1M 2017 and going forward
The estimates in the above table for capital costs should be construed to be +/-
30o/o for each of the options.
ln an effort to determine a prudent course of action to address the Post Falls project,
a significant Assessment Study was performed. This assessment considered a
number of different options that might address the issues described above. The
report of this assessment is attached to this document. This assessment concluded
that the most prudent course of action was to redevelop the site by keeping the
existing powerhouse and location.
Business Case Justification Narrative Page 4 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 60 of 108
Post Falls HED Redevelopment Program
Subsequently, a Feasibility Study was undertaken to evaluate different alternatives
that could be done to redevelop the existing powerhouse. These include
replacement of the present units with some new parts and pieces and modernizing
the plant to the extent possible. lt also considered a full redevelopment which would
effective remove all of the existing equipment and replace it with new - still retaining
the existing powerhouse structure. This Feasibility Study recommended that the
project be redeveloped by shutting down the plant, removing the old equipment,
and replacing it with new. This report on the Feasibility Workshop is attached to this
document.
Finally, a team of Avista made up of personnel from the GPSS department,
Licensing and Environmental, Power Supply, Asset Management, and
Procurement convened a series of meetings to analyze the results of the Feasibility
Study recommendation and explore its conclusions and assessed how the
recommended solution addressed the issues such as equipment reliability,
personnel safety, and risks associated with potential disruption of fishery and
recreational needs. Significant financial analysis was performed by the Power
Supply group in support of this effort to ascertain the most attractive alternative that
addressed the issues. This was summarized in a final presentation in April of 2016.
This was presented to the steering committee identified above. That presentation
is attached to this document.
The final conclusion of all of this effort recommended that a full replacement of the
existing units and other powerhouse equipment be replaced in their entirety with
new equipment. lt was estimated that the project would cost $58,100,000 (+l- 30o/o).
It was also demonstrated that due to a shorter construction period, it is more
beneficial to shut down the plant during this reconstruction. lt was estimated the
entire project would take five years once it was initiated. This decision was recorded
in a summary message to a group of stakeholders and is attached to this document.
This work will replace the existing six 1 10 year old generating units with six new
variable blade turbine generator units. Work will also include needed ancillary
replacements and powerhouse remediation to attain a 50 year lived project. In
addition, the efficiency of the new generating equipment will result in an
improvement in output capacity and energy. This project will result in an estimated
40o/oincrease in capacity and 15% increase in energy and reduce future major
maintenance costs.
Business Case Justification Narrative Page 5 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 61 of 108
Posf Falls HED Redevelopment m
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Post Falls HED
Redevelopment Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Reidt
Business Case Owner
An Vickers
Pç9
Business Case Sponsor
Date: '/¿)7c)
Date
Template Version: 0212412017
5 VERSION HISTORY
Version lmplernented
By
Revision
Date
Approved
By
Approval
Date
R.eaeon
1.0 Steve Wenke 04t1912017 Jacob Reidt 04t19t2017 lnitialversion
Business Case Justification Narrative Page 6 of 6
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 62 of 108
Certified Rebuild D10R CAT Dozer
I GENERAL INFORMATION
Requested Spend Amount $ 700,000
Req uesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Greg Wiggins
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The plant uses a plant Budget Committee to evaluate, prioritize, and oversee project
work at the station. This group consists of the Plant Manager, General Foreman,
Plant Mechanic and a Plant Technician.
This project was first identified by plant mechan¡cs and equipment operators. Using
past maintenance logs along with an assessment on the current status of the
machine a Project Request was submitted to the plant Budget Committee for a
rebuild on the major components.
The plant Budget Committee utilizes an in-house Maintenance Project Review
scoring matrix. The review process focuses around Personnel and Public Safety,
Environmental Concerns, Regulatory/lnsurance Mandates, Ongoing Maintenance
lssues, Decreasing Future Operating Costs, lncreasing Efficiency, Managing
Obsolete Equipment and Assessing the Risk of Equipment Failure.
The Maintenance Project Review scoring matrix revealed risks around Safety,
Ongoing Maintenance, Decreasing Future Operating Costs and Equipment Failure.
The project request and detailed estimate was brought fonruard to Corporate Finance
and Planning Analyst for further analysis. The project was then presented to the
Thermal Operations and Maintenance Manager for plant budget approval.
Approved projects are assigned a project Lead from the plant staff depending on
discipline. Large complex projects may be assigned Engineering staff and/or a
Project Manager from Generation Production and Substation Support Department
to oversee. Project status and updates are discussed at the weekly plant
maintenance meetings.
2 BUSINESS PROBLEM
Kettle Falls Generation Station utilizes two D10 CAT dozers to move nearly 500,000
green tons of waste wood around the storage area each year. Two primary tasks the
Fuel Equipment Operators use the dozers throughout the day for is moving new material
out into the inventory storage area and bringing in waste wood fuel to be burned for the
plant operations.
Business Case Justification Narrative Page 1 of5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 63 of 108
Certified Rebuild D10R CAT Dozer
The fuel yard operates 24-7 receiving wood waste from over 20 contracted sawmills.
Semi-trucks move product out of the mills to the plant where the wood waste is moved
via a conveyor system. The dozers move the material out from underneath the conveying
system to the storage pile. lf the dozers break down and material is not moved out from
the conveying system, trucks will begin to back up in the yard and possibly create issues
on H\A/Y 395. On average the plant receives 60-80 semi-truck loads of fuel each day
from area sawmills. Maintaining the waste wood receiving equipment at the plant is
critical to the plant overall operations. Other markets are available for waste wood such
as beauty bark, wood pellets and press board. Having a highly reliable waste wood
system keeps transportation costs down which benefits the customer in lower fuel costs
to the plant.
The Fuel Equipment Operators also use the dozers throughout the day to move wood
into the reclaiming system to be burned for the plant operations. The 53MW facility cannot
operate on wood waste without the use of a dozer. The plant may be operated on natural
gas at 50o/o capacity but is not classified as a renewable source and the REC's are lost
when operating in that mode. The unit is less efficient and not designed to operate on
natural gas for extended periods of time.
Normally one dozer is operating while the other is in standby until the 250 hour service is
needed then the standby machine it put into service while the other sits in standby.
Typically the dozer is operated 10-12 hours each day. On average each machine
operates 2,000 hours per year.
Major overhauls require the dozer to be shipped over 80 miles to the nearest service
center in Spokane. This work is planned and schedule around the annual maintenance
outage in the Spring to reduce the risk to plant availability due to the loss of the standby
dozer from an unexpected breakdown.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Do nothing $o
1. Rebuild the engine and transmission $230,000 05 2017 06 2017
2. Purchase Certified Rebuilt CAT D10R $700,000 05 2017 06 2017
3. Purchase New CAT D10 Dozer or
equivalent
$1,800,000 06 2017 06 2017
The plant has been operating and maintaining D10 dozers for over 30 years and has
kept maintenance records of the equipment. Historical data on record over the past 20
years shows the engine on the D10R has never reached 9,000 hours of operation
between failures. The transmission has never reached 10,000 hours of operation
between failures. The CAT D10R dozer has over 36,000 operating hours on the
machine chassis. Major components have been rebuilt over the years including the
motor, transmission and final drives. The major rebuilds are planned on a time base
maintenance plan. Minor components found in the auxiliary systems including
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 64 of 108
Certified Rebuild D10R CAT Dozer
radiators, coolers, hoses, belts, seals, gaskets, bearings, wiring, switches, gauges,
tracks, pads, pins and blade are basically ran untilfailure.
Discussions with the equipment manufacture service representative identified three
options to consider, major rebuild of critical components, a complete certified rebuild and
purchase of new equipment.
The four options were discussed and doing nothing was not an option as the motor had
failed and the transmission will fail at some point.
Option 1 is rebuilding the engine and transmission were identified as time based
maintenance projects and funded as a Major Maintenance O&M project for 2017. There
were uncertainties around what other issues we would find as we pulled the motor and
transmission. There was risks the costs and scope could increase as auxiliary
equipment including the final drives, steering clutches, brakes and minor equipment
were removed and inspected.
The engine failed last Fall with 8,600 hours. We were given options of rebuilding our
engine if the head was able to be machined down, purchase an already rebuilt engine
or purchase a new engine. Rebuilding our engine would increase the time in which the
plant would be operating with only one dozer available putting plant operations and fuel
contracts at risk. Working with Western States we were able to negotiate a new engine
with warranty for the same price of a rebuilt engine. A new engine was installed in
October of 2016 for $1 19,000.
Option 2 is purchase the Certified Rebuilt CAT D10R dozer. The rebuilt dozer, which is
currently an Avista Kettle Falls asset, will be completely disassembled down to the
machine frame. All hoses, belts, seals, gaskets, bearings, wiring, switches and gauges
will be new. The frame will be reconditioned to original performance of new machine.
Engine and transmission will be reconditioned and updated to Caterpillar Certified
Rebuild Standards. The dozer will be issued a new serial number and carry like new
machine warranty.
Recommendation is to pursue option 2 to purchase a Certified Rebuilt CAT D10R
dozer. The rebuild will be completed during the schedule annual maintenance outage
and will be complete two weeks prior to the plant startup. Transfer to plant is scheduled
to be June 2017 . Because of the engine failure in $1 19k was spent in 2016, $500k will
be spent in 2017. $230,000 will be reduced from K07 O&M for 2017 by eliminating the
Major Maintenance project of the engine and transmission rebuild.
The Certified Rebuild on our existing D10R will reset the time based maintenance of the
major and minor equipment. Reliability on the D10R will be increased as it will be back
to like new condition. Steering and brakes will be like new making for safer operation
on the fuel píle.
Western States Equipment has experience rebuilding equipment. The scope of work
and costs for 2017 are attached.
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 65 of 108
Certified Rebuild D10R CAT Dozer
Option 3 is purchasing a new D10 CAT dozer or equivalent was considered but cost,
long lead time and issues around operating our current D10T we eliminated this option.
A new D10T was purchased in 2012 at the cost of $1 .6 million for a new machine.
Working with Western States a new CAT D10T dozer would now cost around $1.8
million. The D10T has newer emissions equipment which increased the exhaust
temperature compared to the D10R. The extremely high manifold temperatures cause
sawdust to catch on fire in the engine compartment throughout the hot summer months.
Modifications to the D10T over the past years include large blowers moving sawdust off
the top of the engine and ceramic coating the intake manifolds have reduced the fires
on the D10T but not eliminated the problem.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 66 of 108
Certified Rebuild D10R CAT Dozer
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Certified Rebuild D10R CAT
Dozer Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:,H** [løø-*,Date: "l ltt I tot I
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
ereguwigg .vvtns
Kettle Falls Plant Manager
Business Case Owner
Andy Vickers
Business Case Sponsor
Date
Template Version: 03107 12017
Director of GPSS
5 VERSION HISTORY
VtirCiôä"lmplemented
BY
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Greg Wiggins 04t12t2017 Jacob Reidt 04t17t2017 lnitial version
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 67 of 108
Cabinet Gorge Gantry Crane Replacement
I GENERAL INFORMATION
1.1 Steering Gommittee or Advisory Group lnformation
Steering Committee members are comprised of: Director - GPSS, Manager,
Hydro Operations & Maintenance and Manager - Project Delivery. Steering
Committee members are provided a monthly project status report but, meet only in
the event a decision point is needed.
Other key stakeholders include: Manager, Clark Fork River Hydro; Manager,
Mechanical Engineering. Additional Cabinet Gorge Hydro Electrical Development
mechanical staff that more directly represent the interests of the plant itself are
consulted regularly.
2 BUSINESS PROBLEM
The gantry crane at Cabinet Gorge Hydro Electrical Development was used in the
original construction of the plant in 1952-53. The crane is rated at275 tons but can
perform lifts as heavy as 330 tons on an occasional basis given that a certified test
has been performed. As the asset has aged, various upgrades and updates have
been made to prolong the crane's usefulness. However, it has become apparent
that the crane is unable to perform the duties required of it in a dependable
manner.
The gantry crane is of the only means of moving the large machinery found at
Cabinet Gorge Hydro Electric Development such as moving/placing transformers,
tailgates and generators. lt is also the only way other equipment can be moved
into and out of the plant. lts inability to function reliably impacts the work that is
able to be performed at the plant and presents a safety risk to personnel if the
crane fails to control the load. There is also a risk of not being able to accomplish
repairs in the event of an emergency related to any one of the four generating
units. ln essence, the gantry crane is a bottle neck preventing both annual
maintenance work and capital improvements alike.
The crane has a long history of breakdowns and operational problems. Most
recently, during the Cabinet Gorge Unit #1 rehabilitation project spanning from
2014 to 2016, problems with the crane caused significant delays. Some examples
include:
Relay/Contactor control problem - approx. 6 days
Requested Spend Amount $3,530,000
Req uesting Organ ization/Department Generation Production and Substation Support
Business Gase Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Project
lnvestment Driver Asset Condition
Business Case Justification Narrative Page 1 of8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 68 of 108
Cabinet Gorge Gan Crane Replacement
Gear/bearing problem - approx. 3 weeks
Brake problem - approx. 2 days
Additional problems experienced with the crane during the Unit #1 rehabilitation
are documented in a memo by Ryan Bean, dated November 13,2015, attached as
Appendix A below.
lnspections performed by Professional Crane lnspections in the years 2010,2012,
2015 and 2016 each give the crane an overall condition level 3 indicating that
"Minor to moderate performance issues exist. PCI recommends repair or
adjustment as soon as practical." Copies of these inspection reports can be made
available upon request. A summarized list of foreman reports dating back to 1966
can be found in Appendix B below.
The successful outcome of this project would be to deliver a state-of-the-art crane
capable of safely and reliably providing rated lifting capabilities for the likes of draft
tube bulkheads, Generation Step-Up transformers and any one of the four
generators.
A properly functioning crane at Cabinet Gorge Hydro Electric Development
enables Avista to tend to the aging assets and maintenance needs of plant
machinery to ensure that they run safely and reliably.
Customers benefit in the ability to adequately and safely maintain this equipment
to continue to provide low cost and reliable energy.
3 PROPOSAL AND RECOMMENDED SOLUTION
Do Nothinq: doing nothing is an option however, given the criticality of this asset,
doing nothing would leave the plant at risk should an emergency arise
necessitating the crane's use
Alternative #1: Full Replacement. Advantages of this option include new structure
designed and rated for 330T from conception, modernized controls utilizing current
technology, reduced maintenance costs, elimination of as-building the existing
crane structure, full archived drawing and product data set and removal of any
lead-based paint and asbestos contamination risks.
Alternative #2: Replacement w/Extended Reach. This alternative expands on
alternative #1 by utilizing extended reach to enable reach to the transformers and
leg pass-through design enabling access to the draft tube bulkheads.
Replacement with extended reach represents a modest increase (comparatively)
Option Estlmated
Gapltal Cost
$tart Complete
Do nothing $o
Alternative 1: Full Replacement $5,308,449 03t2017 12t2018
Alternative 2: Replacement Mextended
reach
$7,272,000 03t2017 12t2018
Alternative 3: Refurbishment $3,894,173 03t2017 12t2018
Business Case Justification Narrative Page 2 of 8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 69 of 108
Cabinet Gorge Gantry Crane Replacement
in price but will provide savings in terms of usability for the foreseeable future in
terms of lifting capability. The estimated capital cost of $7,272,000 represents a
very high level estimate at this point.
Alternative #3: Refurbishment. Advantages of refurbishment included lower up-
front costs resulting from retaining the majority of the steel structure and a reduced
level of demolition and installation work. However, this alternative would require
lead-based paint and asbestos abatement and without X-ray examination of each
rivet, it would be impossible to accurately and definitively assess the true condition
of the structure.
A final decision has yet been made with regard to selection of Alternatives 1,2, or
3. However, with any option we anticipate construction will take upwards of four
months, following dismantling of the existing crane. Due to weather conditions
inherent in north ldaho, it would be optimal to construct the new crane during the
months of June to September. Given the long lead time expected in the
manufacturing of a new crane (upwards of twelve months), we anticipate that all
construction will be completed and the project placed in service no later than
December 31,2018.
Business Case Justification Narrative Page 3 of 8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 70 of 108
Cabinet Gorge Gan Crane Replacement
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Gantry Crane
Replacement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
4,/
[) irerÞ. GP eç
Mcn cÐMñL,t¿ß & Prùt
Date: bf ?Oy¡7
Date
Tem plate Version : 03107 12017
er- 9
Business Case Sponsor
VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Terri Echegoyen 4t14t2017 Steve Wenke 4t14t2017 lnitial version
Business Case Justification Narrative Page 4 of 8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 71 of 108
Cabinet Gorge Gantry Crane Replacement
APPENDIX A
DATE: NOVEMBER 13TH, 2015
TO: FILE, JACOB REIDT, RANDY PEIRCE, BOB WEISBECK, MIKE SHOFF
FROM: RYAN BEAN
SUBJECT: CABINET GORGE UNIT 1 - GANTRY CRANE ROTOR PICK
PROBLEMS
Backsround
The scope of work during the Unit 1 rehabilitation included two picks of the generator rotor
complete with field poles installed. The first pick removed the rotor from the stator and placed it
in the shop for field pole removal. The rotor was then moved to the rotor storage building until
the field poles were returned after being refurbished by RPR Hydro (subcontractor to GE). The
field poles were reinstalled in the rotor storage building and the rotor was then placed back in the
stator.
An Engineered Pick Plan was produced in accordance with ASME Code Section 830.2-3.I.7 thaf
allows for occasional picks for loads exceeding rated limits up to 125o/o of the nameplate rating.
The crane nameplate is275 tons with an occasional pick of up to 343.8 tons. The rotor with lifting
device weighs approx 330 tons. The cranes ability to lift this load was confirmed by Bedford
Crane during the initial installation. The code allows an occasional pick not to exceed two
occurrences in a 12 month period provided the crane manufacturer or other qualified person has
reviewed the crane design to handle the load.
Inconsistencies During Operation
During the initial removal of the rotor from the stator, the micro drive and main hoist motor were
used. The micro drive operated as expected, however the main hoist motor appeared to struggle
when initially engaged. While returning the rotor to the stator on September 22nd,2015, an issue
was experienced where the main hoist did not operate as expected during raising. This was a
repeatability issue with the main hoist where the hoist may raise, stall, or lower the rotor when the
control lever was taken back into the same notch repeatedly. The lift was stopped and an
investigation followed.
Investisation and Troubleshooting
V/ith assistance from PCI and K&N Electric, an investigation and troubleshooting of the power
and control systems followed. Components checked included the control lever, overloads,
contactors, resistors, motor currents, brakes, and micro-drive operation. Everything appeared to
be operating correctly, albeit in an overloaded condition due to the above nameplate load. The
micro-drive operated reliably throughout testing. This lead us to believe the problem resides
downstream of the control system, potentially with either the motor output or mechanical drive
system. The gear train was visually inspected via available access ports and appeared to be in
good shape and operated smoothly.
Original records of the hoist motor test data indicate the existing hoist motor reaches its nameplate
current of 160 amps at a load of approximately 205 tons. This limits the service cycle at 240 amps
with a load of approx. 320 amps to approximately one to two minutes without overheating resistor
banks. This would require several lifting and cooling offperiods to complete the lift. This reflects
Business Case Justification Narrative Page 5 of 8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 72 of 108
Cabinet Gorge Gantry Crane Replacement
what we experienced in the field with tripping of the overload relays during sustained lifting at
approx. 250 amps.
The crane micro-drive arrangement was also inspected, which consists of an additional motor and
speed reducer that can be clutched in or out as necessary. The arrangement utilizes the same main
hoist drivetrain and brakes (with an additional motor brake) without using the main hoist motor.
Per Mark Oney's crane evaluation dated May 10, 1994 and design drawings, the micro-drive is
rated for continuous duty without overheating. Hoisting speed is reduced during operation to
slightly less than 0.5 feet per minute.
Conclusion
This has historically been a difficult pick for this crane and the system appears to have reached an
impasse where the main hoist is no longer capable of producing the power to function at l00Yo.'We suspect the issue lies in either the motor output, which has been operated above its nameplate
current a number of times in the past, or due to an increase in mechanical drag in the gear train.
Per the results of our initial investigation and a stakeholder meeting on October 5fh,2015, (Ryan
Bean, Andy Vickers, Mike Gonnella, Bob Weisbeck, Brand McNamara, Rob Selby, and Jeremy
Winkle in attendance) and in agreement with the project Foreman Mike Shoff, the rotor pick was
completed using the installed micro-drive system, without the use of the main hoist motor.
References
L. CG 1 Rotor Pick Plan Oct 201-5 Revl-
2. ASME Crane code for CGL
3. Crane Report by Mark Oney, May 10 994
4. D-1570Ls00Ict952 - Gantry Clearance Diagram with notes
5. 3O4E-25-O40-0L-01, 02, 03,04, 05,08 - Micro Drive Arrangement Drawings
6. 1952 Load Test Data7. 1993 Load Test Data
Business Case Justification Narrative Page 6 of 8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 73 of 108
Cabinet Gorge Gantry Crane Replacement
APPENDIX B: SUMMARIZED FOREMAN REPORTS
Job Title Begin
date End date Description
Gantry Crane -
Mechanical
Maintenance
5t2311966 7t1t1966
Replaced sheaves and greased bearings
on large hook. Applied oil to bearings on
trolley. Drained and cleaned gear cases.
Checked brakes.
Repair Gantry Crane 3t31t1969 4t9t1969
Large bevel gear was removed. New
bushing was installed and the drive
reassembled. Wheel guards were
repaired and installed.
Re-reeve Gantry
Crane Main Hook -
Cabinet Gorge
Station
12t2t1976 12t14t1976 Old cable was removed and new cable
added to the drums.
Crane Maintenance 11t14t1988 11t14t1988 Main hoist gear box inspected. Friction
brake assembly was seized together.
Redo Crane Track
Splices 4t5t1993 5t13t1993 Weld holding rails together were
repaired.
Gantry Crane -
Bridge Drive Motor 1t23t1997 2t11t1997
The bridge drive motor on the Gantry
Crane was removed and sent in for
repair. Report includes repair details.
Crane Maintenance 6t28t1999 7t29t1999
The bridge motor, brake and gearbox
were inspected. Trolley motor removed
and sent to K&N for maintenance.
Annual Safety
lnspection for Gantry
Crane
7t12t2000 7t12t2000 Mechanical and Electrical inspection of
crane components.
Crane Maintenance 5t1t2000 7t13t2000
Crane was pressure washed. Full
structural inspection completed. Rusting
areas noted. The main and auxiliary
hoists were load tested.
Gantry Crane
Maintenance "03"6t16t2003 8t26t2003
Replaced all races and several bearings,
and repaired sheaves of the main hoist
block. Replumbed bridge brake system
and repaired/replaced several brake
components. Maintained the trolley
controller (electricians), main and
auxiliary hoist cables, and open
Business Case Justification Narrative Page 7 of I
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 74 of 108
Cabinet Gorge Gantry Crane Replacement
Job Title Begin
date End date Description
275Ton Gantry
Crane Load Test 6t5t2006 6t8t2006
Components of the main hoist had been
modified necessitating a load test
(Repod from load test on the 275 ton
gantry cane).
Crane Maintenance
2010 9115t2010 9t15t2010 Abbreviated maintenance on the gantry
crane. See report for details.
Gantry Crane Oil
Analysis 4119t2011 4t19t2011 OilAnalysis results for Gantry Crane
components.
Gantry Crane
Maintenance 2Q11 4t11t2011 4t20t2011
Report includes details on maintenance
of the gantry crane, checklist included.
Report state the crane in in dire need of
a paint iob.
Annual Maintenance
Gantry Crane 4t9t2012 5t3t2012 Crane condition regarding many items is
not satisfactory, see report for details
detailed Foreman repofts can be found here > c01m1 14lG:llForemanreports.accdb
sååt
Business Case Justification Narrative Page 8 of 8
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 75 of 108
Base Load Hydro
1 GENERAL INFORMATION
Requested Spend Amount $1,149,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Mike Magruder
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Gategory Program
Driver Asset Condition
1.1 Steering Gommittee or Advisory Group lnformation
Most projects are proposed through Operations and Engineering. The projects are vetted
holistically by Operations and Engineering to evaluate the issue, determine available
options, confirm prudency, and bring the potential solutions forward for discussion with the
Advisory Group consisting of the Plant Managers and the Manager of Hydro Operations. A
similar vetting process is followed for funding emergency projects with the impacted
stakeholders included.
Over the course of the year, the program funding is actively managed by the Manager of
Hydro Operations through monthly analysis and reporting for end of year expected spend.
2 BUSINESS PROBLEM
Avista's Base Load Hydro (or Base Hydro) program includes the Post Falls, Upper Falls,
Monroe Street, and Nine Mile Hydroelectric Developments. These are all located on the
upper Spokane River and are "run of river" plants which require them to have a constant
water level in their forebay. It also includes minor capital projects at the Generation Control
Center and on the Generation Control Network. It can also include some projects at the Post
Street 115kV Substation where the two downtown hydro plants are tied into the grid.
The purpose of this program is provide funding for these plants to accomplish the objectives
of keeping operating expenses as low as possible and maintain a level of reliability as
indicated by the Equivalent Availability Factor (EAF) in the graph below. This program
covers the smaller capital expenditures and upgrades required to safely and reliably operate
the Upper Spokane River plants and continue their low cost. Projects completed under this
program include replacement of failed equipment and small capital upgrades to plant
facilities. The business driver for this program is a combination of Asset Condition, Failed
(or Failing) Plant, and addressing operations deficiencies.. Most of these projects are short
in duration, typically well within the budget year, and many are reactionary to plant
operations issues.
Business Case Justification Narrative Page 1 of5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 76 of 108
Base Load Hydro
*ase lly*ro ?**nl KPls
* 3 ãqütvrtfrt Àqú¡Þl*Ty fa¿rar {€¡f}¡ rdtirå ¡¿ nði" rrç.
ælöâltttVd.a * ð.*:1åAâ9 â.ûihntr* ttt 19tr114 å ¡ôå!¡.r hTdß sÈ4,å fôru.ãrt !qs!v.¡.*r Arú¿t*Þi:Ít' ñã(ltr{tÂf¡
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a+ttr+taú 'ltat+a+t++
ssûÊ,rüÐ,
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s{û6,1*$
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s3&*,lût
*18û,1&
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,.ð"i."%'*"*u.å*f,*"t*,sf.,*F*-É$n{**}'{.""{"'*--'***s.o-f "}1*$}*.*"4"*,å$M*nth
Examples of projects completed in20l6 or in progress under this business case include:
o Monroe St. - V/ater Drain and Diversion Installation. This project captured high
flows on the site that were washing away some of the visitor amenities.
o Nine Mile - Replace Failed Spillway Gate Controls. This project will replace failed
controls that allow the spillway to automatically adjust to maintain a forebay level.
. Upper Falls * Upgrade Headgate Camera. This replaced a non-functioning camera
used for some area surveillance and to observe the trash rake operation on the intake.
o Post Falls - Replace Switch Building Drain Field. This project is to move ponding of
water away from the foundation structure to maintain the integrity of the building.
o Nine Mile - Install Roof Safety Handrail. This addresses a personnel safety item.
o Post Falls - Install N. Channel Downstream Warning System. This is a system that
warns the public in the event of a start of a spill or a significant increase in spill at the
site.
The Program funding requests are submitted to the Capital Planning Group (CPG) through
the business case review process. The business case expenditures over the last 5 years are
shown below.
- ffÉd, *,15, Ufåâçêã¡å aÉ
Aå¡åLL&tå^
,4bove
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 77 of 108
Base Load Hydro
Base Load F{ydro Hxpenditures
Previous Five Years
sl,ooo,ooo
sgoo,ooo
s800,000
5700,000
$60o,ooo
$soo,
s400,
$soo,
$200,
$100,
000
000
000
000
000
So I I
2013 2015 201,6
3 PROPOSAL AND RECOMMENDED SOLUTION
These base load hydro plants are among the oldest plants in Avista's generating fleet. The
option to "Do Nothing" is impractical in that existing machinery and systems periodically
fail and are required to be replaced. Having no costs allocated to address those concerns is
impractical.
The second proposal is to continue with the Base Hydro program business case as it is
intended for asset condition, failed plant and operations. The program is actively managed
and the vetting process considers all options for projects including doing the project under
maintenance, the Base Hydro program, or a specific project business case.
The last proposal to eliminate funding for this program introduces greater risk to the ongoing
operation of the plants by reducing the efficiency of operations and administration to set up
and execute the required projects, especially for failed plant and operations. The program
gives us the flexibility to respond quickly and prudently.
The recommended option to pursue is the second proposal to continue with the Base Hydro
program business case as it is intended for asset condition, failed plant and operations. The
program is actively managed and the vetting process considers all options for projects
including doing the project under maintenance, the Base Hydro program, or a specific project
201.42-OL2
24fl 20'13 zA14 20rõ 20t6
$631,961 $905,557 $664,783 9342,194 $394,849
Option Capltal GoEt Start Complete
Do nothing $0
Maintain Existing Base Hydro Program Buslness Case $350k - $1.15M Annual Annual
Make all small projecfs as sfandalone projects $s.1M - $5.9M Annual Annual
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 78 of 108
Base Load Hydro
business case. The program offers greafer efficiency to manage "drop-in" or emergency
projects allowing for better response time.
The annual requested budget amount is conservative to cover potential large expenditures
that do not require a new project business case to be developed. The annual amount is
reasonable, especially given that the program is actively managed and there is a means to
release or request funds through the CPG.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 79 of 108
Base Load Hydro
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Base Load Hydro Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
ll¡.. t{qtu Oos â tl4¿"*e*.*(-/Business Case Owner
e?r
O irn cfo, 6 PSs
Business Case Sponsor
Date fl re /en,7
Date
Template Version: 03107 12017
5 VERSION HISTORY
Vereion lmplemented
By
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Mike Magruder 03117117 Jacob Reidt 04t19t2017 lnitialversion
Business Case Justification Narrative Page 5.of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 80 of 108
Baseload Thermal Program
1 GENERAL INFORMATION
Requested Spend Amount $3,100,000 per year
Requesting Organization/Department Generation Production and Substation Support
Business Gase Owner Thomas Dempsey
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Program
Driver Failed Plant & Operations
1.1 Steering Committee or Advisory Group Information
This business case request is for Avista's base load thermal plants, Kettle Falls and
Coyote Springs 2. The purpose of this program is for these plants to keep their
operating expenses as low as possible by providing funding for specific efforts to
allow the plants to accomplish that objective.
Smaller and emergent projects planned for Kettle Falls are identified and prioritized
through their plant Budget Committee. The plant Budget Committee utilizes an in-
house Maintenance Project Review scoring matrix.
Projects planned specifically for Coyote Springs 2 are identified and prioritized
during the Annual Budgeting process, with emergent projects discussed during the
Monthly Owners committee meetings between Avista management and Coyote
Springs management. Some of the projects that fall within this business case are
joint projects between Portland General Electric (PGE) and Avista. Those
"common" projects are also'reviewed in an owner committee setting during meetings
at the plant that take place on a monthly basis.
lndividual projects are identified and approved by the Manager of Thermal
Operations and Maintenance, specific plant managers and/or GPSS management.
Some specific jobs under this program may require additional financial analysis if
they are sufficiently large or there are several options that can be chosen to meet
the objective. These projects are reviewed with finance personnelto make sure that
they are in the best interest of our customers.
2 BUSINESS PROBLEM
Various projects for Coyote Springs 2 and Kettle Falls Generating Station are
necessary to ensure continued safe, low cost, reliable and compliant electrical
generation for Avista's electric customers. Work includes replacement of items
identified through asset management decisions and programs necessary to
maintain reliable and low operating costs of these plants. As this program proceeds,
it is expected that forced outage rates and forced de-rates of these facilities will
decrease to a level one standard deviation less than the current average resulting
in more economic benefits for the Program. The projects that are opened under this
Business Case Justification Narrative Page 1 of4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 81 of 108
Baseload Thermal Program
business case are not known in advance. Most of the individual projects are small
in nature and are required due to regulatory or environmental requirements,
emergent safety items, or for continued reliable operation. Examples of recent
expenditures under this Program include:
r Kettle Falls - Replace the Furnace Grate Drive System, part of the system
that moves the burned fuel from the boiler to the ash disposal system
(Reliability)
o Kettle Falls - Replace Furnace Forced Draft Fan motor, the fan that blows
the wood waste fuel into the boiler where it is burned (Reliability)
o Kettle Falls - Diesel Fueling System, providing additional containment and
system to improve the onsite diesel fuel handling system (Regulatory or
Environmental)
o Kettle Falls - Replace the Turbine/Generator fire system (Safety)
. Coyote Springs 2 - Replace the Reheat Steam Attemperator, the system
used to control the steam temperature in the boiler (Reliability)
. Coyote Springs 2 - Upgrade the Medium Pressure steam control valves
(Safety and Reliability)
. Coyote Springs 2 - Upgrade the NOx analyzer, part of the plant emission
monitoring system that monitors the Nitrous Oxide emissions (Regulatory or
Environmental)
. Coyote Springs 2 - lmprove physical site security, addition of key card
access door locks on critical facility doors. (Regulatory, Safety)
3 PROPOSAL AND RECOMMENDED SOLUTION
This program is necessary to sustain or improve the existing operating costs for
Coyote Springs 2, the Coyote Springs Common Facilities, and Kettle Falls
Generating Station. Work includes replacement of items identified through asset
management decisions and programs necessary to maintain reliable and low
operating costs of these plants. The Capital Retirement Unit Catalog for Kettle Falls
and "Other" became effective January 1,2017. Due to this Retirement Unit Catalog
update, $900,000 in additional funds are necessary for 2017, in order to cover
capital projects that were previously identified as Operation and Maintenance. The
Base Load Thermal Business case is reassessed for adjustments on a 5 year cycle.
Option Gapital
Cost
Start Complete Riek
Mitigation
As proposed $3,100,000 Ongoing, required for operation
Unfunded Program
Business Case Justification Narrative Page 2 of 4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 82 of 108
Baselo ad Thermal Program
A 5 year historical graph of expenditures is attached to help assess future capital
funding for the Base Thermal Plant. This spending pattern indicates the diligence
that is applied to capital requests as managed by the Kettle Falls plant Budget
Committee and the joint owners of Coyote Springs during their monthly meetings.
As mentioned above, there is opportunity to adjust this amount every five years if
needed.
s2,s00,000
$2,000,000
51,soo,r0o
S1,ooCI,CIoo
$s00,000
$o
51,s90,60sI
Baseload Thermal Capital Program
52,244,540 52,08g,rs+
st,162,197
2013 201,4 20l,s
$t,sto,szt
241,62012
Business Case Justification Narrative Page 3 of 4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 83 of 108
Baselo ad Thermal Program
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Baseload Thermal Program
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
-'t =,
'Vg' *tThomas Demp'sey f/"0/'^
D ìrurfr, êlgs
Date
Date
Template Version: 0212412017
Andy Vickers
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
BY
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Mike Mecham 04t05t2017 Jacob Reidt 04t14t2017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 84 of 108
Regulating Hydro
1 GENERAL INFORMATION
Requested Spend Amount $3,533,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Mike Magruder
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
Most projects are proposed through Operations and Engineering. The projects are vetted
holistically by Operations and Engineering to evaluate the issue, determine available
options, confirm prudency, and bring the potential solutions forward for discussion with the
Advisory Group consisting of the Plant Managers and the Manager of Hydro Operations. A
similar vetting process is followed for funding emergency projects with the impacted
stakeholders included.
Over the course of the year, the program funding is actively managed by the Manager of
Hydro Operations through monthly analysis and reporting for end of year expected spend.
2 BUSINESS PROBLEM
Avista's Regulating Hydro program includes the Cabinet Gorge (Idaho) and Noxon Rapids
(Montana) Hydroelectric Developments on the Clark Fork River and the Long Lake (V/A)
and Little Falls (WA) Hydroelectric Developments on the lower Spokane River. Because
ofthe storage available in their reservoirs, these plants are operated to support energy supply,
peaking power, provide continuous and automatic adjustment of output to match the
changing system loads, and other types of services necessary to provide a stable electric grid
and to maximize value to Avista and its customers. These plants are the four largest hydro
plants on Avista's system representing more than 950 MW of power.
Because these plants are used to provide a wide variety of grid services, energy and power
supply, and other types of electric grid support services, the availability for the generating
units in these plants is paramount. The purpose of this program is to provide funding to
achieve availability targets (Equivalent Availability Factor or EAF) of 85%o or higher.
Business Case Justification Narrative Page 1 of5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 85 of 108
Regulating Hydro
*egulating llydra Plant fPls
f Vå€uÈ ûf læi €serãl¡Õñ duê 1ô larrd fltåtF
¿ to.*cãrt €quþrÞrrÅrãllâb{tiv fe*Õ. {€Åf!
a YTg Vål$ã at¿ã'l €*Erslþã due t{, tôrced ê*aåñ*t
3å8}å
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c
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{t,
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ú
{tu*
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t[fr
o
atâ.
s' a tqtrirâãê¡* ,{sâ¡låbiliiy f¡.rêr {ÊÂFi, rtJ¿'q !2 ffiæ, eB.
æàårfê íTd1ð - û.tS4SÂtg bGr€hffirktór 3SM1é, & ?â'ts hyd.r nlias
tgrÕ,xûð
5819.1ûö
å7*û,1{B
$$w,1ûû
35&,XûC
tq*û,x0â
s3ûû,1ûð
såût,1ûå
s1rÕ,1û*
$xt0
*-*þÇ.f --.$-*i"'f ,*iS!-e.*"þ{.-*.{.{,.**.d-*,"*,*{,S*-S..'S*,ÇS
This program covers the smaller capital expenditures and upgrades required to safely and
reliably operate four largest hydro plants and to achieve the EAF target. Maintaining these
plants safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System. Projects
completed under this program include replacement of failed equipment and small capital
upgrades to plant facilities. The business driver for this program is a combination of Asset
Condition, Failed (or Failing) Plant, and addressing operations deficiencies. Most of these
projects are short in duration, typically well within the budget year, and many are reactionary
to plant operations issues.
Examples of projects completed in2016 or in progress under this business case include:
o Cabinet Gorge - Tunnel Access Improvement; this work removed loose rock along the
access road and installed protective metal netting to address the hazard of falling rocks
on personnel and equipment. (Rock ScalingÀ{etting)
o Noxon - Install Dam Pressure Monitoring System; this work provided specialized
instrumentation so that operators and engineers can monitor the structural stability of the
dam.
. Long Lake - Spillway Improvements; this project replaced and enhanced some areas of
the Long Lake spillway section by removing and replacing areas of the decaying 100
year old concrete. (Rebuild Parapet WalliExtend Spillway Walkway)
ftâgr¡1ät¡rig t*ydra Pla*ts are pla*t: lvberelh* $lrtpüt *f lhe plâßt c*â h'ê shâped thrsug**ut the d*y - LF,
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 86 of 108
Regulating Hydro
o Little Falls - Replace Spillway Log Boom; this is a plant safety system that diverts
floating debris from the generating units and can provide a boundary to keep the public
away from thehazardous intake area of the dam.
o Noxon - Replace Unit 5 Turbine Bearing Cooling System
. Long Lake - Install Redundant Spillgate Hoist System; this work added a FERC required
secondary system so that in the event of a failure of one system, the spillgates could still
be operated with a second power source to assure ability to manage river flows at the
project and provide safe operation of the spillway.
The Program funding requests are submitted to the Capital Planning Group (CPG) through
the business case review process. The business case expenditures over the last 5 years are
shown below.
Regu[at[ng l{ydra Exp*nditures
Frevisus Fiv* Years
S6,*ffi,üût
Ss,**&,Gû$
$4,ût}t,üûû
$ã,ü{}*$#t}
*ä,***,ücc
$1,*fl,*$üû
Éñ+ú
1fi'r a añl.)?n¡ q
3 PROPOSAL AND RECOMMENDED SOLUTION
The plants that make up the Regulating Hydro group provide the most flexibility of any of
the generating assets owned by Avista. As such, they provide a wide variety of critical and
economical services that allows Avista to optimize the entire energy portfolio.
Consequently, the option of doing nothing to maintain these units is a poor economic choice
on behalf of Avista's customers and shareholders.
S:.znn Five year Average
I
2&3.4
2912 20r3 zA14 20'15 20,l6
$1,514,577 $2,517,815 $2,519,775 $4,073,698 $5,558,100
Option Capital Cost Start Complete
Do nothing - not a viable option $o
Maintain Existing Regulating Hydro Program Busrness Case $1.5M - $5.5M Annual Annual
Make all small projecfs as sfandalone projects $3.1M - $5.9M Annual Annual
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 87 of 108
Regulating Hydro
The second option is to continue with the Regulating Hydro program business case as it is
intended for asset condition, failed plant and operations. The program is actively managed
and the vetting process considers all options for projects including doing the project under
maintenance, the Regulating Hydro program, or a specific project business case.
The last option to eliminate funding for this program introduces greater risk to the ongoing
operation of the plants by reducing the efficiency of operations and administration to set up
and execute the required projects, especially for failed plant and operations. The program
gives us the flexibility to respond quickly and prudently.
The recommended option to pursue is the second proposal to continue with the Regulating
Hydro program business case as it is intended for asset condition, failed plant and operations.
The program is actively managed and the vetting process considers all options for projects
including doing the project under maintenance, the Regulating Hydro program, or a specific
project business case. The program offers greater efficiency to manage "drop-in" or
emergency projects allowing for better response time.
The annual requested budget amount is conservative to cover potential large expenditures
that do not require a new project business case to be developed. The annual amount is
reasonable, especially given that the program is actively managed and there is a means to
release or request funds through the CPG.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 88 of 108
Regulating Hydro
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Regulating Hydro Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Date: ,f / tq /-n
/4 O
l4er. f{v"Lrc OP¡ { ,la*.à4<n-æ--!
Business Case Owner
Date
,4n/re*er5
tf
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
BY
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Mike Magruder 03t17 t17 Jacob Reidt 04t19t2017 lnitialversion
Tempfate Version: 03107 12017
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 89 of 108
Colstrip 3&4 Capital Projects
1 GENERAL INFORMATION
Requested Spend Amount $10-$20 Million per year
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Thomas C Dempsey
Business Case Sponsor Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
This Business Case request is for Colstrip 3&,4 capital projects. Avista does not operate the
facility nor does it prepare the annual capital budget plan. The current operator provides the
annual business plan and capital budgets to the owner group every September. They also
provide individual project summaries which characterize the work using categories similar
in concept the Avista business case drivers. Avista reviews these individual projects. Some
of them are reclassified to O&M if the work does not conform to our own capitalization
policy. Avista does not have a "line item veto" capability for individual projects but it can
present concerns during the September owners' meeting. Ultimately, the business plan is
approved in accordance with the Ownership and Operation Agreement for units 3&4 that six
companies are party too. This Business case represents the final approved budget after
subtracting items that we will expense instead of charging to capital.
2 BUSINESS PROBLEM
This Business Case represents the entire body of capital work performed in a calendar year
at Colstrip. This includes a variety of types of projects that Talen (current operator)
characteúzes using the following categories:
o ENVMD- Environmental Must Do
o Sustenance
o Regulatory
o Reliability Must Do
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapltal
Cost
Start Complete Riek
Mitisatlon
Ongoing Operations (Yes/No Vote)$10-$20M N/A
Business Case Justification Narrative Page 1 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 90 of 108
Colstrip 3&4 Capital Projects
Colstrip Capital is required as part of ongoing operations of the facility.
o The operator (Talon) reviews each proposed project. Discretionary items are
reviewed in a hurdle rate analysis.
o The operator reviews the risk mitigation for each alternative using the
busrness risk worksheet as well as describe the nature of the risks for each
alternative.
o Those that meet the criteria are submitted as part of an overall budget to the
owner committee,
c This process is repeated annually
o The annualbusrness plan is available on request.
. Although alternatives are not available for consideration at this level,
individual projects are reviewed and considered by all the joint owners.
Projects may be delayed and changed per committee recommendation to the
operator of the facility.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 91 of 108
Colstrip 3&4 Capital Projects
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Colstrip 3&4 Capital Projects
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Date 4l zt I zøtt
Business Case Owner
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Business Case Sponsor
Date
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5 VERSION HISTORY
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Business Case Justification Narrative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 92 of 108
Clark Fork Settlement Agreement
1 GENERAL INFORMATION
Requested Spend Amount $ 17,725,513
Requesting Organization/Department Clark Fork License lmplementation
Business Case Owner Tim Swant
Business Gase Sponsor Bruce Howard
Sponsor Organ ization/Department Legal
Gategory Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
ln mid-1996, stakeholders were invited to meet with a neutral facilitator to develop
a process for participating in the relicensing of these projects. There evolved a Clark
Fork Relicensing Team, which included representatives from nearly 40
organizations, including representatives from federal, state, and local government
agencies, five lndian tribes, special interest groups, conservation groups, property
owners, and Avista Corporation. The Relicensing Team established five technical
working groups, covering: 1) fisheries; 2) water resources; 3) wildlife, botanical, and
wetlands; 4) land use, recreation, and aesthetics; and 5) cultural resources
management. The team developed protection, mitigation, and enhancement
(PM&E) measures that were the basis for the comprehensive Settlement
Agreement filed with Avista's license application. The Settlement Agreement
establishes processes and includes 26 PM&E measures to resolve a wide range of
complex and conflicting natural resource interests. Avista led this collaborative
effort and signed the Agreement, making commitments for the 45-year term of the
license. FERC incorporated the Settlement Agreement into the new license. Under
the Settlement Agreement and license, the licensee works through a Management
Committee (MC), comprised of one representative of each of the 27 parties to the
Agreement, to implement the PM&E measures. ln addition, the Clark Fork
Settlement Agreement (CFSA) and license require Avista to provide funding for
PM&E implementation over the course of the term.
All proposed PM&E activities and associated budgets are developed through one
of the three technical working groups identified in the settlement agreement and
approved by the MC, which strives to make all decisions, including approval of
planned activities and expenditures, by consensus. FERC reviews and approves
annualwork plans to implement license requirements.
BUSINESS PROBLEM
Avista owns and operates the Noxon Rapids and Cabinet Gorge hydroelectric
developments (Clark Fork Project No. 2058). The operation of the Clark Fork Project
is conditioned bythe Clark Fork SettlementAgreement, signed in 1999, and FERC
2
Business Case Justification Narrative Page 1 of3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 93 of 108
Clark Fork Settlement Agreement
License No. 2058, effective date of March 1, 2001. Avista evaluated whether to
proceed with a traditional licensing process in the 1990s, which typically led to
conflict and litigation, or pursue a different strategy. The Company elected to pursue
an agreement through a collaborative effort. During the negotiations, Officers and
Directors of the company were informed and engaged, and officer approval was
required for the Settlement. This business case represents the ongoing resolution
of these issues and the means by which Avista fulfills its obligations under the CFSA
and the FERC License.
The License was issued to Avista Corporation for a period of 45 years to operate
and maintain the Clark Fork Project No. 2058. The License, and associated Code
of Federal Regulation, includes hundreds of specific legal requirements, many of
which are reflected in License Articles 404-430. These Articles derived from a
comprehensive settlement agreement between Avista and over 20 other parties,
including the States of ldaho and Montana, various federal agencies, five Native
American tribes, and numerous Non-Governmental Organizations. We are requiredto develop, in consultation with the Management Committee, âf annual
implementation plan and report, addressing all PM&E measures of the License. ln
addition, implementation of these measures is intended to address ongoing
compliance with Montana and ldaho Clean Water Act requirements, the
Endangered Species Act (fish passage), and state, federal and tribal water quality
standards as applicable. License articles also describe our operational
requirements for items such as minimum flows, and reservoir levels, as well as dam
safety and public safety requirements.
3 PROPOSAL AND RECOMMENDED SOLUTION
Funding of the Clark Fork License lmplementation is essential to remain in
compliance with the FERC license and CFSA for permission to continue to own and
operate the hydro-electric facilities. This commitment was made in 2001, and is
ongoing. At that time, Avista determined that the Settlement was in the best interest
of Avista, our customers, our shareholders, and the communities we serve. These
decisions were documented throughout the process at that time.
lf the PM&Es and license articles are not implemented and/or funded, we would be
in breach of an agreement and in violation of our License. There would be high risk
for penalties and fines, new license requirements, higher mitigation costs, and loss
of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro Electric
Facilities. Ultimately, FERC has the authority to revoke our operating license and
we could risk a competing license or even losing the facility. Loss of operational
Option Capital Cost Start Complete
Do nothing 0 N/A
Fund the annual request $17,725,513 01t2017 12t2017
Business Case Justification Narrative Page 2 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 94 of 108
Clark Fork Settlement Agreement
flexibility, or, in the extreme, of these generation assets, would create substantial
new costs, to the detriment of our customers and the company.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Clark Fork Settlement
Agreement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Date
Business Case Owner
Date
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1.0 Heide Evans 03t29t17 Bruce Howard 03t29t17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 95 of 108
Clark Fork Seúflem ent Agreement
flexibility, or, in the extrerne, of these generation assets, would create substantial
new costs, to the detriment of our customers and the company.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Clark Fork Settlement
Agreement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1, The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatíves.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
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Role:
Date: o, /r1 /e,r.z/r5 Su'n*- ffl
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1.0 Heide Evans t3l2st17 Bruce Howard 03129t17 lnitialversion
Business Case Justification Nanative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 96 of 108
Hydro Safety Minor Blanket
1 GENERAL INFORMATION
Requested Spend Amount $350,000.00
Req uesting Organ ization/Department Hydro Compliance
Business Case Owner Michele Drake
Business Case Sponsor Bruce Howard
Sponsor Organization/Department Legal
Gategory Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Funded projects are identified in several ways. During periodic site inspections,
FERC staff may identify a new specific concern or point out an existing item that is
deficient or in need of repair. ln other cases, Avista has assessed the condition of
safety items at our dams, and proactively plans replacement or addition of a new
safety measure. Replacement can be driven by physical condition/age/function,
changing standards in FERC guidance, industry practice, or emergent public safety
needs. All projects are subject to the conceptual approval of the Chief Dam Safety
Engineer and to additional internal review and oversight.
2 BUSINESS PROBLEM
Section 10(c) of the Federal Power Act authorizes the Federal Energy Regulatory
Commission (FERC) to establish regulations requiring owners of hydro projects
under its jurisdiction to operate and properly maintain such projects for the protection
of life, health, and property. FERC's Division of Dam Safety and lnspections
establishes national guidance and policy, and Regional Offices implement this
responsibility. 18 CFR Part 12 delegates to the Regional Engineer the authority to
require safety devices, where necessary. Section 12.42 of the Regulations states
that, "To the satisfaction of, and within a time specified by the Regional Engineer,
an applicant or licensee must install, operate, and maintain any signs, lights, sirens,
barriers, or other safety devices that may reasonably be necessary or desirable to
warn the public of fluctuations in flow from the project or othenruise, to protect the
public in the use of the project lands and waters."
ln addition to the broad regulatory discretion given to FERC, Avista is subject to
liability should we not maintain safety-related equipment at our hydro facilities. This
work is aimed at reducing both regulatory and liability risks. Some of the projects
under this budget are planned, but others are opportunistic. We take advantage of
other planned work to coordinate dam safety actions, and at times, we have to
replace equipment that has been damaged due to flow conditions. 1
Projects identified for 2017 include replacement of the boater safety cable at Noxon
Rapids and replacement of a boater safety sign at Post Falls.
Business Case Justification Narrative Page 1 of3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 97 of 108
Hydro Safety Minor Blanket
1. The boater safety cable at Noxon Rapids is more than 30 years old, and has
begun to show visual signs of failure, including listing, rusted floats and
deteriorating concrete. Operators and hydro safety staff identified the item
as in need of repair or replacement.
2. The boater safety sign at Post Falls was installed in 1994 and utilizes neon,
molded bulb lighting. A FERC inspector identified that the sign was becoming
difficult to read, and informally suggested replacement. Upon investigation,
some of the individual letters fail to illuminate.
In both cases, repair of the existing item was considered. However the age and
condition of the items and improvements in technology have made repair moot.
1. "Guidelines for Public Safety at Hydropower Project" https://www.ferc.qov/industries/hvdropower/safetv/quidelines/public-
safetv.odf
2. Avista's Hydro Public Safety Plans for each of it hydro facilities.
3 PROPOSAL AND RECOMMENDED SOLUTION
Funding of these activities protect employees, contractors, and the general public,
and reduces financial risk to Avista.
Non-Funding activity would ultimately result in total failure of safety equipment,
subjecting Avista to additional liabilities due to possible regulatory penalties, injuries
or loss of life, and is therefore not a recommended option.
Optlon Capltal Cost Start Gompleto
Do nothing 0
Fund annual request $350,000 01 2017 122017
Business Case Justification Narrative Page 2 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 98 of 108
Hydro Safety Minor Blanket
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Hydro Safety Minor Blanket
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Date
Business Case Owner
P
Signature:
Print Name
Title:
Role:
Date
Business Case Sponsor
5 VERSION HISTORY
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Vereion lmplemented
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1.0 Heide Evans 03117t17 Bruce Howard 04t03t17 lnitial version
Business Case Justification Narrative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 99 of 108
Hydro Safety Minor Blanket
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Hydro Safety Minor Blanket
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Date: 'l
Date (1
Business Owner
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5 VERSION HISTORY
Version lmplemented
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By
Approval
Date
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1.0 Heide Evans 031171'17 Bruce Howard 04t03t17 lnitialversion
Template Version: 03/07/201 7
Eusiness Case Justillcation Nanatiye Page 3 ot 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 100 of 108
Kettle Falls Water Treatmenú System
1 GENERAL INFORMATION
Requested Spend Amount $4,750,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
The Steering committee is comprised ofthe Manager of Thermal Operations & Maintenance,
the Kettle Falls Plant Manager, the Manager of Contracts & Project Management, the
Manager of Corporate Environmental Compliance, and the Manager of Mechanical
Engineering for GPSS.
Monthly project status updates will be distributed via email indicating the status of the scope,
schedule and budget ofthe project.
Steering committee meetings will be coordinated if decisions need to be made, due to
significant changes to the scope, schedule or budget based on unforeseen circumstances
andl or risk identifi cation.
1.2 Customers & Stakeholders:
This projects impacts internally the Thermal Operations & Maintenance teams, including
the crews at Kettle Falls, Mechanical Engineering and Environmental Compliance. By
providing these stakeholders with a properly maintained water treatment system we are
providing them with reliability of the system and regulatory compliance assurance.
This project impacts our external customers by ensuring we are in compliance with
environmental regulations and protecting the public safety of ground water. 'We are also
ensuring our customers have predictable, affordable power. When units go offline
unscheduled, we are forced to purchase power on the open market andlor produce power
with our less cost effective generating facilities. These alternatives come at the risk of higher
and/or unpredictable power costs per MWH for both our customers and shareholders.
2 BUS¡NESS PROBLEM
Maior Driver:
The water effluent discharged from the plant contains trace levels of mercury. To abate the
mercury in the effluent, an expensive high quality food grade acid is added to the boiler
water supply. V/ith this treatment, mercury levels are not detectable.
In2}l5,the water source for the plant was moved from the City of Kettle Falls to a new well
system owned by Avista to reduce the water supply costs and to provide the City with needed
Business Case Justification Narrative Page 1 ofS
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 101 of 108
Kettle Falls Water Treatmenú System
additional capacity for their system. V/hen this new water source was used for the plant, the
water chemistry was different than the City Water source, leading to trace levels of mercury
again. As with the previous effort, more of the expensive food grade acid was added to the
treatment system. This again resulted in effluent with no detectable level of mercury.
While the current system meets the source and environmental needs, Kettle Falls Generating
Station needs a more cost effective, long-term solution to achieve environmental permit
compliance and to improve the water treatment process.
Kettle Falls is subject to the following regulatory drivers surrounding water treatment:
Washington State Department of Ecology
o National Pollutant Discharge System (NPEDS), 126 priority pollutants
o Discharge water limits (into the Columbia River)
Currently, two intended short term solutions have been deployed to ensure environmental
compliance with increasing and unsustainable operating costs. These two solutions have
been evaluated to determine which best meets the cost effective, environmentally sound,
long term solution being sought to best manage costs.
1. Use of high quality food grade acid
2. RentaliTest Reverse Osmosis (RO) system in place at one fourth (%) of full operating
capacity
Secondary Driver:
The present water treatment system has been in service since the plant went on line in 1983.
The original water treatment demineralization system is aging. The two (2) demineralizer
trains in service are controlled by the original automated control system or Programmable
Logic Controllers (PLC's). Mechanical valves that control the water treatment are failing.
The control system needs to be upgraded to a modern platform and the programming needs
to be rewritten. Because of glitches with the existing control program, the system can get
locked in step until it is reset which uses more chemicals and water, increasing operating
expenses. The panel board for controlling the system has hardwired buttons/indicators that
need to be replaced to allow soft control from a touch panel. The analyzers used are from a
company that is no longer in business and replacement parts cannot be purchased. There is
also a Caustic/Acid dilution rack that is seeing increasing coruosion on piping and valves
need to be replaced. Overall the existing water treatment system needs an overhaul or
replacement.
Risks:
The continued use of the food grade acid does abate the mercury in the effluent, but
significantly increases O&M costs to run the unit. This treatment does not mitigate the
performance risk associated with an aging/obsolete demineralization water treatment
system. The current demineralization system requires a substantial amount of Plant Operator
and Technicians time and effort to reset the system due to component and controls
malfunctions. The system also requires corrective actions to fix pump, hose and valve leaks
(see attached work order history).
a
Business Case Justification Narrative Page 2 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 102 of 108
Kettle Falls Water Treatmenú System
Drivins Metrics:
Through routine internal environmental testing we found that we were discharging trace
amounts of mercury into the Columbia River due to acid and caustic chemicals injected into
the cooling tower and boiler water purification treatment processes. The system is intended
to bring these down to non-detectable levels of mercury.
Success Measures:
The Nalco DMS model will be run for any proposed water treatment system to ensure the
system will meet our environmental requirements. The Nalco DMS model projects the
outcome of water treatment solutions based on the quality and quantity of the incoming
source water, and the quantity of chemicals introduced in the water purification process.
References/Studies:
o Depaftment of Ecology - Self reported "Violation Letter", ll20l20l5
o URS Corporation - Mercury Source Review & Strategy Developmeît,2ll2l2ÙI5
o Nalco, DMS - Water Treatment System Review, 711612015
o Avista Maximo V/ater Treatment V/ork Order History
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltal
Gost
Requested
Start
Requeoted
Complete
Riek
lUlitigatlon
Do nothing $o N/A
Option 1 - Full Scale RO/EDIwater
treatment sysfem
$4.75M 02.2016 06.2018
Option 2 - Full Scale Water Treatment
Sysfem TBD by vendor during RFP
process
$4.75M 02.2016 06.2018
Option 3 - Upgrade current
demineralizer train
unknown 02.2016 06.2018
Impacts:
V/hile the Operations staff at Kettle Falls will need to be trained to operate the new water
treatment system, no additional staff will be needed to meet the operational requirements.
The water treatment system placed in service will be chosen based on O&M costs for
treatment and other costs to repair or replace the existing water treatment system.
Alternatives:
l. The present system of food acid treatment only adds $30,000/ month incremental
O&M expense to supply and manage this treatment. This can continue, however
this option does not address the issues associated with the existing water treatment
plant.
2. Installation of a new Reverse Osmosis (RO) and Electrodionization (EDÐ water
treatment system to replace much of the existing water treatment system, OR
Business Case Justification Narrative Page 3 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 103 of 108
Kettle Falls Water Treatmenú System
3. Installation of an alternative water treatment system TBD by vendors during an
RFP process that would replace much of the existing water treatment system, OR
4. Upgrade the current demineralizer train. Re-write the programming and move the
control and monitoring to the existing plant control system. This option would also
replace worn and non-performing valves and analyzers with new ones.
Risk Mitisation:
This project will improve the reliability of the treated water that is required for the boiler. It
will also provide environmental compliance assurance by addressing mercury levels and
other point source pollutants by upgrading or replacing or enhancing the water treatment
system. Failure to find a long term, cost effective means to treat and provide water for the
boiler could result in environmental compliance violations that could result in significant
penalties andlor changes in permitting regulations with increased operating and capital costs
to meet compliance.
Selected Alternative:
A selected alternative has not been determined at this time. The alternatives will be
evaluated and a final solution will be determined.
Timeline:
o 2016 - Preliminary Analysis for RO/EDI'Water Treatment System
o 2017 - Request for Proposal Process
o 2018 - In Service
Alienment with Strateeic Initiatives:
Mandatory and compliance. The water treatment process needs to adhere to environmental
regulations.
Safe and reliable infrastructure. The water treatment system is an essential operating system
of the plant, failure of the system impacts operations.
Budeet:
The rough +l- 25% estimate for the project is currently at $4.75M based on initial review
conducted by Nalco for water treatment solution alternatives.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 104 of 108
Kettle Falls Water Treatmenú System
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Water Treatment
System Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Andy Vickers
cob idt
Mgr. Contracts & Project Management
Date M
Date
Template Version: 0212412017
Dir. GPSS
Business Case Sponsor
5 VERSION HISTORY
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1.0 Tara Moses 4t5t2017 Steve Wenke 4t10t2017 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 105 of 108
Spokane River License Implementation
I. GENERAL INFORMATION
Requested Spend Amount $2,033,063
Requesting Organ ization/Department Spokane River License lmplementation
Business Case Owner Speed Fitzhugh
Business Case Sponsor Bruce Howard
Sponsor Organization/Department Legal
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Decisions related to annual implementation activities are reviewed and approved by
technical working groups (i.e., fish, aquatic weeds, water quality, recreation, land
use, and cultural) comprised of Avista, Tribal, local, state (ldaho and Washington),
and federal agency staff. The activities are specific to the Federal Energy Regulatory
Commission (FERC)-approved resource and operational plans that were developed
to address Spokane River Project License conditions. Capital projects are
undertaken only to meet the requirements of the Spokane River License.
I¡. BUSINESS PROBLEM
Avista must have a license from FERC to operate the Spokane River Project. The
Spokane River Project consists of the Post Falls Hydroelectric Development (HED),
Upper Falls HED, Monroe Street HED, Nine Mile HED and Long Lake HED. Avista's
prior license expired in2007;Avista undertook a relicensing effort beginning formally
in 2002 to secure a new license, consisting of a collaborative process with over 200
stakeholders. The process ultimately resulted in FERC's issuance of a 5O-year
license to Avista to operate and maintain the Spokane River Project, No 2545,
effective June 18, 2009. This License defines how Avista shall operate the Spokane
River Project and includes several hundred requirements, through license
conditions, that we must meet.
The License was issued pursuant to the Federal Power Act (FPA) and embodies
requirements of a wide range of other laws (The Clean Water Act, The Endangered
Species Act, The National Historic Preservation Act, etc.). These requirements are
also expressed through specific license articles (known as Protection Mitigation and
Enhancement Measures (PME)), relating to fish, terrestrial, water quality, recreation,
land use, education, cultural and aesthetic resources.
Avista also entered into additionaltwo-party agreements with local state, and federal
agencies and the Spokane Tribe. Avista's FERC license and agreements include
mandatory conditions issued by the ldaho Department of Environmental Quality
(401 Water Quality Certification, issued June 5, 2008), the Washington Department
of Ecology (401 Certification, issued May 8, 2009), the U.S. Forest Service (Federal
Power Act 4(e), issued May 4, 2007), U.S. Bureau of Land Management, as well as
Business Case Justification Narrative Page I of3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 106 of 108
Spokane River License lmplementation
commitments joined in with the ldaho Department of Fish and Game, ldaho
Department of Parks and Recreation, City of Coeur d'Alene, and the City of Post
Falls, Kootenai County Parks and Waterways, Washington Parks and Recreation
Commission, the Washington Department of Natural Resources, and articles set
forth in Form L-1 (entitled "Terms and Conditions of License for Constructed Major
project Affecting Lands of the United States"). During the seven-year relicensing
process, we engaged stakeholders in direct negotiations and we also engaged in
litigation to challenge some proposed conditions. Avista's officers and Board were
updated regularly during these efforts, and officers were engaged at key decision
points. Ultimately, FERC retains oversight jurisdiction for license compliance;
however, other entities, such as state agencies, assert their authority to
independently enforce license terms, The FERC license ensured Avista's ability to
operate the Spokane River project on behalf of our customers for another 50 years.
III. PROPOSAL AND RECOMMENDED SOLUTION
Complying with our license is mandatory to continued permission to operate the
Spokane River Project. Funding the implementation activities for the Spokane River
Project License is essentialto remain in compliance with the FERC license. There
are no practicable alternatives to meet compliance. Avista evaluated the potential
of surrendering the Spokane River license at the beginning of the relicensing
process, determining that this option would be detrimental to our customers, the
company, and the communities we serve.
lf the PM&Es, license adicles and settlement agreements are not implemented
and/or funded, we would be out of compliance with and/or in violation of our
License. This would lead to penalties and fines, new license requirements, court
costs, higher mitigation costs, and loss of operational flexibility. Ultimately, FERC
has the authority to revoke our License if we do not comply with the terms and
conditions required by it. Loss of operational flexibility, or in the extreme, loss of our
generation assets, would create substantial new costs to our customers and no
benefits.
Option Capital Cost Start Gomplete
Do nothing $0
Fund the annual request $2,033,063 01 2017 122017
Business Case Justification Narrative Page 2 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 107 of 108
Spokane River License lmplementation
IV APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Spokane River License
lmplementation Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Date
Business Case Owner
Signature:
Print Name
Title:
Role:
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Business Case Sponsor
Date
Template Version: 03107 12017
V. VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Heide Evans 03t15t17 Bruce Howard 3t30t17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 4
Case No. AVU-E-17-01
S. Kinney, Avista
Schedule 3, Page 108 of 108