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August 25,2011
Jean D.Jewell,Secretary
Idaho Public Utilities Commission
Statehouse Mail
W.472 Washington Street
Boise,Idaho 83720 \/——1 D
Dear Ms.Jewell:
RE:Avista Utilities 2011 Electric Integrated Resource Plan
Per the Commission’s Integrated Resource Plan Requirements outlined in Case No.U
1500-165,Order No.22299,Case No.GNR-E-93-1,Order No.24729 and Case No.GNR-E
93-3,Order No.25260 ,Avista Corporation dib/aJ Avista Utilities,hereby submits for filing
an original,unbound,unstapled copy,an electronic copy and 7 copies of its 2011 Electric
Integrated Resource Plan.The Appendices to the plan are provided in by electronic copy.
Paper use and printing costs have been reduced by putting supporting documents on the
Company’s web site at www.avistautilities.comlresources/plans/electric.asp.
The Company submits the IRP to public utility commissions in Idaho and
Washington every two years as required by state regulation.Avista regards the IRP as a
methodology for identifying and evaluating various resource options and as a process by
which to establish a plan of action for resource decisions.
The 2011 Plan is notable for the following:
•The Company is currently long on energy until 2020 and capacity until 2019;
•The Preferred Resource Strategy (PRS)includes 240 MW of wind,4 MW of
thermal plant upgrades,212 MW of SCCT,540 MW of CCCT,13 aMW of
distribution efficiencies and grid modernization,and 310 aMW of energy
efficiency over the next 20 years;
•48 percent of future load growth is met by new energy efficiency, reducing
projected load growth to 1.3 percent per year;and
•This plan includes the Company’s first service territory wide Conservation
Potential Assessment study.
Please direct any questions regarding this report to Clint Kalich at (509)495-4532.
Sincerely,-
Linda Gervais
Manager,Regulatory Policy
State and Federal Regulation
linda.gervais(avistacorp .com
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TABLE OF CONTENTS
Executive Summary i
Introduction and Stakeholder Involvement 1-1
Loads and Resources 2-1
Energy Efficiency 3-1
Policy Considerations 4-1
Transmission & Distribution 5-1
Generation Resource Options 6-1
Market Analysis 7-1
Preferred Resource Strategy 8-1
Action Items 9-1
Safe Harbor Statement
This document contains forward-looking statements. Such statements are
subject to a variety of risks, uncertainties and other factors, most of which are
beyond the Company’s control, and many of which could have a significant
impact on the Company’s operations, results of operations and financial
condition, and could cause actual results to 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.
Table of Figures
Figure 1: Load-Resource Balance—Winter 18 Hour Capacity .............................. ii
Figure 2: Load-Resource Balance—Summer 18 Hour Capacity ........................... ii
Figure 3: Load-Resource Balance—Energy ........................................................ iii
Figure 4: Efficient Frontier .................................................................................... iv
Figure 5: Average Mid-Columbia Electricity Price Forecast .................................. v
Figure 6: Henry Hub Natural Gas Price Forecast ................................................. vi
Figure 7: Cumulative Conservation Acquisitions ................................................. vii
Figure 8: 2011 Preferred Resource Strategy (Annual Average Energy) ............. viii
Figure 9: Projected Price of Greenhouse Gas Emissions ..................................... x
Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
...................................................................................................................... xi
Figure 2.1: Avista’s Service Territory and Generation Resources ..................... 2-2
Figure 2.2: Population Percent Change for Spokane and Kootenai Counties .... 2-3
Figure 2.3: Total Population for Spokane and Kootenai Counties ..................... 2-3
Figure 2.4: House Starts Total Private (SAAR) .................................................. 2-4
Figure 2.5: Percent Change to Employment ...................................................... 2-5
Figure 2.6: Non-Farm Employment .................................................................... 2-5
Figure 2.7: Avista Customer Forecast ................................................................ 2-6
Figure 2.8: Household Size Index ...................................................................... 2-9
Figure 2.9: Electricity Usage per Customer ..................................................... 2-10
Figure 2.10: Avista’s Retail Sales Forecast ..................................................... 2-11
Figure 2.11: Annual Net Native Load ............................................................... 2-12
Figure 2.12: Winter and Summer Peak Demand ............................................. 2-13
Figure 2.13: Electricity Load Forecast Scenario .............................................. 2-14
Figure 2.14: Winter 18-Hour Capacity Load and Resources ............................ 2-21
Figure 2.15: Summer 18-Hour Capacity Load and Resources ........................ 2-22
Figure 2.16: Annual Average Energy Load and Resources ............................. 2-23
Figure 3.1: Historical and Forecast Conservation Acquisition ............................ 3-2
Figure 3.2: Analysis Approach Overview ........................................................... 3-4
Figure 3.3: Cumulative Conservation Potentials, Selected Years ...................... 3-8
Figure 3.4: Incremental Annual Achievable Energy Efficiency (MWh) vs. Avoided
Cost .......................................................................................................... 3-10
Figure 3.5: Energy Savings, Achievable Potential Case by Avoided Costs
Scenario ................................................................................................... 3-14
Figure 3.6: Supply Curves of the Evaluated Conservation Measures ............. 3-15
Figure 3.7: Cost of Existing & Future Conservation ......................................... 3-17
Figure 3.8: Cost of Conservation per Customer per I-937 ............................... 3-17
Figure 4.1: Annual Greenhouse Gas ............................................................... 4-12
Figure 4.2: Price of Greenhouse Gas Credits in each Carbon Policy .............. 4-14
Figure 5.1: Avista Transmission Map ................................................................. 5-2
Figure 6.1: New Resource Levelized Costs ..................................................... 6-11
Figure 6.2: Historical and Planned Hydro Upgrades ........................................ 6-13
Figure 6.3: Long Lake Second Powerhouse Concept Drawing ........................ 6-14
Figure 7.1: NERC Interconnection Map ............................................................. 7-2
Figure 7.2: 20-Year Annual Average Western Interconnect Energy .................. 7-3
Figure 7.3: New Resource Added (Nameplate Capacity) .................................. 7-5
Figure 7.4: Henry Hub Natural Gas Price Forecast............................................ 7-6
Figure 7.5: Shale Gas Production Forecast ....................................................... 7-8
Figure 7.6: Northwest Expected Energy .......................................................... 7-10
Figure 7.7: Regional Wind Expected Capacity Factors .................................... 7-11
Figure 7.8: Price of Greenhouse Gas Credits in each Carbon Policy .............. 7-12
Figure 7.9: Distribution of Annual Average Carbon Prices for 2020 ................. 7-14
Figure 7.10: Historical AECO Natural Gas Prices ............................................ 7-15
Figure 7.11: Stanfield Annual Average Natural Gas Price Distribution ............ 7-16
Figure 7.12: Stanfield Natural Gas Distributions .............................................. 7-16
Figure 7.13: Wind Model Output for the Northwest Region .............................. 7-21
Figure 7.14: 2010 Actual Wind Output BPA Balancing Authority ..................... 7-21
Figure 7.15: Mid-Columbia Electric Price Forecast Range .............................. 7-23
Figure 7.16: Western States Greenhouse Gas Emissions ............................... 7-25
Figure 7.17: Base Case Western Interconnect Resource Mix ......................... 7-26
Figure 7.18: Mid-Columbia Prices Comparison with and without Carbon
Legislation................................................................................................. 7-27
Figure 7.19: Western U.S. Carbon Emissions Comparison ............................. 7-28
Figure 7.20: Unconstrained Carbon Scenario Resource Dispatch ................... 7-28
Figure 7.21: Average Annual Mid-Columbia Electric Prices for Alternative
Greenhouse Gas Policies ......................................................................... 7-29
Figure 7.22: Nominal Levelized Mid-Columbia Electric Prices for Alternative
Greenhouse Gas Policies ......................................................................... 7-30
Figure 7.23: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas
Policies ..................................................................................................... 7-30
Figure 7.24: Average Annual Mid-Columbia Price Comparison of Greenhouse
Gas Policies .............................................................................................. 7-32
Figure 7.25: Expected Greenhouse Gas Emissions Comparison .................... 7-32
Figure 7.26: Natural Gas Price Scenario’s Greenhouse Gas Emission Prices 7-34
Figure 7.27: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts ...... 7-34
Figure 7.28: Wind Sensitivity Mid-Columbia Price Changes ............................ 7-35
Figure 7.29: Wind Sensitivity Negative Pricing ................................................ 7-36
Figure 7.30: Change to Resource Revenues ................................................... 7-37
Figure 8.1: Resource Acquisition History ........................................................... 8-2
Figure 8.2: Conceptual Efficient Frontier Curve ................................................. 8-4
Figure 8.3: Physical Resource Positions (Includes Conservation) ..................... 8-6
Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State RPS 8-
7
Figure 8.5: Energy Efficiency Annual Expected Acquisition ............................... 8-9
Figure 8.6: Annual Average Load and Resource Balance ............................... 8-11
Figure 8.7: Winter Peak Load and Resource Balance ..................................... 8-12
Figure 8.8: Summer Peak Load and Resource Balance .................................. 8-12
Figure 8.9: Avista Owned and Controlled Resource’s Greenhouse Gas
Emissions ................................................................................................. 8-14
Figure 8.10: Expected Case Efficient Frontier ................................................. 8-15
Figure 8.11: Power Supply Expense Range .................................................... 8-21
Figure 8.12: Real Power Supply Expected Rate Growth Index $/MWh (2012 =
100) .......................................................................................................... 8-22
Figure 8.13: Power Supply Cost Sensitivities .................................................. 8-23
Figure 8.14: Greenhouse Gas Related Power Supply Expense ...................... 8-24
Figure 8.15: Efficient Frontier Comparison ...................................................... 8-25
Figure 8.16: Efficient Frontier Comparison ...................................................... 8-26
Figure 8.17: Efficient Frontier Comparison with Tail Var90 .............................. 8-27
Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison .......................... 8-36
Figure 8.19: Load Growth Scenario’s Cost/Risk Comparison .......................... 8-37
Table of Tables
Table 1: The 2011 Preferred Resource Strategy ................................................ viii
Table 2: The 2009 Preferred Resource Strategy ................................................. ix
Table 1.3 Washington IRP Rules and Requirements ......................................... 1-6
Table 2.1: Global Insight National Long Range Forecast Assumptions ............. 2-4
Table 2.2: Company-Owned Hydro Resources ............................................... 2-16
Table 2.3: Company-Owned Thermal Resources ............................................ 2-18
Table 2.4: Mid-Columbia Capacity and Energy Contracts ............................... 2-19
Table 2.5: Large Contractual Rights and Obligations ....................................... 2-20
Table 2.6: Washington State RPS Detail (aMW) ............................................. 2-26
Table 2.7: Winter 18-Hour Capacity Position (MW) ......................................... 2-27
Table 2.8: Summer 18-Hour Capacity Position (MW) ...................................... 2-28
Table 2.9: Average Annual Energy Position (aMW) ......................................... 2-29
Table 3.1: Energy Forecasts and Cumulative Savings (Across All Sectors for
Selected Years) .......................................................................................... 3-7
Table 3.2: Incremental Annual Achievable Potential Energy Efficiency (aMW) . 3-9
Table 3.3: Cumulative Achievable Savings from Conversion to Natural Gas ... 3-10
Table 3.4: Cumulative Achievable Savings from Conversion to Natural Gas by
State (MWh) .............................................................................................. 3-11
Table 3.5: Varying Growth Scenario Descriptions............................................ 3-13
Table 3.6: Varying Growth Scenario Results (MWh) ........................................ 3-13
Table 3.7: Achievable Potential with Varying Avoided Costs .......................... 3-15
Table 4.1: Modeled Greenhouse Gas Policies ................................................. 4-12
Table 5.1: New Resource Integration Costs ...................................................... 5-9
Table 5.2: Distribution Loss Energy Savings (MWh) ........................................ 5-12
Table 6.1: CCCT (Air Cooled) Levelized Costs .................................................. 6-4
Table 6.2: Simple Cycle Plant Cost and Operational Characteristics................. 6-4
Table 6.3: Simple Cycle Plant Levelized Costs per MWh .................................. 6-5
Table 6.4: Northwest Wind Project Levelized Costs per MWh ........................... 6-6
Table 6.5: Solar Nominal Levelized Cost ($/MWh) ............................................ 6-7
Table 6.6: Coal Capital Costs (2012$) ............................................................... 6-8
Table 6.7: Coal Project Levelized Cost per MWh............................................... 6-8
Table 6.8: Other Resource Options Levelized Costs ....................................... 6-10
Table 6.9: Other Resource Options Levelized Costs ($/MWh) ........................ 6-10
Table 6.10: New Resource Levelized Costs Considered in PRS Analysis ....... 6-12
Table 6.11: New Resource Levelized Costs Not Considered in PRS Analysis 6-12
Table 6.12: Hydro Upgrade Potential ............................................................... 6-13
Table 6.13: Rathdrum CT Upgrade Options ($/MWh) ...................................... 6-16
Table 6.14: Coyote Springs 2 Upgrade Options ($/MWh) ................................ 6-17
Table 7.1: AURORAXMP Zones........................................................................... 7-2
Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis . 7-4
Table 7.3: Natural Gas Price Basin Differentials from Henry Hub ...................... 7-7
Table 7.4: Monthly Price Differentials for Stanfield ............................................ 7-7
Table 7.5: Monthly Price Differentials for Stanfield .......................................... 7-12
Table 7.6: January through June Area Correlations......................................... 7-17
Table 7.7: July through December Area Correlations ...................................... 7-18
Table 7.8: Area Load Coefficient of Determination (Std Dev/Mean) ................ 7-18
Table 7.9: Area Load Coefficient of Determination (Std Dev/Mean) ................ 7-19
Table 7.10: Expected Capacity factor by Region ............................................. 7-20
Table 7.11: Annual Average Mid-Columbia Electric Prices ($/MWh) ............... 7-24
Table 7.12: Impacts of Greenhouse Gas Mitigation Policies in the West ......... 7-33
Table 8.1: 2011 Preferred Resource Strategy ................................................... 8-8
Table 8.2: 2009 Preferred Resource Strategy ................................................... 8-8
Table 8.3: Avista Medium-Term Winter Capacity Tabulation ........................... 8-13
Table 8.4: Avista Medium-Term Summer Capacity Tabulation ........................ 8-13
Table 8.5: Nominal Levelized Avoided Costs ($/MWh) .................................... 8-17
Table 8.6: Preferred Resource Strategy Avoided Cost ($/MWh)...................... 8-18
Table 8.7: Updated Annual Avoided Costs ($/MWh)........................................ 8-19
Table 8.8: PRS Rate Base Additions from Capital Expenditures ..................... 8-20
Table 8.9: Preferred Portfolio Cost and Risk Comparison (Millions $) ............. 8-25
Table 8.10: Preferred Resource Strategy ........................................................ 8-27
Table 8.11: Least Cost Portfolio ....................................................................... 8-28
Table 8.12: Least Risk Portfolio ....................................................................... 8-28
Table 8.13: 50/50 Cost and Risk Midpoint Portfolio ......................................... 8-29
Table 8.14: 75/25 Cost Risk Portfolio ............................................................... 8-29
Table 8.15: 25/75 Cost Risk Portfolio ............................................................... 8-30
Table 8.16: PRS without Apprentice Credits .................................................... 8-30
Table 8.17: 2009 IRP Portfolio ......................................................................... 8-31
Table 8.18: PRS without Wind Portfolio ........................................................... 8-31
Table 8.19: CCCT with Solar after 2015 Portfolio ............................................ 8-32
Table 8.20: National Renewable Energy Standard .......................................... 8-32
Table 8.21: PRS without Conservation ............................................................ 8-33
Table 8.22: PRS Conservation Avoided Costs 25% Lower .............................. 8-33
Table 8.23: PRS Conservation Avoided Costs 25% Higher ............................. 8-34
Table 8.24: PRS Conservation Avoided Costs 50% Higher ............................. 8-34
Table 8.25: Low Load Growth Resource Strategy ........................................... 8-36
Table 8.26: High Load Growth Resource Strategy........................................... 8-37
Table 8.27: Summary of Resource Portfolios .................................................. 8-38
Table 8.28: Winter 18-Hour Capacity Position (MW) Net of Conservation with
New Resources ........................................................................................ 8-39
Table 8.29: Summer 18-Hour Capacity Position (MW) Net of Conservation with
New Resources ........................................................................................ 8-40
Table 8.30: Average Annual Energy Position (aMW) With New Resources .... 8-41
Table 8.31: Washington State RPS Detail with New Resources (aMW) .......... 8-42
2011 Electric IRP Introduction
Avista has a long tradition of innovation as a provider of clean, renewable energy. The
2011 Integrated Resource Plan (IRP) continues the tradition by looking into the future
energy needs of our customers. The IRP analyzes and outlines a strategy to meet
projected demand and renewable portfolio standards through energy efficiency and a
careful mix of new renewable and traditional energy resources.
Plant upgrades and conservation measures are an integral part of Avista’s 2011 IRP
resource strategy. Avista expects to add increasing amounts of new renewables to its
generation portfolio in the coming years. Renewables represent viable energy sources
that diversify our resource mix and reduce the need for fossil fuels.
The challenge of integrating renewable resources such as wind and solar is that they
are intermittent resources, meaning the wind does not always blow and the sun does
not always shine. Customers expect high reliability; therefore, utilities will still need
energy from natural gas and hydropower to keep the lights on. This presents a
challenge to resource planners, who must consider reliability as well as rate and
environmental impacts.
Avista’s electricity sales growth is expected to be 1.6 percent over the next two
decades. The Company projects it will have sufficient resources to meet this growth
through 2018.
Each IRP is a thoroughly researched and data-driven document to guide responsible
resource planning for the Company. The IRP is updated every two years and looks 20
years into the future. This plan is developed by Avista’s professional energy analysts
using sophisticated modeling tools and input from interested community stakeholders.
The plan’s Preferred Resource Strategy (PRS) section covers the Company’s projected
resource acquisitions over the next 20 years.
Some highlights of the PRS include:
A newly signed contract for the Palouse Wind project located near Spokane,
Washington will fulfill Avista’s RPS obligations through 2019.
An additional 42 aMW of wind or qualified renewable energy credits are required
by 2020.
Energy efficiency reduces load growth by 48 percent. Aggressive energy
efficiency measures are expected to save 310 aMW of cumulative energy over
the next 20 years.
756 MW of clean-burning natural gas-fired generation facilities are required
between 2018 and 2031.
Avista’s grid modernization and distribution feeder upgrade programs are
projected to reduce load by about five aMW by 2013.
Transmission upgrades will be needed to carry the output from new generation.
Avista will continue to participate in regional efforts to expand the region’s
transmission system.
This document is mostly technical in nature. The IRP has an Executive Summary and
chapter highlights at the beginning of each section to help guide the reader. Avista
expects to begin developing the 2013 IRP in early 2012. Stakeholder involvement is
encouraged and interested parties may contact John Lyons at 509-495-8515 or
john.lyons@avistacorp.com for more information on participating in the IRP process.
Executive Summary
Avista Corp 2011 Electric IRP
Executive Summary
Avista’s 2011 Integrated Resource Plan (IRP) guides its strategy over the next two
years and indicates the overall direction of resource procurements for the remainder of
a 20-year planning horizon. It provides a snapshot of the Company’s resources and
loads and guidance for future resource acquisitions. The resultant Preferred Resource
Strategy (PRS) is a mix of wind generation, energy efficiency, upgrades at existing
generation and distribution facilities, and new gas-fired generation.
The PRS balances cost, reliability, rate volatility, and renewable resource requirements.
Avista’s management and the Technical Advisory Committee (TAC) stakeholders play a
central role in guiding the development of the PRS and the IRP as a whole by providing
significant input on modeling and planning assumptions, and the general direction of the
planning process. TAC members include customers, commission staff, the Northwest
Power and Conservation Counsel, consumer advocates, academics, utility peers,
government agencies, and interested internal parties.
Resource Needs
Plant upgrades and conservation measures are an integral part of Avista’s 2011 IRP
resource strategy, but they are ultimately inadequate to meet all expected future load
growth. Absent new resource additions or new conservation measures, annual energy
deficits begin in 2020, with loads and a planning margin exceeding resource capability
by 49 aMW. Energy deficits rise to 218 aMW in 2026 and 475 aMW in 2031. Absent
new resource additions or new conservation measures, the Company will be short 98
MW of summer capacity in 2019.1 In 2026 and 2031, capacity deficits rise to 352 MW
and 774 MW, respectively. Winter capacity deficits begin at 42 MW in 2020 and
increase to 401 MW in 2026 and 883 MW in 2031.2
Increasing deficits are a result of forecasted 1.6 percent energy and capacity load
growth through 2031. The expiration of long-term purchase and sale contracts on a net
basis also increases deficiencies. Figures 1 through 3 provide graphical representations
of projected load and resource balances before the addition of PRS resources. The
vertical bars in the figures show Avista’s resource mix including hydroelectric, baseload
thermal resources (such as Colstrip and Coyote Springs 2), peaking thermals (such as
Northeast and Rathdrum), and net market transactions (includes long-term purchases
and sales plus our expected short-term market transactions). The lower lines in the
figures represent the load forecast and the upper lines include the load forecast plus a
planning margin and operating reserves. The load forecast uses sustained 18-hour
peaks.3 The forecasted needs would be higher absent energy efficiency acquisitions. A
more thorough discussion of loads and resources position is in Chapter 2.
1 This position assumes Avista relies on its share of regional power surpluses through 2021 as identified
by the Northwest Power and Conservation Council and documented further in Chapter 2. 2 Ibid. 3 The 18-hour sustained peak metric assumes six peak hours for three days in a row.
Executive Summary
Avista Corp 2011 Electric IRP
Figure 1: Load-Resource Balance—Winter 18 Hour Capacity
Figure 2: Load-Resource Balance—Summer 18 Hour Capacity
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Executive Summary
Avista Corp 2011 Electric IRP
Figure 3: Load-Resource Balance—Energy
Modeling and Results
Avista uses a multiple-step approach to develop its Preferred Resource Strategy. It
begins by identifying and quantifying potential new generation resources to serve
projected demand needs across the West. A Western Interconnect-wide study explains
the impact of regional markets on the Northwest electricity marketplace. Avista then
maps its existing resources to the present transmission grid configuration in a model
simulating hourly operations for the Western Interconnect from 2012 to 2031.
The model adds cost-effective new resources and transmission to meet growing loads.
Monte Carlo-style analysis varies hydroelectric generation, wind generation, load,
forced outages, greenhouse gas emission cost estimates, and natural gas price data
over 500 iterations of potential future market conditions. The simulation estimates Mid-
Columbia electricity markets, and the iterations collectively form the IRP Expected
Case.
Each new resource and energy efficiency option is valued against the Expected Case
Mid-Columbia electricity market to identify its future value to the Company, as well as its
inherent risk measured as year-to-year 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 the Company by developing optimal mixes of new resources at each point on an
efficient frontier.4 The PRS provides a “least reasonable cost” portfolio that
simultaneously minimizes future costs and risks given legislatively mandated or
expected future environmental constraints. An efficient frontier helps determine the
4 See Chapter 8 for a detailed discussion of the efficient frontier concept.
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Executive Summary
Avista Corp 2011 Electric IRP
tradeoffs between risk and cost. The approach is similar to finding an optimal mix of risk
and return when developing a personal investment portfolio. As expected returns
increase, so do risks. Reducing risk reduces overall returns. Identifying the PRS is
similar to an investor’s dilemma. There is a trade-off between power supply costs and
power supply cost variability. Figure 4 presents the change in cost and risk from the
PRS on the Efficient Frontier. Lower power cost variability comes from investment in
more expensive, but less risky, resources. The PRS selection is the location on the
efficient frontier where the increased cost justified the reduction in risk.
Figure 4: Efficient Frontier
The IRP includes several scenarios that help identify tipping points where the PRS
could change under alternative conditions to the Expected Case. Chapter 8 includes
scenarios for load growth, capital costs, higher energy efficiency acquisitions, and
greenhouse gas policies.
Electricity and Natural Gas Market Forecasts
Figure 5 shows the 2011 IRP electricity price forecast in the Expected Case, including
the modeled range of prices over the 500 Monte Carlo iterations described previously.
The forecasted levelized average Mid-Columbia market price is $70.50 per MWh in
nominal dollars over the next 20 years; the off-peak price is $63.94 per MWh and the
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Executive Summary
Avista Corp 2011 Electric IRP
on-peak price is $75.42 per MWh. These prices include the market impacts of
greenhouse gas mitigation beginning in 2015.5
Figure 5: Average Mid-Columbia Electricity Price Forecast
Electricity and natural gas prices are highly correlated because natural gas fuels
marginal generation resources in the northwest during most of the year. Figure 6
presents nominal levelized Expected Case natural gas prices at Henry Hub, as well as
the range of forecasts from the 500 Monte Carlo iterations performed for the case. The
average is $6.70 per decatherm over the next 20 years. See Chapter 7 for more detail
on the Company’s natural gas price forecast.
5 The forecast assumes a western region reduction of 14 percent by 2032.
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Executive Summary
Avista Corp 2011 Electric IRP
Figure 6: Henry Hub Natural Gas Price Forecast
Energy Efficiency Acquisition
Avista commissioned a 20-year Conservation Potential Assessment in 2010. The study
analyzed over 4,300 equipment and measure options for residential, commercial, and
industrial applications. Data from this study formed the basis of the IRP conservation
potential evaluations. Figure 7 shows how energy efficiency decreases Avista’s energy
requirements by 120.2 aMW, or approximately ten percent.6 By 2031, energy efficiency
reduces load by 310 aMW (288 aMW net after measure life expectancy adjustments).
More detail about Avista’s energy efficiency programs is contained in Chapter 3.
6 The Company has acquired 156.3 aMW of conservation since 1978; however, the assumed 18-year
average life of the conservation portfolio means that some of the measures have reached the end of their
useful lives and are no longer reducing loads. The 18-year assumed life of measures accounts for the
difference between the Gross and Net lines in Figure 7.
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Executive Summary
Avista Corp 2011 Electric IRP
Figure 7: Cumulative Conservation Acquisitions
Preferred Resource Strategy
The PRS includes careful consideration by Avista’s management and the Technical
Advisory Committee of the information gathered and analyzed in the IRP process. It
meets future load growth with efficiency upgrades at existing generation and distribution
facilities, conservation, wind, and simple- and combined-cycle natural gas-fired
combustion turbines. Figure 8 displays the resource mix for the 2011 Preferred
Resource Strategy layered on top of Avista’s current resources.
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Executive Summary
Avista Corp 2011 Electric IRP
Figure 8: 2011 Preferred Resource Strategy (Annual Average Energy)
The PRS has changed only modestly from the 2009 IRP. The PRS resources of both
the 2009 and 2011 IRPs, on a nameplate capacity basis, are in Tables 1 and 2 below.
Table 1: The 2011 Preferred Resource Strategy
Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 120 35
SCCT 2018 83 75
Existing Thermal Resource Upgrades 2019 4 3
NW Wind 2019-2020 120 35
SCCT 2020 83 75
CCCT 2023 270 237
CCCT 2026 270 237
SCCT 2029 46 42
Total 996 739
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2012-2031 28 13
Energy Efficiency 2012-2031 419 310
Total 447 323
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Other
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Existing Resources
Load w/o DSM + Cont.
Load w DSM + Cont.
Executive Summary
Avista Corp 2011 Electric IRP
Table 2: The 2009 Preferred Resource Strategy
Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
Northwest Wind 2012 150 48
Little Falls Unit Upgrades 2013-2016 3 1
Northwest Wind 2019 150 50
Combined-Cycle Combustion Turbine 2019 250 225
Upper Falls 2020 2 1
Northwest Wind 2022 50 17
Combined-Cycle Combustion Turbine 2024 250 225
Combined-Cycle Combustion Turbine 2027 250 225
Total 1,105 792
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2010-2015 5 3
Energy Efficiency 2010-2029 339 226
Total 344 229
The present value of the investment required to support the 2011 PRS is just over $0.84
billion; the nominal total capital expense is $1.7 billion over the IRP timeframe. Avista
also forecasts spending $1.4 billion over the IRP timeframe on conservation
acquisitions.
Greenhouse Gas Emissions
As with all Avista IRPs since 2007, the costs of greenhouse gas policies are included in
the Expected Case for this IRP. Since the 2009 IRP, less certainty exists around the
direction of future of greenhouse gas policies. To address this uncertainty, the 2011 IRP
considers four policies. Each represents a different policy alternative beginning in 2015.
The policies are: 1) a regional cap and trade regime, 2) a national cap and trade regime,
3) a national carbon tax, and 4) the absence of any greenhouse gas policy. The impacts
of greenhouse gas policies on the Expected Case are the result of a weighted average
of these policies as included in the stochastic analysis of the IRP. Figure 9 presents
emissions cost assumptions on a per-short ton basis.
Executive Summary
Avista Corp 2011 Electric IRP
Figure 9: Projected Price of Greenhouse Gas Emissions
Figure 10 shows projected greenhouse gas emissions for existing and new Avista
generation assets.7 The grey area of Figure 10 represents incremental greenhouse gas
emissions where there is no national or regional greenhouse gas policy.8
7 Figure 10 does not include emissions from market or contract purchases. It also does not reduce
Company emissions commensurate with market or contract sales. 8 Existing Avista resources, and those selected to meet load growth, under a scenario without a
greenhouse gas policy likely would generate higher emissions due primarily to increased operation at
Colstrip.
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National GHG Tax
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Expected Case
Regional GHG Policy
Executive Summary
Avista Corp 2011 Electric IRP
Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
Action Items
The Company’s 2011 Action Plan outlines activities and studies between now and the
2013 Integrated Resource Plan. It includes input from Commission Staff, the Company’s
management team, and the Technical Advisory Committee. Action Item categories
include resource additions and analysis, demand side management, environmental
policy, modeling and forecasting enhancements, and transmission planning. Chapter 9
contains 2011 IRP Action Items.
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New Resources
Existing Resources
Tons per MWh of Load
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
1. Introduction and Stakeholder Involvement
Avista Utilities submits a biennial Integrated Resource Plan (IRP) to the Idaho and
Washington public utility commissions.1 The 2011 IRP is Avista’s twelfth plan. It
identifies and describes a Preferred Resource Strategy (PRS) for meeting load growth
while balancing cost and risk measures with environmental mandates.
The Company is statutorily obligated to provide reliable electricity service to its
customers at rates, terms, and conditions that are just, reasonable, and sufficient.
Avista assesses different resource acquisition strategies and business plans to acquire
resources to meet resource adequacy requirements and optimize the value of its current
resource portfolio. We use the IRP as a resource evaluation tool rather than a plan for
acquiring a particular set of assets. The 2011 IRP continues refining our resource
acquisition efforts.
IRP Process
The 2011 IRP is developed and written with the aid of a public process. Avista actively
seeks input for its IRPs from a variety of constituents through the Technical Advisory
Committee (TAC). The TAC list of 75 individuals includes Commission Staff from Idaho
and Washington, customers, academics, government agencies, consultants, utilities,
and other interested parties who accepted an invitation to join, or had asked to be
involved in, the planning process.
The Company sponsored six TAC meetings for the 2011 IRP. The first meeting was on
May 27, 2010, and the last was on June 23, 2011. TAC meetings covered different
aspects of the 2011 IRP planning activities and solicited contributions to, and
assessments of, modeling assumptions, modeling processes, and results. Table 1.1
contains a list of TAC meeting dates and the agenda items covered in each meeting.
1 Washington IRP requirements are contained in WAC 480-100-238 Integrated Resource Planning. Idaho
IRP requirements are outlined in Case No. U-1500-165 Order No. 22299, Case No. GNR-E-93-1, Order
No. 24729, and Case No. GNR-E-93-3, Order No. 25260.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
Table 1.1: TAC Meeting Dates and Agenda Items
Meeting Date Agenda Items
TAC 1 – May 27, 2010 Work Plan
Load & Resource Balance Update
Resource Planning Environment
2011 IRP Topic Discussions – Analytical
Process Changes, Hydro Modeling,
Resource Adequacy, Loss of Load
Probability, Energy Efficiency and Scoping
the 2011 Plan
TAC 2 – September 8 and 9,
2010
Lancaster Plant Tour
Upper Falls and Monroe Street Tour
Resource Assumptions
Reliability Planning
Sustainability Report
Combined Heat and Power Generation
Energy Efficiency
TAC 3 – December 2, 2010 Transmission Costs and Issues
Potential Hydro Upgrades
Potential Thermal Upgrades
Load Forecast
Stochastic Modeling
TAC 4 – February 3, 2011 Natural Gas Price Forecast
Electric Price Forecast
Resource Requirements Projections
Portfolio and Market Scenario Planning
TAC 5 – April 12, 2011 Conservation Avoided Cost Methodology
Conservation
Smart Grid
Draft Preferred Resource Strategy
Portfolio Alternatives & Scenarios
TAC 6 – June 23, 2011 High Wind Market Analysis
Preferred Resource Strategy and Scenario
Analysis
IRP Action Items
IRP Section Highlights
Agendas and presentations from the TAC meetings are in Appendix A and on Avista’s
website at http://www.avistautilities.com/inside/resources/irp/electric. Past IRPs and
TAC presentations are also here.
Avista wishes to acknowledge the contributions of a number of external TAC
participants in Table 1.2.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
Table 1.2: External Technical Advisory Committee Participants
Participant Organization
Robin Toth Greater Spokane Inc.
Dave Van Hersett Resource Development Associates
John Dacquisto Gonzaga University
Deborah Reynolds Washington Utilities and Transportation Commission
Steve Johnson Washington Utilities and Transportation Commission
David Nightingale Washington Utilities and Transportation Commission
Rick Applegate Washington Utilities and Transportation Commission
Nancy Hirsch Northwest Energy Coalition
Kirsten Wilson Washington State General Administration
Rick Sterling Idaho Public Utilities Commission
Tom Noll Idaho Power
Ken Corum Northwest Power and Conservation Council
Keith Knitter Grant County Public Utilities District
Becky King Chelan County Public Utilities District
Villamour Gamponia Puget Sound Energy
Kevin Rasler Inland Empire Paper
Mike Connolley Idaho Forest Group
Rob Haneline McKinstry
Issue Specific Public Involvement Activities
In addition to the TAC meetings, Avista sponsors and participates in several other
collaborative processes involving a range of public interests.
External Energy Efficiency (“Triple E”) Board
The Triple E Board, formed in 1995, provides stakeholders and public groups biannual
opportunities to discuss Avista’s energy efficiency efforts. The Triple E Board grew out
of the DSM Issues group. This predecessor group was influential in developing the
country’s first conservation distribution surcharge in 1995.
FERC Hydro Relicensing – Clark Fork River Projects
Over 50 stakeholder groups participated in the Clark Fork hydro-relicensing process
beginning in 1993. This led to the first all-party settlement filed with a FERC relicensing
application, and eventual issuance of a 45-year FERC operating license in February
2003. The nationally recognized Living License concept was a result of this process.
This collaborative process continues in the implementation phase of the Living License,
with stakeholders participating in various protection, mitigation, and enhancement
efforts at the projects.
Low Income Rate Assistance Program (LIRAP)
LIRAP is coordinated with four community action agencies in Avista’s Washington
service territory. The program began in 2001 and reviews administrative issues and
needs on a quarterly basis.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
Regional Planning
The Pacific Northwest’s generation and transmission system is operated in a
coordinated fashion. Avista participates in the efforts of many organization’s planning
processes. Information from this participation supplements Avista’s IRP process. Some
of the organizations that Avista participates in are:
Western Electricity Coordinating Council
Northwest Power and Conservation Council
Northwest Power Pool
Pacific Northwest Utilities Conference Committee
ColumbiaGrid
Northwest Transmission Assessment Committee
North American Electric Reliability Council
Future Public Involvement
As explained above, 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.
2011 IRP Outline
The 2011 IRP consists of nine chapters plus an executive summary and this
introduction. A series of technical appendices supplement this report.
Executive Summary
This chapter summarizes the overall results and highlights of the key results of the 2011
IRP.
Chapter 1: Introduction and Stakeholder Involvement
This chapter introduces the IRP and details public participation and involvement in the
integrated resource planning process.
Chapter 2: Loads and Resources
The first half of this chapter covers Avista’s load forecast and related local economic
forecasts. The last half describes the Company’s owned generating resources, major
contractual rights and obligations, capacity, energy and renewable energy credit
tabulations, and reserve obligations.
Chapter 3: Energy Efficiency
This chapter discusses Avista’s energy efficiency programs. It provides an overview of
the conservation potential assessment and summarizes the energy efficiency modeling
results for the 2011 IRP.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
Chapter 4: Policy Considerations
This chapter focuses on some of the major policy issues for resource planning, such as
state and federal greenhouse gas policies and environmental regulations.
Chapter 5: Transmission & Distribution
This chapter discusses Avista’s distribution and transmission systems, as well as
regional transmission planning issues. The chapter includes detail on transmission cost
studies used in the IRP modeling, including a summary of our 10-year Transmission
Plan. The chapter includes a discussion of Avista’s distribution efficiency and grid
modernization projects.
Chapter 6: Generation Resource Options
This chapter covers the costs and operating characteristics of the generation resource
options modeled for the 2011 IRP.
Chapter 7: Market Analysis
This chapter details Avista’s modeling and analysis of the various wholesale markets
applicable to the 2011 IRP.
Chapter 8: Preferred Resource Strategy
This chapter details Avista’s 2011 Preferred Resource Strategy (PRS) and explains how
the PRS could change in response to scenarios differing from the Expected Case.
Chapter 9: Action Items
This chapter provides an overview of the progress made on Action Items from the 2009
IRP. It details new Action Items to start and/or complete between the issuance of the
2011 IRP and prior to the 2013 IRP.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
Regulatory Requirements
The IRP process for Washington has several requirements documented in Washington
Administrative Code (WAC). Table 1.3 summarizes where within the IRP the applicable
WACs are addressed.
Table 1.1 Washington IRP Rules and Requirements
Rule and Requirement Plan Citation
WAC 480-100-238(4) – Work
plan filed no later than 12 months
before next IRP due date. Work
plan outlines content of IRP.
Work plan outlines method for
assessing potential resources.
Work plan submitted to the UTC on August 31,
2010; see Appendix B for a copy of the Work Plan.
WAC 480-100-238(5) – Work
plan outlines timing and extent of
public participation.
Appendix B
WAC 480-100-238(2)(a) – Plan
describes mix of energy supply
resources.
Chapter 6- Generation Resource Options
WAC 480-100-238(2)(a) – Plan
describes conservation supply.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(a) – Plan
addresses supply in terms of
current and future needs of utility
ratepayers.
Chapter 2- Loads & Resources
WAC 480-100-238(2)(b) – Plan
uses lowest reasonable cost
(LRC) analysis to select mix of
resources.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers resource
costs.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers market-
volatility risks.
Chapter 4- Policy Considerations
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238 (2)(b) – LRC
analysis considers demand side
uncertainties.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(b) – LRC
analysis considers resource
dispatchability.
Chapter 6- Generation Resource Options
Chapter 7- Market Analysis
WAC 480-100-238(2)(b) – LRC
analysis considers resource
effect on system operation.
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
WAC 480-100-238(2)(b) – LRC
analysis considers risks imposed
on ratepayers.
Chapter 4- Policy Considerations
Chapter 6- Generation Resource Options
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers public policies
regarding resource preference
adopted by Washington state or
federal government.
Chapter 2- Loads & Resources
Chapter 4- Policy Considerations
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers cost of risks
associated with environmental
effects including emissions of
carbon dioxide.
Chapter 4- Policy Considerations
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(c) – Plan
defines conservation as any
reduction in electric power
consumption that results from
increases in the efficiency of
energy use, production, or
distribution.
Chapter 3- Energy Efficiency
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
includes a range of forecasts of
future demand.
Chapter 2- Loads & Resources
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
develops forecasts using
methods that examine the effect
of economic forces on the
consumption of electricity.
Chapter 2- Loads & Resources
Chapter 5- Transmission & Distribution
Chapter 8- Preferred Resource Strategy
WAC 480-100-238-(3)(a) – Plan
develops forecasts using
methods that address changes in
the number, type and efficiency of
end-uses.
Chapter 2- Loads & Resources
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan
includes an assessment of
commercially available
conservation, including load
management.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan
includes an assessment of
currently employed and new
policies and programs needed to
obtain the conservation
improvements.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP
WAC 480-100-238(3)(c) – Plan
includes an assessment of a wide
range of conventional and
commercially available
nonconventional generating
technologies.
Chapter 6- Generator Resource Options
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(d) – Plan
includes an assessment of
transmission system capability
and reliability (as allowed by
current law).
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(e) – Plan
includes a comparative
evaluation of energy supply
resources (including transmission
and distribution) and
improvements in conservation
using LRC.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
WAC-480-100-238(3)(f) –
Demand forecasts and resource
evaluations are integrated into
the long range plan for resource
acquisition.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
Chapter 6- Generator Resource Options
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(g) – Plan
includes a two-year action plan
that implements the long range
plan.
Chapter 9- Action Items
WAC 480-100-238(3)(h) – Plan
includes a progress report on the
implementation of the previously
filed plan.
Chapter 9- Action Items
WAC 480-100-238(5) – Plan
includes description of
consultation with commission
staff. (Description not required)
Chapter 1- Introduction and Stakeholder
Involvement
WAC 480-100-238(5) – Plan
includes description of work plan.
(Description not required)
Appendix B
WAC 480-107-015(3) – Proposed
request for proposals for new
capacity needed within three
years of the IRP.
Chapter 8- Preferred Resource Strategy
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-1
2. Loads & Resources
Introduction & Highlights
An explanation and quantification of Avista’s loads and resources are integral to the
Integrated Resource Plan (IRP). The first half of this chapter summarizes customer and
load forecasts, including forecast ranges, load growth scenarios, and an overview of
enhancements to forecasting models and processes. The second half of the chapter
covers Avista’s current resource mix, including descriptions of owned and operated
generation, as well as long-term power purchase contracts.
Economic Conditions in Avista’s Service Territory
Avista serves electricity customers in most of the urban and suburban areas of 24
counties of eastern Washington and northern Idaho. The service territory is
geographically and economically diverse. Figure 2.1 shows the Company’s electricity
and natural gas service territories.
The Inland Northwest has transformed over the past 25 years, from a natural resource-
based manufacturing economy to a diversified light manufacturing and services
economy. The United States Forest Service manages a significant portion of the
mountainous areas of the region. Reduced timber harvests on federal lands have
closed many local sawmills. Two pulp and paper plants served by Avista manage large
forest holdings and face stiff domestic and international competition for their products.
Avista’s service territory experienced periods of significant unemployment during the
two national recessions of the 1980s. The 1991/92 national recession mostly bypassed
Avista’s service territory, but the 2001 recession greatly affected the area. The IRP
Expected Case projects the present recession to end in 2011. The employment data
reflects the effects of economic recession and expansion. Avista tracks employment
data for the three principal counties in its electricity service territory: Bonner, Kootenai
and Spokane.
Section Highlights
Historic conservation acquisitions are included in the load forecast; higher
acquisition levels anticipated in the IRP reduce the load forecast further.
Annual electricity sales growth from 2012 to 2031 averages 1.6 percent.
Expected energy deficits begin in 2020, growing to 475 aMW by 2031.
Expected capacity deficits begin in 2019, growing to 883 MW by 2031.
Current conservation programs push the need for resources out by two years
for energy and six years for capacity.
Renewable portfolio requirements drive near-term resource needs.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-2
Figure 2.1: Avista’s Service Territory and Generation Resources
Population is generally more stable than employment during times of economic change;
however, it can contract during severe economic downturns as people leave in search
of employment opportunities. Over the past 25 years, the region experienced a net
population loss only in 1987. Figure 2.2 details historic and projected annual population
changes in Kootenai and Spokane counties. Figure 2.3 shows total population.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-3
Figure 2.2: Population Percent Change for Spokane and Kootenai Counties
Figure 2.3: Total Population for Spokane and Kootenai Counties
People, Jobs and Customers
The October 2010 IRP forecast relies on an August 2010 national and September 2010
county-level forecasts. The data focus on two counties–Spokane County in Washington,
and Kootenai County in Idaho–that comprise more than 80 percent of our service area
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-4
economy. Avista purchases the employment and population forecasts from Global
Insight, Inc., an internationally recognized economic forecasting consulting firm.
The Third Technical Advisory Committee included sections on the load forecast and its
underlying assumptions. Table 2.1 presents the key forecast assumptions presented at
that meeting.
Table 2.1: Global Insight National Long Range Forecast Assumptions
Gross Domestic Product 2.7% Housing Starts (millions) 1.58/year
Consumer Price Index 1.9% Job Growth 1.0%/year
Imported Crude 2000$ $70 Worker Productivity 2.0%
Federal Funds Rate 4.75% Consumer Sentiment 90
Unemployment Rate 5.0%
In 2010, as part of a revision in materials provided under contract to Avista, Global
Insight began producing housing start forecasts consistent with the population and
employment forecasts, as shown in Figure 2.4.
Figure 2.4: House Starts Total Private (SAAR)
Employment growth often drives population growth. Figure 2.5 shows historical
employment trends from 1995, and forecast growth through 2035. Overall non-farm
wage and salary employment over the past 15 years averaged 2.9 percent for Kootenai
County and 1.0 percent for Spokane County.
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-5
Figure 2.5: Percent Change to Employment
Figure 2.6 provides additional non-farm employment data. Over the forecast period,
non-farm employment growth is 1.5 percent and 0.9 percent for Spokane and Kootenai
counties, respectively. Employment growth is approximately 3,000 new jobs per year.
Figure 2.6: Non-Farm Employment
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-6
Customer growth projections follow baseline economic forecasts. Employment statistics
have the greatest probability of near term change as the region emerges from the
recession in 2011. Avista tracks four key customer classes: residential, commercial,
industrial, and street lighting. A linear regression using housing starts as the
independent variable is the basis for the residential customer forecasts. Commercial
forecasts rely on a linear regression of residential growth. Industrial customer growth
follows employment growth. Street lighting customer growth is trended with population
growth.
Avista forecasts sales by rate schedule. Overall customer forecasts are a compilation of
the various rate schedules. For example, the residential class forecast is comprised of
separate forecasts prepared for rate schedules 1, 12, 22, and 32 for Washington and
Idaho. See Figure 2.7 for annual customer growth levels by rate class.
Figure 2.7: Avista Customer Forecast
On average during calendar 2010, Avista served 356,567 retail customers: 315,275
residential, 39,488 commercial, 1,375 industrial and 449 street lighting. This is a 15
percent increase from 309,871 retail customers in 2000. In 2010, 33.4 percent of
residential customers, 42.0 percent of commercial customers, 34.6 percent of industrial
customers, and 27.7 percent of street lighting customers were located in Idaho; the
balance was located in Washington. The 2035 forecast predicts 474,316 retail
customers: 419,739 residential, 52,172 commercial, 1,635 industrial and 770 street
lighting. The 25-year compound growth rate averages 1.1 percent, down from 1.7
percent in the 2009 IRP and consistent with a lower population forecast.
250,000
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Commercial Residential
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-7
Weather Forecasts
The Expected Case electricity sales forecast uses 30-year monthly temperature
averages recorded at the Spokane International Airport weather station through 2009.
Several other weather stations are located in Avista’s service territory, but their data are
available for a much shorter duration and high correlations exist between the Spokane
International Airport and these weather stations.
Sales forecasts are prepared using monthly data, as more granular load information is
not available. Heating degree-days measure cold weather load sensitivity; cooling
degree-days measure hot weather load sensitivity.
The load forecast includes projection of climate change impact. Ample evidence of
cooling and warming trends exists in the historical record. The recent trend is a warming
climate compared to the 30-year average. Avista relies on the University of Washington
―Climate Change Scenarios‖ 2008 study converted to heating and cooling degree-days.1
This study provides warming to 87.2 percent of the present 30-year average. Cooling
degree-days are 144.3 percent.
Price Elasticity
Price elasticity is an important consideration in any electricity demand forecast. It
measures the ratio between the demand for electricity and a change in its price. A
consumer who is sensitive to price change has a relatively elastic demand profile. A
customer who is unresponsive to price changes has a relatively inelastic demand
profile. During the 2000-2001 Western Energy Crisis customers displayed increasing
price sensitivity and reduced overall usage in response to relatively large changes in the
price of electricity.
Cross elasticity of demand, or cross-price elasticity, measures the relationship between
the quantities of electricity demanded and to the quantity of potential electricity
substitutes (e.g., propane or natural gas for heat) when the price of electricity increases
relative to the price of the substitute product. A positive cross elasticity coefficient
indicates cross-price elasticity between electricity and the substitute. A negative cross
elasticity coefficient indicates the absence of cross-price elasticity, and that considered
product is not a substitute for electricity but is instead complementary to it. In other
words, an increase in the price of electricity increases the use of the complementary
good, and a decrease in the price of electricity decreases the use of the complementary
good.
The principal application of cross elasticity impact in the IRP is its substitutability by
natural gas in some applications, including water and space heating. The correlation
between retail electricity prices and the commodity cost of natural gas has increased in
recent years as the industry has become more reliant on gas-fired generation to meet
load growth. This increased positive correlation has reduced the net effect of cross price
elasticity between retail natural gas and electricity prices.
1 http://cses.washington.edu/cig/fpt/ccscenarios.shtml.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-8
Income elasticity measures the relationship between a change in consumer income and
the change in consumer demand for electricity. As incomes rise, the ability of a
consumer to pay for more electricity increases. The ability to afford electricity-
consuming appliances also increases. Simply stated, as incomes rise consumers are
more likely to purchase more electricity-consuming equipment, live in larger dwellings
that use more electricity, and use the electrical equipment they have more often. Two of
the most cited present examples of income elasticity are the increased proliferation of
mobile electronic devices and high definition televisions.
The IRP estimates price elasticity by customer class for use in our electricity and natural
gas demand forecasts. The price elasticity statistics used in the 2011 IRP are negative
0.15 for residential and negative 0.10 for commercial customers. Natural gas and
electricity cross-price elasticity is positive at 0.05. Income elasticity is positive 0.75,
meaning electricity is more affordable as incomes rise.
The baseline forecast used in the Expected Case assumes that rising incomes offset
rising electricity and natural gas prices. Thus, there is no net expected impact on
electricity consumption other than that caused by climate change and energy efficiency
programs.
Retail Price Forecast
The retail sales forecast assumes retail prices increase at an average annual rate of
eight percent from 2010 to 2018, followed by increases at the rate of general economic
inflation thereafter. Carbon legislation and renewable energy targets are responsible for
approximately one-fourth of the rate rise.2
Conservation
It is difficult to separate the interrelated impacts of rising electricity and natural gas
prices, rising incomes, and conservation programs on the load forecast. Avista collects
data on total demand, and derives from this data consumption change impacts. Avista
has encouraged its customers to conserve electricity by offering conservation programs
to its customers since 1978. Electricity usage impacts of these programs affect historical
data; therefore, we conclude that the forecast already contains the impacts of existing
conservation levels (7.5 aMW per year of new acquisition). As the 2011 IRP forecasts
increased levels of conservation acquisition relative to history, the increased quantities
reduce retail loads below Expected Case forecast levels.
Use per Customer Projections
A database of monthly electricity sales and customer numbers by rate schedule forms
the basis of the usage per customer forecasts by rate schedule, customer class, and
state from 1997 to 2010. Historical data is weather-normalized to remove the impact of
2 This result assumes that the legislation does not mitigate the impacts of GHG legislation by issuing free
utility allocations. Avista develops its load forecast independently of the IRP process. The load forecast
mitigation assumption therefore differs from the Expected Case in the IRP where carbon mitigation
legislation provides significant offsets and thereby limits the overall rate impact of carbon legislation.
Avista does not expect this assumption difference to affect significantly the IRP results.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-9
heating and cooling degree-day deviations from expected normal values, as discussed
above. Retail electricity price increases reduce electricity usage per customer.
The 2011 IRP includes a forecast of electric vehicles in the Expected Case based on
projections made by the Northwest Power and Conservation Council in its Sixth Power
Plan. The electric fleet is a combination of plug-in hybrids and electric-only passenger
vehicles.
The residential usage per customer forecast trends flat over the long term. This result is
the combination of reductions from embedded conservation, warming temperatures,
price elasticity effects, and increases from electricity vehicle use. The forecast of
household size decreases over time, as shown in Figure 2.8.
Figure 2.8: Household Size Index
Residential customers tend to be homogeneous relative to size of their dwellings.
Commercial customers, on the other hand, are heterogeneous, ranging from small
customers with varying electricity intensity per square foot of floor space to big box
retailers with generally high intensities. The addition of new large commercial
customers, including additions to largest universities and hospitals, can greatly skew
average use per average customer statistics. Usage forecasts for the residential and
commercial sectors are contained in Figure 2.9.
Estimates for residential usage per customer across all schedules are relatively smooth.
Commercial usage per customer increases for several years due to additional existing
and new buildings housing very large customers, including Washington State University
and Sacred Heart Medical Center. Expected additions for very large customers are
included in the forecast through 2015; no additions are included after 2015. Avista
includes only publicly announced long lead-time buildings in its load forecast.
94%
95%
96%
97%
98%
99%
100%
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103%
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1995 2000 2005 2010 2015 2020 2025 2030 2035
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-10
Figure 2.9: Electricity Usage per Customer
Retail Electricity Sales Forecast
Major economic changes between 1997 and 2010 affected the region, not the least of
which was a marked increase in wholesale and retail electricity prices. The energy crisis
of 2000-01 included widespread and permanent conservation efforts by our customers.
Several large industrial facilities closed permanently during the 2001-02 economic
recession. In 2004, rising retail electricity rates further reinforced conservation efforts.
Recently, the economy has experienced a significant recession from which it is slowly
emerging. The recession reduced loads below what they otherwise would be.
Retail electricity consumption rose from 8.2 million MWh in 2000 to 8.9 million MWh in
2010. This 0.75 percent annual average increase was net of the combined impacts of
higher prices and resultant decreases in electricity demand from the Energy Crisis and
economic recessions. Loads recover due to stabilizing electricity prices and recovery
from the present recession. Forecasted average annual increase in retail sales over the
2010 to 2035 period is 1.6 percent.
The sales forecast takes a ―bottom up‖ approach, summing individual customer class
forecasts of customers and usage per customer to produce a retail sales forecast.
Individual forecasts for our largest industrial customers (Schedule 25) include planned
or announced production increases or decreases. Lumber and wood products industries
have slowed down from very high production levels, consistent with the decline in
housing starts at the national level caused by the present economic recession. Lumber
and wood products sector load forecasts account for decreased production levels.
70,000
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-11
Anticipated sales to aerospace and aeronautical equipment suppliers have increased,
and local plants have announced plans to hire more workers and increase their output.
The forecast for 2035 is 13.11 billion kWh, representing a 1.6 percent compounded
increase in retail sales. See Figure 2.10 for Avista’s retail sales forecast.
Figure 2.10: Avista’s Retail Sales Forecast
Load Forecast
Retail sales provide the data used to project load. Retail sales translate into average
megawatt hours using a regression model ensuring monthly load shapes conform to
history. The load forecast is a retail sales forecast combined with line losses across
incurred in the delivery of electricity across the Avista transmission and distribution
system.
Figure 2.11 presents annual net native load growth. Note the significant drop in the
2000-2001 Western Energy Crisis, and smaller declines in the 2009-10 recession
period. Loads from 1997 to 2010 are not weather normalized. Annual growth is
expected to be 1.7 percent compounded over the next twenty and twenty-five years, the
same growth rate as the 2009 IRP but from a lower base of 2010 instead of 2008.
0
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Street Lights Industrial
Commercial Residential
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-12
Figure 2.11: Annual Net Native Load
Peak Demand Forecast
The peak demand forecast represent expected peaks for each year of the IRP
timeframe, not extreme weather peak demands.3 The demand forecast is the product of
an 11-year regression of actual peak demand and native load. Winter and summer peak
demand forecasts are in Figure 2.12.4 Peak loads grow at 1.2 percent compounded
between 2010 and 2020 (219 MW), 1.5 percent over the 20-year IRP period (571 MW),
and 1.55 percent over the 25-year forecast (796 MW).
3 The expected peak demand has a 50 percent chance of exceedance in any year. Historical years
present actual peak demands by year. 4 Ibid.
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-13
Figure 2.12: Winter and Summer Peak Demand
Extreme weather events influence historical peak load data. The comparatively low
1999 peak demand figure was the result of a warmer-than-average winter peak day; the
peak in 2006 was the result of a below-average winter peak day. The 1999 and 2006
peak demand values illustrate why relying on compound growth rates and forecasted
expected peak demand is an oversimplification, and why the Company plans to own or
control enough generation assets and contracts to meet peak demand during extreme
weather events.
Avista has witnessed significant summer load growth in recent years primarily due to
rising air conditioning penetration in its service territory. However, Avista expects to
remain a winter-peaking utility in the near future. It is possible, and we have seen it
occur as recently as 2001, where very mild winter temperatures combined with
extremely hot summer temperatures in a given calendar year results in our summer
peak load exceeding our winter demand level.
The Company produced high and low load forecasts to test the IRPs Preferred
Resource Strategy. These forecasts are very difficult to create because many factors
influence the outcome, and because Avista is unable to obtain alternative economic
forecasts at the county level from Global Insight. In past IRPs Avista used ranges from
the Northwest Power and Conservation Council’s Sixth Power Plan as a guide. This IRP
relies on consultation with internal and external advisors and uses a growth multiplier on
the Expected Case forecast of 1.5 for the high case and 0.5 for the low case.
1,000
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-14
The Expected Case load growth is 1.6 percent. The high growth case scenario is 2.33
percent and the low growth case scenario is 0.93 percent as shown in Figure 2.13. The
Company believes these high and low growth ranges are consistent with the Sixth
Power Plan’s medium high and medium low ranges.
Figure 2.13: Electricity Load Forecast Scenario
Avista Resources and Contracts
Avista relies on a diverse portfolio of generating assets to meet customer loads,
including owning and operating eight hydroelectricity projects located on the Spokane
and Clark Fork Rivers. Its thermal assets include partial ownership of two coal-fired
units in Montana, five natural gas-fired projects, and a biomass plant located near Kettle
Falls, Washington.
Spokane River Hydroelectric Projects
Avista owns and operates six hydroelectric projects on the Spokane River. These
projects received a new 50-year FERC operating license in June 2009. The following
section describes the Spokane River projects and provides the maximum on-peak
capacity and nameplate capacity ratings for each plant. The maximum on-peak capacity
of a generating unit is the total amount of electricity a plant can safely generate. This is
often higher than the nameplate rating for hydroelectric projects. The nameplate, or
installed capacity, is the capacity of a plant as rated by the manufacturer. All six of the
hydroelectric projects on the Spokane River connect to Avista’s transmission system.
1,000
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Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-15
Post Falls
Post Falls is the upper most hydroelectricity facility on the Spokane River. It is located
near the Washington/Idaho border. The project began operating in 1906, and during
summer months maintains the elevation of Lake Coeur d’Alene. The project has six
units, with the last unit added in 1980. The project is capable of producing 18.0 MW and
has a 14.75 MW nameplate rating.
Upper Falls
The Upper Falls project began generating in 1922 in downtown Spokane, and now is
within the boundaries of Riverfront Park. This project is comprised of a single 10.0 MW
unit with a 10.26 MW maximum capacity rating.
Monroe Street
The Monroe Street facility was Avista’s first generation facility. It began serving
customers in 1890 near what is now Riverfront Park. Rebuilt in 1992, the single
generating unit has a 15.0 MW maximum capacity rating and a 14.8 MW nameplate
rating.
Nine Mile
A private developer built the Nine Mile project in 1908 near Nine Mile Falls, Washington,
nine miles northwest of Spokane. The Company purchased the project in 1925 from the
Spokane & Eastern Railway. Its four units have a 17.6 MW maximum capacity and a
26.4 MW nameplate rating.5 The facility received a rubber dam in 2010, replacing the
original flashboard system that maintained higher summer elevations.
The Nine Mile facility presently has major equipment outages. Unit 1 is out of service
and Unit 2 is limited to half load. Unit 4 failed in the spring of 2011. Avista is evaluating
options to restore the plant to full service. Restoration options include refurbishment of
the existing powerhouse, including new turbine runners, or a new powerhouse located
downstream from the existing powerhouse. A decision on the final configuration of Nine
Mile is not yet determined. The Company expects any new generation at the plant will
meet Washington State Energy Independence Act requirements.
Long Lake
The Long Lake project is located northwest of Spokane and maintains the Lake
Spokane reservoir, also known as Long Lake. The facility was the highest spillway dam
with the largest turbines in the world when completed in 1915. The plant received new
runners in the 1990s, adding 2.2 aMW of additional energy. The project’s four units
provide 88.0 MW of combined capacity and have an 81.6 MW nameplate rating.
Little Falls
The Little Falls project, completed in 1910 near Ford, Washington, is the furthest
downstream hydro facility on the Spokane River. A new runner upgrade in 2001
generates 0.6 aMW of renewable energy than the previous runner. The facility’s four
units generate 35.2 MW of on-peak capacity and have a 32.0 MW nameplate rating.
5 This is the de-rated capacity considering the outage of unit 1 and de-rate of unit 2
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-16
Clark Fork River Hydroelectric Project
The Clark Fork River Project 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 of the hydroelectric projects on the Clark
Fork River connect to Avista’s transmission system.
Cabinet Gorge
The Cabinet Gorge project started generating power in 1952 with two units. The plant
added two additional generators in the following year. The current maximum on-peak
capacity of the plant is 270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at
this project began with the replacement of the turbine for Unit 1 in 1994. Unit 3 received
an upgrade in 2001. Unit 2 received an upgrade in 2004. Unit 4 received a turbine
runner upgrade in 2007, increasing its generating capacity from 55 MW to 64 MW, and
adding 2.1 aMW of additional energy.
Noxon Rapids
The Noxon Rapids project includes four generators installed between 1959 and 1960,
and a fifth unit added in 1977. The project is in the middle of a major turbine upgrade,
with one unit receiving a new runner in each calendar year beginning in 2009. The
upgrades add 6.6 aMW of total energy and qualify under Washington State’s Energy
Independence Act renewable energy goals.
Total Hydroelectric Generation
In total, Avista’s hydroelectric plants have 1,065.4 MW of on-peak capacity. Table 2.2
summarizes the location and operational capacities of the Company’s hydroelectric
projects. This table includes the average annual energy output of each facility based on
the 70-year hydrologic record for the year ending 2012.
Table 2.2: Company-Owned Hydro Resources
Monroe Street Spokane Spokane, WA 14.8 15.0 11.6
Post Falls Spokane Post Falls, ID 14.8 18.0 10.0
Nine Mile Spokane Nine Mile Falls, WA 26.0 17.5 12.5
Little Falls Spokane Ford, WA 32.0 35.2 22.1
Long Lake Spokane Ford, WA 81.6 89.0 53.4
Upper Falls Spokane Spokane, WA 10.0 10.2 7.5
Cabinet Gorge Clark Fork Clark Fork, ID 265.2 270.5 124.8
Noxon Rapids Clark Fork Noxon, MT 518.0 610.0 198.3
Thermal Resources
Avista owns seven thermal assets located across the Northwest. Each thermal plant
operates through the 20-year duration of the 2011 IRP. The resources provide
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-17
dependable energy and capacity to serve base loads and provide peak load serving
capabilities. A summary of Avista thermal resources is in Table 2.3.
Colstrip
The Colstrip plant, located in Eastern Montana, consists of four multi-owner coal-fired
steam plants connected to the double circuit 500 kV BPA transmission line under a
long-term wheeling agreement. PPL Global operates the facilities on behalf of the
owners. Avista owns 15 percent of Units 3 and 4. Unit 3 began operating in 1984 and
Unit 4 was finished in 1986. The Company’s share of each Colstrip unit has a maximum
net capacity of 111.0 MW and a nameplate rating of 123.5 MW. In 2006 and 2007
completed capital projects improved efficiency, reliability, and generation capacity at the
plants. The upgrades include new high-pressure steam turbine rotors and digital (versus
the old analog) control systems.
Rathdrum
Rathdrum is a two-unit simple-cycle combustion turbine. This natural gas-fired plant is
located near Rathdrum, Idaho and connects to Avista’s transmission system. It entered
service in 1995 and has a maximum capacity of 178.0 MW in the winter and 126.0 MW
in the summer. The nameplate rating is 166.5 MW.
Northeast
The Northeast plant, located in northeast Spokane, is a two-unit aero-derivative simple-
cycle plant completed in 1978 and connects to Avista’s transmission system. The plant
is capable of burning natural gas or fuel oil, but current air permits prevent the use of
fuel oil. The combined maximum capacity of the units is 68.0 MW in the winter and 42.0
MW in the summer, with a nameplate rating of 61.2 MW. The plant is currently limited to
run no more than approximately 546 hours per year and provides reserve capacity to
protect against reliability concerns and extreme market aberrations.
Boulder Park
The Boulder Park project entered service in Spokane Valley in 2002 and connects to
Avista’s transmission system. The site uses six natural gas-fired internal combustion
reciprocating engines to produce a combined maximum capacity and nameplate rating
of 24.6 MW.
Coyote Springs 2
Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine located near
Boardman, Oregon. This plant connects to BPA’s 500 kV transmission system under a
long-term transmission wheeling agreement. The plant began service in 2003. The
maximum capacity is 274 MW in the winter and 221 MW in the summer and the duct
burner provides the unit with an additional capacity of up to 28 MW. The plant’s
nameplate rating is 287.3 MW.
Kettle Falls and Kettle Falls Combustion Turbine
The Kettle Falls biomass facility entered service in 1983 near Kettle Falls, Washington
and is among the largest biomass plants in North America. The plant connects to
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-18
Avista’s 115 kV transmission system. The open-loop biomass steam plant uses waste
wood products from area mills and forest slash, but can also burn natural gas. A
combustion turbine (CT), added to the facility in 2002, burns natural gas and increases
overall plant efficiency by sending exhaust heat to the wood boiler.
The wood-fired portion of the plant has a maximum capacity of 50.0 MW and its
nameplate rating is 50.7 MW. The plant typically operates between 45 and 47 MW
because of fuel quality issues. The plant’s capacity increases to 57.0 MW when
operated in combined-cycle mode with the CT. The CT produces 8 MW of peaking
capability in the summer and 11 MW in the winter. The CT resource is limited in winter
when the gas pipeline is constrained; for IRP modeling, the plant does not run when
temperatures fall below zero and pipeline capacity serves local natural gas distribution.
Table 2.3: Company-Owned Thermal Resources
Colstrip 3 (15%) Colstrip, MT Coal 1984 111.0 111.0 123.5
Colstrip 4 (15%) Colstrip, MT Coal 1986 111.0 111.0 123.5
Rathdrum Rathdrum, ID Gas 1995 178.0 126.0 166.5
Northeast Spokane, WA Gas 1978 68.0 42.0 61.2
Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6
Coyote Springs 2 Boardman, OR Gas 2003 302.0 249.0 287.3
Kettle Falls Kettle Falls, WA Wood/Gas 1983 47.0 47.0 46.0
Kettle Falls CT6 Kettle Falls, WA Gas 2002 11.0 8.0 7.5
Power Purchase and Sale Contracts
The Company utilizes power supply purchase and sale arrangements of varying lengths
to meet some load requirements. This chapter describes the contracts in effect during
the scope of the 2011 IRP. Contracts provide many benefits including environmentally
low-impact and low-cost hydro and wind power. A 2012 annual summary of Avista large
contracts is in Table 2.5.
Mid-Columbia Hydroelectric Contracts
During the 1950s and 1960s, public utility districts (PUDs) in central Washington
developed hydroelectric projects on the Columbia River. Each plant was oversized
compared to the loads then served by the PUDs. Long-term contracts with public,
municipal, and investor-owned utilities throughout the Northwest assisted with project
financing, and ensured a market for generated surplus power. The contract terms
obligate the PUDs to deliver power to Avista’s points of interconnection with each utility.
6 Includes output of the gas turbine plus the benefit of its steam to the main unit’s boiler.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-19
Avista entered into long-term contracts for the output of four of these projects ―at cost.‖
Later, the Company competed in capacity auctions in 2009 through 2011 to purchase
new short-term contracts at market-based prices. The Mid-Columbia contracts provide
energy, capacity, and reserve capabilities; in 2012, contracts provide approximately 165
MW of capacity and 86 aMW of energy, see Table 2.4 for further details. Over the next
20 years the Douglas PUD (2018) and Chelan PUD (2015) contracts will expire. Avista
may extend these contracts or even gain additional capacity in auctions; however, we
have no assurance that we will be successful in extending our contract rights. Due to
this uncertainty, the IRP does not include these contracts in the resource mix beyond
their expiration dates.
Table 2.4: Mid-Columbia Capacity and Energy Contracts
Counter Party Project(s)
Percent
Share
(%)
Start
Date
End
Date
Estimated
Capacity
(MW)
Annual
Energy
(aMW)
Grant PUD Priest Rapids 3.7 12/2001 12/2052 34 16
Grant PUD Wanapum 3.7 12/2001 12/2052 37 18
Chelan PUD Rocky Reach 4.5 11/2011 06/2012 57 32
Chelan PUD Rocky Reach 3.0 07/2011 12/2014 38 21
Chelan PUD Rock Island 3.0 07/2011 12/2015 19 11
Douglas PUD Wells 3.3 02/1965 08/2018 29 15
2012 Total Contracted Capacity and Energy 165 86
Lancaster Power Purchase Agreement
Avista acquired the output rights to the Lancaster combined-cycle generating station,
located in Rathdrum, Idaho, as part of the sale of Avista Energy to Shell in 2007.
Lancaster (sometimes referred to in the industry as the Rathdrum Generating Station).
The plant connects to the BPA transmission system under a long-term wheeling
agreement. Avista is working with BPA to interconnect the plant with Avista’s
transmission system at the BPA Lancaster substation. Avista has the sole right to
dispatch the plant, and is responsible for providing fuel and energy and capacity
payments, under a tolling PPA with Energy Investors Funds expiring in October 2026.
Bonneville Power Administration – WNP-3 Settlement
Avista (then Washington Water Power) signed settlement agreements with BPA and
Energy Northwest (formerly the Washington Public Power Supply System or WPPSS)
on September 17, 1985, ending construction delay claims against both parties. The
settlement provides an energy exchange through June 30, 2019, with an agreement to
reimburse 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 the Company from BPA through
2019, subject to a contract minimum of 5.8 million megawatt-hours. Avista is obligated
to pay BPA operating and maintenance costs associated with the energy exchange as
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-20
determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987-year
constant dollars.
The second provision provides BPA approximately 32 aMW of return energy at a cost
equal to the actual operating cost of the Company’s highest-cost resource. A further
discussion of this obligation, and how Avista plans to account for it, is under the
Planning Margin heading of this chapter.
Table 2.5: Large Contractual Rights and Obligations
Canadian Entitlement Sale n/a 8 8 5
Clearwater PURPA 06/2013 75 75 52
Douglas Settlement Purchase 09/2018 2 3 3
Lancaster Purchase 10/2026 290 249 222
Nichols Pumping Sale n/a 7 7 7
PGE Capacity Exchange Exchange 12/2016 150 150 0
Small Power PURPA varies 2 1 2
Stateline Purchase 03/2014 0 0 9
Stimson Lumber Purchase 09/2011 4 5 4
Upriver (net load) Purchase 12/2011 8 -1 6
WNP-3 Purchase 06/2019 82 0 42
Reserve Margins
Planning reserves accommodate situations when loads exceed and/or resource outputs
are below expectations due to adverse weather, forced outages, poor water conditions,
or other contingencies. There are disagreements within the industry on reserve margin
levels utilities should carry. Many disagreements stem from system differences, such as
resource mix, system size, and transmission interconnections
Reserve margins, on average, increase customer rates when compared to resource
portfolios without reserves, because of the cost of carrying additional generating
capacity that is rarely used. Reserve resources have the physical capability to generate
electricity, but high operating costs limit their economic dispatch and revenues to offset
purchase costs.
Avista Planning Margin
Avista retains two planning margin targets—capacity and energy. Capacity planning is a
traditional metric ensuring that utilities can meet peak loads at times of system strain,
and cover variability inherent in their generation resources with unpredictable fuel
supplies, such as wind and hydro, and varying loads.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-21
Capacity Planning
Avista plans for peak load events using the regional standard of an 18-hour peak event
covering six hours each day for three consecutive days. Further, the IRP uses a
planning margin level approximating the Northwest Power and Conservation Council’s
targets of 23 percent in the winter and 24 percent in the summer. Avista first estimates
operating reserve requirements for on-system generation, load regulation, and wind
integration. It then adds a planning margin of 15 percent to summer peak load and 14
percent to winter peak load. Adjustments to the net position include market purchases
when surplus capacity exists in the Northwest, as represented by the green bars.7 The
planning margin equals 233 MW in 2012. Additional detail is in Appendix A. Figure 2.14
illustrates the winter peak position and Figure 2.15 shows the summer peak position.
Figure 2.14: Winter 18-Hour Capacity Load and Resources
7 Avista relied on work by the Northwest Power and Conservation Council in its Resource Adequacy
Forum exercises to determine the level of surplus summer energy and capacity. Reliance is limited to
Avista’s prorated share of regional load. See
http://www.nwcouncil.org/energy/resource/Adequacy%20Assessment%2070908.xls. NPCC surplus
estimates phase out over 10 years starting in 2013 by reducing its surplus by 10 percent, the 2014
surplus by 20 percent, the 2015 surplus by 30 percent, and so on. The phase out reflects Avista’s opinion
that outer-year surpluses might not be available for various reasons, including unanticipated load growth,
the retirement of existing resources, or transmission interconnections enabling the export of more
generation outside of the Northwest.
-200
300
800
1,300
1,800
2,300
2,800
3,300
3,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Firm Contracts Avista Share of Excess NW Capacity
Peaking Thermals Baseload Thermals
Hydro Load Forecast
Load + Reserves + Planning Margin
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-22
Figure 2.15: Summer 18-Hour Capacity Load and Resources
Energy Planning
For energy planning, resources must be adequate to meet customer requirements even
where loads are high for extended periods or an outage limits the output of a resource.
Extreme weather conditions can change monthly energy obligations by up to 30
percent. Where generation capability is not adequate to meet these variations,
customers and the utility must rely on the volatile short-term electricity market. In
addition to load variability, a planning margin accounts for variations in hydroelectricity
generation.
As with capacity planning, there are differences in regional opinion on a proper method
for establishing resource planning margins. Many utilities in the Northwest base their
planning on the amount of energy available during the critical water period of 1936/37.8
The critical water year of 1936/37 is low on an annual basis, but it is not necessarily low
in every month. The IRP could target resource development to reach a 99 percent
confidence level on being able to deliver energy to its customers, and it would
significantly decrease the frequency of its market purchases. However, this strategy
requires investments in approximately 200 MW of generation in additional to the
margins included in Expected Case of the IRP. Such expenditure to support this high
level of reliability would put upward pressure on retail rates for a modest benefit. Avista
instead targets a 90 percent monthly energy planning margin confidence interval based
on load hydroelectricity variability. In other words, there is a 10 percent chance of
needing to purchase energy from the market in any given month over the IRP
8 The critical water year represents the lowest historical generation level in the streamflow record.
-200
300
800
1,300
1,800
2,300
2,800
3,300
3,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Firm Contracts Avista Share of Excess NW Capacity
Peaking Thermals Baseload Thermals
Hydro Load Forecast
Load + Reserves + Planning Margin
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-23
timeframe, but on average, the utility would have the ability to meet all of its energy
requirements and be selling electricity into the marketplace.
Beyond load and hydroelectricity variability, Avista’s WNP-3 contract with BPA contains
supply risk. The contract includes a return energy provision in favor of BPA that can
equal 32 aMW annually. Under adverse market conditions BPA almost certainly would
exercise its rights. BPA last exercised its contract rights in 2001. To account for this
contract risk, the energy planning margin is increased by 32 aMW until the contract
expires in 2019. With the addition of WNP-3, load and hydroelectricity variability, the
total energy planning margin equals 228 aMW in 2012. Additional detail is contained in
Appendix A. See Figure 2.16 for the summary of the annual average energy load and
resource net position.
Figure 2.16: Annual Average Energy Load and Resources
Loss of Load Analysis
In the Northwest, loss-of-load analysis tools help address the issue of how much
planning margin is required. Typical results of these models are Loss of Load
Probability (LOLP), Loss of Load Hours (LOLH), and Loss of Load Expectation (LOLE)
measures. A reliable system has typically been defined as having no more than one
interruption event in twenty years, or 5 percent. These analyses can be helpful, but
usually have an inherent flaw due to the need to assume how much out-of-area
generation is available for the study. Avista developed a loss of load analysis model to
simulate reliability events due to poor hydro, forced outages, and extreme weather
conditions on its system, finding that forced outages are the main driver of reliability
events. Avista has robust transmission rights to the wholesale energy markets, but the
-200
300
800
1,300
1,800
2,300
2,800
3,300
3,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e
m
e
g
a
w
a
t
t
s
Net Market Transactions Peaking Thermals
Baseload Thermals Hydro
Load Forecast Load + Contingency
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-24
amount of generation actually available for purchase from third parties is difficult to
estimate in a model. To address this concern, a sophisticated regional model must
estimate required regional planning margins. Avista will continue to monitor and
contribute to such regional model development, with the intent of using the regional
model when it becomes available.
Washington State Renewable Portfolio Standard
In the November 2006 general election, Washington State voters approved Citizens
Initiative 937, now known as the Washington state Energy Independence Act. The
initiative requires utilities with more than 25,000 customers to source 3 percent of their
energy from qualified non-hydroelectric renewables by 2012, 9 percent by 2016, and 15
percent by 2020. Utilities also must acquire all cost effective conservation and energy
efficiency measures. Even though Avista does not require any new generation
resources to meet forecasted energy loads through 2019, this new law requires the
Company to acquire additional qualified renewable generation, or renewable energy
certificates (RECs), to meet the initiative’s renewable goals. Table 2.6 at the end of this
chapter details the forecast amount of RECs required to meet Washington state law,
and the amount of qualifying resources has already in the generation portfolio. The
sales forecast uses the current load forecast and does not include additional
conservation as detailed in the Preferred Resource Strategy chapter. It also illustrates
how the Company will maintain a REC reserve margin of approximately 10 aMW in
2016.
Resource Requirements
The resource requirements discussed in this section do not include additional energy
efficiency acquisitions beyond what is in the load forecast. The Preferred Resource
Strategy chapter discusses conservation beyond the assumptions contained in the load
forecast. The following tables present loads and resources to illustrate future resource
requirements.
During winter peak periods (Table 2.7), surplus capacity exists through 2019 after taking
into account market purchases.9 Without these purchases, a capacity deficit would exist
in 2012. Avista believes that the present market can meet these minor winter capacity
shortfalls and therefore will optimize its portfolio to postpone new resource investments
for winter capacity until 2020.
The summer peak projection (Table 2.8) has lower loads than in winter, but resource
capabilities are also lower due to lower hydroelectricity output and reduced capacity at
natural gas-fired resources due to decreased performance during high-temperature
events. The IRP shows persistent summer deficits throughout the 20-year timeframe,
but regional surpluses are adequate to fill in these gaps. Many near-term deficits are
from decreased hydroelectricity capacity during periods of planned maintenance and
9 Avista relied on work by the Northwest Power and Conservation Council in its Resource Adequacy
Forum exercises to determine the level of surplus summer energy and capacity. Reliance is limited to the
Company’s prorate share of regional load.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-25
upgrades. Taking into account regional surpluses, the load and resource balance is 54
MW short only in 2016. After 2016, when the Portland General Electricity capacity sale
contract expires, the next capacity need is in 2019 at 98 MW.
The traditional measure of resource need in the region is the annual average energy
position. The energy position is in Table 2.9. There is enough energy on an annual
average basis to meet customer requirements until 2020, when the utility is short 49
aMW. Avista will require 112 aMW of new energy by 2025, and 475 aMW in 2031.
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-26
Table 2.6: Washington State RPS Detail (aMW)
On
-
l
i
n
e
Ye
a
r
Up
g
r
a
d
e
En
e
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20
1
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20
1
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20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
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2
7
20
2
8
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3
1
WA
S
t
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63
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63
6
64
6
65
4
66
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67
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67
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68
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69
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70
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70
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71
4
72
1
73
0
73
8
74
6
75
4
76
3
77
2
78
2
79
3
RP
S
%
0%
3%
3%
3%
3%
9%
9%
9%
9%
15
%
15
%
15
%
15
%
15
%
15
%
15
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15
%
15
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15
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15
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15
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RE
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D
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E
W
A
B
L
E
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E
R
G
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19
19
19
20
59
60
61
61
10
4
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5
10
6
10
7
10
8
10
9
11
0
11
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11
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11
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(8
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)
(8
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(8
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)
(8
6
)
(8
7
)
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9
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(9
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(9
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0
0
0
0
0
0
0
0
0
0
RE
C
'
s
R
e
q
u
i
r
e
d
0
(1
9
)
(1
9
)
(1
9
)
(2
0
)
(5
9
)
(6
0
)
(6
1
)
(6
1
)
(1
0
4
)
(1
0
5
)
(1
0
6
)
(1
0
7
)
(1
0
8
)
(1
0
9
)
(1
1
0
)
(1
1
1
)
(1
1
2
)
(1
1
4
)
(1
1
5
)
(1
1
7
)
RE
C
'
s
G
e
n
e
r
a
t
e
d
/
P
u
r
c
h
a
s
e
d
17
23
26
28
28
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
Ex
p
i
r
e
d
/
S
o
l
d
R
E
C
s
0
(2
)
(7
)
(8
)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NE
T
R
E
C
B
A
N
K
17
21
26
28
28
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
RE
C
R
e
s
e
r
v
e
R
e
q
u
i
r
e
m
e
n
t
(
9
5
t
h
P
E
R
C
E
N
T
I
L
E
)
Lo
a
d
0
1
1
1
1
3
3
3
3
5
5
5
5
5
5
5
5
5
5
6
6
Ex
i
s
t
i
n
g
H
y
d
r
o
U
p
g
r
a
d
e
s
0
6
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
To
t
a
l
R
E
C
R
e
s
e
r
v
e
R
e
q
u
i
r
e
m
e
n
t
0
7
8
8
8
10
10
10
10
12
12
12
12
12
12
13
13
13
13
13
13
NE
T
R
E
C
P
O
S
I
T
I
O
N
17
14
21
26
28
(2
0
)
(4
8
)
(4
9
)
(5
0
)
(9
4
)
(9
5
)
(9
6
)
(9
7
)
(9
8
)
(9
9
)
(1
0
1
)
(1
0
2
)
(1
0
3
)
(1
0
5
)
(1
0
6
)
(1
0
8
)
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-27
Table 2.7: Winter 18-Hour Capacity Position (MW)
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L
L
O
A
D
O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e
L
o
a
d
-1
,
6
6
1
-1
,
6
8
8
-1
,
7
0
4
-1
,
7
1
8
-1
,
7
5
1
-1
,
7
8
4
-1
,
8
1
4
-1
,
8
3
9
-1
,
8
6
6
-1
,
8
9
2
-1
,
9
1
9
-1
,
9
4
6
-1
,
9
8
2
-2
,
0
2
0
-2
,
0
6
2
-2
,
0
9
4
-2
,
1
3
1
-2
,
1
6
8
-2
,
2
0
8
-2
,
2
4
9
Fi
r
m
P
o
w
e
r
S
a
l
e
s
-2
4
2
-2
4
2
-2
1
1
-1
5
8
-1
5
8
-8
-8
-7
-7
-7
-7
-7
-6
-6
-6
-6
-6
-6
-6
-6
To
t
a
l
R
e
q
u
i
r
e
m
e
n
t
s
-1
,
9
0
3
-1
,
9
3
0
-1
,
9
1
5
-1
,
8
7
6
-1
,
9
0
9
-1
,
7
9
2
-1
,
8
2
2
-1
,
8
4
6
-1
,
8
7
3
-1
,
8
9
9
-1
,
9
2
5
-1
,
9
5
3
-1
,
9
8
8
-2
,
0
2
7
-2
,
0
6
8
-2
,
1
0
1
-2
,
1
3
7
-2
,
1
7
4
-2
,
2
1
4
-2
,
2
5
5
RE
S
O
U
R
C
E
S
Fi
r
m
P
o
w
e
r
P
u
r
c
h
a
s
e
s
17
5
17
5
17
5
17
5
17
5
17
5
17
4
17
3
90
90
90
90
90
90
90
90
90
90
90
90
Hy
d
r
o
R
e
s
o
u
r
c
e
s
88
0
95
5
96
5
85
4
85
4
86
5
86
1
88
9
88
1
88
9
88
9
88
1
88
9
88
9
88
1
88
9
88
9
88
1
88
9
88
9
Ba
s
e
L
o
a
d
T
h
e
r
m
a
l
s
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
60
6
60
6
60
6
60
6
60
6
Wi
n
d
R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g
U
n
i
t
s
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
To
t
a
l
R
e
s
o
u
r
c
e
s
2,
1
9
2
2,
2
6
7
2,2
7
7
2,1
6
6
2,1
6
6
2,
1
7
7
2,
1
7
2
2,
1
9
9
2,
1
0
8
2,
1
1
6
2,
1
1
6
2,
1
0
8
2,1
1
6
2,1
1
6
2,
1
0
8
1,
8
2
6
1,
8
2
6
1,
8
1
8
1,
8
2
6
1,
8
2
6
Pe
a
k
P
o
s
i
t
i
o
n
B
e
f
o
r
e
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
28
9
33
7
36
2
29
0
25
6
38
5
35
0
35
3
23
6
21
7
19
1
15
5
12
7
89
40
-2
7
5
-3
1
1
-3
5
6
-3
8
8
-4
2
9
RE
S
E
R
V
E
P
L
A
N
N
I
N
G
Re
q
u
i
r
e
d
O
p
e
r
a
t
i
n
g
R
e
s
e
r
v
e
s
-1
6
2
-1
6
4
-1
6
3
-1
6
2
-1
6
5
-1
5
9
-1
6
1
-1
6
3
-1
6
5
-1
6
7
-1
7
3
-1
7
6
-1
8
0
-1
8
2
-1
8
6
-1
7
0
-1
7
0
-1
7
1
-1
7
2
-1
7
3
Av
a
i
l
a
b
l
e
O
p
e
r
a
t
i
n
g
R
e
s
e
r
v
e
s
23
42
42
8
8
8
8
34
34
34
34
34
34
34
34
34
34
34
34
34
Pla
n
n
i
n
g
M
a
r
g
i
n
-2
3
3
-2
3
6
-2
3
9
-2
4
0
-2
4
5
-2
5
0
-2
5
4
-2
5
8
-2
6
1
-2
6
5
-2
6
9
-2
7
2
-2
7
7
-2
8
3
-2
8
9
-2
9
3
-2
9
8
-3
0
4
-3
0
9
-3
1
5
To
t
a
l
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
-3
7
2
-3
5
8
-3
6
0
-3
9
4
-4
0
2
-4
0
0
-4
0
7
-3
8
7
-3
9
2
-3
9
8
-4
0
8
-4
1
4
-4
2
3
-4
3
1
-4
4
1
-4
2
9
-4
3
4
-4
4
1
-4
4
7
-4
5
4
Pe
a
k
P
o
s
i
t
i
o
n
W
i
t
h
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
-8
3
-2
1
2
-1
0
5
-1
4
6
-1
5
-5
7
-3
4
-1
5
7
-1
8
1
-2
1
6
-2
5
9
-2
9
6
-3
4
2
-4
0
1
-7
0
4
-7
4
6
-7
9
6
-8
3
5
-8
8
3
Pl
a
n
n
i
n
g
M
a
r
g
i
n
B
e
f
o
r
e
N
W
M
a
r
k
e
t
16
%
20
%
21
%
16
%
14
%
22
%
20
%
21
%
14
%
13
%
12
%
10
%
8%
6%
4%
-1
1
%
-1
3
%
-1
5
%
-1
6
%
-1
8
%
Av
i
s
t
a
S
h
a
r
e
o
f
E
x
c
e
s
s
N
W
C
a
p
a
c
i
t
y
73
7
65
6
56
5
47
7
40
0
32
6
25
5
18
6
11
5
56
0
0
0
0
0
0
0
0
0
0
Pe
a
k
P
o
s
i
t
i
o
n
W
i
t
h
N
W
M
a
r
k
e
t
65
4
63
5
56
7
37
3
25
4
31
1
19
9
15
2
-4
2
-1
2
5
-2
1
6
-2
5
9
-2
9
6
-3
4
2
-4
0
1
-7
0
4
-7
4
6
-7
9
6
-8
3
5
-8
8
3
Pe
a
k
P
o
s
i
t
i
o
n
W
i
t
h
N
W
M
a
r
k
e
t
55
%
54
%
51
%
41
%
35
%
40
%
34
%
31
%
21
%
16
%
12
%
10
%
8%
6%
4%
-1
1
%
-1
3
%
-1
5
%
-1
6
%
-1
8
%
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-28
Table 2.8: Summer 18-Hour Capacity Position (MW)
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L
L
O
A
D
O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e
L
o
a
d
-1
,
5
1
4
-1
,
5
5
6
-1
,
5
9
7
-1
,
6
4
4
-1
,
6
7
3
-1
,
7
0
1
-1
,
7
2
7
-1
,
7
4
8
-1
,
7
7
1
-1
,
7
9
3
-1
,
8
1
5
-1
,
8
3
8
-1
,
8
6
8
-1
,
9
0
0
-1
,
9
3
7
-1
,
9
6
4
-1
,
9
9
5
-2
,
0
2
6
-2
,
0
5
9
-2
,
0
9
4
Fir
m
P
o
w
e
r
S
a
l
e
s
-2
4
3
-2
1
8
-2
1
2
-1
5
9
-1
5
9
-9
-9
-8
-8
-8
-8
-8
-8
-7
-7
-7
-7
-7
-7
-7
To
t
a
l
R
e
q
u
i
r
e
m
e
n
t
s
-1
,
7
5
7
-1
,
7
7
4
-1
,
8
0
9
-1
,
8
0
4
-1
,
8
3
2
-1
,
7
1
0
-1
,
7
3
6
-1
,
7
5
6
-1
,
7
7
8
-1
,
8
0
0
-1
,
8
2
2
-1
,
8
4
6
-1
,
8
7
6
-1
,
9
0
8
-1
,
9
4
4
-1
,
9
7
1
-2
,
0
0
2
-2
,
0
3
3
-2
,
0
6
7
-2
,
1
0
2
RE
S
O
U
R
C
E
S
Fir
m
P
o
w
e
r
P
u
r
c
h
a
s
e
s
85
85
85
85
85
85
85
83
83
82
82
82
82
82
82
82
82
82
82
82
Hy
d
r
o
R
e
s
o
u
r
c
e
s
90
0
81
9
90
2
85
9
86
6
86
4
88
5
83
3
84
0
85
9
83
3
84
0
85
9
83
3
84
0
85
9
83
3
84
0
85
9
83
3
Ba
s
e
L
o
a
d
T
h
e
r
m
a
l
s
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
55
1
55
1
55
1
55
1
55
1
Wi
n
d
R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g
U
n
i
t
s
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
To
t
a
l
R
e
s
o
u
r
c
e
s
1,9
6
0
1,
8
8
0
1,
9
6
2
1,
9
1
9
1,
9
2
6
1,
9
2
4
1,
9
4
5
1,
8
9
1
1,8
9
7
1,
9
1
6
1,
8
9
1
1,8
9
6
1,
9
1
6
1,
8
9
0
1,
8
9
6
1,
6
6
8
1,
6
4
2
1,
6
4
8
1,
6
6
8
1,6
4
2
Pe
a
k
P
o
s
i
t
i
o
n
B
e
f
o
r
e
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
20
3
10
6
15
2
11
6
94
21
4
20
9
13
5
11
9
11
6
68
51
41
-1
8
-4
8
-3
0
4
-3
6
1
-3
8
5
-3
9
9
-4
6
0
RE
S
E
R
V
E
P
L
A
N
N
I
N
G
Re
q
u
i
r
e
d
O
p
e
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1
%
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%
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4
%
Chapter 2: Loads & Resources
Avista Corp 2011 Electric IRP 2-29
Table 2.9: Average Annual Energy Position (aMW)
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
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9
20
2
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20
2
1
20
2
2
20
2
3
20
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4
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20
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52
2
52
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49
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49
5
49
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49
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48
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48
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48
1
48
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48
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19
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18
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91
81
2
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4
6
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9
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1
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8
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2
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15
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8
15
3
15
4
15
3
14
7
14
6
14
5
14
7
14
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14
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6
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9
8
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9
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11
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28
%
24
%
27
%
26
%
25
%
24
%
20
%
18
%
12
%
10
%
12
%
7%
6%
7%
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%
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5
%
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4
%
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7
%
-1
9
%
-1
8
%
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
3. Energy Efficiency
Introduction
Avista began offering energy efficiency programs in 1978. Some of the most notable
efficiency achievements include the Energy Exchanger program. It converted
approximately 20,000 homes from electricity to natural gas space and/or water heating
from 1992 to 1994. Avista pioneered the country’s first system benefit charge for energy
efficiency in 1995. Our conservation response during the 2001 Western Energy Crisis
exceeded all expectations. Conservation programs regularly meet or exceed regional
shares of energy efficiency gains as outlined by the Northwest Power Planning and
Conservation Council (NPCC).
Figure 3.1 illustrates Avista’s historical electricity conservation acquisitions. The
Company has acquired 156.3 aMW of energy efficiency since 1978; however, the
assumed 18-year average life of the conservation portfolio means that some of the
measures have reached the end of their useful lives and are no longer reducing loads.
The 18-year assumed measure life accounts for the difference between the Cumulative
and Online lines in Figure 3.1.
Section Highlights
Avista began offering conservation programs in 1978.
This IRP includes a Conservation Potential Assessment of the Company’s
Idaho and Washington service territories.
Conservation reduces load growth by 48 percent through the IRP timeframe.
Company-sponsored conservation reduces retail loads by approximately 10
percent, or 120 aMW.
Avista evaluated over 2,800 equipment options and over 1,500 measure
options covering all major end-use equipment, as well as devices and actions
to reduce energy consumption for this IRP.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Figure 3.1: Historical and Forecast Conservation Acquisition
Energy efficiency programs provide a range of conservation and education programs to
residential, low-income, commercial, and industrial customer segments. The programs
are either prescriptive or site-specific. Prescriptive programs, or standard offers, provide
cash incentives for standardized products such as the installation of high-efficiency
appliances. Prescriptive programs are suitable in situations where uniform products or
offerings are applicable for large groups of homogeneous customers. Standardized
programs are primarily for residential and small commercial customers. Site-specific
programs, or customized services, provide cash incentives for any cost-effective energy
savings measure or equipment with an economic payback greater than one year and
less than eight years for lighting projects or between one and 13 years for all other end-
uses and technologies.
Efficiency programs with paybacks of less than one year are not eligible for incentives,
though Avista will assist a customer in program design and implementation. Site-
specific programs require customized services for commercial and industrial customers
because of the unique characteristics of customers’ premises and processes. In some
cases, when it can be established that similar applications of energy efficiency
measures results in somewhat consistent savings estimates and the technically
achievable savings potential is high, a prescriptive approach is offered. An example is
prescriptive lighting for commercial and industrial applications. While this application is
not purely prescriptive in the traditional sense, such as with a residential program, a
more prescriptive approach for these types of similar energy efficiency installations
provides for an ease of marketability to customers and vendors.
0
60
120
180
240
300
360
420
480
540
600
0
2
4
6
8
10
12
14
16
18
20
19
7
8
19
8
0
19
8
2
19
8
4
19
8
6
19
8
8
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
cu
m
u
l
a
t
i
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s
a
v
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g
s
(
a
M
W
)
an
n
u
a
l
s
a
v
i
n
g
s
(
a
M
W
)
Cumulative
Online
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
To be consistent with I-937 conservation targets (WAC 480-109 and RCW 19.285) and
the NPCC Sixth Power Plan, Avista supplements its energy efficiency activities by
including potentials for transmissions and distribution efficiency measures. More details
about the transmission and distribution efficiency projects are in the Transmission &
Distribution chapter of this IRP.
Conservation Potential Assessment Approach
After publication of the 2009 Electric IRP, the Washington Utilities and Transportation
Commissions (UTC) requested an external Conservation Potential Assessment (CPA)
study for the 2011 IRP. Avista in 2010 retained Global Energy Partners (Global) to
conduct this study for its Idaho and Washington electric service territories. The CPA
identifies a 20-year potentials study for energy efficiency and demand response and
provides data on resources specific to Avista’s service territory for use in the 2011 IRP
and in accordance with the energy efficiency goals in Washington’s Energy
Independence Act (I-937). The energy efficiency potentials consider such things as the
impacts of existing programs, naturally occurring energy savings, the impacts of known
building codes and standards as of 2010, technology developments and innovations,
changes to the economy and energy prices.
Global took the following steps to assess and analyze energy efficiency and demand
response potentials in the Company’s service territory. Figure 3.2 illustrates the steps.
1. Perform a market assessment of base year consumption for the residential
(including low income), commercial, and industrial sectors. The assessment uses
utility and secondary data to characterize customers’ electric usage behavior in
Avista’s service territory. Global uses this market assessment to develop energy
market profiles that describe energy consumption by market segment, vintage
(existing versus new construction), end-use, and technology.
2. Develop a baseline energy forecast by sector and by end-use for the entire study
period.
3. Identify and analyze energy-efficiency measures appropriate for Avista’s service
territory, including regional savings from energy efficiency measures acquired
through the Northwest Energy Efficiency Alliance (NEEA) efforts.
4. Estimate technical, economic, and achievable energy efficiency potential.
Technical potential involves choosing the most efficient measure, regardless of
cost. Economic potential involves choosing the most efficient cost-effective
measure. Achievable potential adjusts economic potential to account for factors
other than pure economics, such as consumer behavior or market penetration
rates.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Figure 3.2: Analysis Approach Overview
The CPA uses 2009 calendar year data, the first complete year of billing data available
when the study began. Avista’s recent load study, which also uses a 2009 baseline
year, contributed to the selection of the 2009 baseline year for the CPA. This was
Avista’s first external CPA for its Idaho and Washington service territories.
The CPA segments Avista customers by state and by rate class. The rate classes used
in this study included residential, commercial and industrial, general service,
commercial and industrial large general service, extra large commercial, and extra large
industrial. The residential class was further segmented into single family, multi-family,
mobile home and low income customers. The low-income threshold used for this study
was defined as 200 percent of the federal poverty level. Global used the NPCC
calculator to determine future efficiency potentials for the pumping rate class, which
represents 2 percent of total utility loads. Pumping schedules are included in the
calculation of demand response potential, as discussed in the Demand Response
section of this chapter. Within each segment, energy use was characterized by end-use
(e.g., space heating, cooling, lighting, water heat, motors, etc.) and by technology (e.g.,
heat pump, resistance heating, or furnace for space heating).
The baseline forecast is the “business as usual” metric without new utility conservation
programs. Energy savings from new energy efficiency measures are compared against
this baseline. This baseline of annual electricity consumption and peak demand by
customer segment and end-use supports projections of energy usage absent future
efficiency programs. The baseline forecast includes projected impacts of known building
codes and energy efficiency standards as of 2010 when the study was conducted that
have direct bearings on the amount of utility program energy efficiency potential that
exists over and above the effects of these efforts, including projected market condition
changes. Market changes include customer and market growth, income growth, retail
Energy Efficiency
Potential
Energy Market
Profiles
by end use, fuel,
segment, and vintage
Avista data
Secondary data
(NWPCC, U.S. Census)
Forecast assumptions:
Customer growth
Price forecast
Purchase shares
Codes and standards
Energy efficiency measure list
Measure costs
Energy analysis to
estimate savings
Develop prototypes and
perform energy analysis
Baseline Forecast
by End Use
Base-year Energy
Consumption
by state, fuel, and
sector
Avista data
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
rates forecasts, trends in end-use and technology saturations, equipment purchase
decisions, consumer price elasticity, income and persons per household, as well as
customer potential estimates in the context of total energy use in the future so that
projections of available energy efficiency savings can be derived.
The baseline forecast used in the CPA, prior to the consideration of efficiency
potentials, projects overall electricity consumption growth of 48 percent. This
compounded average annual growth rate of 1.7 percent during this 20-year period is
consistent with Avista’s current and previous IRP forecasts.
For each customer sector, a robust list of electrical energy efficiency measures was
compiled, drawing upon the NPCC Sixth Power Plan, the Regional Technical Forum
(RTF), and other measures considered applicable to Avista. This list of energy efficiency
equipment and measures included 2,808 equipment options and 1,524 measure
options, representing a wide variety of end-use equipment, as well as devices and
actions able to reduce energy consumption. A comprehensive equipment list and
measure options are in Appendix C. Measure cost, savings, estimated useful life, and
other performance factors were characterized for the list of measures and economic
screening was performed on each measure for every year of the study to develop the
economic potential. Many measures do not pass the economic screen of avoided cost,
but some measures might become part of the energy efficiency program as contributing
factors evolve during the 20-year planning horizon.
Overview of Energy Efficiency Potentials
Global utilized an approach adhering to the conventions outlined in the National Action
Plan for Energy Efficiency (NAPEE) Guide for Conducting Potential Studies (November
2007).1 The NAPEE Guide represents the most credible and comprehensive national
industry practice for specifying energy efficiency potential. Specifically, three types of
potentials are in this study:
Technical Potential
Conservation potential uses the most efficient option commercially available to each
purchase decision, regardless of cost. This theoretical case provides the broadest
and highest definition of savings 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 does not
take into account the cost-effectiveness of the measures. Further, this study defines
technical potential as “phase-in technical potential,” assuming only that the portion of
the current equipment stock that has reached the end of its useful life and is due for
turnover is changed out by the most efficient measures available. Non-equipment
measures, such as controls and other devices (e.g., programmable thermostats)
phase-in over time, just like the equipment measures. Lighting retrofits, which are in
1 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for
2025: Developing a Framework for Change. www.epa.gov/eeactionplan.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
effect early replacements of existing lighting systems, count as a non-equipment
measure in this CPA study.
Economic Potential2
Economical conservation results from the purchase of the most cost-effective option
available for a given equipment or non-equipment measure. 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 Council.3 The inclusion of non-energy benefits did not
make any of the failing measures pass. Measures that passed the economic screen
represent aggregate economic potential. As with technical potential, economic
potential calculations use a phased-in approach. Economic potential is a hypothetical
upper-boundary of savings potential representing only economic measures; it does
not consider customer acceptance and other factors.
Achievable Potential
Achievable Potential refines economic potential by taking into account expected
program participation, customer preferences, and budget constraints. For purposes of
this particular CPA, Global provided two types of achievable potential – Maximum and
Realistic.
Maximum Achievable Potential is the upper boundary of the achievable potential range
or the maximum achievable savings that could be achieved through Avista’s energy
efficiency programs. Maximum Achievable Potential presumes incentives that are
sufficient to ensure customer adoption. Oftentimes, incentives take the form of rebates
that typically represent a substantial portion of the customer’s extra cost for the energy
efficient measure. These high incentives are combined with substantial administrative
and marketing costs that are used for customer awareness campaigns and educational
opportunities. It also considers a maximum participation rate by customers for the
various energy efficiency programs designed to deliver the various measures. Global
also developed a Market Acceptance Rate which is a factor based on the Council’s
ramp rate curves used in the Sixth Power Plan. These factors were applied to the
estimate of economic potential from the CPA study to estimate Maximum Achievable
Potential.
Realistic Achievable Potential represents the lower boundary of achievable potential or
a forecast of achievable savings resulting from customer behavior and penetration rates
of efficient technologies. It uses a set of Program Implementation Factors, which take
into account existing market, financial, political and regulatory barriers that are likely to
limit the amount of savings that may be achieved through energy efficiency programs.
2 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”. 3 There are other tests that can be used to represent the economic potential (e.g., Participant or Utility
Cost), but the TRC is generally accepted as the most appropriate representation of economic potential
because it tends to be most representative of the net benefits of energy efficiency to society as a whole.
The economic screen uses the TRC as a proxy for moving forward and representing achievable energy
efficiency savings potential for those measures that are most widely cost-effective.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
For example, it considers that other goals such as low rates and customer equity
influence the development of final program designs and savings targets. It also
considers customer incentive levels that are in line with typical industry practice, defined
marketing campaigns, and internal budget constraints. Political barriers often reflect
differences in regional attitudes toward energy efficiency and its value as a resource.
The Realistic Achievable Potential also reflects recent utility experience and reported
savings from past and present programs.
The CPA forecasts incremental annual Maximum Achievable Potential for all sectors at
9.8 aMW (85,824 MWh) in 2012, increasing to cumulative savings of 321.4 aMW
(2,815,551 MWh) by 2031. The CPA forecasts annual Realistic Achievable Potential for
all sectors at 5.7 aMW (or 49,804 MWh) in 2012, increasing to cumulative savings of
231.2 aMW (or 2,025,679 MWh) by 2031. Table 3-1 and Figure 3-3 show the CPA
results for baseline energy use, technical, economic, and realistic achievable potential.
The projected baseline electricity consumption forecast increases 43 percent during the
20-year planning horizon. Projected achievable energy savings, as a percentage of the
baseline energy forecast, grows from 0.6 percent in 2012 to 16.1 percent in 2031.
Figure 3.3 compares the technical, economic, achievable potentials, and cumulative
first-year savings, at selected years. It is important to note, that in the early years, the
difference between Maximum Achievable Potential and Realistic Achievable Potential is
minimal and converges at the end of the 20-year planning horizon. Realistic Achievable
Potential merely adjusts assumptions regarding the rate at which the savings are
estimated to be acquired during the planning period.
Table 3.1: Energy Forecasts and Cumulative Savings (Across All Sectors for Selected
Years)
Energy Forecasts
(MWh) 2012 2017 2022 2027 2031
Baseline Forecast 8,799,039 9,463,880 10,417,347 11,536,869 12,574,182
Achievable 8,749,236 9,068,483 9,476,769 9,998,002 10,548,503
Economic 8,569,382 8,037,426 8,018,993 8,594,412 9,282,289
Technical 8,487,766 7,441,765 6,981,872 7,281,206 7,842,616
Energy Savings
(MWh) 2012 2017 2022 2027 2031
Achievable 49,804 395,397 940,578 1,538,868 2,025,679
Economic 229,657 1,426,454 2,398,355 2,942,457 3,291,894
Technical 311,274 2,022,115 3,435,475 4,255,664 4,731,566
Energy Savings
(% of Baseline) 2012 2017 2022 2027 2031
Achievable 0.6% 4.2% 9.0% 13.3% 16.1%
Economic 2.6% 15.1% 23.0% 25.5% 26.2%
Technical 3.5% 21.4% 33.0% 36.9% 37.6%
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Figure 3.3: Cumulative Conservation Potentials, Selected Years
Conservation Targets
This IRP process includes conservation targets for Washington’s energy efficiency
portion of the Energy Independence Act (I-937) goal. Other components including
conservation from distribution and transmission efficiency improvements also meeting
this target would be additive to this conservation target for a complete target for
Washington comparable to what is included in the Sixth Power Plan target. Additionally,
since this IRP uses a methodology consistent with the NPCC methodology, the
conservation target for Idaho is more aggressive than required.
Based on first year and incremental savings, Table 3.2 illustrates Avista’s Realistic and
Maximum Achievable Potential for 2012-2013, as well as a comparison with the Sixth
Power Plan’s calculator option 1. This calculator is intended to provide an approximation
of the level of conservation that utilities should target in order to be consistent with the
Council’s regional goals. The CPA study completed for Avista incorporates this
methodology into an Avista-specific estimate of savings potential to be acquired through
its programs.
During the first five years, lighting and appliance standards slow residential baseline
growth rates, reducing the potential for savings from residential energy efficiency
programs. Commercial and industrial potential shows consistent growth.
For the 2012-2013 compliance period, the Sixth Power Plan goal is within the goal
range developed in the CPA, with a floor of Realistic Achievable Potential and a ceiling
of Maximum Achievable Potential. However, the Sixth Power Plan includes components
other than conservation such as distribution system efficiencies. When savings due to
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2031
sa
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t
Achievable
Economic
Technical
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
these efficiencies are subtracted from the Sixth Power Plan goals, the resulting values
are well within the range of the potential study.
Table 3.2: Incremental Annual Achievable Potential Energy Efficiency (aMW)
2012 2013
NPCC Sixth Power Plan Target
Idaho 5.17 5.60
Washington 8.22 8.90
Total 13.39 14.50
Less Distribution Efficiency from the Sixth Plan
Idaho -0.22 -0.28
Washington -0.47 -0.60
Total -0.69 -0.88
Sixth Power Plan Target without Distribution Efficiency
Idaho 4.95 5.32
Washington 7.75 8.30
Total 12.70 13.62
Incremental Achievable Potential Range4
Idaho 1.95 – 3.50 2.17 – 4.51
Washington 3.74 – 6.30 4.31 – 8.58
Total 5.69 – 9.80 6.48 – 13.09
Achievable from Existing Programs
Idaho 1.58 1.55
Washington 2.93 2.85
Total 4.51 4.40
Goal Range per Conservation Potential Assessment
Idaho 3.53 – 5.09 3.72 – 6.06
Washington 6.67 – 9.23 7.16 – 11.43
Total 10.20 – 14.32 10.88 – 17.49
Figure 3.4 shows incremental annual achievable roughly tracking avoided costs
throughout the study period, but factors in addition to avoided cost can influence
achievable potential, particularly where programs are ramping up or are ramping down.
These impacts are particularly relevant in the early years of the CPA study.
4 Incremental Realistic Achievable Potential was used for purposes of modeling resource acquisition from
conservation. For I-937, a range target will be presented with the ceiling of the range being Maximum
Achievable Potential and the floor being Realistic Achievable Potential as determined by the independent
CPA.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Figure 3.4: Incremental Annual Achievable Energy Efficiency (MWh) vs. Avoided Cost5
Electricity to Natural Gas Fuel Switching
Fuel switching from electricity to natural gas is included in the targets as described
above. Tables 3.3 and 3.4 illustrate savings potentials from converting electric furnaces
and water heaters to natural gas. Nearly all savings are in the residential sector.
Conversion ramps up slowly, but because it removes most of the electricity use from
two of the largest residential end uses (water heating and space heating), it accounts for
a substantial portion of savings by 2031. For water heating, about one-fourth of the
savings from gas conversions occurs in new construction. For furnaces, new
construction accounts for roughly one-third of the total.
Table 3.3: Cumulative Achievable Savings from Conversion to Natural Gas
2012 2017 2022 2027 2031
Water heater - convert to gas potential
(MWh)
45.7 4,967 69,406 146,834 201,182
Water heater - convert to gas percentage of
total potential
0.1% 1% 7% 10% 10%
Furnace - convert to gas potential (MWh) 10.1 2,527 45,979 108,447 158,470
Water heater - convert to gas percentage of
total potential
0.0% 1% 5% 7% 8%
5 Avoided costs are 2009 real dollars and include energy costs, risk, losses, avoided T&D, and the 10 percent Power
Act premium.
$-
$13
$25
$38
$50
$63
$75
$88
$100
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40,000
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Extra Large Industrial Extra Large Commercial
Large Commercial Small Commercial
Residential Avoided Costs
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Table 3.4: Cumulative Achievable Savings from Conversion to Natural Gas by State
(MWh)
Washington Conversion Potential 2012 2017 2022 2027 2031
Water heater - convert to gas potential 36 3,966 55,623 117,942 161,411
Furnace - convert to gas potential 1 1,509 31,082 76,213 112,522
Total Washington conversion potential 37 5,475 86,705 194,155 273,933
Idaho Conversion Potential 2012 2017 2022 2027 2031
Water heater - convert to gas potential 10 1,001 13,783 28,893 39,770
Furnace - convert to gas potential 9 1,018 14,898 32,234 45,948
Total Idaho conversion potential 19 2,019 28,681 61,127 85,718
Comparison with the Sixth Power Plan Methodology
As required by Washington Administrative Code (WAC) Chapter 480-109-010 (3)(c),
Avista below describes the technologies, data collection, processes, procedures and
assumptions used to develop its I-937 biennial targets, along with changes in
assumptions or methodologies used in the Company’s IRP or the NPCC Sixth Power
Plan. WAC Chapter 480-109-010 (4)(c) requires UTC approval, approval with
modifications, or rejection of the targets.
Global met with the NPCC staff to compare methodologies and approaches to ensure
methodological consistency. The CPA methodology is consistent with the Sixth Power
Plan in several key ways. Both the NPCC Sixth Power Plan and Global’s approaches
utilized end-use models employing a bottom-up approach. The models draw on
appliance stock, saturation levels and efficiencies information to construct future load
requirements. Global conducted a thorough review of baseline and measure
assumptions used by the NPCC and developed a baseline energy use projection,
absent any additional energy efficiency measures while including the impact of known
codes and standards currently approved. The study reviewed and incorporated NPCC
assumptions when Avista-specific or more updated data was not available.
The CPA study developed a comprehensive list of energy-efficiency technologies and
end-use measures, including those in the Sixth Power Plan. Since the efficiency
measures, equipment, and other data used in the Sixth Power Plan are somewhat
dated, information on measures and equipment specific to Avista were updated for this
CPA. Global developed equipment saturations, measure costs, savings, estimated
useful lifetimes and other parameters based on data from the Sixth Power Plan
Conservation Supply Curve workbook databases, the Regional Technology Forum,
NEEA reports, and other data sources. Similar to the Sixth Power Plan, the study
accounts for the difference between lost and non-lost opportunities, and how this affects
the rate at which energy efficiency measures penetrate the market. The study used the
Total Resource Cost (TRC) test as the measure for judging cost-effectiveness. A
comprehensive list of measures and equipment evaluated in the CPA study is included
in Appendix C. For a more detailed discussion of measures and equipment evaluated
within the potential study, please refer to the Conservation Potential Assessment report
prepared by Global in Appendix D.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
After screening measures for cost-effectiveness, the CPA applied a series of factors to
evaluate realistic market acceptance rates and program implementation considerations.
The resulting achievable potential reflects the realistic deployment rates of energy
efficiency measures in Avista’s service territory. These factors account for market
barriers, customer acceptance, and the time required to implement programs. To
develop these factors, Global reviewed the ramp rates used in the Sixth Power Plan
Conservation Supply Curve workbooks and considered Avista’s experience.
The Sixth Power Plan assesses a 20-year period beginning in 2010, while the CPA
study begins in 2012. Where the Sixth Power Plan relies on average regional data, the
CPA utilized data from Avista’s service territory, as well as more recent economic data.
Therefore, an allocation of regional potential based on sales, as applied in the Sixth
Power Plan, would not necessarily account for Avista’s unique service territory
characteristics such as customer mix, use per customer, end-use saturations, fuel
shares, current measure saturations, and expected customer and economic growth. In
addition, some industries included in the Sixth Power Plan might not exist in Avista’s
service territory. While the Sixth Power Plan incorporates Distribution System
efficiencies, the Avista CPA includes only energy efficiency from energy conservation
while Distribution System efficiencies and Thermal System efficiencies would be
incorporated into Avista’s I-937 targets from other sources.
The Sixth Power Plan assumed that 85 percent of the cost-effective, or economic, non-
lost opportunity potential will be achieved over the 20 years covered by the Sixth Power
Plan. The projected achievement amount during the first 10 years (consistent with the I-
937 timeframe) is approximately 60 percent. For lost opportunities, the plan assumes
achievement of approximately 65 percent of the cost-effective, or economic, potential
during the 20-year period. Due to ramp rates used within the plan, this equates to only
37 percent achievement within the first 10 years, the period considered for I-937. The
CPA study assumed that cost-effective measures reach a maximum saturation level of
85 percent over the 20-year period for lost opportunities, and 65 percent to 85 percent
for non-lost opportunities. These figures equal or exceed adoption rates assumed within
the Sixth Power Plan.
Sensitivity of Potential to Customer and Economic Growth
The CPA study shows that energy efficiency offsets roughly 50 percent of load growth,
whereas the Sixth Power Plan estimates that energy efficiency can offset 80 percent.
While Avista’s service territory differs from the larger region in many ways, including its
climate and particular customer mix, there are other contributing factors to this
difference. One significant factor may be the CPA customer and economic growth
assumptions. To understand how growth affects the results of the study, Global
LoadMAP modeled several scenarios with lower customer and economic growth, as
indicated in Table 3.5.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Table 3.5: Varying Growth Scenario Descriptions
Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Home size
(physical size in
square feet)
~ 1% per year growth Capped at 110% of
existing household
size
Capped at 110% of
existing household size
Per capita income
growth
1.6% 2011–2015;
2.2% 2016–2020;
2.1% thereafter
1.6% after 2016 1.6% after 2016
Residential sector
market growth
1.30% after 2015 (WA)
1.25% after 2015 (ID)
no change 1.0% after 2015 (WA &
ID)
Commercial sector
market growth,
Washington &
Idaho
~ 2.0% (varies by
segment)
no change 1.0% all segments
Table 3.6 shows that as economic and customer growth decreases, the ability of energy
efficiency to offset growth increases. In the reference scenario, energy efficiency offsets
54 percent of growth in consumption, while in the lower growth scenarios, energy
efficiency offsets 55 percent and 77 percent of growth. This is the case because with
reduced levels of new construction, both load growth and energy savings drop, but
savings from the retrofit of existing buildings are a greater proportion of overall growth.
Table 3.6: Varying Growth Scenario Results (MWh)
Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Baseline forecast 2012 8,799,039 8,799,039 8,799,033
Baseline forecast 2031 12,574,182 12,272,136 11,025,256
Load Growth 2012-2031 3,775,143 3,473,097 2,226,222
Achievable potential case forecast 2031 10,697,432 10,361,667 9,302,736
Achievable potential savings 2031 2,025,679 1,910,469 1,722,519
Percentage of growth offset 54% 55% 77%
Avoided Cost Sensitivities
Global modeled several scenarios with varying avoided costs assumptions in addition to
the Expected Case used for the 2011 IRP to test sensitivity to changes in avoided costs.
The scenarios included 150 percent, 125 percent, and 75 percent of the avoided costs
relative to the Expected Case. Figure 3.5 illustrates the avoided cost scenarios. Overall,
due to the technical potential ceiling, energy efficiency proved to be insensitive to
avoided cost assumptions. In particular, acquiring incremental energy efficiency
becomes increasingly expensive, so that increases in avoided costs do not provide
equivalent percentage increases in achievable potential. The Expected Case achievable
potential is approximately 16.8 percent of the baseline forecast by 2031. With the 150
percent avoided cost case, achievable potential increases by 15 percent compared with
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
the Expected Case reference scenario, while the 125 percent and the 75 percent
avoided cost cases yielded achievable potential equal to 79 percent and 108 percent of
the reference scenario respectively. Table 3.5 shows achievable potential under the four
avoided cost scenarios.
In 2012, 52 percent of the projected achievable potential is from residential class
measures. By 2017, a shift occurs whereby 68 percent of the achievable potential
comes from non-residential classes, with the significant portion of these savings, 42
percent, estimated to come through the large general service segment. In the residential
sector in 2017, approximately 40 percent of projected savings come from interior
lighting, followed by water heating, space heating and electronics. In subsequent years,
residential savings from lighting decreases, with space and water heating providing
greater relative savings potential.
In the commercial and industrial sectors, lighting accounts for approximately 62 percent
of savings potential in 2017 followed by heating, ventilation and air conditioning (HVAC),
office equipment, exterior lighting and machine drives. Over time, the savings potential
from lighting decreases, but still remains close to half of the savings potential in 2031.
Figure 3.5: Energy Savings, Achievable Potential Case by Avoided Costs Scenario
0
500,000
1,000,000
1,500,000
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150% of avoided costs
125% of avoided costs
75% of avoided costs
Technical Potential
100% of avoided costs
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Table 3.7: Achievable Potential with Varying Avoided Costs
Reference
Scenario
75% of
Avoided
Costs
125% of
Avoided
Costs
150% of
Avoided
Costs
Achievable potential savings
2031 (MWh)
2,025,679 1,590,850 2,186,730 2,327,510
Percentage change in
savings vs. 100% avoided
cost scenario
n/a -21% 8% 15%
Heat pump water heater measures in the Sixth Power Plan were projected to replace
compact fluorescent lights (CFLs) contribution (i.e., significant savings at relatively low
costs) in earlier plans. The CPA found that heat pump water heaters are not cost-
effective, with the exception of new single-family homes, under the Expected Case.
However, the measure becomes cost-effective for more market segments under the 150
percent of avoided cost scenario.
Figure 3.6 shows supply curves composed of the stacked measures and equipment in
2031 in ascending order of avoided cost. Since there is a gap in the cost of the energy
efficiency measures moving up the supply curve, the measures with a very high cost
cause a rapid sloping of the curve. The portfolio average cost for each case is shown as
well. The shift of the supply curve toward the right as avoided costs increase is a
consequence of increasing amounts of cost-effective potential, but the average cost of
acquiring that potential is increasing also.
Figure 3.6: Supply Curves of the Evaluated Conservation Measures6
6 The triangles in Figure 3.6 indicate the portfolio average cost for each avoided cost scenario.
$0.00
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% Reduction from Baseline in 2032
Expected Case
75% avoided costs scenario
125% avoided costs scenario
150% avoided costs scenario
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Energy Efficiency-Related Financial Impacts
I-937 requires utilities with over 25,000 customers to obtain a fixed percentage of their
electricity from qualifying renewable resources and to acquire all cost-effective and
achievable energy conservation. For the first 24-month period under the law (2010-
2011), this equaled a ramped-in share of the regional ten-year target identified in the
Sixth Power Plan. Penalties of at least $50 per MWh exist for utilities not achieving
Washington targets for conservation resource acquisition.
Regional discussions were under way regarding the definition of “pro-rata” during the
2009 IRP. Avista proposed ramping the 10-year targets identified in the Sixth Power
Plan instead of acquiring 20 percent of the first ten-year target identified in the Sixth
Power Plan. The “pro-rata” amount would have created drastic ramping challenges,
especially in the early years. Due to inconsistencies between the 2009 IRP and the
Council’s methodology, the Company elected to use the NPCC’s Option #1 of the Sixth
Power Plan to establish its conservation acquisition target, adjusted to include electric-
to-natural gas space and water heating fuel conversions. The acquisition target was 11
percent greater than Avista’s IRP energy efficiency target for the same period. In April
2010, the UTC approved the Company’s ten year Achievable Potential and Biennial
Conservation Target Report in Docket UE-100176.
The I-937 requirement to acquire all cost-effective and achievable conservation poses
significant financial implications for Washington customers. In 2012, the projected
incremental annual cost to Washington customers is $2.0 million. This annual amount
grows to $41.8 million by the tenth year, representing a total of $199.2 million over this
ten-year period for Washington. Figure 3.7 shows the annual cost (in millions) for this
acquisition of past and future conservation. As shown in the figure, future cost for new
conservation reflects margin returns as compared to historical acquisition.
This incremental level of acquisition driven by Washington I-937 will result in annual rate
increases to Washington electric customers of an approximate range of $8 to $302 per
average customer across all classes. Figure 3.8 illustrate the annual cost associated
with the energy efficiency acquisition required to meet I-937 goals.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Figure 3.7: Cost of Existing & Future Conservation
Figure 3.8: Cost of Conservation per Customer per I-937
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Annual Savings
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Avg Customer Cost of Total Conservation
Avg Customer Cost of Incremental Conservation
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Integrating Results into Business Planning and Operations
The CPA and IRP energy efficiency evaluation processes provide high-level estimates
of cost-effective conservation acquisition opportunities. While results of the IRP
analyses establish baseline goals for continued development and enhancement of
conservation programs, the results are not detailed enough to form an acquisition plan.
Avista uses IRP evaluation results to establish a budget for conservation measures, to
help determine the size and skill sets necessary for future conservation operations, and
for identifying general target markets for energy efficiency programs. This section
provides an overview of recent operations of the individual sectors as well as
conservation business planning.
For this IRP, the Company procured its first external conservation potential assessment
study for Washington and Idaho from Global Energy Partners. This study is useful for
the implementation of energy efficiency programs in the following ways.
Identifying by sector, segment, end-use and measure where energy savings may
come from during the next 20-year timeframe. The implementation staff can use
CPA results to determine which segments and end-uses/measures to target
through energy efficiency programs.
Identifying measures with the highest TRC benefit-cost ratios and targeting those
lowest cost resources with the greatest benefit.
Identifying measures that appear to have great adoption barriers by looking at
the economic versus achievable results by measure. Implementation staff can
then better develop programs around barriers that may exist.
Improving the design of current program offerings. Implementation staff can
review the measure level results by sector and compare the savings with the
largest-savings measures currently offered by the Company. This analysis may
lead to the elimination of some programs or the addition of other programs.
Consideration might be given to identifying lost opportunities (i.e. “low-hanging
fruit”) and whether to target one particular measure over another measure. One
possibility may be to offer higher incentives on measures with higher benefits and
lower incentives on measures with lower benefits.
In addition to how the IRP results and the potential study flow into operational planning,
an overview of 2010 and 2011 energy efficiency acquisitions by sector is given below.
This is prior to the implementing the actions mentioned above.
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 by Avista during 2010 included space and water heating
conversions, ENERGRY STAR® appliances, ENERGY STAR® homes, space and water
equipment upgrades and home weatherization.
Avista offers the remaining residential energy efficiency programs through other
channels. For example, a third party administer JACO operates the refrigerator/freezer
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Avista Corp 2011 Electric IRP
recycling program. CFL and specialty CFL buy-downs at the manufacturer level provide
customers access to lower-priced CFL bulbs. Home energy audits, subsidized by a
grant from the American Recovery and Reinvestment Act (ARRA), began in 2010. This
program offers home inspections that include numerous diagnostic tests and provides a
leave-behind kit containing CFLs and weatherization materials. Finally, Avista provides
educational tips and CFLs at various rural and urban events in an effort to reach all
areas within its service territory.
Avista processed over 36,000 energy efficiency rebates in 2010, benefiting
approximately 25,000 households. Nearly $6.3 million in customer rebates offset the
cost of implementing energy efficiency upgrades. Residential programs contributed
24,247 MWh and nearly 1.1 million therms of energy savings.
The results of an Ecotope study resulted in several planned modifications to the 2011
residential programs. These modifications include the discontinuation of the windows
program, contractor installed weatherization requirements (eliminating do-it-yourself
projects), reducing incentives for electric to natural gas water heater conversion, and
the inclusion of the rooftop damper program on the residential form. We address these
efficiency program modifications below.
The CPA study illustrates potential markets and provides a list of cost-effective
measures analyzed through the on-going energy efficiency business planning process.
This review of residential program concepts and their sensitivity to more detailed
assumptions will feed into program plans for target markets. Potential measures not
currently considered at the time of the CPA that may arise in the future will be
reevaluated for possible inclusion in the Business Plan.
Residential Energy Efficiency Offering In Depth
Avista encourages customers to take part in home energy audits. Employees and
customers in Spokane County can sign up for a comprehensive home energy audit
offered by Avista for as low as $49. Funding for this pilot program comes from a
combination of Avista energy efficiency funds and federal stimulus dollars through the
Energy Efficiency Community Block Grant program. Avista collaborated with the City of
Spokane, Spokane County and the City of Spokane Valley to provide this program at a
significantly reduced cost.
The home energy audits use certified professionals with state-of-the-art equipment and
techniques to identify home energy use and safety improvements. The auditor
discusses existing energy use, if there are any energy efficiency concerns, and areas of
the home that are not as comfortable as owners would like them to be. Once the audit is
complete, the customer receives a detailed report on the findings, along with
recommendations to make their home more energy efficient.
In addition to a wealth of information, participating homeowners receive an energy
efficiency/weatherization kit with a retail value of approximately $50. It contains compact
fluorescent light bulbs, low-flow showerheads, expanding foam sealant and other
energy-saving materials. Customers are able to visit www.avistautilties.com to find out
more and to view a video about this and other energy efficiency programs.
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP
Limited Income Sector Overview
Six Community Action Agencies (CAAs) administer low-income programs. During 2010
these programs targeted a range of end-uses including space and water heating
conversions, ENERGY STAR refrigerators, space and water heating equipment
upgrades, and weatherization which are offered site-specifically through individualized
home audits. The Company also funds health and human safety investments
considered necessary to ensure habitability of homes and protect investments in energy
efficiency, as well as administrative fees enabling CAAs to continue to deliver these
programs.
During 2010, the Company convened the Low Income Collaborative to explore new
approaches promoting low-income conservation, identify barriers to its development and
to address issues raised by The Energy Project in Avista’s 2009 Washington General
Rate Case. On September 1, 2010, the Company filed the conclusions of the Low
Income Collaborative as requested by the UTC.
Issues addressed through the low income collaborative included defining the low-
income customer class, identifying market barriers to the success of low income energy
efficiency programs, identifying measures for success, and identifying low income
energy efficiency delivery mechanisms and funding sources.
The CAAs had 2010 budgets of $1.3 million for Washington and $660,000 for Idaho.
The Company processed about 1,500 rebates, benefitting approximately 550
households. During 2010, the Company paid $1.7 million in rebates to the CAAs to
provide fully subsidized energy efficiency upgrades, health and human safety, and
administrative costs for the CAAs to administer these programs. The CAAs spent nearly
$144,000 on health and human safety, which was 8.3 percent of their total expenditures
and within their 15 percent allowance for this spending category. Low Income energy
efficiency programs contributed 2,102 MWh of electricity savings and 61,271 therms of
natural gas savings.
All of the CAAs received a funding increase in 2011 resulting from recent rate cases in
both Washington and Idaho making the total funding $2 million for Washington,
$940,000 for Idaho, and an additional $40,000 for conservation education.
CAAs submitting for reimbursement in 2011 must include the age of the home and
square footage to improve billing analysis and other evaluation efforts. Energy savings
claims are now consistent with the regular residential programs, rather than CAAs using
various models to estimate their energy savings. Impact evaluation led the Company to
believe that these models were treating the installation of measures individually, rather
than incrementally, resulting in overestimates of savings achieved. This change should
provide for higher realization rates since the original estimates should be closer to
actual observations in billing analysis. This modification was made in response to
Ecotope’s 2011 Energy Impact Evaluation Report of Select 2008 Programs.
The CAAs are required to submit marginally cost-effective measures for “pre-approval”
to protect the cost-effectiveness of the portfolio. This process has been in effect for the
past three years and has allowed the Company to manage on a monthly basis the
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Avista Corp 2011 Electric IRP
overall TRC for the Low Income Portfolio. Examples of measures that need pre-
approval include natural gas furnaces, natural gas water heaters and ENERGY STAR
refrigerators.
Non-Residential Sector Overview
For the non-residential sectors (commercial, industrial and multi-family applications),
energy efficiency programs are offered on a site-specific or custom basis. We can offer
a more prescriptive approach when treatments result in similar savings and the
technical potential is high. An example is the prescriptive lighting program. The
applications are not purely prescriptive in the traditional sense, such as with residential
applications where homogenous programs are provided for all residential customers;
however, a more prescriptive approach can be applied for these similar applications.
Non-residential prescriptive programs offered by Avista include, but are not limited to,
space and water heating conversions, space and water heating equipment upgrades,
appliance upgrades, cooking equipment upgrades, personal computer network controls,
commercial clothes washers, lighting, motors, refrigerated warehouses, traffic signals,
and vending controls. Also included are residential program offerings such as multi-
family direct install through UCONS (which ended in December 2009, however, a
handful of projects were reported in 2010) and multi-family market transformation since
these projects are implemented site-specifically unlike other residential programs.
During 2010, the Company processed approximately 2,400 energy efficiency projects
resulting in the payment of $7.9 million in rebates paid directly to customers to offset the
cost of their energy efficiency projects. These projects contributed 43,430 MWh of
electricity and 742,559 therms of natural gas savings.
In January 2011, Avista launched two new prescriptive programs – commercial windows
and insulation and commercial natural gas HVAC. Another prescriptive program, for
standby generator block heaters, was evaluated and launched April 1, 2011. A survey of
various municipalities in 2010 to determine saturation levels of light-emitting diode traffic
signals and as a result, this program will end. Participants submitting paperwork by
December 15, 2011, will still be eligible to receive an incentive payment. The
Leadership in Energy and Environmental Design building rating program ended
December 31, 2010. Projects completed by December 31, 2011 with paperwork
submitted by March 31, 2012, will be eligible for an incentive.
Energy Smart Grocer is a regional, turnkey program administrated through PECI. This
program has been operating for several years. This program will approach saturation
levels during the early part of this 20-year planning horizon. We implement the
remaining programs in the site-specific sector through the Company’s energy efficiency
infrastructure.
The programs highlighted by the recently completed CPA study will be reviewed for the
development of target marketing and the creation of new energy efficiency programs. All
electric-efficiency measures with a simple payback exceeding one year and less than
eight years for lighting measures or thirteen years for other measures automatically
qualify for the non-residential portfolio. The IRP provides account executives, program
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Avista Corp 2011 Electric IRP
managers/coordinators and energy efficiency engineers with valuable information
regarding potentially cost-effective target markets. However, the unique and specific
characteristics of a customer’s facility override any high-level program prioritization for
non-residential customers.
Non-Residential Energy Efficiency Example
The scope of this energy efficiency project included a solution to replace an existing
compressor used to circulate water in Medical Lake. The existing equipment was a 50
horsepower screw compressor with a 1,750-RPM three-phase motor that operated 24
hours per day, seven days per week from May 1st through October 31st. The proposed
replacement for the existing equipment was five Solar Bee solar-powered DC agitators
used to circulate the lake. The compressor is projected to be removed after four of the
five solar units have been installed. The estimated annual energy savings associated
with this energy efficiency project is approximately 128,000 kWh, which is equivalent to
the 50 horsepower compressor running at an estimated 80 percent of full load for six
months. Non-quantified non-energy benefits (NEBs) associated with this project include
improved water quality and reduced (or possibly eliminated) chemical treatment. The
energy efficiency incremental measure cost for the customer is approximately $57,000
and estimated savings of $8,916 in annual energy costs at current rates. At completion,
the customer would receive an estimated $25,000 incentive, which would reduce their
6.4-year simple payback to 3.6 years.
Demand Response
Prior to the addition of energy efficiency resources, additional capacity resources were
estimated to be needed in 2013. Once energy efficiency resources were layered onto
existing supply-side resources in the PRiSM model, this capacity need was moved out
to 2019 for summer capacity and 2021 for winter capacity. This capacity need comes
from expiring contracts as well as native load growth.
As part of the CPA study, Global evaluated typical demand response program options,
including direct load control, curtailable and demand bidding/buy-back programs. Using
the Company’s capacity costs, prior to the inclusion of energy efficiency, Global found
that these demand response programs were cost-effective. However, because energy
efficiency is assumed to be acquired first consistent with I-937, the savings resulting
from energy efficiency removed the need for additional capacity, making demand
response not cost effective at this time.
Since Avista does not have an immediate capacity shortage, the Company will not
continue to model demand response programs in the near term, but may continue to
evaluate some of these demand response programs in the future.
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
4. Policy Considerations
Many environmental policy issues could significantly affect the operation of the
Company‟s current generation resources and could affect the types of resources it
might pursue in the future. Over time, the direction of these expected future policy
considerations has changed, sometimes dramatically. The Company expects the nature
and impact of future environmental policies to continue changing. The 2009 IRP
included an Environmental Policy chapter that mainly focused on greenhouse gas policy
and renewable portfolio standards. The current political and regulatory environments
have changed significantly since the publication of the last IRP. The immediate
prospects for implementation of cap and trade programs to reduce greenhouse gas
emissions has diminished, leading to a new focus on regulatory measures pursued by
the Environmental Protection Agency (EPA) and on political and legal initiatives
commenced by environmental groups to apply pressure on thermal generation –
specifically coal-fired generation. The areas of regulation have particular implications,
as they involve regulation of emissions affecting regional haze, coal ash disposal,
mercury emissions, water quality, as well as greenhouse gas emissions. This chapter
provides an overview and discussion about some of the more pertinent environmental
policy issues facing the Company.
Environmental Concerns
Environmental concerns, such as greenhouse gas emissions, present a unique
resource planning challenge due to the continuously evolving nature of environmental
regulation and its ever-changing projections of the scope and costs of various
programs. If environmental concerns were the only issue faced by electric utilities,
resource planning would be reduced to a determination of the required 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 and manage financial risks
compound utility planning complexity. Each generating resource has distinctive
operating characteristics, cost structures, and environmental challenges. Traditional
generation technologies, like coal-fired and natural gas-fired plants, are well understood
and provide capacity along with energy.
Chapter Highlights
Avista‟s Climate Change Council monitors green
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Coal-fired units have high capital costs, long permitting and construction lead times, and
relatively low and stable fuel costs. They are difficult, if not impossible in some
jurisdictions, to site due to state laws and local opposition, and environmental issues
ranging from the impacts of coal mining to power plant emissions. Further, remote mine
locations increase cost by either the transportation of coal to the plant or the
transportation of the generated electricity to load. By comparison, natural gas-fired
plants have relatively low capital costs as compared to coal, are typically located close
to load centers, can be constructed in relatively short time frames, emit less than half
the greenhouse gases emitted by coal, and are the only utility-scale baseload resource
that can be developed in certain locations. However, fuel price volatility affects natural
gas-fired plants. They are also challenged by having diminished performance during
periods of hot weather, by the difficulty of securing water rights for their efficient
operation, and by the fact that the plants still emit significant greenhouse gases relative
to renewable resources.
Renewable energy technologies such as wind, biomass, and solar generation have
different challenges. Renewable resources are attractive because they have low or no
fuel costs and few, if any, emissions. However, renewable generation can have limited
or no on-peak capacity contribution to the operation of the Company‟s system, and
intermittent renewable resources can present integration challenges and require
additional non-renewable generation capacity investment. These resources also
generally have high upfront capital costs, and have their own environmental challenges
to overcome, particularly with respect to siting. Similar to coal plants, renewable
resource projects are located near their fuel sources. The need to site renewable
resources in remote locations often requires significant investments in transmission
interconnection and capacity expansion, as well as raising possible wildlife and
aesthetic issues, such as those that utility-scale solar projects in the southwestern U.S.
have encountered. Unlike coal or natural gas-fired plants, the fuel for non-biomass
renewable resources cannot be transported from one location to another to better utilize
existing transmission facilities or to minimize opposition to project development.
Biomass facilities themselves can be particularly challenged because of their
dependence on the health of the forest products industry and access to biomass
materials located in publicly owned forests.
Furthermore, the long-term economic viability of renewable resources is uncertain for at
least two important reasons. First, federal investment and production tax credits and
direct grants in lieu of tax incentives are scheduled to expire in 2012 or 2013, depending
on the technology. The continuation of credits and grants cannot be assumed in light of
the impact such subsidies have on the finances of the federal government and the
relative maturity of wind technology development. Second, the costs of renewable
technologies are affected by many relatively unpredictable factors, such as renewable
portfolio standard mandates, material prices and currency exchange rates, the effects of
which cannot be accurately predicted. Capital costs for wind and solar have decreased
since the 2009 IRP, but there are no guarantees that prices will continue to stay at
current levels.
Though there appears to be very little, if any, chance that a national greenhouse gas
cap and trade program being implemented soon, there still is a great deal of uncertainty
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Avista Corp 2011 Electric IRP
around its regulation. There is strong regional and national support to address climate
change. Since the 2009 IRP publication, many changes in the approach and potential
for actual greenhouse gas emissions regulation have occurred, including:
Consideration is presently being given toward a clean energy standard at the
federal level, instead of a more direct form of greenhouse gas emission
regulation, such as a cap and trade program;
The current split of control between the U.S. House of Representatives and the
Senate effectively postpones national cap and trade legislation for greenhouse
gas emissions until after the 2012 election, at the earliest;
The EPA has commenced actions to regulate greenhouse gas emissions under
the Federal Clean Air Act, although some of these efforts have been delayed and
the agency „s justification for advancing some of its initiatives are being judicially
challenged ; and
Development of economy-wide cap and trade regulation at the regional level now
focus primarily on California and British Columbia rather than on the broader
Western Climate Initiative.
Avista’s Climate Change Policy Efforts
Avista‟s Climate Policy Council is a clearinghouse for all matters related to climate
change. In regards to climate change, the Council:
Facilitates internal and external communications on climate policy issues;
Analyzes policy impacts, anticipates opportunities and evaluates strategy for
Avista; and
Develops recommendations on climate related policy positions and action plans.
The core team of the Climate Policy Council includes a designated chairperson, key
officers, and representatives from Environmental Affairs, Government Relations,
Corporate Communications, Engineering, Energy Solutions, Legal Affairs, and
Resource Planning. Other areas of the Company participate as needed. The monthly
meetings for this group include work divided into immediate and long-term concerns.
The immediate concerns include such topics as reviewing and analyzing proposed or
pending state and federal legislation, reviewing corporate climate change policy, and
responding to internal and external data requests about climate change issues. Longer-
term issues involve topics such as emissions tracking and certification, providing
recommendations for greenhouse gas goals and activities, evaluating the merits of
different greenhouse gas policies, actively participating in the development of
legislation, and benchmarking climate change policies and activities against other
organizations.
Avista maintains its membership in the Clean Energy Group, which includes Calpine,
Entergy, Exelon, Florida Power and Light, Pacific Gas & Electric and Public Service
Energy Group. This group collectively evaluates and supports different greenhouse gas
policies. Avista also participates in national and regional discussions about hydroelectric
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
and biomass issues through membership in national hydroelectric and biomass
associations.
Avista’s Position on Climate Change Legislation
Avista anticipates the passage of federal greenhouse gas (climate change) legislation in
some form within the next five years. A comprehensive national climate change policy
could assume the form of a cap and trade program, carbon tax, national portfolio
standard, emissions performance standard, or some combination of the four. The
Expected Case in this IRP uses 2015 as the starting date for greenhouse gas emissions
costs. The 2015 start date was chosen early in the development of the modeling
exercises for this plan, and the actual effective date will most likely be after 2015 by the
time legislation could be enacted and rules promulgated. The Company chose to
develop a weighted cost using four different cases for greenhouse gas emissions
because of the uncertainty about the timing and scope of this legislation. The four cases
include regional cap and trade, national cap and trade, national carbon tax and no
greenhouse gas policies. Details about the different greenhouse gas policies modeled
for this IRP are located at the end of this chapter.
The current lack of a definitive greenhouse policy direction makes an uncertain planning
environment as Avista plans to meet future customer loads. Avista does not have a
preferred form of greenhouse gas policy at this time, but supports federal legislation that
is:
Workable and cost effective;
Fair;
Protective of the economy and consumers;
Supportive of technological innovation; and
Includes emissions from developing nations.
Workable and cost effective legislation should be crafted to produce actual greenhouse
gas reductions through a single system, as opposed to competing, if not conflicting,
state, regional and federal systems. The legislation also needs equitable distribution
across all sectors of the economy based on relative contribution to greenhouse gas
emissions. Protecting the economy and consumers is of utmost importance. The
legislation cannot be so onerous that it stalls the economy or fails to have any sort of
adjustment mechanism in case the market solution fails causing allowance or offset
prices to escalate at unmanageable rates. Supporting technological innovations should
be a key component of any greenhouse gas legislation because innovation can help
contain costs, as well as provide a potential economic boost to the manufacturing
sector. Climate change legislation must involve developing nations with increasing
greenhouse gas emissions and legislation should include strategies for working with
other nations directly or through international bodies to control worldwide emissions.
Greenhouse Gas Emissions Concerns for Resource Planning
Resource planning in the context of greenhouse gas emissions regulation raises
concerns about the balance between the Company‟s obligations for environmental
stewardship and the cost implications for our customers. Consideration must be given to
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Avista Corp 2011 Electric IRP
the cost effectiveness of resource decisions as well as the need to mitigate the financial
impact of potential future emissions risks.
Complying with greenhouse gas regulations, particularly in the form of a cap and trade
mechanism, involves two actions: ensuring the Company maintains sufficient
allowances and/or offsets to correspond with its emissions during a compliance period,
and undertaking measures to reduce the Company‟s future emissions. Enabling
emission reductions on a utility-wide basis can entail any of the following:
Increasing efficiency of existing fossil-fueled generation resources;
Reducing emissions from existing fossil-fueled generation through fuel
displacement including co-firing with biomass or biofuels;
Permanently decreasing the output from existing fossil-fueled resources and
substituting it with lower emitting resources;
Decommissioning or divesting of fossil-fueled generation and substituting lower
emitting resources;
Reducing exposure to market purchases of fossil-fueled generation, particularly
during periods of diminished hydropower production, by establishing larger
reserves based on lower emitting technologies; and
Increasing investments in energy efficiency measures.
With the exception of increasing Avista‟s commitment to energy efficiency, the costs
and risks of the actions listed above cannot be adequately, let alone fully, be evaluated
until the nature of greenhouse gas emission regulations is known; that is, after a
regulatory regime has been implemented and the economic effects of its interacting
components can be modeled. A specific reduction strategy as part of an IRP may be
forthcoming when greater regulatory clarity and more precise modeling parameters
exist. In the meantime, the model for this IRP uses the average cost of the weighted
policies discussed at the end of this chapter. The 2011 IRP focuses on the costs and
mitigation of carbon dioxide since it is the most prevalent and primary greenhouse gas
emitted from fossil-fueled generation sources.
National Greenhouse Gas Emissions Legislation
Several themes have emerged from various climate change legislative proposals
considered since publication of the 2009 IRP. These include:
Climate change is now viewed as largely an anthropogenic or human-developed
phenomenon.
A preference in certain economic sectors towards application of greenhouse gas
regulations on an economy-wide basis, rather than on piecemeal regulatory
approaches that target specific sectors or technologies.
Technology will be a key component to reducing overall greenhouse gas
emissions, particularly in the electric sector. Significant investment in carbon
capture and sequestration technology will be needed because coal will continue
to be an important part of the U.S. generation fleet into the near future.
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Developing countries must be involved in reducing global emissions as
greenhouse gas emissions generally increase along with economic growth.
The longer federal legislation takes to enact, the higher the probability of
inconsistent state and regional regulatory schemes. A patchwork of regulation
may obstruct the operation of businesses serving multiple jurisdictions by
causing market disruptions and increasing the uncertainty of how federal and
disparate state and regional regulatory systems might interact.
These themes all point toward a need to develop national greenhouse gas legislation in
a timely manner to ensure the best environmental and economic outcomes. The
Waxman-Markey bill (H.R. 2454), passed in the U.S. House of Representatives in June
2009, importantly acknowledged these multi-jurisdiction problems by proposing to
effectively supersede state and regional cap and trade regulation over emissions
covered under federal law between 2012 and 2017.
Federal Policy Considerations
The direction of federal policies toward greenhouse gas emissions mitigation has
changed since the 2009 IRP. In that document, the Company projected a national cap
and trade program would be enacted and effective in 2012. This IRP assumes some
version of a national greenhouse gas policy will be in place starting in 2015, but the type
of policy is uncertain. If the models for this IRP did not have to be locked down early in
the process, we would have pushed the timeframe out even further because of the
uncertainty of any federal-level climate change policy with the current split between the
House and the Senate, the soft state of the U.S. economy, and the upcoming 2012
elections. Given this low level of certainty, the Company developed four hypothetical
greenhouse gas policy models. Details are provided later in this chapter.
Avista‟s main concern with any potential federal cap and trade legislation involves
compliance costs, an issue centering primarily, though not exclusively, on emission
allowances. Avista favors the Edison Electric Institute approach where half of the
allowances allocated to electric utilities are load-based and the other half are emissions-
based. This more equitable compromise would provide prevent a windfall for non-utility
generators with large historical greenhouse gas emissions at the expense of utilities,
like Avista, that already rely on non-emitting renewable energy. Administrative or direct
allocation, at least in the beginning of the program, is also favored because it will
mitigate compliance cost impacts on customers while the allowance markets and
emissions reductions technologies are developed.
There currently is no pending federal climate change legislation before Congress. In lieu
of comprehensive climate change legislation, early in 2011, President Obama endorsed
the idea of a Clean Energy Standard that would result in the nation deriving 80 percent
of its electricity by 2035 from renewable resources and lower greenhouse gas emitting
generation, such as natural gas-fired generation, “clean coal” generation with captured
and sequestered emissions, and nuclear power. Formal Clean Energy Standard
legislation has yet to be introduced in Congress. At the time this IRP was prepared,
members of the U.S. Senate had collected comments on a White Paper on a Clean
Energy Standard and Senator Jeff Bingaman (D-New Mexico) was drafting legislation in
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Avista Corp 2011 Electric IRP
coordination with the President‟s staff, which he said in early June 2011, likely would not
pass the Senate Energy and Natural Resources Committee. Even greater doubts exist
that such a proposal could pass the U.S. House of Representatives. Given that Clean
Energy Standard legislation in not likely to be enacted during 2011and 2012, Avista did
not model the Clean Energy Standard for this IRP.
The 111th Congress considered renewable energy standard legislation (RES), such as
the Waxman-Markey bill; (H.R. 2454) and S. 1462 by Senator Bingaman. Such
proposals contemplated a renewable energy standard of between 10 and 25 percent by
specific dates. These measures generally included a “hydro netting” provision; this
provision excludes loads served by hydropower energy from the RES requirement. For
example, if a utility has 1,000 aMW of load, a 10 percent RES goal, and 200 aMW of
hydroelectric generation; then the utility‟s RES goal would only be 80 aMW instead of
100 aMW because of the hydro-netting. Federal legislation has conceptually – and
significantly – differed from the Energy Independence Act (I-937) in Washington State,
in particular with respect to hydro-netting. The absence of hydro-netting in I-937 makes
the Washington law more restrictive than proposed federal renewable energy
requirements. Therefore, absent Idaho RPS legislation, Avista would need to meet only
the federal renewable energy requirements for its Idaho service territory. National
legislation so far also includes existing biomass generation resources, including Kettle
Falls, against the renewable energy standard, as well as power from upgrades to
hydropower facilities that were effectuated before 1999 (the date established in I-937 to
determine resource eligibility). Treatment of renewable resources in federal legislation
would not have allowed the Company to use renewable energy credits (RECs) from
resources that were only eligible under federal law, but not I-937, to comply with
Washington‟s renewable energy targets. However, Avista would be able to make REC
sales from federally eligible facilities into a national market and into states governed
solely by federal requirements (i.e., Idaho) and those states whose renewable energy
eligibility requirements are similar to federal ones. More details about I-937 are included
in the Washington policy consideration section 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 through the
end of 2012 for wind and through the end of 2013 for other renewable resources. We
did not model an extension of these tax incentives because of the uncertainty of their
continuation due to the current federal budget deficit situation. If extended, the PTC or
ITC may accelerate the development of some regional renewable energy projects to
meet the extended deadline.
State and Regional Level Policy Considerations
The failure of the federal government to enact greenhouse gas policies during the
current decade encouraged several states, such as California and New Mexico, to
develop their own climate change laws and regulations. Climate change legislation can
take many forms, including economy-wide regulation in the form of a cap and trade
system. However, comprehensive climate change policy can also have multiple
individual components, such as renewable portfolio standards, energy efficiency
standards, and emission performance standards; all of these standards have been
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
enacted in Washington, but not necessarily in other jurisdictions where Avista operates.
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 currently 29 states, including the District of Columbia, with active
renewable portfolio standards.
One of the more notable state-level greenhouse gas initiatives outside of the Pacific
Northwest include the Regional Greenhouse Gas Initiative (RGGI) agreement between
ten northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont)
to implement a cap and trade program for carbon dioxide emissions from power plants.
The District of Columbia, Pennsylvania, and some Canadian provinces are also
participating as RGGI observers. RGGI‟s cap and trade regulations have been effective
since January 2009. New Jersey‟s Governor Christie announced in May 2011 that he
was withdrawing his state from RGGI at the end of 2011. While the Governor still
endorsed the need to reduce greenhouse gas emissions, he argues that RGGI is not
the right mechanism for achieving reductions. Some claim that Governor Christie‟s
action may severely undermine the future prospects for RGGI.
The Western Regional Climate Action Initiative, otherwise known as the Western
Climate Initiative (WCI), began with a February 26, 2007, agreement to reduce
greenhouse gas emissions through a regional reduction goal and market-based trading
system. This agreement included the following signatory jurisdictions: Arizona, British
Columbia, California, Manitoba, Montana, New Mexico, Oregon, Utah, Quebec and
Washington. In July 2010, the WCI released its Final Design for a regional cap and
trade regulatory system to cover 90 percent of the societal greenhouse gas emissions
within the region by 2015. So far, the only state to enact legislation authorizing the
regulation of greenhouse gas emissions under a cap and trade system is California
(New Mexico adopted administrative regulations to regulate greenhouse gas emissions
in conjunction with other states, but it did so absent legislative authorization).
At the municipal level, there are several cities participating in the U.S. Mayors Climate
Protection Agreement to reduce GHG emissions to seven percent below 1990 levels by
2012.
A federal cap and trade program, such as that envisioned by the Waxman-Markey
legislation, will not operate in isolation. Members of the Western Climate Initiative, such
as Washington, Oregon, and Montana, can – as some of them have already – pursue
complementary policies to regulate emission sources covered under cap and trade
regulation, as well as those that will not be regulated under a cap and trade program.
The adoption of greenhouse gas goals and any associated regulations by Washington
could directly affect the Company‟s generation assets in the state, which are largely
comprised of the Kettle Falls Generating Station and the Northeast Combustion turbines
and Boulder Park peaking facilities. Oregon‟s greenhouse gas goals and potential future
regulations could apply to the Coyote Springs 2 project.
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Idaho Policy Considerations
Idaho is not a member of the Western Climate Initiative and currently does not regulate
greenhouse gases or have a renewable portfolio standard (RPS). However, the Idaho
Department of Environmental Quality will be administering greenhouse gas standards
under its Clean Air Act delegation from the EPA.
Montana Policy Considerations
Montana has a non-statutory goal to reduce greenhouse gas emissions to 1990 levels
by 2020. In 2007, the Legislature passed House Bill 25. This law requires that new coal-
fired facilities built in the state to sequester 50 percent of their emissions. Montana‟s
renewable portfolio standard 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. While involved in the Western Climate
Initiative, Montana has not considered any legislation to authorize its participation in and
implementation of WCI‟s regional cap and trade system. The Montana Department of
Environmental Quality does not handle regional haze issues affecting coal-fired
generation located in the state, as the agency does not have delegation under the
Clean Air Act to regulate regional haze. The federal EPA is responsible for the
application of regional haze criteria to the Colstrip coal-fired plants.
Montana had already implemented a mercury emission standard under Rule 17.8.771
that applies to Colstrip. The standard requires mercury reductions to 0.9 pounds per
trillion Btu beginning January 1, 2010. Avista‟s generation at Colstrip already has
emissions controls that meet Montana‟s mercury emissions goals.
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 reductions of greenhouse gas emissions to 10 percent below 1990
levels by 2020, and 75 percent below 1990 levels by 2050. These reduction goals are in
addition to 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 (CCCT) by paying into the Climate Trust of
Oregon. Senate Bill 838 created a renewable portfolio standard that requires large
electric utilities to generate 25 percent of annual electricity sales with renewable
resources by 2025. Intermediate term goals include five percent by 2011, 15 percent by
2015, and 20 percent by 2020. Oregon is an active member in the Western Climate
Initiative, but it has not passed the legislation necessary to implement the WCI‟s cap
and trade proposal. The Boardman Coal Plant, which is the only active coal-fired
generation facility in Oregon, plans to cease using coal by 2020. Portland General
Electric‟s decision to make near-term emissions control investments and to discontinue
the use of coal serves as an example of how regulatory, environmental, political and
economic pressure can culminate in an agreement that results in the early closure of a
low-cost coal-fired power plant.
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Washington State Policy Considerations
Circumstances similar to those that led to the close of the Boardman coal-fired facility in
Oregon encouraged the owners of the Centralia Coal Plant (TransAlta) 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 pressure
brought about the scheduled closure of the Centralia Plant. The State of Washington
enacted several measures concerning fossil-fueled generation emissions and
generation resource diversification. A law, enacted in 2004, requires new fossil-fueled
thermal electric generating facilities of more than 25 MW of generation capacity to
mitigate CO2 emissions through third party mitigation, purchased carbon credits, or
cogeneration. Washington‟s Energy Independence Act (I-937), was passed by the
voters 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 three percent of retail load by 2012, nine percent by 2016 and
15 percent by 2020. Failure to meet these RPS requirements results in a $50 per MWh
fine. The initiative also requires utilities to acquire all cost effective conservation and
energy efficiency measures. Additional details about the energy efficiency portion of I-
937 are located in the Energy Efficiency chapter.
Avista expects to meet or exceed its renewable requirements between 2012 and 2015
through a combination of qualified hydroelectric upgrades and renewable energy credit
(REC) purchases. The 2011 IRP Expected Case ensures that the Company meets all I-
937 RPS goals.
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 goals of this Executive Order became law when the Legislature enacted Senate Bill
6001 in 2007. This law prohibits electric utilities from entering into long-term financial
commitments beyond five years duration for fossil-fueled generation with greenhouse
gas emissions exceeding 1,100 pounds per MWh. Beginning in 2013, the emissions
performance standard can be lowered every five years to reflect the emissions profile of
the latest commercially available CCCT. The emissions performance standard
effectively prevents utilities from developing new coal-fired generation 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 generation that contain more
than 12 percent of the total power from unspecified sources. The Legislature further
amended Senate Bill 6001 in 2011 to allow long-term contracts for output from the
Centralia Coal Plant in conjunction with that plant making certain emission investments
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
and ceasing to use coal in 2020 for one unit and 2025 for the other unit. This law
change occurred after completion of the modeling for this IRP.
Taking the next step to achieve the State‟s greenhouse gas reduction goals, the
governor introduced legislation (Senate Bill 5735 and House Bill 1819) during the 2009
Legislative Session to authorize the Department of Ecology to adopt rules, consistent
from recommendations from the Western Climate Initiative, enabling the state to
administer and enforce a regional cap and trade program. When that legislation failed,
Governor Gregoire signed Executive Order 09-05 directing the Department of Ecology
to develop emission reduction “strategies and actions”, including complementary
policies, to meet Washington‟s 2020 emission reduction target by October 1, 2010. This
directive requires the agency to “provide to each facility that the Department of Ecology
believes is responsible for the emission of 25,000 metric tons or more of carbon dioxide
equivalent each year in Washington with an estimate of each facility‟s baseline
emissions and to designate each facility‟s proportionate share of greenhouse gas
emission reduction necessary to achieve the state‟s 2020 emission reduction” goal. The
department is also asked, by December 1, 2009, to develop emission benchmarks, by
industry sector, for facilities the Department of Ecology believes will be covered by a
federal or regional cap and trade program. The state may advocate the use of these
emission benchmarks in any federal or regional cap and trade program as an
appropriate basis for the distribution of emission allowances. The department must
submit recommendations regarding its industry benchmarks and their appropriate use to
the Governor by July 1, 2011.
Greenhouse Emissions Measurement and Modeling
Greenhouse gas tracking is an important part of the IRP modeling process because
emissions policy poses a significant risk to Avista. Reducing greenhouse gas emissions
from power plants will fundamentally alter the resource mix as society moves towards a
carbon constrained future. However, there are currently no federal laws limiting
greenhouse gas emissions, estimated costs still need to be projected for planning
purposes because expectations for greenhouse gas regulation can significantly alter
resource decisions.
Figure 4.1 shows the carbon price forecast for this IRP. The 2011 IRP assumes
greenhouse gas emissions policies will not take effect until 2015. To simulate the
expected impacts of greenhouse gas regulation, the Company developed four policy
models and estimated their assumed financial impact on the energy marketplace. Each
policy represents a potential path governments could take over the next several years.
We assigned weighting factors to each policy and the weighted average price of the
policies is included in the Expected Case. The four greenhouse gas policies used in this
IRP are defined in Table 4.1.
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Figure 4.1: Annual Greenhouse Gas
Table 4.1: Modeled Greenhouse Gas Policies
Regional
Greenhouse Gas
Policy
30 – Reductions in California, Oregon, Washington, and New
Mexico between 2014 and 2019.
– Shifts to National Climate Policy in 2020.
National Climate
Policy
30 – Federal legislation only applies beginning in 2015
– About 15 percent below 2005 levels by 2020 and about
35 percent below 2005 levels by 2030.
National Carbon
Tax
30 – Federal legislation only applies beginning in 2015.
– $33 per short ton, then 5 percent per year escalation for
the remainder of the study.
No Greenhouse
Gas Reductions
10 – No carbon reduction program.
– State-level emission performance standards apply and
no new coal-plants are added in the Western U.S.
The Regional Greenhouse Gas policy simulates the decision by several western states
to require greenhouse gas reductions under the auspices of the Western Climate
Initiative (WCI) because a national policy has not been enacted. This policy does not
include all of the WCI members because some states have enacted little, if any,
legislation to allow their states to participate in the WCI cap and trade market. This
policy begins in 2014 and is restricted to California, New Mexico, Oregon and
0
50
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National Cap & Trade
National Carbon Tax
Regional Carbon Policy
No Carbon Policy
Expected Case
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Washington. The policy is superseded in 2020 by a National Climate Policy, described
below. The Regional Greenhouse Gas Policy results in a 10 percent reduction of
electric generation greenhouse gas emissions below 2005 levels by 2020. Projected
prices start at $5 per short ton of CO2 in 2014 and escalate by $1 per year up to $9 per
short ton in 2019. All greenhouse gas measurements and costs in this chapter are in
short tons. In 2020, when the policy switches to a national focus, the price starts at $15
and escalates to $73 per ton in 2030. This policy was weighted by 30 percent in the
model.
The National Climate Policy begins in 2015. This scenario assumes no state level cap
and trade programs. The greenhouse gas emissions reductions are about 15 percent
below 2005 levels by 2020 and about 35 percent below 2005 levels by 2030. Prices
start at $15 per ton in 2015 and escalate to $115 per ton in 2030. This policy was
weighted 30 percent in the model.
The design of the National Carbon Tax Policy loosely resembles the carbon tax in
British Columbia and shows some of the implications of moving to a tax instead of a cap
and trade program. The tax would start in 2015 at the national level and would
supersede any state-level greenhouse gas cap and trade programs. The tax starts at
$33 per ton in 2015 and increases to $69 in 2030. This policy was weighted 30 percent
in the model.
The No Greenhouse Gas Reductions Policy is an unconstrained carbon case where
there are no national or state-level greenhouse gas emissions reductions policies. This
policy was included because there is a small probability of no greenhouse gas taxes or
cap and trade program being instituted. This policy is also necessary to be able to
determine the cost of the other greenhouse policies, since there is the actual cost of a
tax or a credit, plus the additional cost of a less greenhouse gas intensive resource
portfolio. Even though this unconstrained carbon policy does not have any national or
state-level greenhouse gas policies, state-level emissions performance standards are
still applied and no new coal plants were allowed in the model. This policy received a 10
percent weighting in the model.
We also considered the addition of a regulatory model, to represent in spirit of the
direction the EPA is using through the Clean Air Act and through other EPA actions that
are fostering the early closing of coal-fired plants, such as Boardman and Centralia.
These actions include regional haze, mercury abatement, cash ash handling and
disposal, among others. The unique nature of each coal-fired facility, combined with the
different political and environmental climates in each of the western states, made this
type of policy too complex to model at this time. Future IRPs may include some of these
EPA-related regulations as they are developed.
Figure 4.2 shows the greenhouse gas emissions costs per short ton under each of the
policies and under the Expected Case.
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP
Figure 4.2: Price of Greenhouse Gas Credits in each Carbon Policy
$0
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Delayed National Climate Policy
National GHG Tax
No GHG Reductions
Expected Case
Regional GHG Policy
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-1
5. Transmission & Distribution
Introduction
This chapter describes Avista’s transmission system, completed and planned upgrades,
transmission planning issues, and estimated costs and issues of new generation
resource integration.
Coordinating transmission system operations and planning activities among regional
transmission providers is necessary to maintain reliable and economic transmission
service for Avista customers. Transmission providers and interested stakeholders
continue to modify the region’s approach to planning, constructing, and operating the
transmission system under Federal Energy Regulatory Commission (FERC) rules, and
state and local siting agencies guidance. This chapter complies with Avista’s FERC
Standards of Conduct compliance program governing communications between Avista
merchant and transmission functions.
Avista’s Transmission System
Avista owns and operates a system of over 2,200 miles of electric transmission
facilities. This includes approximately 685 miles of 230 kilovolt (kV) line and 1,527 miles
of 115 kV line. Figure 5.1 illustrates the Company’s transmission system. The Company
owns an 11 percent interest in 495 miles of a 500 kV line between Colstrip and
Townsend, Montana. The transmission system includes switching stations and high-
voltage substations with transformers, monitoring and metering devices, and other
system operation-related equipment. The system transfers power from Avista’s
generation resources to its retail load centers. Avista also has network interconnections
with the following utilities:
Bonneville Power Administration (BPA)
Chelan County PUD
Grant County PUD
Idaho Power Company
NorthWestern Energy
PacifiCorp
Pend Oreille County PUD
Chapter Highlights
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-2
Figure 5.1: Avista Transmission Map
Network interconnections enhance reliability and serve as points of receipt for power
from generating facilities outside of a utility service area. Avista has interconnections to
deliver its Colstrip, Coyote Springs 2, Lancaster, Washington Public Power Supply
System Washington Nuclear Plant No. 3 settlement contract, and Mid-Columbia
contract power. Avista serves various wholesale loads using government-owned and
cooperative utility interconnections at transmission and distribution voltage levels.
Recent Transmission Improvements
Since the 2009 IRP, Avista made the following transmission enhancements:
Added a 115 kV capacitor bank at Grangeville;
Installed new 115 kV substation and transmission integration equipment at Idaho
Road;
Replaced a failed transformer at the Avondale 115 kV substation;
Reconstructed the 115 kV switchyard and distribution substation, and added a
capacitor bank to the Nez Perce 115 kV substation;
Reconductored the Airway Heights to North Fairchild line section of the Airway
Heights - Silver lake 115 kV line,
Installed a new capacitor bank at the Airway Heights substation; and
Reconductored selected portions of the Moscow area 115 kV system.
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-3
Future Upgrades and Interconnections
Station Upgrades
As reported in the 2009 IRP, Avista planned to upgrade its Moscow, Noxon, Pine Creek
and Westside 230 kV substations. These stations have undersized transformers, do not
provide 21st century reliability, and are near the end of their useful lives. The Moscow
station upgrades, scheduled for completion in 2014, will result in a new facility with a
single 250 MVA 230/115 kV station using a double bus-double breaker configuration for
230 kV service. The 115 kV yard is in a breaker-and-a-half configuration. Over the next
five to 10 years, the three remaining stations will be upgraded. Beyond these, plans
exist for several new 115 kV capacitor banks throughout Avista’s transmission system in
the near future.
Transmission Upgrades
Avista plans to complete several 115 kV reconductor projects throughout its
transmission system over the next decade. These projects focus on replacing decades-
old small conductor with conductor capable of greater load-carrying capability and more
efficient (i.e., fewer electrical losses) service. A future IRP will discuss these savings
and timeline after further analysis is completed.
South Spokane 230 kV Reinforcement
Transmission studies continue to support a need for an additional 230 kV line to the
south and west of Spokane. Avista currently has no 230 kV source in these areas, and
instead relies on its 115 kV system for load service as well as bulk power flows through
the area. The project scope is under development, and preliminary studies indicate the
need for the following (or similar) projects:
A new 230/115 kV station near Garden Springs. Property acquisition for the
Garden Springs station and preliminary geo-technical station design work has
commenced;
Tap of the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and
construction of a new 230 kV switching station (for later development of a
230/115 kV substation); alternatively, reconstruction of the 115 kV circuits
between Beacon and Ninth & Central, and the installation of a 230/115 kV station
at that site could be pursued;
Connecting the Liberty Lake 230 kV station with the Garden Springs 230 kV
station; alternatively, connecting the Ninth & Central station to the Garden
Springs station;
Construction of a new 230 kV line from Garden Springs to Westside; and
Origination and termination of the 115 kV lines from the new Spokane 230/115
kV station(s).
The South Spokane 230 kV Reinforcement project will be scoped by the end of 2012
with planned energization by the end of 2018. The project will enter service in a staged
fashion beginning in 2014
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-4
Additional Work Required from the Avista Five and Ten-Year Plans
Following are examples of additional improvements to the Avista System in the next five
to ten years. Since load growth rates in the various areas of the system are unknown,
items presently on the list may or may not occur in this timeframe; more certainty is
gained as time passes.
West Plains 115 kV Reinforcement
Irvin 115 kV Project
Glenrose Tap – Ninth and Central 115 kV line
Beacon 230/115 kV Station Partial Rebuild
New Distribution Stations:
o Otis Orchards (2011)
o Hillyard (2013)
o Hawthorne (2013)
o North Moscow Additional Transformer (2013)
o Spokane Downtown West (2014)
o Greenacres (2014)
Canada/Northwest/California 500 kV Transmission Project (CNC) and Devils Gap
500/230 kV Interconnection
The Transmission Coordination Work Group (TCWG, see below) continues to evaluate
a new transmission line involving four major projects.
500 kV high voltage alternating current facilities from Selkirk in southeast British
Columbia to the proposed Northeast Oregon (NEO) Station, with an intermediate
interconnection with Avista at a new Devils Gap Substation, located near
Spokane;
500 kV high voltage AC or high voltage direct current facilities running from the
NEO Station to the Collinsville Substation in the San Francisco Bay Area;
Interconnection near Cottonwood Substation in northern California (a direct
current segment);
Voltage support at the interconnecting substations; and
Remedial actions for project outages.
The Canada-Northwest-California (CNC) project would allow access to new renewable
resources in the Pacific Northwest, Canada, and, at times, the southwestern United
States. Immediate and future environmental and resource needs of Avista and other
Western interconnected utilities could be aided by this project. Further, Avista expects
the project will increase the utilization of its existing transmission facilities. Through its
participation in TCWG and other regional and sub-regional forums, Avista makes all
project information available to group members, including resource developers, load
serving entities, energy marketers, and independent transmission owners.
The CNC project continues to move forward with an altered set of ownership
assumptions. The ultimate project size has not been determined. In late 2010, the CNC
project was bifurcated into a northern section and a southern section. BC Hydro has
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-5
taken responsible for the northern segment, comprised of the 500 kV interconnection
between Selkirk and the proposed NEO station. The northern segment could be a
double circuit 500 kV AC line with 3,000 MW of transfer capability, or a single circuit 500
kV AC line with 1,500 MW of capacity. Preferred line routing for the northern segment
remains the ―eastern route‖, this would utilize the Avista Addy-Devils Gap 115 kV line
corridor. A 500 MVA bi-directional 500/230 kV phase shifted interconnection between
the CNC project and Avista’s transmission system remains the preferred option and
would be the major impact to Avista.
The scope of the southern portion of the project has been reduced from a nominal 3,000
MW of transfer capability to 2,000 MW. Much work remains to determine if the southern
portion should be an alternating current or a direct current line, and whether brownfield
development (replacement of existing transmission with higher voltage and/or higher
capacity facilities) can be accomplished while maintaining reliable system operation.
Pacific Gas and Electric (PG&E) is no longer leading the southern segment project; the
Western Area Power Administration (WAPA) has assumed its leadership.
Regional Transmission System
BPA owns and operates most of the regional transmission system in the Pacific
Northwest. The federal entity operates over 15,000 miles of transmission-level facilities
throughout the Pacific Northwest and owns the largest portion of the region’s high
voltage (230 kV or higher) transmission grid. Avista uses BPA transmission to transfer
output from its remote generation sources to Avista’s transmission system, including its
Colstrip units, Coyote Springs 2, Lancaster and its Washington Public Power Supply
System Washington Nuclear Plant No. 3 settlement contract. Avista also contracts with
BPA for Network Integration Transmission Service to transfer power to 10 delivery
points on the BPA system to serve portions of the Company’s retail load.
The Company participates in the BPA transmission and rate case processes, and in
BPA’s Business Practices Technical Forum, to ensure charges remain reasonable and
support system reliability and access. Avista also works with the BPA and other regional
utilities to coordinate major transmission facility outages.
Future development likely will require new transmission assets by federal and other
entities. BPA is developing several transmission projects in the Interstate 5 corridor, as
well as projects in southern Washington that are necessary for integration wind
generation resources located in the Columbia Gorge. Each project has the potential to
increase BPA transmission rates and thereby affect Avista’s costs.
FERC Planning Requirements and Processes
The Federal Energy Regulatory Commission (FERC) provides guidance to both regional
and local area transmission planning. This section describes several requirements and
processes of the federal regulator important to Avista’s transmission planning.
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-6
Attachment K
FERC approved Attachment K to Avista’s Open Access Transmission Tariff (OATT).
The attachment satisfies nine transmission principles in FERC Order 890 ensuring open
planning processes, and formalizes coordination of local, regional, and sub-regional
transmission planning.
Avista regularly develops a biannual Local Planning Report (in coordination with Avista's
five- and ten-year Transmission Plans). Avista encourages participation of its
interconnected utilities, transmission customers, and other stakeholders in the Local
Planning Process.
The Company uses ColumbiaGrid to coordinate planning with sub-regional groups.
Regionally, Avista participates in several Western Electricity Coordinating Council
(WECC) processes and groups, including Regional Review processes, Transmission
Expansion Planning Policy Committee (TEPPC), Planning Coordination Committee
(PCC), and the newly formed Transmission Coordination Work Group (TCWG).
Participation in these efforts supports regional coordination of Avista's transmission
projects.
Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) coordinates and promotes
electric system reliability in the Western Interconnection. It also supports efficient and
competitive power markets, assures open and non-discriminatory transmission access
among its members, provides a forum for resolving transmission access or capacity
ownership disputes, and provides an environment for coordinating the operating and
planning activities of its members as set forth in WECC Bylaws. Avista participates in
WECC’s Planning, Operations, and Market Interface Committees, as well as various
sub groups and other processes such as the TCWG.
Northwest Power Pool
Avista is a member of the Northwest Power Pool (NWPP). Formed in 1942 when the
federal government directed utilities to coordinate operations in support of wartime
production, NWPP committees include the Operating Committee, the Pacific Northwest
Coordination Agreement (PNCA) Coordinating Group, and the Transmission Planning
Committee (TPC). The TPC exists as a forum addressing northwest electric planning
issues and concerns, including a structured interface with external stakeholders.
The NWPP serves as an electricity reliability forum, helping to coordinate present and
future industry restructuring, promoting member cooperation to achieve reliable system
operation, coordinating power system planning, and assisting the transmission planning
process. NWPP membership is voluntary and includes the major generating utilities
serving the Northwestern U.S., British Columbia and Alberta. Smaller, principally non-
generating, utilities participate in an indirect manner through their member systems,
such as the BPA.
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-7
ColumbiaGrid
ColumbiaGrid formed on March 31, 2006 to develop sub-regional transmission plans,
assess transmission alternatives (including non-wires alternatives), provide a decision-
making forum, and to provide a cost-allocation methodology for new transmission
projects. This group formed in response to several FERC initiatives. Avista joined
ColumbiaGrid in early 2007. The ColumbiaGrid agreements help different organizations
and groups determine areas of transmission work, and establish agreements to carry
out the plans.
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. NTTG members coordinate with state governments to manage their
transmission system operations, products, business practices, and high-voltage
transmission network planning to meet and improve transmission delivery services.
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 is evaluating membership in
NTTG to foster collaborative relationships with our interconnected utilities.
Transmission Coordination Work Group
The Transmission Coordination Work Group (TCWG) is a joint effort of Avista, BPA,
Idaho Power, Pacific Gas and Electric, PacifiCorp, Portland General Electric, Sea
Breeze Pacific-RTS, and TransCanada to coordinate transmission project
developments expected to interconnect at or near a proposed Northeast Oregon station
near Boardman, Oregon. These projects follow WECC Regional Planning and Project
Rating Guidelines. Detailed information on projects presently under consideration is at
www.nwpp.org/tcwg.
Most of the projects developed through the TCWG transferred to their own Project
Review Groups, placed on hold, or terminated. The TCWG work effort has been
significantly reduced over the past year because of the number of terminated and on-
hold projects.
Avista Transmission Reliability and Operations
Avista plans and operates its transmission system pursuant to applicable criteria
established by the North American Electric Reliability Corporation (NERC), WECC and
NWPP. Through involvement in WECC and NWPP standing committees and sub-
committees, it participates in developing new and revised criteria, and coordinates
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. Portions of Avista’s
transmission system are fully subscribed for retail load service. Transmission capacity
not reserved and scheduled to move power to satisfy long-term (greater than one year)
obligations is marketed on a short-term basis and used by Avista for short-term
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-8
resource optimization or by third parties seeking short-term transmission service
pursuant to FERC requirements under Orders 888, 889 and 890.
Transmission Construction Costs
The following sections provide an overview of Avista’s estimated resource integration
costs for the 2011 IRP. Integration points are divided into locations where
interconnection study work has been completed and additional points where new
resources might be interconnected. Rigorous analyses are not performed for off-system
alternatives because of the breadth of study needed for those estimates. Limited study
work has been completed, except for projects with existing generation interconnection
requests to Avista’s transmission group. Completing transmission studies without
detailed project parameters is nearly impossible (and any decisions based on such work
would be flawed) and it is therefore inappropriate to represent any figures as more than
preliminary. Approximate worst-case estimates were developed based on engineering
judgment for neighboring system impacts. Generation interconnection costs are for
locations within the Avista transmission system. Internal cost estimates are in 2011
dollars and using engineering judgment with a 50 percent margin for error. Construction
timelines are from the beginning of the permitting process to line energization.
Integration of Resources External to the Avista System
Avista’s load serving entity function must submit generation interconnection and
transmission service requests on third party transmission systems. The third party
determines transmission system integration and wheeling service costs for delivering
new resource power to Avista’s system.
At BPA’s present wheeling rate, integrating 300 MW (assuming the transmission service
were available from the off system resource to the Avista transmission system) would
cost about $4.4 million per year plus $2.5 million per year for line losses.
It is likely that the Company would invest $50 million for a 300 MW resource to increase
capacity to third-party transmission systems. These investments may not need to be
made at the time of interconnect, but will have to be upgraded in time to maintain
FERC’s market power requirements and maintain present levels of access to the energy
market. If Avista acquires a resource located on a third-party network, detailed studies
will need to be completed to understand system impacts.
Eastern Montana Resources
A regional study sponsored by the NWPP and Northwest Transmission Assessment
Committee (NTAC) found that enhancement of existing 500 kV and 230 kV facilities
would be required to integrate additional generation from Montana. Power transfer from
eastern Montana to the Northwest is affected by several constraints. A more detailed
study effort focusing on relieving constraints from central and eastern Montana
continues as a joint effort by Avista, BPA, NorthWestern Energy, PacifiCorp, and Puget
Sound Energy. Preliminary results indicate that perhaps as much as 480 MW of
additional transfer from Montana can be achieved, however engineering-level
construction cost estimates to fix constraints within the various transmission systems
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
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have not yet been completed. It should also be noted that various facilities in the Avista
transmission system would need to be upgraded to achieve this additional transfer.
Integration of Resources on the Avista Transmission System
The Avista-LSE requested a number of generator interconnection studies in several
areas of the Avista transmission system for the 2011 IRP. The following project and cost
information was presented at the Third Technical Advisory Committee meeting on
December 2, 2010, these cost estimates are presented in Table 5.1.
Table 5.1: New Resource Integration Costs
Location Notes
Size
(MW)
Cost
($ millions)
West of Spokane, WA No transmission additions 4 0
West of Spokane, WA Requires new 115 kV line 75 15
West of Spokane, WA Requires two new 230 kV lines 254 30-55
Benewah, ID No transmission additions 300 5
Rosalia, WA No transmission additions 300 8
Rathdrum, ID Requires generation dropping 300 5
Rathdrum, ID Requires generation dropping 400 5
Othello, WA No transmission additions 17 0
Othello, WA Requires new 115 kV line and
substation1
100 13-25
Othello, WA Requires new 230 kV line and
substation
250 21-32
Sandpoint, ID Depends on BPA interconnection 50 2-5
Sandpoint, ID Cost prohibitive and not studied 100 N/A
Cabinet Gorge, ID 115 kV reconductor 60 2-10
Spokane, WA Monroe Street hydro project 20 3
Spokane, WA Monroe Street hydro project 60 3
Post Falls, ID Post Falls hydro project 14 1
Spokane, WA Upper Falls hydro project 14 1
After the completion of the IRP’s Preferred Resource Strategy and the preference for
nearly 500 MW of natural gas capacity in North Idaho. The Resource Planning group
requested further study work on specific transmission lines for a more detailed cost of
interconnection. This study is in Appendix E. The study shows that in most locations,
potential plants can be integrated at similar costs as presented in Table 5.1 as long as a
RAS system (generation dropping) is in place. The study further identifies the cost of
adding additional network facilities so a RAS system is no longer required.
1 Note that the 100 MW estimate is for 115 kV integration, and the 250 MW estimate is for 230 kV
integration, and does not include mitigation of contractual constraints on the Avista 230 kV system in the
area.
Chapter 5 – Transmission & Distribution
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Lancaster Integration
Avista has proposed and evaluated an interconnection with BPA at its Lancaster
Substation. Avista and BPA have determined that the preferred alternative is to loop the
Avista Boulder-Rathdrum 230 kV line into the BPA Lancaster 230 kV station. This
interconnection will allow Avista to eliminate or offset BPA wheeling charges for moving
the output from Lancaster to Avista’s system. Besides reduced transmission payments
to BPA by Avista, the interconnection benefit both Avista and the BPA by increasing
system reliability, decreasing losses, and delaying the need for additional transformation
at the BPA Bell Substation. The proposed plan of service also represents the best
option for service from Avista’s sole perspective. Studies also indicate that looping the
Boulder-Rathdrum 230 kV line into the Lancaster Substation may allow more transfer
capability across the combined transmission infrastructure of Avista and BPA. The
present Colstrip Upgrade Project study indicates that all of the upgrades (from AVA,
BPA, and NWE) could increase the Montana to Northwest path by as much as 800
MW—the associated projects include much more than the Lancaster loop-in work.
Construction on the Lancaster project could be completed by the end of 2012 or at
some point in 2013, depending on BPA’s construction schedule. Avista is working
closely with BPA to assure the timely construction of the BPA facilities required to
facilitate this interconnection.
Distribution Efficiencies
Avista delivers electrical energy from generators to customer meters through a network
of conductors (links) and stations (nodes). The network system is operated at different
voltages depending upon the distance the energy must travel to reduce current losses
across the system. A common rule to determine efficient energy delivery is one kV per
mile. For example, a 115 kV power system commonly transfers energy over a distance
of 115 miles while 13 kV power systems are generally limited to delivering energy 13
miles.
Avista’s categorizes its energy delivery systems between transmission and distribution
voltages. Avista’s transmission system operates at 230 kV and 115 kV nominal
voltages. Avista’s distribution system operates between 4.16 kV and 34.5 kV, but
typically at 13.2 kV in its urban service centers. In addition to voltages, the transmission
system operates distinctly from the distribution system. For example, the transmission
system is a network linking multiple sources with multiple loads, while the distribution
system configuration uses radial feeders to link a single source to multiple loads.
System Efficiencies Team
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 (T&D) 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.
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
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Distribution Feeders
Avista’s distribution system consists of approximately 330 feeders covering 30,000
square miles. The feeders range in length from three to 73 miles. For rural distribution,
feeder lengths vary widely to meet the electrical loads resulting from the startup and
shutdown business swings of the timber, mining and agriculture industries.
The system efficiencies team evaluated several efficiency programs across the urban
and rural distribution feeders. The programs consisted of the following system
enhancements:
Conductor losses;
Distribution Transformers;
Secondary Districts; and
Var compensation.
The energy losses, capital investments, and reductions in operations and maintenance
(O&M) costs resulting from the individual efficiency programs under consideration were
combined on a per feeder basis. This approach provided a means to rank and compare
the energy savings and net resource cost for each feeder.
Economic Analysis
Prior to the 2009 IRP an economic analysis was performed to determine the net
resource costs to upgrade each feeder for the four program areas listed above. The net
resource cost determines the avoided cost of a new energy resource levelized over the
asset’s life cycle expressed in dollars per megawatt. This economic value is calculated
by estimating the capital investment, energy savings, and avoidance of operations and
maintenance (O&M) and interim capital investments resulting from feeder upgrades.
The O&M avoided costs for upgrades were determined by modeling existing feeders in
the Availability Workbench program. This program is an expected value model
combining a weighted average time and material cost of equipment failure with the
probability of failure. The distribution feeder’s conductor, transformers, and ancillary
equipment were used to develop the failure model for each studied feeder. Customer,
material and labor costs incurred by outages, and equipment failure were the
parameters used to measure the economic risk of a failure. The results were calibrated
to the expected value model by industry indexes and Avista’s actual outage history.
Many of the projects found to be cost effective in the study are now a part of the grid
modernization project discussed below. There were 60 feeders remaining for potential
re-builds and based upon preliminary energy and O&M savings estimates. All appear
cost effective. However, these projects need further study to develop detailed cost and
energy savings estimates, further improved reliability and replacing aging infrastructure
may also contribute to the decision to proceed with rebuild projects. Based on the
preliminary cost and energy estimates shown in Figure 5.2, losses could be reduced by
6.1 aMW by the end of the IRP planning period.
Grid Modernization
Avista is investing in grid modernization technology with the aid of three federal grants
promoting the development of grid modernization applications. These grants require the
Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-12
Company to invest in grid modernization training and grid improvement. The following is
a discussion of the programs, and the progress of the investment. Figure 5.2
summarizes projected energy savings for Grid Modernization (Smart Grid) and
Distribution Feeder Rebuild projects over the 20-year IRP planning period. Table 5.2
shows the projected loss savings for 2012 and 2013.
Figure 5.2: Cumulative Distribution Loss Savings from Grid Modernization and
Feeder Upgrades
Washington’s Energy Independence Act targets for energy efficiency capture first year
energy savings. Avista will capture the first year energy savings entirely in the year
when the assets are placed in service. The Evaluation, Measurement and Verification
process will focus on the 12-month period extending forward from the date assets are
place in service.
Table 5.2: Distribution Loss Energy Savings (MWh)
Location 2012 2013
Smart Grid 34,839 6,477
Distribution Feeders 1,626 4,351
Total 36,465 10,828
Smart Grid Workforce Training Grant
Avista received a three-year, $1.3 million government grant to invest in facility and
training programs to educate workers for developing, managing, and maintaining the
future grid. Workers are trained at the Jack Stewart Training Center, working in a model
neighborhood and substation to learn about grid modernization technology. Avista is
also developing a curriculum for local universities and an online portal to provide
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Chapter 5 – Transmission & Distribution
Avista Corp 2011 Electric IRP
5-13
training opportunities outside of the organization. Another goal of this grant is to share
best practices on Smart Grid training.
Smart Grid Investment Grant (SGIG)
The $20 million Smart Grid Investment Grant (SGIG) covers investment to the Spokane
area grid improvement project. This project includes upgrades for 59 circuits, 14
substations, and 110,000 electric customers. Avista is contributing $42 million dollars to
this project to automate the system. 42,000 MWh or 4.8 aMW of loss savings are
expected. Conservation Voltage Reduction (CVR) makes up 83 percent of the loss
savings. This project will enable Avista to remotely control and operate the distribution
system through a series of wireless controls and fiber communication between
switches, reclosers, capacitor banks, and voltage regulators. The Distribution
Management System will remotely operate the system and will be able to automatically
detect and restore faults.
Smart Grid Demonstration Project (SGDP)
Avista is a partner in the regional Smart Grid Demonstration Project (SGDP). Avista is
using an $18.9 million government grant to employ grid modernization technology in
Pullman, Washington, as part of the Pacific Northwest Smart Grid Demonstration
Project. Avista is contributing $14.9 million to the Pullman project and other parties are
contributing an additional $4.0 million. The partners are Itron, HP, Washington State
University, and Spirae. This project encompasses 13 circuits, three substations, and
includes network automation. The project involves replacement of 14,000 electric and
6,000 natural gas meters with digital meters with wireless communication. Customers
with these new meters will be able to use a web portal to track energy usage in near
real time. This project should reduce system losses by 6,763 MWh.
Feeder Rebuild Program
Beginning in 2012, Avista will begin rebuilding distribution feeders to capture energy
savings from reducing losses, increase reliability, and decrease future O&M costs. In
2012, the Company will begin work on three feeders; the feeders include BEA12F1 and
F&C12F2 (urban feeders located in Spokane) and a rural feeder in Wilbur, Washington
(WIL12F2).
As an example, an 11-mile section of the Wilbur feeder (WIL12F2) was chosen as one
of the initial feeder upgrades because of reliability and operational deficiencies. The
Wilbur feeder has several issues. The small diameter conductor sags at unacceptable
levels during frequent icing events in the area. The high impedance of this conductor
also increases the difficulty of determining where faults occur. The average age of the
transformers being replaces is over 50 years. Finally, this feeder is also difficult to repair
quickly because of its remote location. Over the last five years, the feeder has averaged
50 outages per year with a 400-minute average outage duration.
The 2012 feeder rebuilds will be completed between June and December 2012 and we
expect to reduce losses by 1,626 MWh annually. The schedule of feeders has yet to be
determined for 2013, but will likely include five or six feeder upgrades for approximately
3,325 MWh of expected loss savings annually. These estimates range between plus or
minus 30 percent depending on construction scheduling, feeder selection, load levels,
and other factors. The ultimate scope and timing of the feeder rebuild programs will
Chapter 5 – Transmission & Distribution
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depend on the actual results of the first several feeder rebuild projects and on the
availability of resources and operational needs of the Company.
Transmission Topologies and Distribution Feeder Sizing
Avista is planning a new modeling system that will incorporate transmissions topology,
station locations and load growth. Historically, Avista’s power grid was designed and
built to adhere to reliability and capacity guidelines resulting in the lowest upfront cost.
This approach was reasonable considering the low electricity costs of that time. As the
cost of energy increases, life cycle economic analyses are warranted to evaluate power
system losses corresponding to different power grid configurations.
The new and comprehensive analysis will review several different transmission
topologies to determine the most efficient configuration for moving bulk power through
and by Avista’s system. The transmission topologies will consider the efficiency
between star network, hub and loop, southern loop and southern source. Avista’s load
service will be incorporated in this analysis by determining ideal substation placement
and feeder sizes as well as forecasted load growth. The comprehensive analysis will
evaluate many of the items listed below.
Develop a performance criteria to determine system measures;
Develop a base case to measure existing system performance;
Develop a methodology to determine a full build out load case;
Identify reasonable transmission topologies for evaluation;
Identify reasonable guidelines for substation placement;
Identify reasonable guidelines for distribution feeder sizes; and
Bound the analysis to ensure the system remains reliable, compliant, and
operationally flexible.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
6. Generation Resource Options
Introduction
There are many generating resource options available to meet future resource deficits.
Avista can upgrade existing resources, build new facilities, or contract with other energy
companies for future delivery. This section describes the resources considered to meet
future resource needs. The new resources described in this chapter are mostly generic.
Actual resources may differ in size, cost, and operating characteristics due to siting or
engineering requirements.
Assumptions
For the Preferred Resource Strategy (PRS) analysis, Avista only considers
commercially available resources with well-known cost, availability and generation
profiles. These resources include gas-fired combined cycle combustion turbines
(CCCT), simple cycle combustion turbines (SCCT), large-scale wind, and certain solar
technologies proven on a large-scale commercial basis. Several other resource options
described later in the chapter were not included the PRS analysis, but their costs were
estimated for comparative analysis.
Levelized costs referred to throughout this section are at the generation busbar. The
nominal discount rate used in the analyses is 6.8 percent. Nominal levelized costs result
from discounting nominal cash flows at the rate of general inflation.
Renewable resources eligible for federal tax incentives receive such incentives based
on the current federal law. Wind benefits end in 2012; solar tax benefits end in 2016,
and all other renewable benefits end in 2013. The levelized costs in this chapter
assume maximum available energy for each year instead of expected generation. For
example, wind generation assumes 31 percent availability, CCCT generation assumes
90 percent availability, and SCCT generation assumes 92 percent availability. The
following are definitions for the levelized cost components used in this chapter:
Section Highlights
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Capital Recovery and Taxes: Includes depreciation, return on capital, income
taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
generation asset investment.
Allowance for Funds Used During Construction (AFUDC): The cost of money for
construction payments before the utility can recover costs of prudently acquired
generation resources.
Federal Tax Incentives: The estimated federal tax incentive (per MWh), whether
in the form of a production tax credit (PTC), a cash grant, or an investment tax
credit (ITC), attributable to certain generation options.
Fuel Costs: The cost of fuels such as natural gas, coal, or wood per the efficiency
of the generator. Additional details on fuel prices are in the Market Modeling
section.
Fuel Transport: The cost to transport fuel to the plant, including pipeline capacity
charges.
Greenhouse Gas Emissions Adder: Cost of carbon dioxide (greenhouse gas)
emissions based on Wood Mackenzie forecast.
Fixed Operations and Maintenance (O&M): Costs related to operating the plant
such as labor, parts, and other maintenance services (pipeline capacity costs are
included for CCCT resources) that are not based on generation levels.
Variable O&M: Costs per MWh related to incremental generation.
Interconnection Capital Recovery: Includes depreciation, return on capital,
income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
transmission asset investments needed to interconnect the generator.
Excise Taxes and Other Overheads: Includes miscellaneous charges for non-
capital expenses.
At the end of this section, various tables show Incremental capacity, heat rates,
generation capital costs, fixed O&M, variable costs, and peak credits.1 Figure 6.2 shows
the levelized costs of different resource types in comparison. All costs shown in this
section are in nominal dollars unless otherwise noted. Further information on the plant
assumptions used in this section is in the Northwest Power and Conservation Council’s
(NPCC) Sixth Power Plan.
1 Peak credit is the amount of capacity a resource contributes at the time of system peak load.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Gas-Fired Combined Cycle Combustion Turbine (CCCT)
Gas-fired CCCT plants provide a reliable source of both capacity and energy for a
relatively inexpensive capital investment. The main disadvantage is generation cost
volatility due to a reliance on natural gas.
CCCTs in this IRP are of a “one-on-one” (1x1) configuration, using both water- and air-
cooling technologies. The 1x1 configuration consists of a single gas turbine, a single
heat recovery steam generator (HRSG), and a duct burner to gain more generation from
the HRSG. These plants have nameplate ratings between 250 MW and 300 MW each.
A “2x1” CCCT plant configuration is possible with two turbines and one HRSG,
generating up to 600 MW. The most likely CCCT configuration for Avista is a 270 MW
air-cooled plant located in the Idaho portion of Avista’s service territory. Potential sites
for a future combined cycle plant would likely be on the Avista transmission system to
avoid third-party wheeling rates. Another advantage of siting a CCCT resource in
Avista’s service territory is access to a low cost natural gas pipeline and fuel sources.
Within Avista’s area, siting decisions then come down to choosing the state to locate a
new plant. Most of Avista’s load is in Washington, but the state’s natural gas excise tax
and carbon dioxide mitigation requirements place a gas-fired plant at an economic
disadvantage relative to siting the same plant in an adjoining state. Siting a CCCT in
Idaho economically benefits ratepayers with a lower sales tax rate, the absence of a
natural gas excise tax, and no fees for carbon dioxide mitigation.
Cost and operational estimates for CCCTs modeled in the IRP use data from the
NPCC’s Sixth Power Plan, but adjusted to reflect air-cooled technology costs by
Avista’s engineering staff. The heat rate modeled for an air-cooled CCCT resource is
6,925 Btu/kWh in 2012. The projected CCCT heat rate falls by 0.5 percent annually to
reflect an allowance for anticipated technological improvements. The plants include
seven percent of rated capacity as duct firing at a heat rate of 9,690 Btu/kWh. If Avista
were able to site a water-cooled plant, the heat rate would likely be two percent lower
and net plant output might increase by five MW.
The IRP models forced outages at six percent per year, with 21 days of annual plant
maintenance. CCCT plants are capable of backing down to 65 percent of nameplate
capacity, and ramping from zero to full load in four hours. Carbon dioxide emissions are
117 pounds per decatherm of fuel burned. The maximum capability of each plant is
highly dependent on ambient temperature and plant elevation. For modeling, winter
capability is likely to increase by 4 percent and summer capability is likely to decrease
by 6 percent, though these estimates are highly dependent upon ambient temperatures.
The capital cost used for this IRP for an air-cooled CCCT located in Idaho on Avista’s
transmission system with AFUDC is $1,323 per kW. Fixed O&M is $16 per kW-year.
Table 6.1 shows the overnight-levelized cost for an air-cooled CCCT resource in
nominal dollars per MWh.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Table 6.1: CCCT (Air Cooled) Levelized Costs
Item Nominal $/MWh
Capital recovery and taxes 20.25
AFUDC 2.69
Federal Tax Incentives 0.00
Fuel Costs 48.81
Fuel Transport 5.18
Greenhouse Gas Emissions Adder 13.65
Fixed O&M 2.67
Variable O&M 2.35
Interconnection Capital Recovery 0.31
Excise taxes and Other Overheads 3.16
Total Cost 99.07
Gas-Fired Combustion Turbines and Reciprocating Engines
Gas-fired combustion turbines (CTs) and reciprocating engines, or peaking resources,
provide low-cost capacity and are capable of providing energy as needed. Technology
advances allow the plants to start and ramp quickly, enabling them to provide regulation
services and reserves for load following and for variable resources such as wind
generation.
The IRP models four peaking resource options: Frame (GE 7EA) and hybrid aero-
derivative (GE LMS 100), Reciprocating Engines (Wartsila 20V34), and Aeroderivative
(GE LM 6000). The different peaking technologies range in their abilities to follow load,
their costs, their generating capabilities, and their energy-conversion efficiencies. Cost
and operational estimates rely on the Northwest Planning and Conservation Council’s
Sixth Power Plan. Table 6.2 compares some of the peaking resource operating and cost
characteristics. All plants assume the same 0.5 percent annual real dollar cost decrease
and forced outage and maintenance rates. The levelized cost for each of the
technologies is in Table 6.3.
Table 6.2: Simple Cycle Plant Cost and Operational Characteristics
Item Frame Hybrid
Reciprocating
Engine
Aero-
Derivative
Capital Cost with AFUDC ($/kW) 679 1,272 1,308 1,186
Fixed O&M ($/kW- yr) 12.70 9.20 15.00 15.00
Heat Rate (Btu/kWh) 11,841 8,782 8,762 9,276
Variable O&M ($/MWh) $1.13 $5.63 $11.25 $4.50
Segment Size (MW) 83 94 99 46
The lowest cost resource in Table 6.3 is the hybrid CT technology. However, this
comparison can be misleading, as a peaking resource does not operate at its theoretical
maximum operating levels. Peaking resources generally operate a small percentage of
the time. Therefore, a lower capacity cost resource may be more appropriate than a
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
lower per unit cost resource when considering the number of expected operating hours
in the broader IRP modeling process.
Table 6.3: Simple Cycle Plant Levelized Costs per MWh
Capital Recovery and Taxes 10.33 19.37 19.38 18.06
AFUDC 0.89 1.67 1.67 1.56
Federal Tax Incentives 0.00 0.00 0.00 0.00
Fuel Costs 81.33 60.32 60.18 63.72
Fuel Transport 0.00 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 22.75 16.87 16.84 17.83
Fixed O&M 2.00 1.46 2.30 2.37
Variable O&M 1.38 6.91 13.82 5.53
Interconnection Capital Recovery 0.44 0.44 0.43 0.44
Excise Taxes and Other Overheads 4.67 3.72 4.05 3.89
Wind
Concerns over the environmental impact of carbon-based generation technologies have
increased demand for wind generation. Governments are promoting wind generation
through a combination of tax credits, renewable portfolio standards, and climate change
legislation. The 2009 American Recovery and Reinvestment Act extended the PTC for
wind through December 31, 2012, and provided an option for wind generation owners to
select a 30 percent investment tax credit (ITC) or cash grant instead of the PTC.
The IRP includes two wind generation resources: on-system and off-system. Both
resources have the same capital costs and wind pattern, but differ in the cost of
transmission to deliver the energy to Avista’s system. On-system projects must pay only
transmission interconnection costs, whereas off-system projects must pay both
interconnection and third party wheeling costs.
Wind resources benefit from having no emissions profile or fuel costs, but they are not
dispatchable, and have high capital and labor costs relative to other resource options.
Wind capital costs in 2012, including AFUDC and transmission interconnection, are
expected to be $1,850 per kW with annual fixed O&M costs of $51 per kW-yr (including
costs due to intermittent generation). These estimates come from Avista’s experience in
the wind market at the time of the IRP. The capacity factors in the Northwest are likely
to vary depending upon the location. Northwest wind has a 31.2 percent average
capacity factor; on-system wind projects have a 29.75 percent capacity. A statistical
method, based on regional wind studies, derives a range of annual capacity factors
depending on the wind regime in each year (see stochastic modeling assumptions for
more details.
Levelized costs, using these expected capacity factors and capital and operating costs
are in Table 6.4. These wind generation cost estimates assume the use of the federal
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
cash grant for any project brought online by the IRP models before 2013 and assume
Avista system interconnection cost of approximately $150 per kW. Actual wind resource
cost will vary depending on a project’s capacity factor, interconnection point, and the tax
incentive eligibility. Further, this plan assumes that any wind resources selected in the
PRS include the 20 percent renewable energy credit (REC) apprenticeship adder for
Washington State eligible renewable resources. This adder applies only in the state of
Washington for compliance in meeting its Energy Independence Act (I-937), requiring
15 percent of the construction labor to be apprentice through a state-certified
apprenticeship program to qualify. The costs shown below do not reflect the
consumption of (i.e., wind integration) or lack of ancillary services generated by wind
relative to other generation technologies.
Table 6.4: Northwest Wind Project Levelized Costs per MWh
Capital Recovery and Taxes 77.59 73.98 58.40
AFUDC 8.19 7.80 6.16
Federal Tax Incentives (2012 only) -23.93 -22.82 -18.01
Fuel Costs - - -
Fuel Transport - - -
Greenhouse Gas Emissions Adder - - -
Fixed O&M 27.59 26.31 22.37
Variable O&M 2.76 2.76 2.76
Interconnection Capital Recovery 7.99 18.67 26.78
Excise Taxes and Other Overheads 1.66 2.07 2.25
Solar
Solar generation technology costs have fallen substantially in the last several years
owing to help from renewable portfolio standards and government tax incentives, both
inside and outside of the United States. Solar costs in this IRP are 27 percent lower
than in the 2009 IRP. Even with these large cost reductions, solar still is uneconomic
when compared to other generation resources because of its low capacity factor and
still-high capital cost. Solar does provide predictable on-peak generation that generally
complements the loads of summer-peaking utilities.
Utility-scale photovoltaic generation can be optimally located for the best solar radiation.
Solar thermal can produce a higher capacity factor than photovoltaic projects (up to 30
percent) and can store energy for several hours. Capital costs in the IRP, including
AFUDC, for solar generation technologies are $5,802 per kW for photovoltaic and
$5,538 for solar-thermal or concentrating solar projects. A well-placed utility-scale
photovoltaic system located in the Pacific Northwest would achieve a capacity factor of
less than 20 percent. Two solar technologies were studied for this IRP (photovoltaic and
solar-thermal), but only utility-scale photovoltaic was included as an option for the PRS.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Avista does not believe that solar-thermal is an economically viable option in Avista’s
service territory given our modest solar resource.
The levelized costs of solar resources, including federal incentives, are in Table 6.5.
Even with declining prices, solar will continue to struggle as a cost-competitive resource
in the Northwest until technology improves capacity factors, installation costs decline at
a more rapid pace, or government entities create further policies or tax incentives to
make this resource more attractive. One advantage solar has in the state of Washington
is if the total plant is less than five megawatts it can generate two RECs that qualify for
the Washington State Energy Independence Act for every megawatt hour of generation.
Table 6.5: Solar Nominal Levelized Cost ($/MWh)
Capital Recovery and Taxes 370.14 201.85
AFUDC 29.49 22.44
Federal Tax Incentives (117.60) (64.58)
Fuel Costs - -
Fuel Transport - -
Greenhouse Gas Emissions Adder - -
Fixed O&M 39.73 30.00
Variable O&M - 1.38
Interconnection Capital Recovery 1.67 9.75
Excise Taxes and Other Overheads 1.79 1.78
Coal
The coal generation industry is at a crossroads. In many states, like Washington, new
coal-fired generation is unlikely due to emissions performance standards.2 In other parts
of the country, coal remains a viable option, but the risks associated with future carbon
legislation make investments in this technology potentially subject to significant upward
price pressures. Avista assumes it will not build any new coal-fired generation resources
due to the risk of future national carbon mitigation legislation and the effective
prohibition in Washington state law. Technologies reducing or capturing greenhouse
gas emissions in coal-fired resources might enable coal to become a viable technology
in the future, but the technology is not commercially available. Although Avista will not
pursue coal in this plan, three coal technologies are shown to illustrate their costs: super
critical pulverized, integrated gasification combined cycle (IGCC), and IGCC with
sequestration. IGCC plants gasify coal, thereby creating a more efficient use of the fuel
lowering carbon emissions and removing other toxic substances before combustion.
Sequestration technologies, if they become commercially available, might potentially
sequester 90 percent of carbon dioxide (CO2) emissions, effectively reducing CO2
2 The Washington State legislature passed Senate Bill 6001 in 2007, effectively prohibiting in-state
electric utilities from developing coal-fired facilities that do not sequester emissions or purchasing long-
term contracts from coal-fired facilities.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
emissions from 205 pounds per MMBtu to 20.5 pounds per MMBtu. Table 6.6 shows the
costs, heat rates, and CO2 emissions of the three coal-fired technologies based on
estimates from the NPCC’s Sixth Power plan and adjusted for Avista’s projected
inflation rates. Table 6.7 shows the nominal levelized cost per MWh based on the
capital costs and plant efficiencies shown in Table 6.6.
Table 6.6: Coal Capital Costs (2012$)
2
Super-Critical 3,583 8,910 205
IGCC 4,001 8,594 205
IGCC with Sequestration 5,334 10,652 25
Table 6.7: Coal Project Levelized Cost per MWh
Capital Recovery and Taxes 56.82 64.70 86.27
AFUDC 9.66 13.06 17.41
Federal Tax Incentives 0.00 0.00 0.00
Fuel Costs 14.28 13.77 17.07
Fuel Transport 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 30.00 28.93 4.30
Fixed O&M 11.87 12.10 12.10
Variable O&M 3.80 8.70 11.74
Interconnection Capital Recovery 10.31 10.46 4.79
Excise taxes and Other Overheads 3.04 3.20 2.16
Other Generation Resource Options
A thorough IRP considers generation resources that are not generally available in large
quantities or those not commercially or economically ready for utility-scale development,
but may be over the 20-year IRP planning horizon. This is particularly true for some
emerging technologies that are attractive from an environmental perspective, but are
currently higher-cost than other resources. Avista analyzed the following resources for
this IRP using estimates from the NPCC’s Sixth Power Plan but did not select them for
the Preferred Resource Strategy: biomass, geothermal, co-generation, nuclear, landfill
gas, and anaerobic digesters. It is possible that these resources could compete with
those assumed in the IRP. If so, Avista’s RFP processes will identify them and their
selection will displace resources otherwise included in the IRP strategy. The expected
cost of these resource options per MWh is in Table 6.8 and Table 6.9.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Woody Biomass
Avista’s Kettle Falls Generation Station is a 50 MW wood-fired plant Avista built and has
operated since 1983. The viability of another Avista biomass projects depends
substantially on the availability and cost of the fuel supply. Many announced biomass
projects fail because of problems securing long-term fuel sources. Where an RFP
identifies a potential project, Avista will consider it for a future acquisition.
Geothermal
Northwest utilities have developed an increased interest in geothermal energy over the
past several years. Geothermal energy provides renewable capacity and energy with
minimal carbon dioxide emissions (zero to 200 pounds per MWh). The federal
government has extended production tax credits to this technology through December
31, 2013. Geothermal energy struggles due to high upfront development costs and risks
stemming from drilling several holes thousand feet below the earth’s crust; each hole
can cost over $3 million. Geothermal costs are low once drilling ends, but the risk
capital required to locate and prove a viable site is significant. Costs shown in this
section do not account for dry-hole risk associated with sites that do not prove to be
viable resources after drilling has taken place.
Landfill Gas
The Northwest has successfully developed landfill gas resources. The Spokane area
had a project, but it was retired after the fuel source depreciated to an unsustainable
level. Based upon costs from the NPCC, landfill gas resources are economically
promising, but are limited in their size, quantity, and location.
Anaerobic Digesters (Manure/Wastewater Treatment)
Like landfill gas, 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 electricity generators.
These facilities tend to be significantly smaller than utility-scale generation projects (less
than five MW). A survey of Avista’s service territory found no large-scale livestock
operations capable of implementing this technology.
Wastewater treatment facilities can host anaerobic digesters. Digesters installed when a
facility is constructed helps the economics of a project greatly, though costs range
greatly depending on the system configuration. Retrofits to existing wastewater
treatment facilities are possible, but tend to have higher costs. Many of these projects
offset energy needs of the facility, so there may be little, if any, surplus generation
capability.
Small Cogeneration
Avista has relatively 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/emissions costs, and credit toward Washington’s
I-937 targets. The PRS does not include small cogeneration; where a customer pursues
this resource, Avista will consider it along with other generation options.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Nuclear
Nuclear plants are not a resource option in the IRP given the uncertainty of their
economics, the apparent lack of regional political support for the technology, U.S. policy
implications, and the negative experience Avista had with its participation in WNP-3 in
the 1980s. Like coal plants, nuclear resources could be in Avista’s future because other
utilities in the Western Interconnect may be able to incorporate nuclear power in their
resource mix and offer Avista an ownership share. Given these considerations, Avista
does not include any nuclear generation in its Preferred Resource Strategy. The viability
of nuclear power could change as national policy priorities focus attention on de-
carbonizing the nation’s energy supply. Nuclear capital costs are difficult to forecast, as
there have been no new nuclear facilities built in the United States since the 1980s.
Projected costs are from industry studies and recent nuclear plant license proposals.
Table 6.8: Other Resource Options Levelized Costs
Landfill
Gas
Manure
Digester
Waste
Water
Treatment
Capital Recovery and Taxes 31.56 67.15 63.40
AFUDC 2.45 4.66 4.88
Federal Tax Incentives -8.49 -8.49 -8.49
Fuel Costs 32.66 0.00 0.00
Fuel Transport 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 0.00 0.00 0.00
Fixed O&M 4.87 8.42 7.07
Variable O&M 26.25 33.16 41.45
Interconnection Capital Recovery 4.54 4.54 0.34
Excise Taxes and Other Overheads 2.96 2.00 2.11
Total Cost 96.80 111.45 110.76
Table 6.9: Other Resource Options Levelized Costs ($/MWh)
Small
Co-Gen
Wood
Biomass Geothermal Nuclear
Capital Recovery and Taxes 53.91 57.59 65.86 97.88
AFUDC 5.36 6.02 11.39 27.26
Federal Tax Incentives 0.00 -8.49 -16.98 -16.98
Fuel Costs 30.60 53.59 0.00 10.36
Fuel Transport 3.19 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 8.56 0.00 4.63 0.00
Fixed O&M 0.00 34.80 32.16 16.85
Variable O&M 11.05 5.11 6.22 1.38
Interconnection Capital Recovery 0.36 4.65 4.49 4.55
Excise Taxes and Other Overheads 2.33 4.25 2.06 1.43
Total Cost 115.36 157.52 109.83 142.72
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
New Resources Cost Summary
Avista has several resource alternatives to select from for this IRP. Each provides
differing benefits, costs, and risks. The role of the IRP is to identify the relevant
characteristics and choose a set of resources that are actionable, meet customer’s
energy and capacity needs, balance renewable energy requirements, and minimize
customer costs. Figure 6.1 shows the comparative cost per MWh of each of the new
resource alternatives. Tables 6.13 and 6.14 provide detailed assumptions for each type
of resource. The ultimate resource selection goes beyond simple levelized cost
analyses and considers the capacity contribution (or lack thereof for wind and solar) of
each resource, among other items discussed in the IRP.
Figure 6.1: New Resource Levelized Costs
$0 $50 $100 $150 $200 $250 $300 $350
Solar Photovoltaic
Solar Thermal
Wood Biomass
Coal (IGCC w/ Seq)
Nuclear
Coal (IGCC)
Manure Digester
Waste Water Treatment
Coal (Super-Critical)
Wind Off System
Small Co-Gen
Geothermal
Reciprocating Engine
Frame SCCT
Wind Montana
Wind On System
Landfill Gas
Aero SCCT
Hybrid SCCT
CCCT (1x1) w/ duct burner (air)
CCCT (1x1) w/ duct burner (water)
dollars per MWh
Total Cost
Greenhouse Gas Adder
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Table 6.10: New Resource Levelized Costs Considered in PRS Analysis
Resource
Size
(MW)
Heat
Rate
(Btu/
kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Variable
O&M
($/MWh)
Peak
Credit
(Winter/
Summer)
CCCT (water cooled) 275 6,722 1,261 16.1 2.14 104/96
CCCT (air cooled) 270 6,856 1,324 16.1 1.91 104/96
Frame CT 83 11,841 708 12.7 1.13 104/96
Hybrid CT 94 8,782 1,326 9.2 5.63 104/96
Reciprocating Engines 99 8,762 1,364 15.0 11.25 100/100
Aero CT 46 9,276 1,237 15.0 4.50 104/96
Wind (on-system) 40 n/a 1,896 51.4 2.25 0/0
Wind (off-system) 40 n/a 1,896 51.4 2.25 0/0
Solar (photovoltaic) 5 n/a 6,092 46.8 0.00 5/60
Table 6.11: New Resource Levelized Costs Not Considered in PRS Analysis
Resource
Size
(MW)
Heat
Rate
(Btu/
kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Variable
O&M
($/MWh)
Peak
Credit
(Winter/
Summer)
Pulverized Coal 300 8,910 3,583 69.0 3.09 100/100
IGCC Coal 300 8,594 4,001 69.0 7.09 105/95
IGCC Coal w/ Seq. 250 10,652 5,334 69.0 9.56 100/100
Solar (thermal) 25 n/a 5,646 69.0 1.13 5/100
Wind (off-system MT) 40 n/a 1,760 51.4 2.25 0/0
Woody Biomass 25 13,500 4,170 207.0 4.16 100/100
Geothermal 15 n/a 5,017 201.3 5.06 110/90
Landfill Gas 3.2 10,600 2,285 29.9 21.38 100/100
Manure Digester 0.85 10,250 4,862 51.8 27.01 100/100
Wastewater Treatment 0.85 10,250 4,862 46.0 33.76 100/100
Small Co-Generation 5 4,456 3,922 0.0 9.00 104/96
Nuclear 500 10,400 6,522 103.5 1.13 100/100
Hydroelectric Project Upgrades
Avista continues to upgrade many of its hydroelectric facilities. The latest hydroelectric
upgrade added nine MW to the Noxon Rapids Development in April 2011. Upgraded
Noxon Rapids Unit 4 will enter service in April 2012. Figure 6.1 shows the history of
upgrades to Avista’s hydroelectric system in additional average megawatts by year and
cumulatively. Avista will have added 40.1 aMW of incremental hydroelectric energy
between 1992 and 2013.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Figure 6.2: Historical and Planned Hydro Upgrades
Following upgrades at Noxon Rapids, Avista expects to pursue an upgrade at Nine Mile
and annual upgrades to the Little Falls project over a four-year period. The Little Falls
upgrades will include new turbine runners, generators, and other electrical equipment.
The upgrade at Nine Mile could be a new powerhouse or a replacing the current units.
Several other potential hydroelectric upgrades might add capacity and energy at the
Long Lake, Cabinet Gorge, Post Falls, and Monroe Street projects. These upgrades are
not included in the portfolio analysis and no estimated costs are in this IRP because
further study is required. Such studies are part of the IRP’s Action Plan. Table 6.8
shows the hydroelectric upgrade studies. Large hydro upgrades can help meet Avista’s
renewable energy goals under I-937, benefit from federal tax incentives, and help
mitigate dissolved gases.
Table 6.12: Hydro Upgrade Potential
Upper Falls 2 1
Long Lake Second Powerhouse 60 - 120 18 - 20
Cabinet Gorge Second Powerhouse 50 7
Post Falls New Powerhouse 19 4
Monroe Street Second Powerhouse 38 16
0
10
20
30
40
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Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Upper Falls
The Upper Falls hydroelectric upgrade would consist of replacing the single unit’s
turbine runner and modifying the existing draft tube to improve efficiency. Initial costs
estimates are $7 million or $3,500 per kW, for an additional two MW of capacity and
8,760 MWh of energy. This upgrade would require FERC licensing changes and help
meet Avista’s I-937 renewable energy goals.
Long Lake Second Powerhouse
Avista studied a second powerhouse at Long Lake about 20 years ago using a small
arch dam located on the south end of the project site. See Figure 6.3 for a concept of
the project. The potential cost of this resource could exceed $120 million and provide an
additional 158,000 to 178,000 MWh of energy per year and 60 to 120 MW of added
capacity. This project would be a major undertaking and would take several years to
complete. It would require major changes to the Spokane River license, but could help
reduce total dissolved gas concerns by reducing spill at the project. The incremental
capacity would also help meet future winter peak loads, but may not contribute greatly
to summer peak needs. The incremental energy might qualify under I-937.
Figure 6.3: Long Lake Second Powerhouse Concept Drawing
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Cabinet Gorge Second Powerhouse
Avista is exploring the addition of a second powerhouse at the Cabinet Gorge project
site to mitigate total dissolved gas. A new powerhouse would benefit from an existing
diversion tube around the dam. The potential cost of this resource could be as high as
$115 million. The new powerhouse could provide 57,000 MWh of additional energy per
year, and 50 MW of additional capacity. This project would be a major engineering
project, take several years to complete, and require major changes to the Clark Fork
River FERC license. As with the other potential hydroelectric upgrade projects, this
project might help Avista meet its I-937 renewable energy goals.
Post Falls Refurbishment
The Post Falls hydroelectric project is 105 years old. An upgrade to this project includes
a total rebuild of the powerhouse and equipment while leaving the exterior intact. The
project would remove the existing horizontal units, replacing them with higher efficiency
and higher capacity vertical units. The cost of this upgrade could be as high as $75
million. It would add 33,000 MWh of energy each year and provide an additional 19 MW
of capacity. Like the other potential hydroelectric projects, this would require a
reopening of the Spokane River FERC license and might help meet Avista’s I-937
renewable energy goals.
Monroe Street Second Power House
Avista replaced the powerhouse at its Monroe Street project on the Spokane River in
1992. An upgrade option would include the addition of a new powerhouse to capture
additional flows and be a major undertaking requiring substantial cooperation with the
city because of disruption in the Riverfront Park and downtown Spokane area during
construction. This project would require dredging the river on the western edge of the
park and creating a tunnel between city hall and the Monroe street substation. The
expected cost for this project would be $95 million, and it could create an additional
142,000 MWh of energy per year and 37.5 MW of incremental capacity. The
incremental generation of the upgraded facility might help meet Avista’s I-937
renewable energy goals.
Thermal Resource Upgrades
Several upgrade opportunities exist in Avista’s thermal fleet that would add capacity
and/or increase operating efficiency. Avista plans an economic viability study for each
option prior to the 2013 IRP. The following is a list of potential upgrades to the
Rathdrum and Coyote Springs 2 projects that the Avista may consider. Table 6.9 is a
summary of the nominal levelized costs of each of the upgrade options for the
Rathdrum CT and Table 6.10 provides nominal levelized costs for the Coyote Springs 2
upgrade options.
Rathdrum CT to CCCT Conversion
The Rathdrum CT has two GE 7EA units in simple cycle configuration built in 1994 with
an approximate 160 MW of combined output used to serve customers in peak load
conditions. It is possible to convert this peaking facility to a combined cycle plant by
adding between 78 and 91 MW of steam-turbine capacity (depending upon
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
temperature) and increasing its operating efficiency from a heat rate of 11,612 Btu/kWh,
in its existing configuration, to a heat rate of about 7,986 Btu/kWh. The capital cost for
this upgrade is $81.5 million. Two major issues challenge this conversion. The first is
cooling water. Avista does not have water rights adequate to cool the plant with water.
Therefore, it is likely that air-cooling at the plant is necessary at higher cost. The second
major issue is noise. Major residential development now exists at the plant site. Given
these concerns, this option is not in the PRS.
Rathdrum CT Water Demineralizer
Another potential upgrade at Rathdrum is to add a water demineralizer to allow inlet
fogging in the summer. This upgrade would increase plant capacity by 17.6 MW and
increase its operating efficiency by 0.5 percent on hot summer days. The upgrade will
cost approximately $1 million.
Table 6.13: Rathdrum CT Upgrade Options ($/MWh)
Capital recovery and taxes 18.62 15.39 4.92
AFUDC 1.94 1.61 0.08
Federal Tax Incentives 0.00 0.00 0.00
Fuel Costs 54.31 53.25 80.89
Fuel Transport 5.53 5.42 8.06
Greenhouse Gas emissions adder 15.19 14.90 22.63
Fixed O&M 2.45 2.45 0.00
Variable O&M 1.62 1.87 1.24
Interconnection capital recovery 0.54 0.54 0.00
Other Emissions 0.00 0.00 0.00
Excise taxes and other overheads 3.45 3.39 4.88
Coyote Springs 2 Inlet Chiller
There are two potential inlet chiller options for increasing summer capacity at the
Coyote Springs 2 CCCT plant in Boardman, Oregon. One option is to add an inlet chiller
to cool the air going into the machine; the second option is to add a thermal unit in
addition to a chiller to optimize chiller operations. Avista estimates this upgrade to add
30 MW of capacity on a 100-degree day at a cost of $10 million. Adding the thermal
storage technology capacity in conjunction with an inlet chiller would increase plant
capacity by an additional 2.2 MW for an additional $1.0 million.
Coyote Springs 2 Cold Day Controls
Another upgrade option at the Coyote Springs 2 plant is to install an upgraded CT
control system to increase its operating performance on cold days. This software
upgrade could increase capacity by 17.6 MW on a zero-degree day at an estimated cost
of $4.5 million.
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP
Coyote Springs 2 Advanced Hot Gas Path Components
Coyote Springs 2 could benefit from the installation of advanced hot gas path
components. This upgrade could add approximately 8 MW of capacity around the year
and increase efficiency by one percent. The estimated cost for this upgrade is $18
million with additional annual plant maintenance costs of $3.9 million.
Coyote Springs 2 Cooling Optimization Hardware
Adding cooling optimization hardware to Coyote Springs may add 2.6 MW of capacity
around the year and improve plant efficiency by 0.5 percent. The estimated cost of this
project is $7.2 million.
Table 6.14: Coyote Springs 2 Upgrade Options ($/MWh)
Capital recovery and taxes 53.23 55.79 20.20 17.41 47.12
AFUDC 0.91 0.95 0.17 0.30 0.80
Federal Tax Incentives - - - - -
Fuel Costs 46.42 46.42 46.42 45.91 46.19
Fuel Transport 4.53 4.53 4.53 4.67 4.70
Greenhouse Gas emissions adder 12.99 12.99 12.99 12.84 12.92
Fixed O&M - - - 36.10 -
Variable O&M - - - - -
Interconnection capital recovery 4.32 4.32 4.32 4.44 4.44
Other Emissions - - - - -
Excise taxes and other overheads 2.95 2.96 2.96 4.50 2.95
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
7. Market Analysis
Introduction
This section describes the electricity and natural gas market environment developed for
the 2011 IRP. Contained in this chapter are risks Avista considers when meeting
customer demands at lowest reasonable cost. The analytical foundation for the 2011
IRP is a fundamentals-based electricity model of the entire Western Interconnect. The
market analysis compares potential resource options on their net value when operated
in the wholesale marketplace, rather than on the simple summation of their installation,
operation, maintenance, and fuel costs. The Preferred Resource Strategy (PRS)
analysis uses these net values when selecting future resource portfolios.
Understanding market conditions in the geographic areas of the Western Interconnect is
important, because regional markets are highly correlated because of large
transmission linkages between load centers. This IRP builds on prior analytical work by
maintaining the relationships between the various sub-markets within the Western
Interconnect, and the changing values of company-owned and contracted-for resources.
The backbone of the analysis is AURORAxmp, an electric market model that dispatches
resources to loads across the Western Interconnect with given fuel prices, 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 the states
west of the Rocky Mountains, the Canadian provinces of British Columbia and Alberta,
and the Baja region of Mexico as shown in Figure 7.1. The modeled area has an
installed resource base of approximately 240,000 MW.
Section Highlights
Gas and wind resources dominate new generation additions in the West.
Shale gas lowers gas and electricity price forecasts from the previous IRP.
A growing Northwest wind fleet reduces springtime market prices below zero
in some hours.
Federal greenhouse gas policy is uncertain; the IRP quantifies this uncertainty
by modeling four different mitigation regimes.
The Expected Case reduces Western Interconnect greenhouse gas emissions
by 28 percent (18 percent from current levels) relative to a case without a
carbon mitigation regime.
Carbon mitigation policy increases Western Interconnect costs by $3.5 billion
annually.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.1: NERC Interconnection Map
The Western Interconnect is separated from interconnects to the east and ERCOT
except by eight inverter stations. The Western Interconnect follows operation and
reliability guidelines administered by the Western Electricity Coordinating Council
(WECC).
The Western Interconnect electric system is divided into 16 AURORAxmp modeling
zones based on load concentrations and transmission constraints. After extensive study
in the 2009 IRP, Avista models the Northwest region as a single zone because this
configuration dispatches resources in a manner most reflective of historical operations.
Table 7.1 describes the specific zones modeled in this IRP.
Table 7.1: AURORAXMP Zones
Northwest- OR/WA/ID/MT Southern Idaho
Eastern Montana Wyoming
Northern California Southern California
Central California Arizona
Colorado New Mexico
British Columbia Alberta
North Nevada South Nevada
Utah Baja, Mexico
Fundamentals-based electricity models range in their abilities to emulate power system
operations accurately. Some models account for every bus and transmission line, while
other models utilize regions or zones. An IRP requires regional price and plant dispatch
information but does not require detailed modeling at the bus level.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Western Interconnect Loads
The 2011 IRP relies on a load forecast for each zone of the Western Interconnect.
Avista uses external sources to quantify load growth estimates across the west. These
load estimates include impacts of increasing energy efficiency and demand destruction
caused by potential emissions legislation and the associated price increases expected
to reduce loads over time from their present trajectory.
Specific regional load growth levels are in Table 7.2. Avista projects that overall
Western Interconnect loads rise 1.65 percent annually over the next 20 years, from
103,840 aMW in 2012 to 141,654 aMW in 2031. Included in this forecast are rising plug-
in electric vehicle (PHEV) loads. Load growth rates without PHEV would be 1.57
percent. Absent conservation efforts, Western Interconnect loads are 9,000 aMW higher
in 2031. Figure 7.2 illustrates the load forecast and the impacts of new conservation and
PHEVs. The Northwest grows more slowly than the Western Interconnect at large.
Loads rise one percent per year over the IRP timeframe.
Figure 7.2: 20-Year Annual Average Western Interconnect Energy
Transmission
The IRP reflects various regional transmission projects announced over the past several
years. Many of these projects move distant renewable resources to load centers in
support of state-level renewable portfolio standards (RPS). Transmission upgrades
included in the IRP are in Table 7.2. Transmission upgrades within AURORAxmp zones
were not included explicitly in the model, as they do not affect power transactions
between zones.
-
25,000
50,000
75,000
100,000
125,000
150,000
175,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis
Canada – PNW Project British Columbia Northwest 2018 3,000
PNW – California Project Northwest California 2018 3,000
Eastern Nevada Intertie North Nevada South Nevada 2015 1,600
Gateway South Wyoming Utah 2015 3,000
Gateway Central Idaho Utah 2015 1,320
Gateway West Wyoming Idaho 2016 1,500
SunZia/Navajo Transmission Arizona New Mexico 2016 3,000
Wyoming – Colorado Intertie Wyoming Colorado 2013 900
Hemingway to Boardman Idaho Northwest 2019 1,500
New Resource Additions
An estimate for new resource capacity in the Western Interconnect is forecasted as part
of the long-term electric market price forecast. It accounts for load growth and various
other mandates. These additions meet capacity, energy, ancillary services, and
renewable portfolio mandates. To meet capacity requirements, gas-fired CCCT or
SCCT, solar, wind, coal IGCC, coal IGCC with sequestration, and nuclear were options
were considered.1 For the first time, Avista assumes that no new pulverized coal
additions in the Western Interconnect over the forecast horizon.
Many states have created RPS requirements promoting renewable generation to curb
greenhouse gas emissions, provide jobs, and to diversify the energy mix of the United
States. 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 their RPS obligations differently. AURORAxmp cannot model RPS
levels explicitly. Instead, Avista input RPS requirements into the model at levels
satisfying state laws. Renewable resource portfolios adequate to meet Western
Interconnect RPS obligations were input using work by the Northwest Power and
Conservation Council (NPCC); these percentages formed the basis for RPS shortfalls in
each state. Beyond the manually input RPS resources, the model selected no additional
renewables.
Figure 7.3 illustrates new capacity and RPS additions made in the modeling process.
Wind and solar facilities meet most renewable energy requirements.. Geothermal,
biomass, and hydroelectric resources provide a more limited contribution to RPS needs.
Renewable resource choices are modeled to differ by state depending on the
requirements of state laws and the availability of renewable resources in a region. For
example, the Southwest will meet RPS requirements with solar and wind given policy
choices by those states. The Northwest will use a combination of wind and hydroelectric
upgrades because the economic costs of these resources are the lowest. Rocky
1 Wind receives a five percent capacity credit on a regional basis; it receives no capacity credit where
selected to meet Avista requirements.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Mountain states will predominately use wind to meet RPS requirements, again due to
the fact that wind is the least-cost renewable resource modeled in the IRP.
Figure 7.3: New Resource Added (Nameplate Capacity)
Fuel Prices and Conditions
Fuel cost and availability are some of the most important drivers of resource values.
Some resources, including geothermal and biomass, have limited fuel options or
sources, while coal and natural gas have more fuel sources. Hydro and wind use free
fuel sources, but are highly dependent on weather.
Natural Gas
The fuel of choice for new base load and peaking capability continues to be natural gas.
Natural gas is subject to price volatility, though increasing unconventional sources may
reduce future volatility. Avista uses forward market prices and a combination of two
forecasts from prominent energy industry consultant to develop its natural gas price
forecast for this IRP.2 The forecast uses an equal weighting of the consultant forecasts
and forward prices in 2012.3 After 2012, the weighting of forward prices fell by 10
percent each year through 2016. After 2016, the forecast includes a 50/50 weighting of
the two consultant forecasts. For example, in 2015 the price forecast is a weighted
average of the market (20 percent), Consultant 1 (40 percent) and Consultant 2 (40
percent). The long-term forecasts include impacts of potential national carbon
legislation. Carbon legislation will increase demand for natural gas as generation shifts
away from coal. Figure 7.4 shows the price forecast for Henry Hub; the levelized
nominal price is $7.30 per Dth. The forecast without carbon legislation is $6.78 per Dth.
2 Consultant forecasts as of December 2010. 3 The 50 percent weighting applies to the average of the two consultant forecasts.
-
10,000
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Natural Gas CCCT
Hydro
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Solar
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.4: Henry Hub Natural Gas Price Forecast
The forecast from Consultant 1 assumes a timely and moderate economic recovery and
aggressive long term demand growth from the power sector in part due to an improved
competitive position relative to coal. The forecast includes a modest federal carbon
price of $14 per metric ton beginning 2016 and rising to $25/metric ton by 2025. This in
turn results in accelerated coal retirements pressuring prices early in the forecast. A
brief price respite occurs following carbon legislation but prices resume their build as
competition for capital, equipment and labor from strong recovery in oil demand drive up
gas drilling costs and supply growth from shale gas moderates. An Alaskan gas pipeline
around 2026 produces a brief gas glut but is quickly absorbed and the uptrend in prices
resumes.
The forecast from Consultant 2 assumes a more gradual and modest economic
recovery including a more moderate rebound in power demand early in the forecast.
Their outlook reflects an expectation of significant low cost supplies from shale gas
resources that quickly respond to rising demand. The improved predictability of shale
gas volumes and costs prompt active hedging by producers when prices escalate
counteracting the trend and resulting in more stable pricing. This forecast does not
include carbon legislation or an Alaskan natural gas pipeline.
Price differences across North America depend on demand at the trading hubs and the
pipeline constraints between them. Many pipeline projects are in the works in the
Northwest and the west to access historically cheaper gas supplies located in the Rocky
Mountains. Table 7.3 presents western gas basin differentials from Henry Hub prices.
Prices converge over the course of the study as new pipelines and new sources of gas
$0.00
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Expected Case Consultant 1 Consultant 2 Market
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
come online. To illustrate the seasonality of natural gas prices, monthly Stanfield price
shapes in Table 7.4 show various forecast years.
Table 7.3: Natural Gas Price Basin Differentials from Henry Hub
Basin 2012 2015 2020 2025 2030
Stanfield 93.4% 94.4% 90.3% 92.6% 90.6%
Malin 94.7% 95.7% 92.5% 94.9% 92.9%
Sumas 93.7% 94.6% 88.5% 90.5% 88.3%
AECO 89.1% 90.6% 86.3% 88.1% 85.8%
Rockies 93.6% 94.9% 90.6% 89.4% 87.2%
Southern CA 97.5% 99.3% 99.3% 100.0% 102.7%
Stanfield 93.4% 94.4% 90.3% 92.6% 90.6%
Table 7.4: Monthly Price Differentials for Stanfield
Month 2012 2015 2020 2025 2030
Jan 94.4% 95.9% 92.2% 94.7% 92.5%
Feb 94.4% 96.1% 92.0% 94.7% 92.5%
Mar 94.0% 95.6% 92.0% 94.3% 93.9%
Apr 92.6% 94.1% 89.4% 91.3% 90.0%
May 92.2% 93.1% 88.2% 90.4% 88.8%
Jun 92.3% 93.1% 88.2% 90.5% 88.5%
Jul 92.6% 92.9% 87.8% 90.0% 88.0%
Aug 92.7% 93.1% 88.0% 90.0% 88.3%
Sep 93.0% 93.9% 89.7% 92.1% 89.2%
Oct 93.3% 94.8% 90.6% 93.6% 90.4%
Nov 94.4% 95.0% 92.5% 95.3% 92.7%
Dec 94.9% 95.0% 92.7% 94.9% 92.5%
Unconventional Natural Gas Supplies
Shale natural gas production has game-changing impacts on the natural gas industry,
dramatically revising the amount of economical natural gas production. Shale gas often
is lower in cost than conventional natural gas production because of economies of
scale, near elimination of exploration risks and standardized, sophisticated production
techniques that streamline costs and minimize the time from drilling to market delivery.
Shale gas could continue to greatly alter the natural gas marketplace, holding down
both price and volatility over the long run as production quickly responds to changing
market conditions. This in turn leads to numerous ripple effects, including longer-term
bilateral hedging transactions, new financing structures including cost index pricing,
and/or vertical integration by utilities choosing to limit their exposure to natural gas price
increases and volatility through the acquisition of shale-gas reserves as illustrated by
the recent purchase of reserves by Northwest Natural Gas Company. See Figure 7.5 for
the projected change in contribution of shale to other sources of natural gas between
2009 and 2035.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.5: Shale Gas Production Forecast4
Shale gas is not free of controversy. Concerns include water, air, noise, and seismic
environmental impacts arising from unconventional extraction techniques. Water issues
include availability, chemical mixing, groundwater contamination, and disposal. Air
quality concerns stem from methane leaks during production and processing. Mitigating
excessive noise in urban drilling and elevated seismic activity near drilling sites are also
fomenting apprehension. State and federal agencies are reviewing the environmental
impacts of this new production method. As a result, unconventional natural gas
production in some areas has stopped. Increased environmental protections might
increase costs and environmental uncertainty could precipitate increased price volatility.
Shale gas production influences the U.S. liquid natural gas (LNG) market. It has broken
the link between North American natural gas global LNG prices. Numerous planned re-
gasification terminals are on hold or cancelled. Some facilities now seek approvals to
become LNG exporters rather than importers. These changes appear to affect gas
storage and transportation infrastructure. For example, the Kitimat LNG export terminal
in northern British Columbia, if built, will export significant LNG quantities to Asian
markets. These exports will affect overall market conditions for natural gas in the United
States and the Pacific Northwest.
Coal
As discussed earlier in this chapter, there are no new coal plants built for the Western
Interconnect. Therefore, the coal price forecasts affect only existing coal facilities. Each
plant’s historical fuel costs escalate by rates contained in a consultant’s study. The
average annual price increase over the IRP timeframe is 1.4 percent. For the Colstrip
facility, where Avista has access to project-specific information, Avista did not rely on
the consultant study. Instead, it used an escalation rate based on existing contracts.
Woody Biomass
The future price and availability of woody biomass (or hog fuel) is critical to
understanding the viability of new wood-fired facilities. Hog fuel availability is highly
4 Source: Energy Information Administration (EIA)
Shale Gas,
16%
Other
Sources,
84%
2009
Shale Gas,
47%Other
Sources,
53%
2035
Source: EIA
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
dependent on overall lumber demand. Avista has operated its Kettle Falls wood-fired
generator since 1983. When it was constructed, hog fuel was a waste product from area
sawmills that procured at a near-zero cost. The plant had surplus fuel even into the mid-
2000s, but has struggled since then to procure enough reasonably priced fuel because
of the impacts of a recession on the housing market, and the resultant decrease in
lumber demand. The IRP projects biomass prices in the west to extend from historical
levels at a rate of three percent per year to reflect ongoing tight market conditions.
Hydroelectric
The Northwest and British Columbia 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 particularly valuable for meeting peak load demands, following general
intra-day load trends, shaping energy for sale during higher-valued peak hours, and
integrating variable generation resources. The key drawback to hydroelectricity is its
output variability a month-to-month and year-to-year.
This IRP uses the results of the Northwest Power Pool’s (NWPP) 2009-10 Headwater
Benefits Study to model regional hydro availability. The NWPP study provides energy
levels for each hydroelectric facility by month over a 70-year hydrological record
spanning the years 1928 to 1999. British Columbia’s hydroelectric plants are modeled
using data from the Canadian government5.
Many of the analyses in the IRP use an average of the 70-year hydroelectric record;
whereas stochastic studies randomly draw from the 70-year record (see Risk Analysis
later in this section), as the historical distribution of hydroelectric generation is not
normally distributed. AURORAxmp maps each hydroelectric plant to a load zone.
For Avista hydroelectric plants, proprietary software provides a more detailed
representation of operating characteristics and capabilities. Figure 7.6 shows average
hydroelectric energy (in red) of 18,172 aMW in Washington, Oregon, Idaho, Western
Montana, and British Columbia. The chart also show the range in potential energy used
in the stochastic study, with a 10th percentile water year of 14,395 aMW (-21 percent),
and a 90th percentile water year of 21,629 aMW (+40 percent).
5 Statistics Canada, www.statcan.gc.ca
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.6: Northwest Expected Energy
AURORAxmp represents hydroelectric plants using annual and monthly capacity
factors, minimum and maximum generation levels, and sustained peaking generation
capabilities. The model’s objective, subject to constraints, is to move hydroelectric
generation into peak hours to follow daily load changes; this maximizes the value of the
system consistent with actual operations.
Wind
Additional wind resources are necessary to satisfy renewable portfolio standards. These
additions mean significant competition for the remaining higher-quality wind sites. The
capacity factors in Figure 7.7 present average generation for the entire area, not for
specific projects. The IRP uses capacity factors from a review of the Bonneville Power
Administration (BPA) and the National Renewable Energy Laboratory (NREL) data.
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.7: Regional Wind Expected Capacity Factors
Greenhouse Gas Emissions
Greenhouse gas regulation is one the greatest fundamental risks facing the electricity
marketplace today because of the industry’s heavy reliance on carbon-emitting thermal
power generation plants. Reducing carbon emissions at existing power plants, and the
construction of low- and non-carbon-emitting technologies, changes the resource mix
over time. No federal regulations presently constrain greenhouse emissions, but federal
legislation is still expected. In the interim, several western states and Canadian
provinces are promoting the Western Climate Initiative as an alternative to federal
legislation. The goal is to develop a multi-jurisdictional greenhouse gas policy.
To simulate greenhouse gas regulation, Avista developed four policy models and their
assumed financial impact on the energy marketplace. Each policy represents a potential
path governments could take over the next several years. The policies received
weighting factors, with the weighted average price of the policies forming the Expected
Case. The four greenhouse gas policies used in this IRP are in Table 7.5:
32.0 33.5 34.5
30.7
37.2 38.5
28.8 29.0
32.3
0
10
20
30
40
50
NW BC AB CA MT WY SW UT CO
ca
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Table 7.5: Monthly Price Differentials for Stanfield
Strategy
Weight
(%) Details
Regional
Greenhouse
Gas Policies
30 – Greenhouse gas reductions in California, Oregon,
Washington, and New Mexico between 2014 and 2019.
– About a 10 percent reduction below 2005 levels by 2020.
– Beginning in 2020, shift to National Climate Policy with
15 percent below 2005 levels by 2030.
National
Climate
Policy
30 – Federal legislation only applies beginning in 2015
– About 15 percent below 2005 levels by 2020 and about
35 percent below 2005 levels by 2030.
National
Carbon Tax
30 – Federal legislation only applies.
– $33 per short ton, then 5 percent per year escalation for
the remainder of the study.
– Begins in 2015.
No
Greenhouse
Gas
Reductions
10 – No carbon reduction program.
– State-level emission performance standards apply and
no new coal-plants added in the Western United States.
Figure 7.8 shows the expected price of greenhouse gas emission for each policy
described in Table 7.5 and the weighted average price comprising of the Expected
Case. The carbon policy in each stochastic study comes from the distribution of the four
cases described above.
Figure 7.8: Price of Greenhouse Gas Credits in each Carbon Policy
$0
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Delayed National Climate Policy
National GHG Tax
No GHG Reductions
Expected Case
Regional GHG Policy
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Risk Analysis
To account for the uncertainty of future electric prices, a stochastic study is preformed
using the variables discussed earlier in this chapter. It is better to represent the
electricity price forecast as a range rather than a point estimate. Point estimates are
unlikely to forecast any of the underlying assumptions perfectly, whereas stochastic
price forecasts develop a more robust resource strategy. For example, fuel price
volatility and carbon risk directly affect natural gas-fired resources but not wind
resources. Wind resources, on the other hand, are subject to varying output on an
hourly, daily, monthly, and annual basis. In prior IRP’s Avista modeled 250 to 300
stochastic iterations or scenarios. This IRP developed 500 iterations to provide a more
robust results distribution to better illustrate potential tail outcomes. The increased
number of studies will affect the overall results of the IRP, but should assist in
explaining the results better, especially at the tails. The next several pages discuss
input variables driving market prices, and describe the methodology and the range in
inputs used in the modeling process.
Greenhouse Gas Prices
Without established federal legislation and no formal rules for western carbon markets,
the expected price of carbon emission is difficult to determine without resorting to a
macroeconomic model. Even with carbon rules in place, prices in a cap and trade
program reflect the tradeoff and interaction between natural gas and coal prices and the
ultimate maximum emissions level allowed by the program. Further, it is likely that
certain states might stop pursuing cap and trade programs because of recent
successes in shutting down northwest coal-fired facilitates. As discussed earlier, four
possible legislative outcomes reflect the uncertainty surrounding future legislation. Each
was included in the stochastic analysis based on its weighting.
The price of carbon mitigation will vary over time, as the natural gas price affects the
cost efficiency of displacing coal-fired generation. When natural gas prices rise, so too
must carbon prices. To account for this relationship, once the carbon policy is randomly
selected based for each scenario the resultant carbon price is adjusted up or down to
reflect the natural gas price forecast in a manner to attain the required carbon mitigation
goal. An example of this adjustment is in Figure 7.9 for the year 2020. The predominant
market prices are between $40 and $49 per short ton of carbon. The distribution
reflected the Carbon Tax policy strategy by approximately 100 of these iterations has a
price of $42.12 per short ton of carbon.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.9: Distribution of Annual Average Carbon Prices for 2020
Natural Gas
Natural gas prices are among the most highly volatile of any traded commodity. Daily
AECO prices ranged between $0.78 and $12.92 per Dth between 2002 and 2010.
Average AECO monthly prices since December 1999 are in Figure 7.10. Prices
retreated from their 2008 highs to a low of $2.69 per Dth in July 2009, but prices have
stabilized in the $3 to $4 range over the past year. This stabilization likely is a result of
both waning demand due to the U.S. recession and shale gas discoveries.
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.10: Historical AECO Natural Gas Prices
There are several valid methods to stochastically model natural gas prices. For this IRP,
Avista uses a new method to represent the price history our industry has witnessed.
The mean prices discussed above are the starting point. Prices then vary using
historical month-to-month volatility using a lognormal distribution. The lognormal
distribution’s standard deviation differs monthly depending on historical month-to-month
changes.
The Stanfield hub natural gas price distribution is in Figure 7.11 for 2012, 2020, and
2030. Mean prices in 2012 are $4.89 per Dth and the median level is $4.80 per Dth. The
90th percentile is $5.49 per Dth and the TailVar90, or average of the highest 10 percent
of the iterations, is $5.92 per Dth. Figure 7.12 illustrates the range of gas prices for each
year of the price forecast. Stanfield prices are black bars; white bars represent the
range between the 10th and 90th percentiles; triangles represent TailVar90.
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.11: Stanfield Annual Average Natural Gas Price Distribution
Figure 7.12: Stanfield Natural Gas Distributions
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Avista Corp 2011 Electric IRP
Load
Several factors drive load uncertainty. The largest short-run driver run is weather. Over
the long-run economic conditions, such as the recent economic downturn, tend to have
a more significant effect on the load forecast. Underlying IRP loads increase at the
levels discussed earlier in this chapter, but risk analyses emulate the varying of weather
conditions and resultant load impacts.
To model weather variation, Avista continues to use a method it adopted for its 2003
IRP. FERC Form 714 data for the years 2005 through 2009 for the Western
Interconnect form the basis for the analysis. Correlations between the Northwest and
other Western Interconnect load areas represent how loads move across the larger
system. This method avoids oversimplifying the Western Interconnect load picture.
Absent the use of correlation, stochastic models merely offset changes in one variable
with changes in another, thereby virtually eliminating the possibility of modeling
correlated excursions. Given the high degree of interdependency across the Western
Interconnect created by significant intertie connections, the additional accuracy in
modeling loads in this matter is crucial for understanding variation in wholesale
electricity market prices. It is also crucial for understanding the value of resources used
to meet variation (i.e., peaking generation).
Tables 7.6 and 7.7 present the load correlations. Statistics are relative to the Northwest
load area (Oregon, Washington, and North Idaho). ―NotSig‖ in the table indicates that no
statistically valid correlation exists in the evaluated load data. ―Mix‖ indicates the
relationship was not consistent across the 2005 to 2009 period. For regions and periods
with NotSig and Mix results, no correlation exists. Tables 7.8 and 7.9 provide the
coefficient of determination (standard deviation divided by the average) values for each
zone. The weather adjustments are consistent for each area, except for shoulder
months where loads tend to diverge from one another.
Table 7.6: January through June Area Correlations
Jan Feb Mar Apr May Jun
Alberta 74% 29% 70% 64% 18% 65%
Arizona 73% 75% 74% 8% Not Sig 8%
Avista 90% 87% 82% 80% 60% 42%
British Columbia 84% 84% 75% 46% Not Sig Mix
Colorado Mix Mix Mix Mix Not Sig Not Sig
Montana 82% 76% 69% 55% 33% 28%
New Mexico 8% Not Sig Not Sig Not Sig 16% Not Sig
North California 34% 36% 8% Not Sig 34% 8%
North Nevada 73% 65% Not Sig 8% 25% 27%
South California 74% 45% 69% 31% 10% 44%
South Idaho 87% 86% 65% 40% 66% 28%
South Nevada 67% 83% 37% Not Sig Mix 16%
Utah 25% Not Sig 8% Not Sig 17% Not Sig
Wyoming 67% 54% 72% 36% 41% 18%
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Table 7.7: July through December Area Correlations
Jul Aug Sep Oct Nov Dec
Alberta 39% 45% 68% 55% 66% 66%
Arizona 9% 26% 9% Mix Mix 55%
Avista 60% 54% 19% 78% 88% 89%
British Columbia 8% Mix Mix 9% 72% 77%
Colorado Mix Mix Mix 54% 71% 49%
Montana Mix Not Sig 27% 53% 81% 86%
New Mexico 25% 27% 43% 17% 35% Not Sig
North California Not Sig Mix 63% Not Sig 26% 25%
North Nevada 29% 48% Not Sig 8% 74% 67%
South California 26% 27% 18% Not Sig Mix 54%
South Idaho 44% 47% Not Sig 46% 84% 83%
South Nevada 16% 18% Not Sig Mix Mix 64%
Utah Not Sig 16% 42% 27% 53% 17%
Wyoming 8% 9% 9% 8% Not Sig 53%
Table 7.8: Area Load Coefficient of Determination (Std Dev/Mean)
Jan Feb Mar Apr May Jun
Alberta 2.7% 2.4% 2.8% 2.6% 2.9% 3.2%
Arizona 5.5% 4.2% 3.4% 6.1% 10.2% 9.5%
Avista 6.7% 5.3% 6.3% 5.6% 5.3% 6.4%
Baja Mexico 9.5% 7.9% 8.5% 9.2% 10.5% 7.6%
British Columbia 5.0% 3.9% 4.5% 5.2% 4.6% 4.0%
North California 5.1% 5.1% 5.0% 5.6% 8.7% 9.5%
Colorado 4.5% 4.2% 4.6% 4.0% 5.4% 8.4%
South Idaho 5.4% 5.7% 5.4% 6.0% 10.2% 13.9%
Montana 5.3% 4.1% 4.0% 4.4% 4.0% 5.9%
Northern Nevada 2.6% 3.0% 2.9% 2.8% 4.8% 5.7%
Southern Nevada 4.8% 3.6% 3.3% 6.6% 13.0% 11.2%
New Mexico 4.5% 4.1% 4.3% 4.5% 7.4% 6.9%
Pacific Northwest 6.6% 5.9% 5.9% 5.7% 4.9% 4.9%
South California 6.0% 5.6% 6.0% 7.0% 8.6% 8.8%
Utah 4.1% 4.3% 4.5% 4.4% 6.3% 9.0%
Wyoming 7.0% 6.7% 6.5% 5.9% 5.0% 8.3%
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Table 7.9: Area Load Coefficient of Determination (Std Dev/Mean)
Jul Aug Sep Oct Nov Dec
Alberta 3.1% 3.2% 2.8% 2.7% 2.6% 3.3%
Arizona 7.0% 6.5% 8.4% 10.0% 4.7% 5.3%
Avista 6.9% 7.2% 5.8% 5.4% 6.6% 7.6%
Baja Mexico 6.4% 6.3% 11.6% 9.9% 7.6% 10.2%
British Columbia 4.7% 4.1% 4.4% 5.0% 6.2% 6.2%
North California 9.6% 7.9% 8.4% 5.3% 5.6% 5.6%
Colorado 7.2% 6.8% 5.8% 4.0% 5.1% 5.0%
South Idaho 5.9% 6.9% 10.5% 4.7% 6.8% 7.1%
Montana 5.1% 5.6% 3.7% 4.0% 5.0% 5.7%
Northern Nevada 5.1% 4.2% 4.9% 2.7% 3.6% 3.5%
Southern Nevada 6.9% 6.3% 12.0% 7.8% 3.8% 4.4%
New Mexico 6.0% 5.7% 5.8% 5.3% 5.0% 4.9%
Pacific Northwest 6.5% 5.2% 4.6% 5.3% 7.0% 8.6%
South California 7.7% 7.8% 10.3% 7.4% 6.8% 6.4%
Utah 5.1% 6.2% 6.7% 4.1% 4.9% 4.4%
Wyoming 8.3% 9.1% 6.1% 5.3% 7.1% 7.6%
Hydroelectric
Hydroelectric generation is historically the most commonly modeled stochastic variable
in the Northwest because it has a large impact on regional electricity prices. The IRP
uses a 70-year hydro record starting with the 1928-29 water year. A randomly drawn
water year is selected from the record using a ―bootstrapping‖ method, meaning that
each water year is used approximately 143 times in the study (500 scenarios x 20 years
/ 70 water year records). There is some debate in the Northwest over whether the
hydroelectric record has year-to-year correlation. Avista’s preliminary work in this area
has not found significant year-over-year correlation; the 70-year water record shows a
modest 41 percent correlation. Low correlation does not necessarily mean that the
correlation is zero. Further study of year-to-year correlation is an action item coming out
of this planning cycle.
Wind
Wind has the most volatile short-term generation profile of any resource presently
available to utilities. Storage, apart from some integration with hydroelectric projects, is
not a financially viable. This makes it necessary to capture wind volatility in the power
supply model to determine its value and impacts on the wholesale power markets.
Accurately modeling wind resources requires hourly and intra-hour generation shapes.
For regional market modeling, the representation is similar to how AURORAxmp models
hydroelectric resources. A single wind generation shape represents all wind resources
in each load area. This shape is smoother than it would be for individual wind plant, but
it closely represents the diversity that a large number of wind farms located across a
zone would create.
This simplified wind methodology works well for forecasting electricity prices across a
large market, but it does not accurately represent the volatility of specific wind resources
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Avista might select as part of its Preferred Resource Strategy. Therefore individual wind
farm shapes form the basis of resource options for Avista.
Ten potential 8,760-hour wind shapes represent each geographic region or facility.
Each year contains a wind shape drawn from the ten representations, as is done with
the hydro record. The IRP relies on two data sources for the wind shapes. The first is
BPA balancing area wind data. The second is NREL-modeled data between 2004 and
2006.
Avista believes that an accurate representation of a wind shape across the West
requires meeting several conditions:
1. The data is correlated between areas and reflective of history.
2. Data within load areas needs to be auto-correlated (each hour correlated to each
other).
3. The average and standard deviation of each load area’s wind capacity factor
needs to be consistent with the expected amount of energy for a particular area
in the year and in each month.
4. The relationship between on- and off-peak wind energy needs to be consistent
with historic wind conditions. For example, more energy in off-peak hours than
on-peak hours where this has been experience historically.
5. Capacity factors for a diversified wind region should never be greater than about
90 percent due to turbine outages and wind diversity within-area.
Absent meeting these conditions, it is unlikely that any wind study provides an adequate
level of accuracy for planning efforts. The methodology developed for this IRP attempts
to keep the five requirements by first using a regression model of the historic data for
each region. The independent variables used in the analysis were month, hour type
(night or day), and generation levels from the prior two hours. To reflect correlation
between regions, a capacity factor adjustment reflects historic regional correlation using
an assumed normal distribution with the historic correlation as the mean. After this
adjustment, a capacity factor adjustment takes account of those hours with generation
levels exceeding a 90 percent capacity factor. The resulting capacity factors for each
region are in Table 7.10. A Northwest region example of an 8,760-hour wind generation
profile is in Figure 7.13. This example, shown in blue, has a 33 percent capacity factor.
Figure 7.14 shows actual 2010 generation recorded by BPA Transmission; in 2010, the
average wind fleet in BPA’s balancing authority had a 27.5 percent capacity factor.
Table 7.10: Expected Capacity factor by Region
Region
Capacity
Factor Region
Capacity
Factor
Northwest 32.0% Southwest 28.9%
California 30.9% Utah 28.8%
Montana 37.2% Colorado 32.2%
Wyoming 38.5% British Columbia 33.4%
Eastern Washington 30.7% Alberta 34.5%
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.13: Wind Model Output for the Northwest Region
Figure 7.14: 2010 Actual Wind Output BPA Balancing Authority6
There is speculation that a correlation exists between wind and hydro, especially
outside of the winter months where storm events bring both rain to the river system and
wind to the wind farms. This IRP does not correlate wind and hydro due to a lack of
historical data to test this hypothesis. Where correlation exists, it would be optimal to
run the model 70 historical wind years with matching historical water years. A continual
study of this relationship is an action item for this plan.
Forced Outages
In most deterministic market modeling studies, plant forced outages are represented by
a simple average reduction to maximum capability. This over simplification generally
represents expected values well; however, in stochastic modeling, it is better to
represent the system more accurately by randomly placing non-hydro units out of
service based on a mean time to repair and an average forced outage rate. Internal
6 Chart data is from the BPA at: http://transmission.bpa.gov/Business/Operations/Wind/default.aspx.
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studies show that this level of modeling detail is necessary only for large natural gas-
fired (greater than 100 MW), coal, and nuclear plants. Forced outage rates and the
mean time to repair data come from analyzing the North American Electric Reliability
Corporation’s Generating Availability Data System (GADS) database.
Other Variables
Coal, hog fuel, fuel oil, and variable O&M variables are modeled stochastically. These
included either normal or lognormal distributions in the study. Due to their moderate
affects on market prices, their details are not discussed here but are in Appendix A.
Market Price Forecast
An optimal resource portfolio cannot ignore the extrinsic value inherent in its resource
choices. The 2011 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 electricity prices are either the operating cost of the marginal unit in the
Northwest or the economic cost to move power into or out of the Northwest. 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 a
summation of the capacity needs of individual utilities in the region. Western regions
can have resource surpluses even where some utilities may be in deficit. This
imbalance can be due in part to ownership of regional generation by independent power
producers, and possible differences in planning methodologies used by utilities in the
region.
AURORAxmp assigns market values to each resource alternative available to the PRS,
but the AURORAxmp 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 analysis to help determine an
optimal resource strategy. Risk analysis uses several market price forecasts with
different assumptions than the expected case or changes the underlying statistics of a
study. The modeling splits alternate cases are into stochastic and deterministic studies.
A stochastic study uses Monte Carlo analysis to quantify the variability in future market
prices. These analyses include 500 iterations of varying natural gas prices, loads,
hydroelectric generation, thermal outages, wind generation shapes, and greenhouse
gas emissions prices. Four stochastic studies—an Expected Case, one case without
greenhouse gas limitations, a high natural gas volatility case, and an early coal plant
retirement case are used. The remaining studies were deterministic scenario analyses.
Mid-Columbia Price Forecast
The Mid-Columbia is Avista’s primary electricity trading hub. The Western Interconnect
also has trading hubs on the California/Oregon Border (COB), Four Corners, Palo
Verde, SP15 (southern California), NP15 (northern California) and Mead. The Mid-
Columbia market is usually least cost because of low cost hydroelectric generation,
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
though other markets can at times be less expensive when Rocky Mountain area
natural gas prices are low and gas-fired generation is setting marginal power prices.
Fundamentals-based market analysis is critical to understanding the market
environment. The Expected Case includes two studies. The first is a deterministic
market view using expected levels for the key assumptions discussed in the first part of
this chapter. The second is a risk or stochastic study with 500 unique scenarios based
on different underlining assumptions for gas prices, load, greenhouse gas emissions
prices, wind generation, hydroelectric generation, forced outages, and others. Each
study simulates the entire Western Interconnect hourly between 2012 and 2031. The
analysis used 18 central processing units (CPUs) linked to a SQL server to simulate the
studies, creating over 45 GB of data requiring 2,000 hours of computing time.
The resultant average market prices developed from the stochastic model are similar to
the results from the deterministic model. Figure 7.15 shows the stochastic market price
results as the horizontal bar and the vertical bars represent the 10th and 90th percentile
for annual average prices. The triangle represents the Tail Var 90. The nominal
levelized price for the 20-year expected prices is $70.50 per MWh. The deterministic
prices are $0.87 per MWh lower than the stochastic prices presented in Figure 7.15.
Figure 7.15: Mid-Columbia Electric Price Forecast Range
The annual averages of the stochastic case on-peak, off-peak and levelized prices are
in Table 7.10. The Mid-Columbia market price averages $70.50 per MWh over the next
20 years. The 2009 IRP annual average nominal price was $93.74 per MWh. Spreads
between on- and off-peak prices are $11.48 per MWh over 20 years.
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Table 7.11: Annual Average Mid-Columbia Electric Prices ($/MWh)
2012 40.87 36.51 44.16
2013 46.13 41.19 49.84
2014 49.11 43.62 53.23
2015 59.86 54.08 64.19
2016 63.25 57.12 67.84
2017 64.53 58.65 68.96
2018 66.55 60.33 71.21
2019 68.26 62.03 72.92
2020 71.05 64.56 75.91
2021 74.88 68.30 79.81
2022 80.49 73.65 85.62
2023 86.28 79.24 91.59
2024 91.26 83.55 97.04
2025 93.71 85.18 100.10
2026 91.35 83.08 97.54
2027 91.37 83.17 97.52
2028 98.30 89.92 104.63
2029 102.25 93.52 108.80
2030 107.56 97.77 114.89
2031 110.55 99.90 118.53
Greenhouse Gas Emission Levels
Greenhouse gas levels increase over the study period absent social policies intended to
reverse the trend. The compliance costs of meeting potential greenhouse gas mitigation
discussed earlier in this chapter provide price signals to encourage reductions in
greenhouse gas emissions. Figure 7.16 shows the expected greenhouse gas emissions
from the 500 market forecast simulations. The average level of greenhouse gas
emissions from electric generation decrease by 11.2 percent over the 20-year study.
The figure also includes the 10th and 90th percentile statistics of the dataset. As
discussed earlier, ten percent of the cases assume no future carbon mitigation policies;
in these cases the incremental emissions are partly offset by now-expected coal plant
retirements7, low natural gas prices, and increased in wind generation that make coal
resources uncompetitive in some months of the forecast.
7 Recently announced retirements included in the 2011 IRP are 1,561 MW in Colorado, 585 MW in
Oregon, and 172 MW in Utah. The 2011 IRP analyses occurred prior to the announcement of the future
closure of the 1,376 MW Centralia Coal Plant in Washington State. Its closure should further carbon
emission reductions beyond those projected in this plan.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.16: Western States Greenhouse Gas Emissions
Resource Dispatch
State-level RPS goals and greenhouse gas legislation will change resource dispatch
decisions and affect future power prices. The Northwest already is witnessing the
market-changing effects of a 5,000+ MW wind fleet. Figure 7.17 illustrates that natural
gas fuels 23 percent of total generation in 2012, and 41 percent in 2031. Coal
generation decreases from 30 percent of Western Interconnect generation in 2012 to 13
percent in 2031. Solar and wind increase from 5 percent in 2012 to 13 percent in 2031.
New renewable generation sources offset coal generation reductions, but natural gas-
fired resources meet load growth.
Public policy changes to encourage renewable energy development and reduce
greenhouse gas emissions have the potential to change the electricity marketplace. On
its present trajectory, policy changes are likely to move the generation fleet toward its
potentially most volatile contributor—natural gas. These policies will displace low-cost
coal-fired generation with higher-cost renewables and gas-fired generation having lower
capacity factors (wind) and higher marginal costs (natural gas). If history is our guide,
regulated utilities will recover their costs from stranded coal plants, requiring customers
to pay even more. Further, wholesale prices likely will increase with the effects of the
changing resource dispatch driven by carbon emission limitations. New environmental
policy driven investment, combined with higher market prices, will necessarily lead to
retail rates that are higher than they would be absent greenhouse reduction policies.
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.17: Base Case Western Interconnect Resource Mix
Scenario Analysis
Scenario analysis evaluates the impact of specific changes in underlying assumptions
on the market. Four stochastic studies were performed to help understand potential
market price changes and to examine the potential risk to Avista’s PRS if certain
assumptions were changed. The scenarios studied used 500 iterations to model the
effects of unconstrained carbon emissions, doubling of natural gas price volatility, and
the early retirement of coal plants. In addition to the stochastic market scenarios,
deterministic scenarios explained the impacts of low natural gas prices, high natural gas
prices, and high wind penetration. Prior IPRs used market scenarios to stress test the
PRS. Since the PRS accounts for a range of possible outcomes in its risk analysis, the
market scenario section is more limited in this IRP. Additional scenarios illustrate the
impacts potential policies might have on the industry, and how Avista could respond.
Unconstrained Carbon Emissions
The Unconstrained Carbon Emissions scenario is necessary to quantify projected
greenhouse gas policy costs. The first study is a deterministic scenario. A second
stochastic study models 500 individual iterations of varying natural gas prices, loads,
wind generation, forced outages, and hydroelectric conditions. The assumptions are
similar to the Expected Case with a few notable exceptions. First, natural gas prices are
lower because of less demand for natural gas caused by the continued use of coal-fired
generation. Without carbon legislation, natural gas prices are $0.52 per Dth lower
levelized over 20 years, a 7.1 percent decrease.
Without projected greenhouse gas mitigation, Mid-Columbia market prices are lower
and the total cost to serve customers is lower. The average of the 500 simulations finds
Hydro
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Avista Corp 2011 Electric IRP
wholesale market prices $17.64 per MWh lower, on a nominal levelized basis,
compared to the Expected Case; this represents a 33.4 percent market price increase
for greenhouse gas emissions mitigation (Figure 7.18). The total cost of fuel in the
Western Interconnect with greenhouse gas mitigation is 7.65 percent higher than
without the greenhouse gas mitigation.
Figure 7.18: Mid-Columbia Prices Comparison with and without Carbon Legislation
Figure 7.19 illustrates the difference between greenhouse gas emissions with and
without the emissions costs included in the Expected Case. Based on the model results
and assumptions, emissions would be 8.5 percent higher in 2020 and 21.5 percent
higher in 2031 without the assumed greenhouse gas penalty. Increased greenhouse
gas emissions from higher coal-fired dispatch levels are the cause (see Figure 7.20).
The Expected Case, which includes greenhouse gas costs, reduces coal dispatch by 36
percent compared to the unconstrained greenhouse gas scenario, while natural gas
generation production increases by 19 percent.
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Chapter 7- Market Analysis
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Figure 7.19: Western U.S. Carbon Emissions Comparison
Figure 7.20: Unconstrained Carbon Scenario Resource Dispatch
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Alternative Greenhouse Gas Mitigation Methods
As part of the development of the Expected Case’s four greenhouse gas policies,
market simulations were conducted to calculate the price of greenhouse gas required to
meet the reduction goal. Figure 7.8, shown earlier, illustrates the prices required to meet
the goals. Figure 7.21 illustrates the corresponding forecasted electric market prices at
Mid-Columbia on an average annual basis. The Expected Case line is the average of
the 500 simulations and the other lines represent the deterministic study results for each
greenhouse gas policy modeled. The values shown in Figure 7.22 are discounted and
levelized over the 20-year study period to represent the average price of power.
Figure 7.21: Average Annual Mid-Columbia Electric Prices for Alternative Greenhouse
Gas Policies
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.22: Nominal Levelized Mid-Columbia Electric Prices for Alternative Greenhouse
Gas Policies
Figure 7.23 shows the annual expected greenhouse gas emissions levels for each of
the policies in. The four potential outcomes represent a range of futures under different
forms of greenhouse gas emissions legislation.
Figure 7.23: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas Policies
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No Carbon Policy
Expected Case
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Mandatory Coal Retirement
Proposed federal greenhouse gas cap and trade legislation is not law. The
Environmental Protection Agency and other organizations have pursued alternative
methods to reduce greenhouse gases from electric generation through regulatory
means. More details surrounding these policy alternatives are in the Planning
Environment chapter. The goal of this scenario is to illustrate the affect on electricity
market prices and system fuel costs where a policy is put in place requiring all coal
plants to retire at the end of 40 years of life, or to be phased out by 2020 if the plant is
already over 40 years old. The study uses 500 iterations as conducted on other studies.
In Figure 7.24 the average annual prices for this scenario are compared to the Expected
Case. The resulting prices levelized are $57.01 per MWh, 19 percent lower than the
Expected Case and 27 percent lower than the National Cap and Trade Strategy. The
surprising fact about this greenhouse gas policy is that Mid-Columbia prices are only 7.3
percent higher than the no carbon penalty case and the policy still achieves substantial
greenhouse gas reductions as shown in Figure 7.25. The driver of these results is that
natural gas-fired units face no carbon costs. Without the emissions adder to natural gas,
the marginal price of power remains as a natural gas-fired plant, and the increase in
power cost is more driven by the increased demand driving natural gas prices higher
and the inclusion of less low cost base load capacity in shoulder months. Although
lower market prices make this greenhouse gas strategy appealing, it does have a
negative consequence.
In Table 7.12 annual incremental costs of each potential strategy are compared and the
Early Coal Plant Retirement strategy is $3.2 billion more costly for the Western
Interconnect as compared to the National Cap and Trade strategy. This increase results
from the forced addition of new resources to replace coal plants rather than letting coal
plants remain on line, but instead dispatching them much less frequently, thus avoiding
new capital investment. One thing to keep in mind, is this a 20 year study of the western
interconnect. A longer-term national model may illustrate different results. Taking into
account national economics may also change opinions on the results as well. In the
end, any greenhouse reduction strategy needs to be a low cost solution that does not
affect the electricity marketplace in a negative manner.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.24: Average Annual Mid-Columbia Price Comparison of Greenhouse Gas
Policies
Figure 7.25: Expected Greenhouse Gas Emissions Comparison
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Table 7.12: Impacts of Greenhouse Gas Mitigation Policies in the West
Unconstrained Greenhouse Gas Case 14% 0.0
Expected Case -18% 3.5
Coal Mandatory Retirement -22% 8.1
National Cap & Trade -29% 4.9
High and Low Natural Gas Price Scenarios
The High and Low Natural Gas Price scenarios illustrate Mid-Columbia electric prices
for differing natural gas prices. These scenarios maintain carbon emissions at the same
level as the Expected Case to determine carbon prices at lower natural gas prices.
Figure 7.4, located earlier in the chapter, shows the low and high natural gas price
forecasts used in this scenario as Consultant 1 and Consultant 2 prices. Using these
prices, the resulting greenhouse gas price forecast assuming a cap and trade
mechanism that achieves the same reductions as the Expected Case is in Figure 7.26.
The natural gas prices in this scenario are approximately plus or minus 20 percent
compared to the Expected Case, but greenhouse gas prices must increase or decrease,
respectively, by approximately 31 percent to achieve the same greenhouse gas levels
as the Expected Case. The Mid-Columbia market price forecasts for the high and low
natural gas price cases are in Figure 7.27. The nominal levelized electric price for the
low gas price case is $57.00 per MWh and $82.17 per MWh for the high gas price case.
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.26: Natural Gas Price Scenario’s Greenhouse Gas Emission Prices
Figure 7.27: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Wind Proliferation and Negative Pricing
Avista uses the IRP process to identify and understand the impacts of potential market
changes, rather than only focusing on Avista’s PRS. In past IRPs, Avista has studied
the market impacts of electric cars and the addition of large amounts of solar generation
to the grid. For this IRP, the non-PRS study focuses on the growing penetration of wind
generation in the Northwest. 2015 was chosen as the period for this study and includes
four sensitivities; the sensitivity included 100 iterations of potential outcomes.
The sensitivities in this case range from 7,000 MW to 17,000 MW (additions of between
zero MW and 10,000 MW to the Expected Case wind penetration forecast) of total wind
capacity in the Northwest. Currently, there is approximately 5,000 MW in the four
northwest states and the Expected Case includes approximately 7,000 MW of wind by
2015. The key results of this study include the change in market prices, the amount of
negative price episodes, and the overall effect of additional wind generation on the
margins of existing Avista facilities.
The first major change to the power market by high wind penetration is the change to
wholesale market prices. Based on the average of the 100 iterations of each case,
Figure 7.28 illustrates the percent change to Mid-Columbia average monthly prices in
cases that increase wind capacity by 2,000, 5,000, and 10,000 MW above the Expected
Case forecast. The major price changes occur in the second quarter of the year. On
average, market price changes are 2 percent lower than the Expected Case with 2,000
MW of additional wind by 2015, 7 percent lower with 5,000 MW, and 11 percent lower
with 10,000 MW.
Figure 7.28: Wind Sensitivity Mid-Columbia Price Changes
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
The reduction in overall wholesale prices comes substantially from negative prices.
Negative pricing can occur when resources must operate irrespective of the price
offered in the wholesale marketplace, and when a resource receives economic benefit
for generation beyond market prices (tax credits and RECs). In some markets negative
prices occur when certain base-load generation resources (e.g., nuclear plants) in total
exceed nighttime loads but must be operated to ensure their availability during the next
day’s peak demand periods. Negative pricing is an issue today in the Northwest when
the region’s hydroelectric system is experiencing high flow condition (generally during
spring runoff) and when there is no wind generation curtailment.
Many hydroelectric facilities must generate electricity and not spill water under varying
licensing requirements. This situation compounds when generation resources, such as
wind, receive federal production tax and renewable energy credits. Wind facilities in the
Expected Case contribute to 193 hours of negative prices, or 2.2 percent of the hours,
as shown in Figure 7.29. With 2,000 MW of additional wind capacity, the frequency of
negative pricing increases to 3.2 percent. With 5,000 MW, prices fall by 6.1 percent.
And with 10,000 MW, prices fall by 9.7 percent.
Figure 7.29: Wind Sensitivity Negative Pricing
The final item reviewed as part of this high wind penetration study is the effect to the
profitability of non-wind and hydro resources and total power supply costs. Figure 7.30
shows that Avista’s coal-fired, combined cycle natural gas-fired, and hydroelectric
revenues decline, but that the value of gas-fired peaking resources will increase. The
estimated impact of increased wind penetration to Avista net power supply cost is a net
increase between 0.03 percent and 0.37 percent.
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Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP
Figure 7.30: Change to Resource Revenues
Market Analysis Summary
Market analysis is a key component of the IRP. The market is where Avista trades its
electricity surpluses and deficits. It is difficult to examine all potential resources
evaluated by Avista for possible inclusion in the PRS without a firm understanding of the
marketplace and how public policy and changes to resource and cost assumptions
affect the market. As prices have declined since the 2009 IRP, and have the potential to
fall farther, the market price forecasts could have an effect on the cost to bring new
resources on to the Avista system and their potential rate effects.
New legislation and regulations affecting the electric system are on the horizon.
Regardless of policies to decrease greenhouse gas emissions, make generation
greener, promote energy independence or affect reliability—power costs will increase
because new capacity and transmission resources are needed to replace aging
infrastructure and serve new load growth. Greenhouse gas emissions and RPS
legislation will diversify fuel supplies, but will also increase demand for natural gas-fired
resources. Policymakers and the public will need to determine if the ultimate benefits of
these types of legislation outweigh the increased costs.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-1
8. Preferred Resource Strategy
Introduction
The Preferred Resource Strategy (PRS) chapter describes potential costs and financial
risks of the Company’s resource acquisition strategy. It details the planning and
resource decision methodologies, describes strategy, considers climate change policy,
and shows how the strategy may evolve if certain expected future conditions change.
The 2011 PRS describes a reasonable low-cost plan along the efficient frontier of
potential resource portfolios accounting for fuel supply risk, price risk, and greenhouse
gas mitigation. Major changes from the 2009 plan include reduced amounts of wind
generation and the introduction of natural gas-fired peaking resources. The plan
includes less wind because of lower expected retail loads resulting from the present
economic downturn and increased conservation acquisition. Expected wind generation
needs are lower due to a modest change in the modeling method used to represent
annual variability from RPS-qualifying resources. The selection of gas-fired peaking
resources resulted from a lower natural gas price forecast, lower retail loads, and the
need for more flexible generation resources to manage the variability associated with
renewable generation.
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 2001 and its replacement with natural gas-fired projects
(see Figure 8.1). After the Centralia sale, Avista acquired 32 MW of gas-fired peaking
capacity and 287 MW of intermediate load gas-fired capacity. In addition, Avista
contracted for 35 MW of wind capacity from the Stateline Wind Project and added 42
MW of new capacity to its hydroelectric fleet through project upgrades. Avista gained
control of the output for the 270 MW Lancaster Generating Facility through a long-term
Section Highlights
fulfill Avista’s
Avista’s first load
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-2
tolling arrangement on January 1, 2010. The Company plans to upgrade its Nine Mile
Falls project. The upgrade could involve replacement with in-kind equipment or a new
powerhouse. Avista plans to complete the last turbine runner upgrade at Noxon Rapids
in 2012, adding seven MW (1 aMW) to the project’s capability.
Figure 8.1: Resource Acquisition History
Resource Selection Process
Avista uses several decision support systems to develop its resource strategy. The PRS
relies on results from the PRiSM model whose objective function is to meet resource
deficits while accounting for overall cost, risk, renewable energy requirements, and
other constraints. The AURORAxmp model, discussed in detail in the Market Analysis
chapter, calculates the operating margin (value) of every resource option considered in
each of 500 potential future outcomes. PRiSM evaluates resource values by combining
operating margins with capital and fixed operating costs. From an efficient frontier,
Avista selects a resource mix meeting all capacity, energy, RPS, and other
requirements.
PRiSM
Avista staff developed the PRiSM model in 2002 to support PRS selection. PRiSM uses
a linear programming routine to support complex decision making with multiple
objectives. Linear programming tools provide optimal values for variables, given system
constraints.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-3
Overview of the PRiSM Model
The PRiSM model requires a number of inputs:
1. Expected Future Deficiencies
o Summer 18-hour capacity
o Winter 18-hour capacity
o Annual energy
o I-937 RPS Requirements
2. Costs to Serve Future Retail Loads
3. Existing Resource Contributions
o Operating margins
o Carbon emission levels
4. Resource Options
o Fixed operating costs
o Return on capital
o Interest expense
o Taxes
o Generation levels
o Emission levels
5. Limitations
o Market reliance (surplus/deficit limits on energy, capacity and RPS)
o Resources available to meet future deficits
o Resource retirement limits (function disabled for 2011 IRP)
o Capital expenditure limits (function disabled for 2011 IRP)
o Emission levels (function disabled for 2011 IRP)
PRiSM uses these inputs to develop an optimal resource mix over time at varying levels
of cost and resultant risk levels. It weights the first decade more heavily than the later
years to highlight the importance of near-term decisions. A simplified view of the PRiSM
linear programming objective function is below.
PRiSM Objective Function
Minimize: (X1 * NPV2012-2022) + (X2 * NPV2012-2031) + (X3 * NPV2012-2061)
Where: X1 = Weight of net costs over the first 10 years (75 percent)
X2 = Weight of net costs over 20 years of the plan (20 percent)
X3 = Weight of net costs over the next 50 years (5 percent)
NPV is the net present value of total cost (existing resource marginal
costs, all future resource fixed and variable costs, and all future
conservation costs and the net short-term market sales/purchases).
An efficient frontier captures the optimal mix of resources, given varying levels of cost
and risk. Figure 8.2 illustrates the efficient frontier concept. The optimal point on the
efficient frontier curve depends on the level of risk Avista and its customers are willing to
accept. Environmental legislation, cost, regulation, and the availability of commercially
ready technologies greatly limit utility-scale resource options. The model does not meet
deficits with market purchases, or allow the construction of resources in any increment
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-4
needed.1 Instead, the model uses market purchases to fill short-term gaps and
constructs resources in block sizes equal to the actual project capacities.
Figure 8.2: Conceptual Efficient Frontier Curve
Constraints
As discussed earlier in this chapter, reflecting real-world constraints in the model is
necessary to create a realistic representation of the future. Some constraints are
physical and others are societal. The major resource constraints are capacity and
energy needs, Washington’s RPS, and the greenhouse gas emissions performance
standard.
The PRiSM model is limited to choosing resources by type and by size. It can select
from combined- and simple-cycle natural gas-fired combustion turbines, wind, and
upgrades to existing thermal resources, and conservation. Sequestered and non-
sequestered coal plants are not an option in this IRP because of Washington’s
emissions performance standard. Detailed hydroelectric upgrade potentials were not
available during PRS development and are not included as resource options.
Washington’s RPS fundamentally changed how the Company meets future loads.
Before the addition of an RPS obligation, the efficient frontier contained a least-cost
strategy on one axis and the least-risk strategy on the other axis, and all of the points in
between. Next, management used the efficient frontier to determine where they wanted
to be on the cost-risk continuum. The least cost strategy typically consisted of gas-fired
1 Market reliance, as identified in Section 2, is determined prior to PRiSM’s optimization.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-5
peaking resources. Portfolios with less risk generally replaced some of the gas-fired
peaking resources with wind generation, other renewables, combined cycle gas-fired
plants, or coal-fired resources. Past IRPs identified resource strategies that included all
of these risk-reducing resources.
Added environmental and legislative constraints greatly reduce the ability to reduce
future costs and/or risks and require the procurement of renewable generation
resources that previously were included for risk-mitigation. Because significant levels of
renewable generation are required under Washington law, the 2011 IRP strategy simply
complies with environmental and legislative constraints.
Resource Deficiencies
Avista no longer uses a one-hour peak planning methodology, instead using the peak
planning methodology recommended by the Northwest Power and Conservation
Council – three-day, 18-hour (6 hours each day) peak events occurring both in the
summer and winter. This method better emulates the Northwest and Avista’s actual
ability to meet short-term peak events with hydroelectric facilities. Avista accounts for
the regional view of surplus power and includes a pro-rata share of regional surpluses
when available. Finally, the peak planning methodology includes other operating
reserves and a planning margin.
Even with the new peak planning methodology, Avista currently projects having
adequate resources between owned and contractually controlled generation to meet
annual physical energy and capacity needs until 2016.2 See Figure 8.3 for Avista’s
physical resource positions for annual energy, summer capacity, and winter capacity.
This figure accounts for the effects of new energy efficiency programs on the load
forecast. Absent energy efficiency, our resource position would be deficient earlier. The
first capacity deficit is short-lived because a 150 MW capacity sale contract ends in
2016. Avista likely will address the 2016 capacity deficit with market purchases as 2016
approaches; therefore, the first long-term capacity deficit begins in the summer of 2019.
Avista’s resource portfolio has 281 MW of natural gas-fired peaking plants available to
serve winter loads and 201 MW available in the summer. For long-term planning, these
resources are available to generate energy at their full capabilities. Operationally, less
expensive wholesale marketplace purchases may displace Avista’s available resources.
On an annual average basis, our loads and resources fall out of balance in 2020 for
energy; the first quarterly energy deficit is in the first quarter of 2013.
PRiSM selects new resources to fill capacity and energy deficits, although the model
may over- or under-build where economics support it. Because of acquisitions driven by
capacity RPS compliance, large energy surpluses result. See Figure 8.3.
2 See Chapter 2 for further details on this peak planning methodology.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-6
Figure 8.3: Physical Resource Positions (Includes Conservation)
Renewable Portfolio Standards
Washington voters approved the Energy Independence Act through Initiative 937 (I-937)
in the November 2006 general election. I-937 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. The
Company has been participating in the UTC’s Renewable Portfolio Standard Workgroup
at the Washington Commission.
Avista expects to meet or exceed its renewable energy requirements between 2012 and
2015 through a combination of qualifying hydroelectric upgrades, the Palouse Wind
project, and a REC purchase. Projected REC positions are in Figure 8.43. I-937 includes
the flexibility to use RECs from the current year, from the previous year, or from the
following year for compliance. REC contingency reserves will be “banked” each year to
account for compliance variability driven by loads and hydroelectric and wind generation
variation. Projected requirements and new resources used to meet future RPS
obligations are in Table 8.31.
3 Figure 8.4 does not show the expected RECs from the Palouse Wind contract, which was signed after
the modeling for the 2011 was completed.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-7
Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State RPS
Preferred Resource Strategy
The 2011 PRS consists of existing thermal resource upgrades, wind, conservation, and
natural gas-fired simple and combined cycle gas turbines. The first resource acquisition
is approximately 42 aMW of wind by the end of 2012 to take advantage of federal tax
incentives.4
Avista will rebuild distribution feeders over the next twenty years. The PRS includes 27
MW of peak capacity savings and 13 aMW of energy savings from smart grid and
distribution feeder initiatives. More discussion on this topic is included in the distribution
upgrades section of the Transmission and Distribution chapter.
The PRiSM model selected an 83 MW simple cycle combustion turbine as its first large
capacity addition by the end of 2018. Another 83 MW simple cycle combustion turbine
follows by the end of 2020. Also in the 2018 to 20 period, existing thermal unit upgrades
add 4 MW of capacity. The PRS adds 43 aMW of additional wind by the end of 2019-20
to meet the 15 percent renewable energy goal.
The PRS includes a 270 MW natural gas-fired combined-cycle combustion turbine
(CCCT) in 2023, and another 270 MW CCCT in 2026, to meet projected capacity
deficits created by the expiration of the Lancaster tolling agreement. Following this need
is a 46 MW simple cycle turbine. In total, the PRS adds 1,024 MW of new generation
capacity by the end of the IRP forecast. Table 8.1 presents the 2011 PRS resource
types, timing and sizes.
4 Avista met this requirement through a 2011 RFP process that selected the Palouse Wind Project.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-8
Table 8.1: 2011 Preferred Resource Strategy
Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 120 35
SCCT 2018 83 75
Existing Thermal Resource Upgrades 2019 4 3
NW Wind 2019-2020 120 35
SCCT 2020 83 75
CCCT 2023 270 237
CCCT 2026 270 237
SCCT 2029 46 42
Total 996 739
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2012-2031 28 13
Energy Efficiency 2012-2031 419 310
Total 447 323
Table 8.2 shows the 2009 Preferred Resource Strategy. The major differences in the
2011 plan are a reduction in the quantity of wind resources and a switch to a
combination of simple and combined cycle resources from only combined cycle gas-
fired resources.
Table 8.2: 2009 Preferred Resource Strategy
Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
Northwest Wind 2012 150 48
Little Falls Unit Upgrades 2013-2016 3 1
Northwest Wind 2019 150 50
Combined-Cycle Combustion Turbine 2019 250 225
Upper Falls 2020 2 1
Northwest Wind 2022 50 17
Combined-Cycle Combustion Turbine 2024 250 225
Combined-Cycle Combustion Turbine 2027 250 225
Total 1,105 792
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2010-2015 5 3
Energy Efficiency 2010-2029 339 226
Total 344 229
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-9
Energy Efficiency
Energy efficiency is an integral part of the PRS analytical process. Energy efficiency is
also a critical component of I-937, where utilities are required to obtain all cost effective
conservation. Avista developed avoided energy costs and compared those figures
against a conservation supply curve developed by Global Energy Partners. The 20-year
forecast of energy efficiency acquisitions is in Figure 8.5. Avista plans to acquire 133
aMW of energy efficiency over the next 10 years and 310 aMW over 20 years. These
acquisitions will reduce system peak, shaving 207 MW from by 2022, and 419 MW in
2031. Please refer to Chapter 3 for a more detailed discussion of energy efficiency
resources.
Figure 8.5: Energy Efficiency Annual Expected Acquisition
Palouse Wind
On February 22, 2011, Avista issued a request for proposals (RFP) for I-937-qualifying
renewable energy. Following the RFP, Avista selected the Palouse Wind project located
between Rosalia and Oakesdale, Washington. The project will have a maximum
capability of approximately 100 MW and an expected annual average energy output of
40 aMW. The contract is a 30-year power purchase agreement with a purchase option
after year 10. The project should be on-line in the second half of 2012. This new
resource is not included in the PRS as it was under contract negotiation during the
development of this plan, this resource meets the PRS Northwest Wind resource need
in 2012.
Reardan Wind Project
Avista purchased development rights for a wind site located in its service territory near
Reardan, Washington, from Energy Northwest in 2008. The fully permitted site has
several years of meteorological data and is ready for construction. This wind site is
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-10
competitive to higher capacity factor sites, as the project does not require any third-
party transmission and is located near Avista work crews.5 This site could supply
between 50 MW and 100 MW of wind generation. With the acquisition of the Palouse
Wind project, development at Reardan is not likely prior to 2018-19.
Little Falls Hydro Upgrades
The 2009 PRS included 0.9 aMW of incremental energy from upgrades to the Little
Falls project between 2013 and 2016. When preparing this plan, Avista expected in-kind
turbine replacements and no incremental energy. Additional study and modeling
identified up to three aMW of incremental energy that will qualify for Washington’s
Energy Independence Act. Final decisions about the upgrades are still pending.
Analysis around this option continues and an update will be in the 2013 IRP.
Distribution Feeder Upgrades
Distribution feeder upgrades were in the PRS for the first time in the 2009 IRP. The
feeder upgrade process began with an upgrade to the Ninth & Central Streets feeder in
Spokane. The decision to rebuild a feeder considers energy savings, operation and
maintenance savings, the age of existing equipment, reliability indexes, and the number
of customers on the feeder. Based on analyses performed for this IRP, Avista likely will
rebuild many of its distribution feeders, limited to five or six per year due to financial and
staffing limitations. Feeder rebuild projects will begin in 2012 or 2013 and the Company
will allocate resources after prioritizing the projects. Savings are subject to change after
further detailed cost analyses and rebuild schedules are completed and more
information is provided in Chapter 5.
Simple Cycle Combustion Turbines
Avista plans to identify potential sites for new gas-fired generation capacity within its
service territory ahead of an anticipated 2019 need. Avista’s service territory has areas
with different combinations of benefits and costs. Locations in Washington would have
higher generation costs because of natural gas fuel taxes and carbon mitigation fees.
However, the potential benefits of a Washington location, including proximity to natural
gas pipelines and Avista’s transmission system; lower project elevations that provide
higher on-peak capacity contributions per investment dollar; and water to cool the
facility, might outweigh the costs. In Idaho, lower taxes and fees decrease the cost of a
potential facility, but there are fewer locations to site a facility near natural gas pipelines,
fewer low cost transmission interconnections, and fewer sites with adequate cooling
water. The identification and procurement of a natural gas project site option is an
Action Item for this IRP.
Loads and Resources Positions
Conservation acquisitions identified in this IRP reduce the load forecast, as shown in
Figure 8.6. The red line illustrates the Company’s load obligation absent energy
efficiency programs. Absent conservation, Avista would need new resources in 2018
rather than 2020.
5 Higher capacity factor wind sites are generally located outside of Avista’s service territory.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-11
Figure 8.6: Annual Average Load and Resource Balance
The first winter peak deficit without the conservation resource would occur in 2020, but
the deficit does not occur until 2022 with the acquisition of new energy efficiency
measures (see Figure 8.7). Avista expects to have modest short-term resource deficits
prior to 2022 and intends to meet these deficiencies with market purchases rather than
acquiring a resource prior to a sustained need. An analysis of regional loads and
resources support the Company’s position that existing regional capacity should be
available to support a robust short-term wholesale market in the timeframe required. A
capacity resource could replace market purchases, without a significant impact on the
long-term portfolio cost, if conditions change and the Company determines that it cannot
depend on the regional market surplus during this period.
The summer peak load and resource position shows a capacity need prior to the first
winter need. Avista’s peak loads are lower in summer than in the winter, but the impacts
on hydroelectric and thermal generation capacity in the summer, due to lower flow
conditions and high temperatures, are greater than the load differences. As shown in
Figure 8.8, summer resource deficits occur in 2013 without conservation and in 2016
(short-term) and 2019 (long-term) with conservation measures. The Company plans to
fill the short-term summer capacity deficit in 2016 with market purchases. Beginning in
2022, summer deficits no longer drive Avista’s capacity needs due to the expiration of
the WNP-3 contract in 2019.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-12
Figure 8.7: Winter Peak Load and Resource Balance
Figure 8.8: Summer Peak Load and Resource Balance
Under Washington regulation (WAC 480-107-15), utilities having generation capacity
deficits within three years of an IRP filing must also file a proposed Request for
Proposals (RFP) with the Washington Utilities and Transportation Commission (UTC).
The RFP is due to the UTC no later than 135 days after the IRP filing. After UTC
approval, bids to meet the anticipated capacity shortfall must be solicited within 30 days.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-13
Tables 8.28 and 8.29, shown later in this section, detail Avista’s capacity position over
the IRP timeframe. With a portion of loads met by Avista’s share of the regional capacity
surplus, Avista does not require winter capacity until 2022. A summer capacity
deficiency does not occur until 2016. Simplified summaries are below in Tables 8.3 and
8.4. They show Avista does not require capacity in the next three years; therefore an
RFP is not required under WAC 480-107-15.
Table 8.3: Avista Medium-Term Winter Capacity Tabulation
2012 2013 2014
Load Obligations 1,890 1,912 1,892
Reserves Planning 371 356 358
Total Obligations 2,261 2,268 2,250
Utility Resources 2,192 2,267 2,277
NW Market Share 737 656 565
Total Resources 2,929 2,923 2,842
Net Position 668 655 592
Table 8.4: Avista Medium-Term Summer Capacity Tabulation
2012 2013 2014
Load Obligations 1,743 1,756 1,785
Reserves Planning 227 322 238
Total Obligations 1,970 2,078 2,023
Utility Resources 1,960 1,880 1,962
NW Market Availability 275 221 178
Total Resources 2,235 2,101 2,140
Net Position 265 23 117
Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions from electric
generation in the Western Interconnect decrease due to the addition of carbon emission
penalties. Avista’s greenhouse gas emissions should fall because of anticipated carbon
reduction policies. Greenhouse gas policies will affect higher-cost coal facilities before
affecting low operating cost facilities, such as Colstrip. New or underutilized natural gas-
fired resources located closer to west coast load centers will replace the coal-fired
facilities. Figure 8.9 presents expected greenhouse gas emissions with the addition of
PRS resources. Overall Company greenhouse gas emissions should fall starting in
2020 as Colstrip output decreases and natural gas-fired generation increases. The 2024
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-14
increase in emissions shown in Figure 8.9 comes from a new CCCT resource. These
emission estimates do not include emissions produced from purchased power or
include a reduction in emissions for off-system sales. The Company expects its
greenhouse gas emissions intensity from owned and controlled generation to fall from
0.36 short tons per MWh to 0.24 short tons per MWh with the current resource mix and
the generation identified in the PRS6.
Figure 8.9: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
Greenhouse gas policy has a clear impact on Avista’s future resource mix. Absent
carbon policy, cumulative greenhouse gas emissions over the 20-year IRP timeframe
would be 18 percent higher, with the difference growing each year of the forecast. By
2031, annual emissions would be 29 percent higher without carbon mitigation. The gray
area illustrates these differences in Figure 8.9.
Efficient Frontier Analysis
Efficient frontier analysis is the backbone of the Preferred Resource Strategy. PRiSM
helps develop the efficient frontier by simulating the costs and risks of several different
resource portfolios. The analysis illustrates the relative performance of potential
portfolios to each other on a cost and risk basis. Thought of a different way, the curve
represents the least-cost strategy at each risk level. The PRS analyses examined the
following portfolios, as detailed here and in Figure 8.10:
Market Only: All resource deficits met with spot market purchases.
Capacity Only: Only capacity deficits met with new resources. Energy and RPS
requirements ignored.
6 Greenhouse gas emissions are not included for the Kettle Falls plant because biomass is a carbon
neutral resource.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-15
Least Cost: All capacity, energy and RPS requirements met with new least-cost
resources. This portfolio ignores power supply expense volatility in favor of
lowest cost resources.
Least Risk: All capacity, energy and RPS requirements met with least-risk
resources. This portfolio ignores the overall cost of the selected portfolio in favor
of minimizing risk.
Efficient Frontier: All capacity, energy and RPS requirements met with sets of
intermediate portfolios between the least risk and least cost options.
Preferred Resource Strategy: All capacity, energy and RPS requirements met
while recognizing both the overall cost and risk inherent in the portfolio.
Figure 8.10 presents the Efficient Frontier. The x-axis is the levelized nominal cost per
year for power supply costs and the y-axis is the levelized standard deviation of power
supply costs.
Figure 8.10: Expected Case Efficient Frontier
The Market Only portfolio is least cost from a long-term financial perspective, but it has
the highest level of risk. The strategy fails to meet capacity, energy, and RPS
requirements with Company-controlled assets.
The Capacity Only strategy meets capacity requirements by adding gas-fired peaking
plants, but wholesale market purchases displace them in most hours. This strategy
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-16
does not meet RPS requirements and does not decrease power supply cost volatility,
except at the tail of the distribution. The Least Cost strategy meets capacity, energy and
RPS requirements at the lowest possible cost by adding gas-fired peaking plants and
minimum levels of wind generation to meet Washington State RPS requirements. The
Least Risk strategy substantially replaces gas-fired peaking plants with gas-fired
combined-cycle combustion turbines, increases the quantity of wind resources, and
adds solar resources to the mix.
All portfolios along the efficient frontier are the least cost portfolio for a given level of risk
and portfolio constraints. The decision to select a particular portfolio along the efficient
frontier curve focuses on volatility reductions gained by spending more capital. Avista
management determines the ultimate selection of the PRS over other potential resource
strategies in an effort to balance overall long-term customer costs with the risks of year-
over-year expense variability. The PRS includes 1.2 percent more costs on average and
4.5 percent less volatility compared to the Least Cost portfolio.
Avoided Costs
The efficient frontier methodology can determine the avoided cost of new resource
additions. There are two avoided cost calculations for this IRP; one for energy efficiency
and one for new generation resources.
Avoided Cost of Conservation
Three portfolios are required to estimate the supply-side cost components necessary to
estimate the avoided cost for conservation. The differences between each portfolio sum
to the avoided cost of conservation:
Market Only: This resource portfolio includes no new resource additions and the
incremental cost of new power supply is the cost to buy power from the short-
term market. The price difference between the Expected Case and the
Unconstrained Carbon scenario is the greenhouse gas policy cost.
Capacity Only: This resource portfolio builds new resource capacity to meet
resource deficits to meet peak load. The difference between the Market Only and
Capacity Only strategies equals the capacity value of the new resources. This
estimate typically shows the incremental cost divided by the incremental kilowatts
of installed capacity. For this example the $/kW adder is translated to $/MWh
assuming a flat energy delivery.
Pre-Preferred Resource Strategy: This resource portfolio is similar to the PRS
resource mix assuming the Company does not pursue the conservation
resource.
Table 8.5 shows the 20-year levelized avoided cost of conservation. The avoided cost
for conservation includes value only for those periods realizing avoided costs. For
example, the avoided costs of conservation programs only include a capacity value in
the years where the Company is short capacity. Further, the market component (Energy
Forecast) applies to each conservation program depending upon the timing of energy
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-17
delivery. For example, an air conditioning program receives an energy value depending
upon prices in the summer months when actual energy savings occur.
Table 8.5: Nominal Levelized Avoided Costs ($/MWh)
2012-2031
Energy Forecast 52.86
Carbon Adder Forecast 17.64
Capacity Value 10.51
Risk Premium 7.38
Total 88.39
I-937 requires that the avoided costs used for conservation include additional items
beyond the actual cost of avoided energy and capacity. Avoided costs increase by 10
percent to bias the IRP toward a preference for conservation. Additionally, reduced
transmission and distribution losses, and operations and maintenance are also
included. The following formula identifies the costs included in the avoided cost for
energy efficiency measures.
{(E + PC + R) * (1 + P)} * (1 + L) + DC * (1 + L)
Where:
E = Market energy price. The price calculated with AURORAxmp is $70.50
per MWh and includes projected greenhouse gas costs.
PC = New resource capacity savings. This value is calculated using
PRiSM and is estimated to be $10.51 per MWh.
R = Risk premium to account for RPS and rate volatility reductions. This
PRiSM-calculated value is $7.38 per MWh.
P = Power Act preference premium. This is the additional 10 percent
premium given as a preference towards energy efficiency measures.
L = Transmission and distribution losses. This component is 6.1 percent
based on Avista’s estimated system average losses.
DC = Distribution capacity savings. This value is approximately $10/kW-
year or $1.14 per MWh.
The following calculation shows the estimated levelized avoided cost for a theoretical
conservation program that reduces load by one megawatt each hour of the year:
{[(52.86 + 17.64 + 10.51 + 7.38) * (1 + 10%)] * (1 + 6.1%) + [1.14 * (1 + 6.1%)]}
= $104.37 per MWh
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-18
Preferred Resource Strategy Avoided Costs
An avoided cost calculation for supply-side resources is developed using conservation
avoided cost estimates and methods, and final PRS data. However, the avoided cost
values for generation resources represent a portfolio including conservation measures
and excluding greenhouse gas emission adders.7 The risk component of the avoided
cost includes renewable energy credits and the difference in cost between combined
and simple cycle CTs to reduce Avista’s market risk. See Table 8.6 for the prices per
MWh. The 20-year levelized cost equates to $84.64 per MWh.
Table 8.6: Preferred Resource Strategy Avoided Cost ($/MWh)
Year Energy Capacity Risk Total
2012 41.19 0.00 0.00 41.19
2013 46.58 0.00 15.20 61.78
2014 49.73 0.00 16.21 65.93
2015 46.76 0.00 17.28 64.04
2016 48.20 0.00 18.42 66.62
2017 51.15 0.00 19.64 70.79
2018 52.91 0.00 20.94 73.85
2019 52.97 16.16 22.33 91.46
2020 53.25 17.52 23.81 94.58
2021 54.45 17.00 25.39 96.83
2022 56.15 16.71 27.07 99.93
2023 57.82 17.18 28.86 103.86
2024 56.89 17.24 30.77 104.90
2025 56.80 17.16 32.81 106.77
2026 58.82 17.42 34.98 111.23
2027 60.36 17.72 37.30 115.38
2028 63.08 18.86 39.77 121.71
2029 64.51 18.54 42.41 125.45
2030 66.29 18.21 45.21 129.71
2031 68.89 17.70 48.21 134.79
New Resource Avoided Costs
Avoided costs are updated as new information becomes available, including changes to
market prices, loads and resources. As such, Table 8.7 represents avoided costs after
the acquisition of the Palouse Wind project. The updated avoided cost schedule is
significantly lower than the preliminary value due substantially to the elimination of the
risk premium. The risk premium is not included in the updated avoided cost table for
three reasons. First, the largest component of the risk premium is the value of meeting
environmental mandates. The risk premium reflects those resources meeting
Washington state renewable performance standard, but there is no guarantee that a
new resource will meet the requirements. Further, Avista’s regulatory commissions have
7 No further greenhouse gas mitigation policies beyond current state and federal regulations are included.
As such, the resource avoided cost calculation does not include this adder. Only when state or federally
imposed greenhouse gas costs are assessed on electric generation will the carbon adder be included in
avoided costs.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-19
not ruled that environmental benefits (i.e., renewable energy credits) from Public Utility
Regulatory Policy Act of 1978 (PURPA) resources are owned by the purchasing utility.
Similarly, the remaining portion of reduced risk is from the benefits of a combined-cycle
combustion turbine relative to a simple-cycle combustion turbine. As with
environmental attributes, there is no guarantee that a PURPA or other resource will
include this benefit. Quantifying the risk benefits requires resource-specific evaluations
through Avista’s IRP models is part of a negotiated PURPA contract. The updated 20-
year levelized avoided cost is $61.46 per MWh.
Table 8.7: Updated Annual Avoided Costs ($/MWh)
Year Energy Capacity Total
2012 41.19 0.00 41.19
2013 46.58 0.00 46.58
2014 49.73 0.00 49.73
2015 46.76 0.00 46.76
2016 48.20 0.00 48.20
2017 51.15 0.00 51.15
2018 52.91 0.00 52.91
2019 52.97 16.16 69.13
2020 53.25 17.52 70.77
2021 54.45 17.00 71.44
2022 56.15 16.71 72.86
2023 57.82 17.18 75.00
2024 56.89 17.24 74.12
2025 56.80 17.16 73.96
2026 58.82 17.42 76.24
2027 60.36 17.72 78.08
2028 63.08 18.86 81.94
2029 64.51 18.54 83.05
2030 66.29 18.21 84.50
2031 68.89 17.70 86.59
Preferred Resource Strategy
Earlier in this chapter, the PRS and summary levelized costs and risk were illustrated
and compared to portfolios along the efficient frontier. This section provides more detail
about the PRS, the associated financial risks of the PRS, the cost of its resultant
emissions, and an index of resultant power supply expenses.
Capital Spending Requirements
One of the major assumptions in this IRP is that Avista finances and owns all new
resources. Using this assumption, and the resources identified in the PRS, the first
capital addition to rate base is in 2013 for distribution feeder upgrades, followed by
additional capital needs for PRS wind development8. Wind or other generation
8 Avista acquired the Palouse Wind Project through a Purchase Power Agreement and this capital
addition is no longer needed.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-20
resources acquired via a power purchase agreement may reduce expected PRS capital
spending. Distribution feeder upgrades may begin in 2012 depending upon operational
availability of resources needed for the work, but 2013 will be the first full year of
commercial operations.
The capital cash flows in Table 8.8 include allowance for funds used during construction
(AFUDC) and account for tax incentives and sales taxes. Costs in Table 8.7 are shown
when capital would be placed in rate base, rather than when capital is actually spent.
The present value of the required investment is just over $0.84 billion and the nominal
total capital expense is $1.7 billion over the IRP timeframe.
Table 8.8: PRS Rate Base Additions from Capital Expenditures
(Millions of Dollars)9
Year Investment Year Investment
2012 0 2022 6
2013 243 2023 6
2014 6 2024 448
2015 6 2025 0
2016 6 2026 0
2017 4 2027 461
2018 7 2028 0
2019 77 2029 0
2020 90 2030 74
2021 251 2031 0
2012-21 Total 690 2022-31 Totals 994
Annual Power Supply Expenses and Volatility
The PRS variance analysis tracks fuel, variable O&M, emissions, and market
transaction costs for the existing resource portfolio. These costs are captured for each
of the 500 iterations of the Expected Case risk analysis. In addition to existing portfolio
costs, new resource capital, fuel, O&M, emissions, and other costs are tracked to
provide a range of potential costs to serve future loads. Figure 8.11 shows expected
PRS costs modeled through 2031 as the white circle (Nominal). In 2012, costs are
expected to be $26 per MWh. The 80 percent confidence interval, represented as the
black bar, ranges between $22 and $31 per MWh. The black diamonds in the figure
represent the TailVar 90 risk level, or the average of the top 10 percent of the worst
outcomes; the 2010 TailVar cost is $32 per MWh, or $6 per MWh above the expected
value.
Power supply costs increase with natural gas and greenhouse gas price increases.
Uncertainty increases over time and the confidence interval band expands. The white
boxes in Figure 8.11 represent the cost per MWh without greenhouse gas costs. For
example, in 2020 the average system costs would be 8.8 percent lower without carbon
9 By acquiring a PPA for the Palouse Wind project, the Company forgoes the large capital investment
shown in 2013.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-21
mitigation. The expected levelized cost for the expected case is $48.59 per MWh and
$43.73 per MWh (10 percent lower) without greenhouse gas costs.
Figure 8.11: Power Supply Expense Range
A common question regarding IRPs is what will be the change to power supply costs
over the time horizon of the plan. Figure 8.12 illustrates expected power supply cost
changes compared to historical power supply costs under the Preferred Resource
Strategy. It shows that power supply costs, on a per-MWh basis have increased 4.1
percent per year over inflation between 2002 and 2010. This 4.1 percent annual growth
rate increase is in Figure 8.12 as a linear black line. By 2021, absent greenhouse gas
emissions costs, power supply costs are expected to be 32 percent higher than 2010,
but up to 41 percent higher with the addition of greenhouse gas emissions costs for an
annual growth rate of 2.6 percent and 3.8 percent respectively.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-22
Figure 8.12: Real Power Supply Expected Rate Growth Index $/MWh (2012 = 100)
Natural Gas Price Risk
The Market Analysis chapter showed the results of high and low natural gas price
forecasts. The PRS includes 752 MW of natural gas-fired resources and exposes
Avista’s customers to increasing levels of natural gas price risk. This section uses
natural gas price forecast scenarios, including changes to expected greenhouse gas
prices, to explain the range of costs resulting from the PRS. Figure 8.13 shows the total
portfolio cost range using different natural gas scenarios compared to the expected cost
of the PRS. The low natural gas price scenario reduces expected costs by 19.5 percent
and the high gas price scenario increases costs by 8.7 percent on a present value
basis. Lower natural gas prices have greater effect on prices than higher prices as the
Using stochastic model results, rather than the deterministic scenarios, illustrates risk
exposure to the wholesale market. The 5th and 95th percentiles reflect variability from
natural gas and other variables. The low natural gas price scenario is reflective of a low
cost future, but the high natural gas price scenario does not reflect the potential cost
excursions that could affect the PRS that is not natural gas price related.
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Historical Energy Crisis
Expected Case Forecast Unconstrained Carbon Forecast
Linear (Historical)
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-23
Figure 8.13: Power Supply Cost Sensitivities
Greenhouse Gas Costs
Avista anticipates some form of federal greenhouse gas policy, although the exact
nature, timing and scope are unknown. As described in the Market Analysis chapter,
four potential greenhouse gas policies are modeled to estimate marginal electricity
costs. The estimate of greenhouse gas emission costs depends on the number of free
allowances provided by the government. Figure 8.14 illustrates the range of total annual
greenhouse gas costs as the percent of free credits allocated to Avista are changed.
For example, if no credits are allocated to Avista in 2022, Avista’s cost to serve
customers will be $91 million ($162 million in total) higher than the Expected Case
where 80 percent of the credits are free and mitigation costs $71 million.
A reduction in output from the Colstrip generators, increased natural gas prices and
increased wholesale electricity prices drive most of the greenhouse gas policy cost
increases. In the marketplace, low marginal cost coal-fired plants dispatch less, or even
turn off, and higher marginal cost natural gas-fired resources replaces their output. The
cost of natural gas resources is higher than it would be absent greenhouse gas costs
because of increased demand for gas-fired resources. These additional costs represent
up to 11 percent of total power supply expenses in the Expected Case.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-24
Figure 8.14: Greenhouse Gas Related Power Supply Expense
Efficient Frontier Comparison of Greenhouse Gas Policies
Three stochastic market studies studied the cost of different greenhouse gas policies: 1)
the Expected Case, 2) Unconstrained Carbon, and 3) Mandatory Coal Retirement.
These three stochastic market forecasts were than assumed to be potential markets in
PRiSM and an efficient frontier for each market future was created, as shown in Figure
8.15. Table 8.9 provides more details about the study results. The PRS portfolio is the
same in the Expected Case and the Unconstrained Carbon Case, but the Mandatory
Coal Retirement Case retires Colstrip Unit 3 in 2023 and Unit 4 in 2026, replacing them
with a CCCT. Colstrip decommissioning costs is not included in figures.
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-25
Figure 8.15: Efficient Frontier Comparison
Table 8.9: Preferred Portfolio Cost and Risk Comparison (Millions $)
2012-2022 Cost NPV 3,094 2,886 2,937
2012-2031 Cost NPV 5,735 5,168 5,458
2022 Expected Cost 636 564 576
2022 Stdev 91 68 71
2022 Stdev/Cost 14% 12% 0
2022 CO2 Emissions (000’s) 2,894 3,498 3,752
2031 CO2 Emissions (000’s) 2,972 4,177 3,560
Portfolio Scenarios
The efficient frontier analysis creates resource portfolios for alternative levels of risk and
cost. Avista’s management selected the PRS to balance costs and risk inherent in our
resource portfolio. The following list of portfolios shows details of alternatives to the
PRS, either along the efficient frontier or “hand-picked” so that the costs of these
choices could be considered. Figure 8.16 illustrates the levelized cost percent change
and the levelized annual standard deviation percent change for each of the portfolios in
comparison to the PRS.
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Expected Case Unconstrained CO2 Case Mandatory Coal Retirement Future
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-26
Figure 8.16: Efficient Frontier Comparison
The Technical Advisory Committee requested Avista to show the efficient frontier and
other portfolios using Tail Var 90 rather than standard deviation as a measure of risk
(Figure 8.17). The TAC wanted to know if we measured risk differently would the
Company draw a different conclusion on its resource choice. The result of this study
shows using Tail Var 90 changes the magnitude of risk as compared to the standard
deviation, but the PRS remains the Company’s best choice. Using Tail Var 90 magnifies
the risk savings of moving from Simple Cycle CTs to Combined Cycle CTs, as the
standard deviation method shows a 5 percent reduction in risk for 2 percent more in
cost, while the Tail Var 90 method shows a 15 percent risk reduction for the same cost
increase.
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National RES
125% of AC for DSM
CCCT/Wind/Solar post '20
150%of AC for DSM
No DSM PRS "like"
PRS-but no Wind
Pay75%of AC for DSM
PRS No Appr. RECPRS
Efficient Frontier
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-27
Figure 8.17: Efficient Frontier Comparison with Tail Var90
The following section describes the resources selected in each of the portfolios
designated in Figure 8.16. Table 8.10 summarizes the PRS.
Table 8.10: Preferred Resource Strategy
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 166 0 46 166 212
0 0 270 270 0 540
0 4 0 0 4 4
35 36 0 0 71 71
0 0 0 0 0 0
57 75 91 87 133 310
8 3 2 1 11 13
-25%
-20%
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annual 20 yr levelized cost percent change as compared to PRS
Efficient Frontier
PRS
No DSM PRS "like"
PRS-but no Wind
Pay75%of AC for DSM 125% of AC for DSM
150%of AC for DSM
CCCT/Wind/Solar post '20
National RES
PRS No Appr. REC
CCCT/Wind (09 IRP)
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-28
Least Cost Portfolio
The Least Cost portfolio is the PRiSM model’s resulting portfolio that meets capacity,
energy and RPS needs at the least expected cost. This portfolio is a combination of
wind and natural gas-fired SCCT generation. Table 8.11 illustrates the generation
resources added in the Least Cost portfolio.
Table 8.11: Least Cost Portfolio
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 83 249 415 83 747
0 0 0 0 0 0
0 0 0 0 0 0
35 24 12 0 59 71
0 0 0 0 0 0
57 75 91 87 133 310
8 3 2 1 11 13
Least Risk Portfolio
The Least Risk portfolio is the portfolio selected by the PRiSM model meeting all
capacity, energy and RPS needs at the least expected risk. PRiSM measures risk using
levelized annual power supply cost variance. This portfolio is a combination of wind,
solar, natural gas-fired SCCT and CCCT generation resources. Table 8.12 illustrates
the resources added in the Least Risk portfolio.
Table 8.12: Least Risk Portfolio
SCCT (Nameplate) 0 0 3 184
CCCT (Nameplate) 0 270 270 0
Thermal Upgrades 0 3 14 0
Wind (Energy) 61 37 0 0
Solar (Energy) 25 27 6 6
Conservation (Energy) 57 75 91 87
Dist. Feeders (Energy) 8 3 2 1
50/50Cost and Risk Midpoint Portfolio
The 50/50 Cost and Risk Midpoint portfolio is the PRiSM model’s portfolio selection that
meets capacity, energy and RPS needs at the midpoint between the least risk and least
cost resource portfolios. This resource portfolio is a combination of wind, solar and
natural gas-fired SCCT and CCCT generation. Table 8.13 illustrates the resources
added in this portfolio.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-29
Table 8.13: 50/50 Cost and Risk Midpoint Portfolio
SCCT (Nameplate) 0 83 0 94
CCCT (Nameplate) 0 0 270 270
Thermal Upgrades 0 0 4 0
Wind (Energy) 35 23 23 12
Solar (Energy) 0 0 0 9
Conservation (Energy) 57 75 91 87
Dist. Feeders (Energy) 8 3 2 1
75/25 Cost and Risk Portfolio
The 75/25 Cost and Risk portfolio is the PRiSM model’s portfolio selection that meets
capacity, energy and RPS needs at the midpoint between the least cost portfolio and
the 50/50 portfolio. This portfolio is similar to the PRS with a combination of wind and
natural gas-fired SCCT generation. Table 8.14 illustrates the resources added under the
75/25 Cost and Risk portfolio.
Table 8.14: 75/25 Cost Risk Portfolio
SCCT (Nameplate) 0 83 249 0
CCCT (Nameplate) 0 0 0 540
Thermal Upgrades 0 0 0 0
Wind (Energy) 35 23 12 12
Solar (Energy) 0 0 0 0
Conservation (Energy) 57 75 91 87
Dist. Feeders (Energy) 8 3 2 1
25/75 Cost and Risk Portfolio
The 25/75 Cost Risk portfolio is the PRiSM model’s portfolio selection meeting capacity,
energy and RPS needs at the midpoint between the Least Risk portfolio and the 50/50
Cost and Risk portfolio. The 25/75 Cost and Risk portfolio includes a combination of
wind, solar, and natural gas-fired SCCT and CCCT generation. Table 8.15 illustrates the
resources added in the 25/75 Cost and Risk portfolio.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-30
Table 8.15: 25/75 Cost Risk Portfolio
SCCT (Nameplate) 0 83 0 0
CCCT (Nameplate) 0 0 540 270
Thermal Upgrades 0 0 4 0
Wind (Energy) 35 23 37 0
Solar (Energy) 0 0 0 5
Conservation (Energy) 57 75 91 87
Dist. Feeders (Energy) 8 3 2 1
PRS without Apprentice Credits
The PRS without Apprentice Credits portfolio represents a resource strategy that
assumes the Company is unable to contract for apprentice labor for new wind resources
and therefore the acquisitions do not qualify for the 20 percent REC credit adder in I-
937. This portfolio is a similar to the PRS, but includes 25 aMW of additional wind
energy. Where wind resources have an average capacity factor of 31 percent, Avista
would need to procure an additional 80 MW of nameplate wind capacity. Table 8.16
illustrates the PRS without Apprenticeship Credits portfolio resource additions.
Table 8.16: PRS without Apprentice Credits
SCCT (Nameplate) 0 166 0 46
CCCT (Nameplate) 0 0 270 270
Thermal Upgrades 0 4 0 0
Wind (Energy) 35 49 12 0
Solar (Energy) 0 0 0 0
Conservation (Energy) 57 75 91 87
Dist. Feeders (Energy) 8 3 2 1
2009 IRP Portfolio
The PRS from the 2009 IRP included 350 MW of wind generation and 750 MW of gas-
fired CCCT generation. The 2009 IRP Portfolio emulates the 2009 PRS with 2011 IRP
adjustments for lower load projections and lower natural gas and market electricity
prices. Table 8.17 illustrates the resource additions under the 2009 IRP Portfolio.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-31
Table 8.17: 2009 IRP Portfolio
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 0 0 0 0 0
0 270 270 270 270 810
0 0 0 0 0 0
44 44 15 0 87 102
0 0 0 0 0 0
57 75 91 87 133 310
8 3 2 1 11 13
PRS without Wind Portfolio
The PRS without Wind Portfolio illustrates the cost of wind additions to the PRS. This
portfolio is the same as the 2011 PRS, but excludes the qualified renewable generation
required by the Energy Independence Act. Table 8.18 illustrates the resources added
under the PRS without Wind Portfolio.
Table 8.18: PRS without Wind Portfolio
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 166 0 46 166 212
0 0 270 270 0 540
0 4 0 0 4 4
0 0 0 0 0 0
0 0 0 0 0 0
57 75 91 87 133 310
8 3 2 1 11 13
CCCT with Solar after 2015 Portfolio
The CCCT with Solar after 2015 Portfolio illustrates the additional cost of using solar,
rather than wind, to meet Washington’s I-937 requirements. Table 8.19 shows the
resources added under the CCCT with Solar after 2015 Portfolio.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-32
Table 8.19: CCCT with Solar after 2015 Portfolio
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 0 0 0 0 0
0 0 270 540 0 810
0 7 3 0 10 10
36 0 0 0 36 36
0 26 7 0 26 33
57 75 91 87 133 310
8 3 2 1 11 13
National Renewable Energy Standard Portfolio
There have been several attempts to implement a federal renewable energy standard.
The National Renewable Energy Standard Portfolio illustrates changes to the PRS
needed to meet renewable requirements at the national level. Depending on the
legislation, Avista may be required to secure an additional 106 aMW10 to cover the
Company’s retail loads in the Idaho service territory. The actual level of wind required
under a federal renewable energy standard would depend upon how the legislation
treats our existing renewable resources and how it considers hydroelectric generation.11
The portfolio assumes that hydroelectric netting would be included and that the federal
law would not supersede state law. We did not model a national energy standard, as
proposed by President Obama, because the PRS most likely would meet the standard
because Avista is already subject to Washington’s emission performance standards.
Table 8.20 illustrates the resources added under the National Renewable Energy
Standard portfolio.
Table 8.20: National Renewable Energy Standard
SCCT (Nameplate) 0 166 0 46
CCCT (Nameplate) 0 0 270 270
Thermal Upgrades 0 4 0 0
Wind (Energy) 47 47 35 49
Solar (Energy) 0 0 0 1
Conservation (Energy) 57 75 91 87
Dist. Feeders (Energy) 8 3 2 1
10 106 aMW is equal to 341 MW of nameplate capacity wind generation at a 31 percent capacity factor. 11 Proposed federal legislation has allowed utilities to “net” hydroelectric generation against retail loads
prior to calculating RPS obligations.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-33
PRS without Conservation Portfolio
The PRS without Conservation Portfolio illustrates the benefits of conservation. This
portfolio meets capacity, energy and RPS needs in a similar manner as the PRS. Table
8.21 illustrates the resources added under the PRS without Conservation Portfolio.
Table 8.21: PRS without Conservation
SCCT (Nameplate) 83 212 83 97
CCCT (Nameplate) 0 0 270 545
Thermal Upgrades 7 0 0 3
Wind (Energy) 35 36 23 0
Solar (Energy) 0 0 0 0
Conservation (Energy) 0 0 0 0
Dist. Feeders (Energy) 8 3 2 1
PRS Conservation Avoided Costs 25% Lower Portfolio
The PRS Conservation Avoided Costs 25% Lower Portfolio illustrates resulting changes
to cost and risk if avoided costs for conservation was set at the avoided cost of
generation resources, or if natural gas prices included in this IRP are too high. This
portfolio represents conservation estimates without discretionary adders. Table 8.22
illustrates the resources added under this portfolio.
Table 8.22: PRS Conservation Avoided Costs 25% Lower
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 166 83 0 166 249
0 0 270 270 0 540
0 0 4 0 0 4
35 24 23 0 59 82
0 0 0 0 0 0
54 61 75 76 115 266
8 3 2 1 11 13
PRS Conservation Avoided Costs 25% Higher Portfolio
The PRS Conservation Avoided Costs 25% Higher Portfolio illustrates the resource
changes that would occur if Avista spent additional dollars toward the acquisition of
additional conservation. This portfolio represents the added conservation at a spending
level of an additional 25 percent and the resulting offset in supply-side resources. Table
8.23 illustrates the resources added under this portfolio.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-34
Table 8.23: PRS Conservation Avoided Costs 25% Higher
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 166 83 0 166 415
0 0 0 270 0 270
0 4 4 0 4 7
35 23 12 0 58 70
0 0 0 0 0 0
61 83 95 94 144 334
8 3 2 1 11 13
PRS Conservation Avoided Costs 50% Higher Portfolio
The PRS Conservation Avoided Costs 50% Higher Portfolio illustrates the resource
changes that would occur if Avista spent an additional 50 percent on the acquisition of
conservation resources. Table 8.24 illustrates the resources obtained in this portfolio.
Table 8.24: PRS Conservation Avoided Costs 50% Higher
Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
0 46 0 83 46 129
0 0 270 270 0 540
0 0 4 0 0 4
35 23 12 0 58 70
0 0 0 0 0 0
62 91 103 94 153 350
8 3 2 1 11 13
Resource Tipping Point Analysis
In many resource plans, a PRS is presented with a comparison to other portfolios to
help illustrate cost and risk trade-offs. This IRP extends the portfolio analysis beyond
this simple exercise by focusing on how the portfolio might change if key assumptions
were changed. This provides an array of strategies in reaction to fundamentally different
futures instead of a single strategy. This section identifies assumptions that could alter
the PRS, such as changes to load growth, varying resource capital costs, hydroelectric
upgrade opportunities, the emergence of other non-wind and non-solar renewable
options, or an expansion of the region’s nuclear generation fleet.
Solar Capital Costs Sensitivity
The capital costs of photovoltaic solar generation significantly decreased since the 2009
IRP and the 30 percent Investment Tax Credit for solar generation was extended
through the end of 2015. Solar generation still is not competitive with wind in the
Northwest, even with lower capital costs and tax credits. A sensitivity analysis
determined the price reduction that would be necessary to make photovoltaic solar
generation competitive with wind generation. The analysis reduced solar capital costs in
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-35
the year 2020 until the PRiSM model selected solar over wind. This analysis also
assumed the double solar REC credit for I-937. The results of the study were that the
capital costs for solar would need to decrease 53 percent, to $2,020/kW (2020 nominal
dollars including AFUDC), in order to make solar competitive with wind generation.
CCCT Capital Cost Sensitivity
CCCTs were the lowest cost resource option in the 2009 IRP. SCCTs are again the
lowest cost resource option, similar to all Avista IRPs prior to its 2009 IRP. A sensitivity
analysis determined why CCCTs were more cost-effective than SCCTs in the 2009 IRP.
The first test involved an analysis of capital costs. The model found that CCCT capital
costs had to be 22 percent lower than forecasted in this IRP to be selected over SCCTs.
Another indication of the change is that O&M cost estimates were lower in the 2009 IRP
($11/kW-year) as compared to the 2011 IRP ($16/kW-year). The 2009 IRP also
assumed that a lower-cost water-cooled plant rather than an air-cooled plant would be
developed. This IRP assumes an air-cooled CCCT due to the increasing difficulty in
obtaining water rights near customer loads. Additional analysis could indicate that
changes in the spark spread, fuel transportation costs, heat rates, or greenhouse gas
policies could affect the selection of CCCTs over SCCTs more than changes in capital
costs. Further, natural gas prices could affect this choice, such as lower or higher prices
could affect this decision, to fully study this theory would require two additional
stochastic studies and this scope of work would extend the timeline for this IRP’s
completion.
Load Forecast Alternatives
An important test in an IRP is its performance across varying load growth sensitivities.
Avista’s loads could grow faster with future development activity after the economy
recovers, or could stagnate in a continued recession. This sensitivity analysis studies
the impact to the PRS if loads grows faster or slower than the Expected Case estimate.
Faster load growth will increase the need for capital and slower load growth will
decrease the need for capital spending on new generation. This analysis focuses on
understanding the changes in the timing of resource decisions based on changes in
load growth.
Loads are expected to grow, net of conservation, at a rate of 1.37 percent over the IRP
timeframe. The Low Load Growth scenario cuts the underlying load growth rate by 50
percent and the High Load Growth case increases expected load growth rate by 50
percent. The sensitivity analysis indicated that, net of conservation, the Low Load
case’s growth rate is 0.19% and the High Load Growth case is 2.4 percent. See Figure
8.18 for load forecast estimates in each case. The load forecast change is not linear
since conservation will make up a greater amount of new load growth in the low case as
conservation programs target existing load (85 percent of load growth). However, in a
high case conservation only makes up 40 percent of load growth that is assumed to be
code requirement driven energy efficiency. As a comparison, the Expected Case
forecast assumes conservation meets 48 percent of new load.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-36
Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison
The lower load growth case’s resource strategy would not change near-term resource
acquisitions (see Table 8.25), but would eliminate the need for some wind and gas-fired
resources later in the IRP time horizon.
Table 8.25: Low Load Growth Resource Strategy
Resources 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 0 0 212 0 212
CCCT (Nameplate) 0 0 0 0 0 0
Thermal Upgrades 0 0 0 4 0 4
Wind (Energy) 35 12 24 0 47 71
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 49 60 69 70 108 247
Dist. Feeders (Energy) 8 3 2 1 11 13
Table 8.26 shows the resource strategy with higher growth rates. The amount of wind
acquisitions would increase by 22 aMW and additional peaking resources would be
required to compensate for higher growth rates. In the later years of the study,
additional gas-fired and wind generation resources would be needed to meet peak load
growth and RPS requirements.
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
Low Load Forecast Expected Case High Load Forecast
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Includes New & Existing Conservation
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-37
Table 8.26: High Load Growth Resource Strategy
Resources 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 83 298 83 46 381 510
CCCT (Nameplate) 0 0 270 540 0 810
Thermal Upgrades 4 6 0 0 10 10
Wind (Energy) 35 23 35 0 58 93
Solar (Energy) 0 0 0 1 0 1
Conservation (Energy) 71 94 122 156 165 443
Dist. Feeders (Energy) 8 3 2 1 11 13
Figure 8.19 shows the cost, and cost range, for each load growth scenario from a dollar
per megawatt-hour perspective. The chart explains a positive correlation between load
growth and the average cost to serve customers.
Figure 8.19: Load Growth Scenario’s Cost/Risk Comparison
Base Case Low Load
Growth
High Load
Growth
Levelized Cost $/MWh 49.75 44.11 54.86
1 Sigma Lower 42.67 36.99 47.80
1 Sigma Higher 56.83 51.23 61.92
$0
$10
$20
$30
$40
$50
$60
$70
$/
M
W
h
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-38
Summary
The Preferred Resource Strategy is the roadmap for a resource acquisition plan that
which balances the tradeoff between cost and risk while preparing the Company to
provide reliable electricity service to its customers. Table 8.27 provides a summary of
the total resources selected for each of the portfolios discussed in this chapter.
Distribution Feeder upgrades are included at the same level (13 aMW) in all portfolios
but are not included in the table.
Table 8.27: Summary of Resource Portfolios
Preferred Resource Strategy 212 540 4 71 0 310
Least Cost 747 0 0 71 0 310
Least Risk 187 540 17 98 64 310
50/50 Cost Risk 177 540 4 93 9 310
75/25 Cost Risk 332 540 0 82 0 310
25/75 Cost Risk 83 810 4 95 5 310
PRS without Apprentice Credits 212 540 4 96 0 310
2009 PRS 0 810 0 102 0 310
PRS Without Wind 212 540 4 0 0 310
CCCT with Solar 0 810 10 36 33 310
National Renewable Energy Standard 212 540 4 177 1 310
PRS without Conservation 475 815 10 94 0 0
PRS Conservation A/C 25% Lower 249 540 4 82 0 266
PRS Conservation A/C 25% Higher 415 270 7 70 0 334
PRS Conservation A/C 50% Higher 129 540 4 70 0 350
Low Load Growth 212 0 4 71 0 247
High Load Growth 510 810 10 93 1 443
The IRP is a continual effort to select cost- and risk-minimizing resources
complementing the Company’s existing resource mix. Its results and insights help
management and policy-makers formulate good decisions on behalf of ratepayers. The
PRS includes a combination of conservation, efficiency improvements including feeder
upgrades, hydroelectric upgrades, wind, and gas-fired simple and combined-cycle
combustion turbines. The resource strategy identified in this report will change in
response to new information, but Avista focuses decision making on near-term resource
acquisitions where substantial changes concerning the data needed to make decisions
are less likely to occur.
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-39
Table 8.28: Winter 18-Hour Capacity Position (MW) Net of Conservation with New
Resources12
12 Native load includes forecasted savings from conservation and distribution efficiencies programs.
20
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Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-40
Table 8.29: Summer 18-Hour Capacity Position (MW) Net of Conservation with New
Resources13
13 Ibid
20
1
2
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n
g
U
n
i
t
s
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
To
t
a
l
R
e
s
o
u
r
c
e
s
1,9
6
0
1,
8
8
0
1,
9
6
2
1,
9
1
9
1,9
2
6
1,9
2
4
1,9
4
5
1,
8
9
1
1,
8
9
7
1,
9
1
6
1,8
9
1
1,8
9
6
1,
9
1
6
1,
8
9
0
1,
8
9
6
1,
6
6
8
1,6
4
2
1,6
4
8
1,
6
6
8
1,
6
4
2
Pe
a
k
P
o
s
i
t
i
o
n
B
e
f
o
r
e
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
21
7
12
4
17
6
14
6
13
0
25
5
25
7
19
1
18
3
18
7
15
2
14
4
14
1
88
62
-1
9
1
-2
4
4
-2
6
7
-2
7
9
-3
3
9
RE
S
E
R
V
E
S
P
L
A
N
N
I
N
G
Re
q
u
i
r
e
d
O
p
e
r
a
t
i
n
g
R
e
s
e
r
v
e
s
-1
5
3
-1
5
6
-1
5
8
-1
5
9
-1
6
1
-1
5
4
-1
5
5
-1
5
6
-1
5
8
-1
5
9
-1
6
0
-1
6
1
-1
6
3
-1
6
5
-1
6
8
-1
5
5
-1
5
4
-1
5
5
-1
5
7
-1
5
6
Av
a
i
l
a
b
l
e
O
p
e
r
a
t
i
n
g
R
e
s
e
r
v
e
s
15
5
66
17
1
15
9
15
9
15
9
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
Pla
n
n
i
n
g
M
a
r
g
i
n
-2
2
7
-2
3
2
-2
3
8
-2
4
4
-2
4
8
-2
5
2
-2
5
5
-2
5
7
-2
5
9
-2
6
2
-2
6
3
-2
6
6
-2
6
9
-2
7
3
-2
7
8
-2
8
2
-2
8
6
-2
9
0
-2
9
5
-3
0
0
To
t
a
l
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
-2
2
7
-3
2
2
-2
3
8
-2
4
4
-2
5
1
-2
5
2
-2
5
5
-2
5
7
-2
5
9
-2
6
2
-2
6
5
-2
6
9
-2
7
1
-2
8
0
-2
8
8
-2
8
2
-2
8
6
-2
9
0
-2
9
5
-3
0
0
Pe
a
k
P
o
s
i
t
i
o
n
W
i
t
h
R
e
s
e
r
v
e
s
P
l
a
n
n
i
n
g
-1
0
-1
9
9
-6
2
-9
9
-1
2
2
3
2
-6
6
-7
7
-7
4
-1
1
4
-1
2
5
-1
3
0
-1
9
2
-2
2
6
-4
7
3
-5
3
0
-5
5
7
-5
7
4
-6
3
9
Pla
n
n
i
n
g
M
a
r
g
i
n
B
e
f
o
r
e
N
W
M
a
r
k
e
t
21
%
11
%
19
%
17
%
16
%
25
%
25
%
21
%
20
%
20
%
18
%
17
%
17
%
14
%
12
%
-2
%
-5
%
-6
%
-6
%
-9
%
Av
i
s
t
a
S
h
a
r
e
o
f
E
x
c
e
s
s
N
W
M
a
r
k
e
t
27
5
22
1
17
8
14
1
10
7
78
52
31
10
3
0
0
0
0
0
0
0
0
0
0
Pe
a
k
P
o
s
i
t
i
o
n
W
i
t
h
N
W
M
a
r
k
e
t
26
5
22
11
7
42
-1
5
81
54
-3
5
-6
7
-7
1
-1
1
4
-1
2
5
-1
3
0
-1
9
2
-2
2
6
-4
7
3
-5
3
0
-5
5
7
-5
7
4
-6
3
9
Pla
n
n
i
n
g
M
a
r
g
i
n
W
i
t
h
N
W
M
a
r
k
e
t
37
%
23
%
29
%
25
%
22
%
29
%
28
%
22
%
20
%
20
%
18
%
17
%
17
%
14
%
12
%
-2
%
-5
%
-6
%
-6
%
-9
%
NE
W
R
E
S
O
U
R
C
E
S
Ne
w
S
i
m
p
l
e
C
y
c
l
e
C
C
0
0
0
0
0
0
0
72
72
14
4
14
4
14
4
14
4
14
4
14
4
14
4
14
4
14
4
18
4
18
4
Ne
w
C
o
m
b
i
n
e
d
C
y
c
l
e
C
C
0
0
0
0
0
0
0
0
0
0
0
0
23
5
23
5
23
5
47
0
47
0
47
0
47
0
47
0
Ne
w
W
i
n
d
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Th
e
r
m
a
l
R
e
s
o
u
r
c
e
U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
To
t
a
l
N
e
w
R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
73
73
14
5
14
5
14
5
38
0
38
0
38
0
61
5
61
5
61
5
65
5
65
5
Pe
a
k
P
o
s
i
t
i
o
n
w
i
t
h
N
e
w
R
e
s
o
u
r
c
e
s
26
5
22
11
7
42
-1
5
81
54
38
6
74
32
20
25
0
18
8
15
4
14
2
85
58
81
16
Pla
n
n
i
n
g
M
a
r
g
i
n
W
i
t
h
N
e
w
R
e
s
o
u
r
c
e
s
37
%
23
%
29
%
25
%
22
%
29
%
28
%
27
%
25
%
29
%
26
%
26
%
38
%
35
%
33
%
31
%
28
%
26
%
28
%
24
%
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-41
Table 8.30: Average Annual Energy Position (aMW) With New Resources14
14 Ibid
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L
L
O
A
D
O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e
L
o
a
d
(
N
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t
o
f
E
f
f
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c
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e
n
c
y
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r
o
g
r
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m
s
)
-1
,
1
0
2
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,
1
2
1
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,
1
3
5
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,
1
4
7
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,
1
6
5
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,
1
8
4
-1
,
1
9
9
-1
,
2
0
8
-1
,
2
2
0
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,
2
3
1
-1
,
2
3
9
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,
2
4
9
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,
2
6
6
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,
2
8
6
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,
3
1
2
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,
3
3
1
-1
,
3
5
1
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,
3
7
2
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,
3
9
6
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,
4
2
1
Fir
m
P
o
w
e
r
S
a
l
e
s
-1
4
0
-1
2
7
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0
9
-5
8
-5
8
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-6
-5
-5
-5
-5
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-5
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-5
-5
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-5
To
t
a
l
R
e
q
u
i
r
e
m
e
n
t
s
-1
,
2
4
2
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,
2
4
8
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,
2
4
4
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,
2
0
5
-1
,
2
2
2
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,
1
9
0
-1
,
2
0
4
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,
2
1
4
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,
2
2
5
-1
,
2
3
6
-1
,
2
4
4
-1
,
2
5
4
-1
,
2
7
1
-1
,
2
9
1
-1
,
3
1
8
-1
,
3
3
6
-1
,
3
5
6
-1
,
3
7
7
-1
,
4
0
1
-1
,
4
2
6
RE
S
O
U
R
C
E
S
Fir
m
P
o
w
e
r
P
u
r
c
h
a
s
e
s
16
3
16
4
16
3
16
5
16
3
11
2
11
1
91
66
66
65
65
65
65
65
65
65
65
65
65
Hy
d
r
o
R
e
s
o
u
r
c
e
s
52
2
52
5
52
7
49
5
49
5
49
5
49
0
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
Ba
s
e
L
o
a
d
T
h
e
r
m
a
l
s
75
5
71
4
75
1
74
4
74
6
74
1
72
4
75
8
72
1
72
1
75
8
72
1
72
1
75
8
68
4
51
5
54
1
51
5
51
5
54
1
Win
d
R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l
R
e
s
o
u
r
c
e
s
1,
4
4
1
1,
4
0
3
1,
4
4
2
1,
4
0
5
1,
4
0
4
1,
3
4
8
1,
3
2
5
1,
3
3
0
1,
2
6
8
1,
2
6
8
1,
3
0
4
1,2
6
6
1,2
6
7
1,3
0
4
1,2
2
9
1,0
6
0
1,0
8
7
1,0
6
0
1,
0
6
0
1,
0
8
7
En
e
r
g
y
P
o
s
i
t
i
o
n
B
e
f
o
r
e
C
o
n
t
i
n
g
e
n
c
y
P
l
a
n
n
i
n
g
19
8
15
5
19
8
20
0
18
2
15
8
12
1
11
7
43
32
61
12
-4
12
-8
8
-2
7
5
-2
6
9
-3
1
7
-3
4
0
-3
3
9
CO
N
T
I
N
G
E
N
C
Y
P
L
A
N
N
I
N
G
Pe
a
k
i
n
g
R
e
s
o
u
r
c
e
s
15
3
15
3
15
3
13
8
15
3
15
4
15
3
14
7
14
6
14
5
14
7
14
6
14
5
14
7
14
6
14
5
14
7
14
6
14
5
14
7
Co
n
t
i
n
g
e
n
c
y
-2
2
8
-2
2
9
-2
3
0
-2
3
1
-2
3
2
-2
3
3
-2
3
3
-2
1
6
-1
9
7
-1
9
8
-1
9
8
-1
9
9
-2
0
0
-2
0
1
-2
0
2
-2
0
3
-2
0
4
-2
0
5
-2
0
6
-2
0
0
En
e
r
g
y
P
o
s
i
t
i
o
n
W
i
t
h
C
o
n
t
i
n
g
e
n
c
y
P
l
a
n
n
i
n
g
12
3
79
12
1
10
7
10
3
79
40
48
-9
-2
1
9
-4
2
-5
9
-4
2
-1
4
5
-3
3
3
-3
2
6
-3
7
6
-4
0
1
-3
9
3
NE
W
R
E
S
O
U
R
C
E
S
Ne
w
S
i
m
p
l
e
C
y
c
l
e
C
C
0
0
0
0
0
0
0
75
75
15
1
15
1
15
1
15
1
15
1
15
1
15
1
15
1
15
1
19
2
19
2
Ne
w
C
o
m
b
i
n
e
d
C
y
c
l
e
C
C
0
0
0
0
0
0
0
0
0
0
0
0
23
7
23
7
23
7
47
4
47
4
47
4
47
4
47
4
Ne
w
W
i
n
d
0
35
35
35
35
35
35
35
47
71
71
71
71
71
71
71
71
71
71
71
Th
e
r
m
a
l
R
e
s
o
u
r
c
e
U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
3
3
3
3
3
3
3
3
3
3
3
3
3
To
t
a
l
N
e
w
R
e
s
o
u
r
c
e
s
0
35
35
35
35
35
35
11
4
12
6
22
5
22
5
22
5
46
2
46
2
46
2
69
9
69
9
69
9
74
1
74
1
Pe
a
k
P
o
s
i
t
i
o
n
w
i
t
h
N
e
w
R
e
s
o
u
r
c
e
s
12
3
11
4
15
6
14
2
13
8
11
4
75
16
1
11
7
20
4
23
4
18
3
40
3
42
0
31
7
36
6
37
3
32
3
34
0
34
8
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-42
On
-
l
i
n
e
Ye
a
r
Ap
p
r
e
n
t
i
c
e
La
b
o
r
Cr
e
d
i
t
Up
g
r
a
d
e
En
e
r
g
y
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
WA
S
t
a
t
e
R
e
t
a
i
l
S
a
l
e
s
F
o
r
e
c
a
s
t
62
8
63
0
63
4
64
4
65
0
65
6
66
3
66
7
67
4
67
8
68
2
68
6
68
7
69
0
69
6
70
2
70
8
71
5
72
3
73
1
74
0
75
0
RP
S
%
0%
3%
3%
3%
3%
9%
9%
9%
9%
15
%
15
%
15
%
15
%
15
%
15
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15
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15
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15
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15
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15
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15
%
RE
Q
U
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R
E
D
R
E
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W
A
B
L
E
E
N
E
R
G
Y
19
19
19
19
59
59
60
60
10
1
10
2
10
3
10
3
10
3
10
4
10
5
10
6
10
7
10
8
10
9
11
0
Re
n
e
w
a
b
l
e
R
e
s
o
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r
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s
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r
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s
0
6
6
6
6
0
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Lo
n
g
L
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19
9
9
1.
0
2.
2
2
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6
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9
3
3
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3
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1.
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5
4
4
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2
2
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No
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1
20
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9
1.
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3
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2
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9
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9
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7
0
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4
4
4
4
4
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4
4
4
4
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w
W
i
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d
20
1
3
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2
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0
42
42
42
42
42
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57
85
85
85
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85
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85
To
t
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l
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u
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n
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17
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68
70
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64
64
64
64
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10
7
10
7
10
7
10
7
10
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10
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7
10
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7
10
7
10
7
NE
T
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17
5
49
50
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5
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5
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4
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1
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(1
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(2
)
(3
)
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Pr
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r
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17
21
68
70
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64
64
64
64
41
46
51
56
60
63
65
67
67
67
65
RE
C
'
s
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e
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)
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(6
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)
(6
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)
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(1
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4
)
(1
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5
)
(1
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)
(1
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)
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9
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(1
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d
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17
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68
70
70
64
64
64
64
79
10
7
10
7
10
7
10
7
10
7
10
7
10
7
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7
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7
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7
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7
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p
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NE
T
R
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C
B
A
N
K
17
21
68
70
70
64
64
64
64
41
46
51
56
60
63
65
67
67
67
65
62
RE
C
R
e
s
e
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R
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(
9
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L
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)
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a
d
0
1
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1
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5
6
6
Ex
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s
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g
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y
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r
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U
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g
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a
d
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0
6
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
To
t
a
l
R
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C
R
e
s
e
r
v
e
R
e
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u
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m
e
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7
8
8
8
10
10
10
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12
12
12
12
12
12
13
13
13
13
13
13
NE
T
R
E
C
P
O
S
I
T
I
O
N
17
14
63
11
0
11
2
65
59
58
57
29
34
39
43
47
50
53
54
55
54
52
49
Table 8.31: Washington State RPS Detail with New Resources (aMW)15
15 Retail sales forecast includes new conservation programs.
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
9. Action Items
The Integrated Resource Plan (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 for ongoing improvements to the
modeling and forecasting procedures and tools, as well as the opportunity to enhance
the process with new research as the planning environment changes. This section
provides an overview of the progress made on the 2009 IRP Action Plan and provides
the 2011 Action Plan.
Summary of the 2009 IRP Action Plan
The 2009 Action Plan included five separate categories: resource additions and
analysis, energy efficiency, environmental policies, modeling and forecasting
enhancements, and transmission planning.
2009 Action Plan – Resource Additions and Analysis
Continue to explore the potential for wind and non-renewable resources.
Issue an RFP for turbines at Reardan and up to 100 MW of wind or other
renewables in 2009.
Finish studies on the costs and environmental benefits of hydro upgrades at Cabinet
Gorge, Long Lake, Post Falls, and Monroe Street.
Study potential locations for the natural gas-fired resource identified to be online
between 2015 and 2020.
Continue participation in regional IRP processes and where agreeable find resource
opportunities to meet resource requirements on a collaborative basis.
Progress Report – Resource Additions and Analysis
After filing the 2009 IRP, the Company issued two RFPs: (1) a 35 aMW Renewable
RFP and (2) a wind turbine RFP for the Reardan development. The 2009 RFP showed
that the anticipated benefits of early construction of Reardan, or a third party acquisition,
identified in the 2009 IRP were not available. The Company retains the Reardan Wind
Project site as an option to meet future RPS goals. Site control provides a hedge
against escalating costs and the limited number of viable Pacific Northwest wind sites.
Additional studies on non-wind renewable energy sources continued throughout this
planning cycle. More details about non-wind renewables are included in the Generation
Resource Options and Preferred Resource Strategy chapters.
Following the 2009 RFP, several wind development firms asked when another RFP
would be issued, indicating that wind turbine prices had fallen greatly since the 2009
RFP and that prices in a new RFP issuance would be competitive to the wholesale
market prices (when including REC sales) when including federal and state tax
subsidies. In response, the Company issued an RFP for approximately 35 aMW of
Washington renewable portfolio standard-qualified renewable energy contracts. The
Company did not include its Reardan Wind Project, as it could not be completed in time
to take advantage of the expiring Federal tax subsidies.1 The Company’s February 2011
1 Federal tax incentives for wind expire at the end of calendar year 2012.
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
RFP received bids for 774 MW of qualifying projects (769 MW of wind and 5 MW of
landfill gas). The Company selected the 105 MW Palouse Wind Project, located near
Oakesdale, Washington. The proposal is a 30-year power purchase agreement with a
buyout option after year 10. Further details regarding this acquisition are contained in
the Preferred Resource Strategy Chapter.
The Company is continuing to research system hydroelectric upgrade options. The
results of these studies are not yet complete, and we therefore were unable to include
the results of these studies in this IRP. Some preliminary results are in the Generation
Resource Options Chapter, and in presentations to the third Technical Advisory
Committee on December 2, 2010. The slides from that presentation are contained in
Appendix A.
Preliminary work on identifying potential locations for future natural gas-fired resources
identified in the 2009 IRP is complete, but a final site selection is not complete. The
2011 PRS pushes the need for the next gas-fired plant until 2019 and changes the
technology from combined to simple cycle. This work will continue and an update given
as an Action Item in the 2013 IRP.
The Company continues to participate in regional IRP processes, attending peer-utility
meetings. Regional utilities participated in our Technical Advisory Committee meetings
to share the latest concepts in resource planning.
2009 Action Plan – Energy Efficiency
Pursue American Reinvestment and Recovery Act of 2009 (ARRA) funding for low
income weatherization.
Analyze and report on the results of the July 2007 through December 2009 demand
response pilot in Moscow and Sandpoint.
Have an external party perform a study on technical, economic, and achievable
potential for energy efficiency in Avista’s entire service territory.
Study and quantify transmission and distribution efficiency concepts as they apply to
meeting Washington’s RPS goals.
Update processes and protocols for conservation measurement, evaluation and
verification.
Determine the potential impacts and costs of load management options.
Progress Report – Energy Efficiency
Avista’s Community Action Agencies received significant increases for low-income
weatherization through ARRA funds. The Idaho Load Management Pilot Final Report,
issued on March 1, 2010, provides details on the Moscow and Sandpoint demand
response project. The pilot included ten successful trial events, including the cycling of
heating and air conditioning units and the short-term interruption of water heaters. Five
percent of the eligible participants agreed to participate in the volunteer program; two
percent of customers participating in the study opted-out of the program during events.
Even though the program successfully showed the capability of a load interruption
program as a reliable capacity resource, the regional power market does not support
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
the present costs of such a program at this time. The Company will continue to monitor
the marketplace to determine if this type of load management program will become cost
effective in the future.
Global Energy Partners (Global) completed a 20-year conservation potential
assessment for our residential, commercial and industrial customers in Idaho and
Washington. Global presented the assessment results at the fifth Technical Advisory
Committee meeting on April 12, 2011. A copy of the presentation is included in
Appendix D, and more details are in the Energy Efficiency chapter.
The study and quantification of transmission and distribution efficiency concepts, as
they apply to meeting Washington’s renewable portfolio standard goals is part of an
ongoing process. It will be refined as the Company prepares its initial Washington
Energy Independence Act compliance report to the Washington Utility and
Transportation Commission. Additional details are in the Energy Efficiency and
Transmission and Distribution chapters of this IRP.
The Company continues to update the processes and protocols for conservation
measurement, evaluation and verification (EM&V). The Company participated in an
EM&V Collaborative in 2010 resulting in an EM&V framework, annual EM&V plans and
development of individual program EM&V plans. This continual EM&V loop will feed
improved processes and protocols for conservation measurement, evaluation and
verification. As part of the conservation potential study, Global Energy Partners looked
at demand response potential and costs. More details about this work are in the Energy
Efficiency chapter.
2009 Action Plan – Environmental Policy
Continue to study the potential impact of state and federal climate change
legislation.
Continue and report on the work of Avista’s Climate Change Council.
Progress Report – Environmental Policy
Avista’s Climate Change Council and the Resource Planning team actively analyze
state and federal greenhouse gas legislation. This work will continue until final rules are
established and laws passed. The focus will then shift to mitigating the costs of meeting
these laws and regulations. Avista has quantified its greenhouse gas emissions using
the World Resources Initiative–World Business Council for Sustainable Development
(WRI-WBCSD) inventory protocol in anticipation of state and federal greenhouse gas
reporting mandates. Details about Climate Change Council efforts are in the Policy
Considerations chapter.
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
2009 Action Plan – Modeling and Forecasting Enhancements
Refine cost driver relationships in the stochastic model.
Continue to refine PRiSM by developing a resource retirement capability to solve for
other risk measurements and by adding more resource options.
Continue developing Loss of Load Probability and Sustained Peaking analysis for
inclusion in the IRP process, and confirm appropriateness of the 15 percent capacity
planning margin assumed for this IRP.
Continue studying the impacts of climate change on the load forecast.
Study load growth trends and their correlation to weather patterns.
Progress Report – Modeling and Forecasting Enhancements
Improvements have continued on stochastic modeling for the IRP. This plan relies on
new methods for modeling natural gas and wind. Work continues on developing a
method to correlate temperature, wind and hydro in the stochastic model. This work will
continue and results reported in the 2013 IRP.
The 2011 IRP includes several refinements to the PRiSM model. A resource retirement
capability was developed, but not utilized for this IRP. We developed a method to
evaluate the true standard deviation of power supply costs for the 2011 IRP, but long
solution times prevented its adoption. This plan also includes more resource options,
and modeling of generators by state and by location on the regional transmission
system.
Loss of Load Probability (LOLP) and Sustained Peaking analysis models were
developed and used for the 2011 IRP. This IRP uses an 18-hour sustained peak over
three days to estimate the need for new resources. Avista developed an LOLP model
for this IRP and presented it to the TAC on September 9, 2010; however, subsequent
testing of the model found that the LOLP study was driven primarily by regional market
availability assumptions that were beyond the scope of the study. The Company will
continue to work with the Northwest Power and Conservation Council to determine the
best methods for identifying regional market availability. More details are in the Loads &
Resources and Preferred Resource Strategy chapters.
The IRP load forecast continues to estimate the impacts of climate change on customer
load growth. More details are included in the Load and Resource chapter of this IRP.
Any changes will be in the 2013 IRP.
Transmission Planning
Work to maintain/retain existing transmission rights on the Company’s transmission
system, under applicable FERC policies, for transmission service to bundled retail
native load.
Continue to participate in BPA transmission practice processes and rate
proceedings to minimize the costs of integrating existing resources outside of the
Company’s service area.
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
Continue to participate in regional and sub-regional efforts to establish new regional
transmission structures (ColumbiaGrid and other forums) to facilitate long-term
expansion of the regional transmission system.
Evaluate costs to integrate new resources across Avista’s service territory and from
regions outside of the Northwest.
Study and implement distribution feeder rebuilds to reduce system losses.
Study transmission reconfigurations that economically reduce system losses.
Progress Report – Transmission Planning
The 2009 IRP transmission planning action item studies continue and are included in
the 2013 Action Plan. Details about progress made toward the maintenance of existing
transmission rights, involvement in BPA processes, participation in regional
transmission processes, and the evaluation of integrating different resources in the IRP
are in the Transmission and Distribution chapter.
Avista has completed a feeder rebuild pilot project at its 9th and Central 12F4 feeder.
The Company received federal stimulus dollars for several “Smart Grid” initiatives that
include projects contained in the 2009 IRP. The Company is developing a program to
rebuild additional feeders as outlined in this plan. Additional details on these projects
are included in the Transmission and Distribution Chapter.
2011 IRP Action Plan
The Company’s 2011 Preferred Resource Strategy provides direction and guidance for
the type, timing and size of future resource acquisitions. The 2011 IRP Action Plan
highlights the activities planned for possible inclusion in the 2013 IRP. Progress and
results for each of the 2011 Action Plan items will be reported to the Technical Advisory
Committee and the results will be included in Avista’s 2013 IRP. The 2011 Action Plan
includes input from Commission Staff, the Company’s management team, and the
Technical Advisory Committee.
Resource Additions and Analysis
Continue to explore and follow potential new resources opportunities.
Continue studies on the costs, energy, capacity and environmental benefits of hydro
upgrades at both Spokane and Clark Fork River projects.
Study potential locations for the natural gas-fired resource identified to be online by
the end of 2018.
Continue participation in regional IRP processes and, where agreeable, find
opportunities to meet resource requirements on a collaborative basis with other
utilities.
Provide an update on the Little Falls and Nine Mile hydroelectric project upgrades.
Study potential for demand response projects with industrial customers.
Continue to monitor regional surplus capacity and Avista’s reliance on this surplus
for near- and medium-term needs.
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
Energy Efficiency
Study and quantify transmission and distribution efficiency projects as they apply to
Washington RPS goals.
Update processes and protocols for conservation measurement, evaluation and
verification.
Continue to determine the potential impacts and costs of load management options.
Environmental Policy
Continue studies of state and federal climate change policies.
Continue and report on the work of Avista’s Climate Change Council.
Modeling and Forecasting Enhancements
Continue following regional reliability processes and develop Avista-centric modeling
for possible inclusion in the 2013 IRP.
Continue studying the impacts of climate change on retail loads.
Refine the stochastic model for cost driver relationships, including further analyzing
year-to-year hydro correlation and the correlation between wind, load, and hydro.
Transmission and Distribution Planning
Work to maintain the Company’s existing transmission rights, under applicable
FERC policies, for transmission service to bundled retail native load.
Continue to participate in BPA transmission processes and rate proceedings to
minimize costs of integrating existing resources outside of Avista’s service area.
Continue to participate in regional and sub-regional efforts to establish new regional
transmission structures to facilitate long-term expansion of the regional transmission
system.
Evaluate the costs to integrate new resources across Avista’s service territory and
from regions outside of the Northwest.
Study and implement distribution feeder rebuilds to reduce system losses.
Continue to study other potential areas to implement Smart Grid projects to other
areas of the service territory.
Study transmission reconfigurations that economically reduce system losses.
Chapter 9–Action Items
Avista Corp 2011 Electric IRP
Production Credits
Primary Avista 2011 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 Power Supply Analyst Research/Author/Editor
Randy Barcus Economic Analyst Load Forecast
Lori Hermanson Utility Resource Analyst Energy Efficiency
Scott Waples Director System Planning Transmission & Distribution
Other Contributors
Name Title
Reuben Arts System Planning Engineer
Thomas Dempsey Manager, Generation Joint Projects
Mike Gonnella Manager of Engineering - Thermal
Jason Graham Mechanical Engineer
Curt Kirkeby Senior Engineer II
Mike Magruder Substation Engineering Manger
Jon Powell Partnership Solutions Manager
Greg Rahn Manager of Natural Gas Planning
Xin Shane Power Supply Analyst
Ken Sweigart Transmission Design Manager
Steve Wenke Chief Generation Engineer
Jessie Wuerst Communications Manager
Contact contributors via email by placing the names in this email address format:
first.last@avistacorp.com