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2011 Integrated
June 2011
Resource Plan
HO
An IDACORP Company
Acknowledgement
Resource planning is a continuous process that Idaho Power Company
constantly works to improve.Idaho Power prepares and publishes an
Integrated Resource Plan (IRP)every two years and expects the experience
gained over the next few years will lead to modifications in the 20-year
resource plan presented in this document.
Idaho Power invited outside participation to help develop the 2011 IRP.
Idaho Power values the knowledgeable input,comments,and discussion
provided by the IRP Advisory Council,and the comments provided by
other concerned citizens and customers.
It takes approximately one year for a dedicated team of individuals at
Idaho Power to prepare the IRP.The IRP team is comprised of individuals
that represent many different departments within the company.IRP team
members are responsible for preparing forecasts,working with the IRP
Advisory Council (IRPAC)and the public,and performing all the analyses
necessary to prepare the resource plan.
Idaho Power looks forward to continuing the resource planning process
with its customers and other interested parties.You can learn more about
Idaho Power’s resource planning process at www.idahopower.com.
Safe Harbor Statement
This document may contain forward-looking statements,and it is important to note that the future results could differ
materially from those discussed.A full discussion of the factors that could cause future results to differ materially can
be found in Idaho Power’s filings with the Securities and Exchange Commission.
Idaho Power Company Table of Contents
TABLE OF CONTENTS
1.Summary .1
Introduction .1
Public Advisory Process .2
IRP Methodology 3
Demand-Side Management 3
Supply-Side Resource Costs 4
Greenhouse Gas Emissions 5
Preferred Resource Portfolio 6
Near-Term Action Plan 7
Public Policy Issues 8
2.Political,Regulatory,and Operational Issues 13
Idaho Energy Plan 13
Idaho Strategic Energy Alliance 13
FERC Relicensing 14
Idaho Water Issues 15
Wind Integration Study 16
Fixed Cost Adjustment 17
Renewable Energy Certificates 18
Federal Energy Legislation 19
3.Idaho Power Today 23
Customer Load and Growth 23
2010 Energy Sources 25
Existing Supply-Side Resources 27
Committed Supply-Side Resources 35
4.Demand-Side Resources 37
Energy Efficiency Program Portfolio Analysis 38
New Energy Efficiency Resources 39
Demand Response Resources 41
5.Supply-Side Resources 43
Renewable Resources 43
Natural Gas-Fired Resources 46
Distributed Generation 48
2011 IRP Page I
Table of Contents Idaho Power Company
Conventional Coal Resources .49
Integrated Gasification Combined Cycle and Carbon Sequestration 49
Advanced Nuclear 50
Transmission 50
6.Planning Period Forecasts 57
Load Forecast 57
Planning Scenarios 64
Existing Resources 65
Natural Gas Price Forecast 69
Resource Cost Analysis 72
7.Transmission Planning 79
Past and Present Transmission 79
Transmission Planning Process 79
Existing Transmission System 81
Transmission Assumptions in the IRP Portfolios 83
8.Planning Criteria and Portfolio Selection 85
Planning Scenarios and Criteria 85
Load and Resource Balance 85
Portfolio Design and Selection 89
9.Modeling Analysis and Results 93
Economic Evaluation Components and Assumptions 93
Risk Analysis and Results 98
Stochastic Analysis 107
Capacity Planning Margin 115
Loss of Load Expectation 119
10.Action Plans 121
Near-Term Action Plan (2011—2020)121
Long-Term Action Plan (202 1—2030)122
Conclusion 124
List of Tables 125
List of Figures 125
List of Appendices 127
Glossary of Abbreviations 129
Page ii 2011 IRP
Idaho Power Company 1.Summary
1.SUMMARY
Introduction
The 2011 Integrated Resource Plan (IRP)
is Idaho Power’s 10th resource plan prepared to
fulfill the regulatory requirements and
guidelines established by the Idaho Public
Utilities Commission (IPUC)and the Public
Utility Commission of Oregon (OPUC).
The 2011 JRP assumes that during the
planning period (2011—2030),Idaho Power
will continue to be responsible for acquiring
resources sufficient to serve all of its retail
customers in its mandated Idaho and Oregon
service areas and that the company will
continue to operate as a vertically integrated electric utility.In developing this plan,Idaho Power hasworkedwiththeIRPAdvisoryCouncil(IRPAC),which is comprised of major stakeholders representingtheenvironmentalcommunity,major industrial customers,irrigation customers,state legislators,public utility commission representatives,and others.There are four primary goals of Idaho Power’splanningprocess.
1.Identify sufficient resources to reliably serve the growing demand for energy withinIdahoPower’s service area throughout the 20-year planning period
2.Ensure the selected resource portfolio balances cost,risk,and environmental concerns
3.Give equal and balanced treatment to both supply-side resources and demand-side measures
4.Involve the public in the planning process in a meaningful way
Idaho Power is responsible for providing safe and reliable electrical service to its service area,which includes most of southern Idaho and a portion of eastern Oregon.In addition to operating undertheregulatoryoversightoftheJPUCandtheOPUC,Idaho Power is a public utility under thejurisdictionoftheFederalEnergyRegulatoryCommission(FERC)and is obligated to plan for andexpanditstransmissionsystemtoproviderequestedfirmtransmissionservicetothirdpartiesandtoconstructandplaceinservicesufficienttransmissioncapacitytoreliablydeliverresourcestonetwork
Highlights
‘The 2011 IRP expected-case load forecast projects peak-hour load will grow69megawatts(MW)annually (1.8 percent)and average-system load will increaseannually29averagemegawatts(aMW)(1.4 percent)over the 20-year planning period.
In 2011,Idaho Power’s demand response programs are expected to reduce peak-hourloadby330MW.
Idaho Power’s ability to import additional amounts of energy from the Pacific Northwest islimitedbyconstraintsontheexistingtransmissionsystem.
Idaho Power’s IRP is updated every two years.
2011 IRP Page 1
1.Summary Idaho Power Company
customers’and the company’s retail customers.2 The 2011 IRP evaluates only the need for additional
transmission capacity necessary to serve retail customers.The total capacity of proposed transmission
line projects may be larger than identified in the IRP in order to accommodate third-party requests and
network customer obligations for capacity on the same transmission path.
The number of customers in Idaho Power’s service area is expected to increase from approximately
492,000 in 2010 to over 650,000 by the end of the planning period in 2030.Even with the recent
recession,population growth in Idaho Power’s service area will require the company to add physical
resources to meet the energy demands of its growing customer base.
With hydroelectric generation as the foundation of its energy production,Idaho Power has an obligation
to serve customer loads regardless of the water conditions that may occur.In light ofpublic input and
regulatory support of the more conservative planning criteria used in the 2002 IRP,Idaho Power will
continue to emphasize a resource plan based on worse-than-median stream flows.The IRP uses more
conservative planning criteria than median water planning,but the criteria are less conservative than
critical water planning.Further discussion of Idaho Power’s planning criteria can be found in Chapter 8.
Idaho Power extended the planning horizon in the 2006 IRP to 20 years.Prior Idaho Power IRPs used a
10-year planning horizon,but with the increased need for resources with long construction lead times,
the need for a 20-year resource plan to support Public Utility Regulatory Policies Act of]978 (PURPA)
contract negotiations,and support from the IRPAC,Idaho Power decided to extend the planning horizon
of the 2006 and future resource plans to 20 years.
Planning for the future is necessary to meet the needs of Idaho Power’s customers today and tomorrow.
While the 2011 IRP addresses Idaho Power’s long-term resource needs,the company plans for the
near-term in accordance with the Energy Risk Management Policy and Standards that were
collaboratively developed in 2002 between Idaho Power,the IPUC staff,and interested customers
(IPUC Case No.IPC-E-01-16).While the IRP has a planning horizon of 20 years and is updated every
two years,the Energy Risk Management Policy and Standards focuses on an 18-month period and is
updated every month.
Public Advisory Process
Idaho Power has involved representatives of the public in the IRP planning process since the early
1990s.This public forum has come to be known as the LRPAC.The IRPAC generally meets monthly
during the development of the IRP,and the meetings are open to the public.Members ofthe council
include political,environmental,and customer representatives,as well as representatives of other public-
interest groups.
As part of preparing the 2011 IRP,Idaho Power hosted a field trip covering wind,hydroelectric,
and natural gas resources,two portfolio-design workshops,and nine monthly IRPAC meetings.
The IRPAC meetings served as an open forum for discussions related to the development of the IRP.
The IRPAC members and the public have made significant contributions to this plan.A list of the 2011
IRPAC members can be found in Appendix C—TechnicalAppendix.
Idaho Power believes working with members of the IRPAC and the public is a rewarding process,
and the IRP is better because of the public involvement.Idaho Power and the members of the IRPAC
recognize that outside perspective is valuable,but also recognize that fmal decisions on the IRP are
Idaho Power has a regulatory obligation to construct and provide transmission service to network or wholesale customers pursuant to a
FERC Tariff.
2 Idaho Power has a regulatory obligation to construct and operate its system to reliably meet the needs of native load or retail customers.
Page 2 2011 IRP
Idaho Power Company 1.Summary
made by Idaho Power.Idaho Power encourages IRPAC members and members of the public to submitcommentsexpressingtheirviewsregardingthe2011IRPandtheplanningprocessingeneral.
Following the filing of the final plan,Idaho Power presents the IRP at public meetings in various citiesaroundthecompany’s service area.In addition,Idaho Power staff presents the plan and discusses theplanningprocesswithvariouscivicgroupsandateducationalseminarsasrequested.
IRP Methodology
The preparation of Idaho Power’s 2011 IRP begins with updating the forecast of future customerdemand.Existing resources,the ability to import electricity,and the performance of existingdemand-side management (DSM)programs are then accounted for in the load and resource balance.The next step involves evaluating new DSM programs and the expansion of existing programs.Finally,Idaho Power evaluates portfolios of supply-side resources designed to eliminate anyremainingdeficits.
Idaho Power primarily uses a financial analysis to compare various resource portfolios to determine thepreferredportfolio.Idaho Power attempts to financially value the costs and benefits of each resourcetype.Traditional resources have fixed and variable costs and a market value for the delivered energy,and Idaho Power includes both the costs and the value when evaluating resources.The cost of anynecessarytransmissionupgradesandthevalueofrenewableenergycertificates(REC)are alsoaccountedforintheanalysis.
Two resources identified in the 2009 IRP are considered committed resources in the 2011 JRP—1)the 300-megawatt (MW)Langley Gulch combined-cycle combustion turbine (CCCT)that is expectedtobeavailableinthesummerof2012,and 2)a 49-MW upgrade of the Shoshone Falls HydroelectricProjectin2015.
For the 2011 IRP,the 20-year planning period was divided into two,10-year segments.Dividing theplanningperiodintothesetwosegmentspreventsnear-term resource decisions from being influenced bytheavailabilityofresourcesthataredependentontechnologicaladvancementsinthesecond10years.
In the first 10-year period (2011—2020),nine resource portfolios were examined.Each resourceportfoliowasdesignedtosubstantiallymeettheenergyandcapacitydeficitsidentifiedintheload andresourcebalance.
For the second 10-year period (202 1—2030),the preferred resource portfolio from the first 10-yearperiodwascoupledwitheachofthe10portfoliosanalyzedforthesecondperiod.Using the preferredportfoliofromthefirst10-year period ensures all the portfolios in the second 10-year period areanalyzedconsistently.
Demand-Side Management
Energy efficiency programs from both the existing portfolio and new program opportunities included inthe2011IRPareforecasttoreduceaverageloadby233averagemegawatts(aMW)by 2030.New energy efficiency opportunities come from a combination of new measures and programexpansions.The cost to acquire energy efficiency will vary between an average of 3.6 cents per kilowatthour(kWh)for existing programs to 5.1 cents per kWh for new program activities and measures for the2011JRP.
Demand response programs for the 2011 IRP are targeted to reduce peak summer load by 351 MW bysummer2016.Demand response resources have an average levelized cost of $48 per kilowatt (kW)over the IRP planning period.Demand response programs as peaking resources have grown dramaticallyinthepastfewyears.The large increase comes from the introduction of the FlexPeak Management
2011 IRP Page 3
1.Summary Idaho Power Company
program,which targets commercial and industrial customers,and the transition of the Irrigation Peak
Rewards program into a dispatchable,direct load-control program as part of the 2011 IRP.
Details on Idaho Power’s existing and proposed DSM programs can be found in Chapter 4 and in
Appendix B—2010 Demand-Side Management Annual Report.An explanation of the methodologies used
to incorporate prior and forecast energy efficiency impacts into the load forecast can be found in
Appendix A—Sales andLoadForecast.
Suppfy-Side Resource Costs
The 2011 IRP forecasts load growth in Idaho Power’s service area and identifies supply-side resources
and demand-side measures necessary to meet the future needs of customers.Recent cost increases have
significantly impacted the cost ofnew supply-side resources,especially when compared to the cost of
the existing resources in Idaho Power’s generation portfolio.Figure 1.1 shows the 2010 costs in dollars
per megawatt hour (MWh)for Idaho Power’s existing hydroelectric resources,coal generation facilities,
and power purchased from the Elkhorn Valley Wind Project.In addition,Figure 1.1 shows the estimated
cost of energy from new resources considered in the 2011 IRP.Existing resource costs are based on
2010 actual costs of capital,fuel,and non-fuel operating and maintenance (O&M).New resource costs
are 30-year levelized estimates (based on expected annual generation),which include capital,fuel,
non-fuel O&M,and the expected-case carbon adder.
$300
$250
$200
$150
$100
$50
$0
NOTES:
1)Costof existing resources based on 2010 cosS
2)Cost of new resources based on 30-year levelized cost estimates
3)Costof existing wind isforthe Elkhcwn Wind Prcect only (Elkhorn produced approximately 80%of the wind generation purchased by Idaba Power during 2010).
Figure 1.1 Cost of existing and new supply-side resources
While it is important to evaluate the costs presented in Figure 1.1,these figures represent only a part of
the total resource cost.In preparing the IRP,Idaho Power must also consider the value that each type of
resource provides in conjunction with the other resources in the company’s generation portfolio.
Supply-side resources have different operating characteristics,making some better suited for meeting
New Resources
Existing Resources
0 CP c —\C—
Page 4 2011 IRP
Idaho Power Company 1.Summary
capacity needs while others are better for providing energy.The low capital cost and dispatch capabilityofasimple-cycle combustion turbine (SCCT)resource makes it a good choice for meeting capacityneeds,as long as it is needed for only short durations to meet peak-hour load.A geothermal resourcetypicallyprovidesmaximumgenerationduringpeakloadperiods,but because it is non-dispatchable andgenerallyprovidesconstantgenerationyearround(baseload),it is considered a better energy resource.Wind is also a good source of energy;however,it provides almost no peak-hour capacity due to thevariableandintermittentnatureofthegeneration.
Figure 1.2 shows the 30-year levelized capital cost in dollars per MW of peak-hour capacity for many ofthesupply-side resources evaluated in the 2011 IRP.This metric provides useful information on thevalueofeachresourcetypeintermsofprovidingpeak-hour capacity.Idaho Power’s peak loadstypicallyoccurbetween3:00 p.m.and 7:00 p.m.on hot summer days;the expected capacity factor foreachresourcetypeduringthistimeperiodisalsoshowninFigure1.2.
$6,000
$5,000
U
$4,000
$3,000 -—--—————-—-—-—---—-——-—-——--——---------—-
—
-
_
_
_
_
_
_
______
0 $2,000 -_____
______
100%$1 000
100°f ioo’89%100%1O074%
___-
$95 $167 $240 j’$600 $670 $679 $745 ,98
$0
,‘
Figure 1.2 30-year levelized capital cost of peak-hour capacity
Resources capable ofproviding 100 percent ofnameplate capacity during peak load periods have anobviouscostadvantagewhencomparedtoresourceswithlowerpeak-hour capacity factors,such aswind.Because wind can be counted only to provide 5 percent of nameplate capacity during thepeak-hour,20 MW of nameplate wind would need to be built to get one MW ofpeak-hour capacity.Acompletediscussionofthecostofcapacityandthetotalcostoftheresourcesanalyzedinthe2011IRPispresentedinChapter6,and details ofthe calculations used to prepare Figure 1.2 are presented inAppendixC—Technical Appendix.
Greenhouse Gas Emissions
Idaho Power owns and operates 17 hydroelectric projects,2 natural gas-fired plants,1 diesel-poweredplant,and shares ownership in 3 coal-fired facilities.Idaho Power’s carbon dioxide(C02)emissions levels have historically been well below the national average for the 100 largestelectricutilitiesintheUnitedStates,both in terms of total CO2 emissions (tons)and CO2 emissionsintensity(pounds [lbs]per MWh),based on the report of 2008 CO2 emissions presented inBenchmarkingAirEmissionsofthe100LargestElectricPowerProducersintheUnitedStates,
2011 IRP Page 5
1.Summary Idaho Power Company
released in June 2010 by the Ceres investor coalition,the Natural Resources Defense Council,
Public Service Enterprise Group,and Portland Gas &Electric (PG&E)Corporation.
In September 2009,Idaho Power’s Board of Directors approved guidelines to establish a goal to reduce
the CO2 emissions intensity of the company’s utility operations.The guidelines are intended to prepare
the company for potential legislative and or regulatory restrictions on greenhouse gas (GHG)emissions,
while minimizing the cost of complying with such reductions on Idaho Power’s customers.
The guidelines establish a goal to reduce Idaho Power’s resource portfolio’s average CO2 emissions
intensity for the 2010 through 2013 time period to a level of 10—15 percent below the company’s
2005 CO2 emissions intensity of 1,194 lbs per MWh.Since Idaho Power’s CO2 emissions intensity
fluctuates with stream flows and the production levels of existing and anticipated renewable resources,
the company has adopted an average intensity reduction goal to be achieved over several years.
At present,generation and emissions from company-owned resources are included in the CO2 intensity
calculation.The company’s progress toward achieving this intensity reduction goal,as well as additional
information on Idaho Power’s CO2 emissions,is currently reported on the company’s website at
www.idahopower.com!NewsCommunity/OurEnvironment/co2lntensity.cfm.Information related to
Idaho Power’s CO2 emissions is also available through the Carbon Disclosure Project at
www.cdproject.net.
Idaho Power’s annual CO2 emissions intensity for 2009 and 2010 were 1,003 lbs per MWh and 1,065 lbs
per MWh respectively,both below the 2005 CO2 emissions intensity level.Idaho Power’s average
CO2 intensity for the goal period-to-date,January 2010—April 2011,is 949 lbs of CO2 per MWh.
This reduction in intensity relative to the 2010 level reflects an increase in hydroelectric generation,as a
result of the current water conditions,and reduced coal-fired generation.For the 2010—2013 time period,
Idaho Power fuiiy expects to achieve its goal of reducing its CO2 emissions intensity from
company-owned resources (relative to the 2005 level of 1,194 lbs CO2 per MWh)by more than
15 percent.
The guidelines are intended to reduce Idaho Power’s near-term CO2 emissions intensity levels in a
manner that minimizes the cost of the reductions on the company’s customers.The 2011 IRP attempts to
quantify the cost and longer term impacts of carbon regulations by including a carbon adder that is
applied to all resources that emit CO2.Additional details regarding the assumptions and analysis are
presented in Chapter 6 and Chapter 9 of the 2011 IRP.
Preferred Resource Portfolio
The preferred portfolio for the 2011 IRP presented in Table 1.1 was constructed by combining the
preferred portfolio for the first 10 years ofthe planning horizon (2011—2020)with the preferred portfolio
for the second 10-year period (202 1—2030).Tn addition to the committed resources (Langley Gulch and
the Shoshone Falls upgrade)the preferred resource portfolio includes 450 MW of market purchases
beginning in 2016 with the completion of the Boardman to Hemingway transmission line.The total
west-to-east transfer capacity reserved on Boardman to Hemingway by Idaho Power is expected to be
450 MW.
The preferred portfolio for the second 10-year period (202 1—2030)represents a balanced strategy of
adding a mixture of renewable resources along with natural gas-fired baseload and peaking resources.
Although the resources in the preferred portfolio for the second 10-year period were analyzed without
the addition of the Gateway West transmission project,Idaho Power plans to continue permitting the
Gateway West project because of uncertainty associated with the location of resources planned so far in
the future and the long lead time required to permit high-voltage transmission projects.
Page 6 2011 IRP
Idaho Power Company
1.Summary
Table 1.1 Preferred portfolios
2011
2012 CCCT (Langley Gulch)*
2013 Solar Demonstration Project
Shoshone Falls Upgrade*
Boardman to Hemingway
Year Resource
Geothermal
SCCT
2027
Solar Power Tower
CCCT
2028 Small Hydro
2029 SCCT
2030
1—3 Boardman to Hemingway (2011—2020)
Year Resource MW
2—6 Balanced 1 (2021—2030)
2021
300 2022
2023
2014
2015
2016
2017
2018
2019
2020
2024
49 2025
450 2026
MW
52
170
50
300
60
170
*Commftted resource
Idaho Power relies primarily on company-owned hydroelectric and coal-fired generation facilities alongwithpurchasedpowertosupplytheenergyneededtoservecustomers.Because Idaho Power’s annualhydroelectricgenerationvariesdependingonwaterconditionsintheSnakeRiver,the percentage ofeachenergysourcealsochangesyear-to-year.
Figure 1.3 shows Idaho Power’s “fuel mix”by resource type for 2010,and Figure 1.4 estimates thecompany’s fuel mix in 2030 based on the implementation of the preferred portfolio.In 2030,Idaho Power’s hydroelectric resources are the predominate resource and provide over 50 percent of themix.Generation from coal-fired resources becomes a smaller part of the mix,being replaced by naturalgasandamixtureofrenewableresources.In preparing Figures 1.3 and 1.4,market purchases wereassumedtobecomprisedoftheestimatedPacificNorthwestenergymarketfuelmixfor2010and2030.
Natural Biomass WasteGasWind0.5%0.5%31%2.6%
Geothermal SolarBiomass Industrial3%l%çs Waste
__Nuclear
7/-0.5%Natural Gas Hydroelectnc9%.
NOTE:2010 Market Purchases are 6%of Idaho Power’s energysources,and the fuel mix is modeled in this graph using theNorthwestPowerPool(NWPP)system mix for 2010.
Figure 1.3 2010 fuel mix
NOTE:2030 Market Purchases are 13%of Idaho Power’s energysources,and the fuel mix is modeled in this chart using the AURORAWashingtonsystemmixfor2030.
Figure 1.4 2030 fuel mixIdahoPoweranticipatestheresourcesinthesecond10-year period will be reconsidered in the 2013 IRPandsubsequentplansasmorecertaintyregardingcarbonregulationsandafederalrenewableelectricitystandard(RES)become available.Future uncertainty requires alternate portfolios be considered in theresourceplanningprocess.Further details regarding the preferred portfolio and the alternate portfolioscanbefoundinChapter10.
Near-Term Action Plan
The Langley Gulch CCCT is currently under construction and is expected to be completed by summer2012.Idaho Power also anticipates beginning preliminary design work for the Shoshone Falls Upgrade
2011 IRP
Page 7
1.Summary
Idaho Power Company
Project in 2012,which is expected to be completed in 2015.Idaho Power is also continuing to work with
federal and state agencies,FERC,other transmission providers,and the public on the Boardman to
Hemingway and Gateway West transmission projects.Major milestones associated with these resources
and programs are presented in Table 1.2.
Table 1.2 Near-term action plan milestones
Year Action
2011 Langley Gulch CCCT construction continues
File 2011 IRP with regulatory commissions
Demand response programs expected to provide 330 MW of load reduction
Continue the Boardman to Hemingway permitting process
Continue the Gateway West NEPA permitting process
Prepare and issue an RFP for the Solar Demonstration Project
2012 Langley Gulch CCCT on line (300 MW)
Evaluate responses to the Solar Demonstration Project and file a Certificate of
Public Convenience and Necessity (CPCN)
Complete design work on the Shoshone Falls Upgrade Project and issue RFP
Continue Boardman to Hemingway permitting process
Continue the Gateway West NEPA permitting process
Solar Demonstration Project on line in late 2012/early 2013
2013 Issue RFP for 8oardman to Hemingway construction
Shoshone Falls Upgrade Project construction begins
File 2013 IRP with regulatory commissions
Continue the Gateway West NEPA permitting process
2014 Shoshone Falls Upgrade Project construction continues
Boardman to Hemingway construction begins
Secure 83 MW PPA for summer 2015 from the east side
2015 Shoshone Falls Upgrade Project on line (49 MW)
File 2015 IRP with regulatory commissions
2016 Boardman to Hemingway construction completed (450 MW)
2017 File 2017 IRP with regulatory commissions
2018
2019 File 2019 IRP with regulatory commissions
2020
Public Policy Issues
The 2011 IRP was completed using computer modeling and other analytical methods.However,
certain public policy questions exist that cannot be directly examined through analytical methods.
Idaho Power has presented these issues to the IRPAC for discussion,but the nature of issues typically
precludes a strong majority opinion from IRPAC members.The public policy issues presented to the
IRPAC are discussed in the following sections.
New Large Loads
Locally,Idaho Power and its customers face internal conflicts created by traditional rate determination
and the cost difference between existing resources and future resources.New customers that connect to
Idaho Power’s system benefit from energy rates based on the low-cost of existing resources that are
embedded in current rates.However,Idaho Power’s existing resources and transmission system are fully
used,and new customers require the addition of generation,transmission,and distribution resources.
Because new resources are more expensive than Idaho Power’s existing portfolio,each new customer
Page 8
2011 IRP
Idaho Power Company
1.Summary
dilutes the existing resource base and increases the cost to all customers.Accordingly,for a number ofyears,Idaho Power has attempted to balance the impact on both the new customer and existingcustomersthroughanintermediateperiodbyusingblockedcontractsthatprovideforanelement ofmarginal-cost pricing.
In addition,Idaho Power’s ability to serve new large loads is limited as growth in summertime peakdemandcontinuestodrivetheneedforadditionalresources.New businesses are attracted to southernIdahodueinparttoIdahoPower’s low rates,which have consistently been some of the lowest in thenation.When a new large customer makes a request for service,Idaho Power must include restrictions inthecontractlimitingthecustomer’s usage during peak summer months.These restrictions typically lastforseveralyearsuntilnewresourcescanbeplannedforandbuilt,and many new large customers areunableorunwillingtoaccepttheseterms.
For the 2011 IRP,an analysis was performed to determine the cost of building additional naturalgas-fired peaking capacity that could be used to serve new large loads.The analysis assumes 80 MW ofcapacityfromaSCCTisaddedtoIdahoPower’s resource portfolio in 2014.The analysis also assumestheadditionalcapacityisbuiltandnonewlargeloadmaterializes.
The results show the net present value of the revenue requirement associated with the fixed and variablecostofaddingtheadditional80MWofcapacitywouldbe$60 million.In addition to positioning thecompanytoservenewlargeloads,which will promote local economic development and create jobs,this additional capacity will be able to assist with integrating wind generation and,when opportunitiesexist,make profitable surplus sales to help offset the fixed costs of ownership.Appendix C—TechnicalAppendixcontainsadditionaldetailsregardingtheanalysis.
Idaho Power recognizes the ability to serve new large loads has an impact on Idaho’s economy.Because ofthis,and the results of the analysis mentioned above,Idaho Power is proposing an additional80MWofpeak-hour load be added to Idaho Power’s load and resource balance beginning with the2013IRP.By adding this additional peak-hour load to the load and resource balance,the additionalcapacitywillcomefromadiversesetofresourcesidentifiedintheIRPprocess,perhaps at a lower cost,and not specifically from the construction of a single new resource.
Asset Ownership
Idaho Power can develop and own generation assets,rely on power purchase agreements (PPA)and market purchases to supply the electricity needs of its customers,or use a combination of thetwoownershipstrategies.Idaho Power expects to continue participating in the regional power marketandenterintomid-term and long-term PPAs.However,when pursuing PPAs,Idaho Power must bemindfulofimputeddebtanditspotentialimpactonIdahoPower’s credit rating.In the long run,Idaho Power believes asset ownership results in lower costs for customers due to the capital and rate ofreturnadvantagesinherentinaregulatedelectricutility.
Emissions Offsets
Depending on market conditions and future regulations,it may be possible to purchase emissions orcarbonoffsetsforlessthanthecostofacarbonallowance.Some members of the IRPAC have suggesteditwouldbeprudentforIdahoPowertohedgecarbonemissionsriskbypurchasingemissionsoffsetspriortotheformalpassageofcarbonlegislation.However,there are differing opinions among IRPACmembers.The principal reason cited for not purchasing offsets today is the uncertainty associated withwhethercarbonoffsetspurchasedtodaywillmeetfuturecarboncontrolrequirementsandregulations.Inaddition,recent draft federal legislation has limited the amount of offsets that may be used to meetreductiontargets.
2011 IRP
Page 9
1.Summary
Idaho Power Company
Uncertainty in the future regulation of carbon is evidenced in the recent collapse of the Chicago Climate
Exchange (CCX).CCX was established in 2003 as the sole voluntary GHG reduction and offset trading
platform for North America and Brazil.In December 2010,CCX ceased trading due to the complete
market free-fall of their carbon emissions product.However,CCX continues generation oftheir carbon
financial instrument (CFI)product as a strictly voluntary GHG emissions offset system.
Idaho Power plans to continue to follow developments related to carbon offsets and options in the event
either becomes a viable alternative.The company could potentially reduce the large financial exposure
of possible carbon regulation for the cost of the option premium.Idaho Power believes it should be able
to recover the cost ofpurchasing emissions offset options as well as the cost of any emissions
offsets purchased.
Technology Risk and Joint Development
In the 2011 IRP,several resource options dependent on developing technology have been evaluated in
various portfolios.Carbon capture and sequestration,integrated gasification combined-cycle (IGCC),
advanced nuclear,and numerous storage technologies are not yet commercially available;however,
the technology may become available during the 20-year planning horizon evaluated in the IRP.
This raises the question of whether Idaho Power should participate in development efforts related to any
of these technologies prior to them becoming commercially available.
Idaho Power believes that,as a medium-sized utility,it would be impractical to lead the development
work on any particular technology.However,as certain technologies are identified that show promise as
being beneficial to Idaho Power and its customers,the company may choose to participate in
development efforts.Idaho Power’s participation would most likely be part of a larger group-effort to
develop a technology jointly with other utilities with similar needs.
Similarly,certain existing and emerging resource technologies are available only in large sizes—
larger than what Idaho Power could or would consider developing alone.If opportunities become
available to jointly develop large resources,Idaho Power plans to evaluate them on a case-by-case
basis.A similar strategy has been used in the past and resulted in Idaho Power’s joint ownership of
three coal-fired resources.
Solar Demonstration Project
While solar technology continues to be more expensive than other alternatives,the cost of solar
resources continues to decrease while the cost of most other resource options has increased.In addition
to providing RECs,solar resources typically deliver energy during the time of day when Idaho Power’s
customer demand is high.
Idaho Power’s 2009 IRP discussed the advantages and disadvantages of several solar demonstration
project options,including a utility-scale project located near an existing substation and a distributed
rooftop program.During the preparation of the 2009 IRP,a substantial amount of support was expressed
by IRPAC members and the public for some type of a local project.
Idaho Power has continued to evaluate the benefits of developing a solar photovoltaic (PV)
demonstration project and the topic was again discussed with the IRPAC as part of preparing the 2011
IRP.Several IRPAC members expressed support for the project to include a research and development
component as well as continued support for developing a solar rooftop program.
As the cost continues to decline,Idaho Power believes solar PV resources will become more prevalent
in the future,and it will be important for the company to have operating experience and be able to
determine what specific type of PV technology provides the most value for Idaho Power customers.
Page 10
2011 IRP
Idaho Power Company 1.Summary
With that in mind,Idaho Power intends to make a more detailed proposal that would allow the companytoinvestinasmall-scale solar PV resource.
Idaho Power anticipates issuing a request for proposal (RFP)before the end of 2011 to design andconstructa500-kW—1-MW solar PV resource to be located in Idaho Power’s service area.A portion ofthefacilitywouldbedevotedtotestingnewPVpaneltechnologies,inverters,and other mounting andtrackingsystems.Idaho Power would also offer to collaborate with the Center for Advanced EnergyStudies(CAES)on relevant research into solar technologies.
Proposals would be evaluated by mid-2012,and if a successful bidder is identified,the company wouldthenfilearequestwiththeIPUCforaCPCN.If approved,it is anticipated the facility could be on lineasearlyastheendof2012.
Based on the 2011 LRP cost estimate for a solar PV resource of $3,750 per kW,the expected cost of theprojectcouldbe$2—$4 million and would require approximately 5—10 acres of land.While the proposedsizeofthisprojectissmallrelativetowhatmightbeconsideredautility-scale project,Idaho Powerbelievesitwillprovideusefuldataandgivethecompanyexperienceowningandoperatingthistype ofresource.It will also allow the company to better evaluate the advantages and disadvantages of utility-scale solar PV projects and distributed rooftop programs.
Idaho Power views this proposal as a demonstration project because of its small size and its primarypurposebeingtocollectinformationonhowsolarPVresourcesintegratewiththecompany’s othersystemresources.In addition to providing valuable information on solar integration,the demonstrationprojectwillprovideanopportunityforIdahoPowertoexpandgreenpowerprogramoptionsforcustomers.
Idaho Power’s REC Management Plan details the company’s intent to continue selling RECs in the neartermuntiltheyareneededtomeetafederalRES.In general,a majority of Idaho Power’s customerssupportthispolicy,as 95 percent of the revenue from the sale of RECs is returned to customers to keeprateslow.However,there is a growing segment of customers who desire,and are willing,to pay apremiumfor,green energy.Idaho Power believes it is important to provide additional options for thesecustomers,and the solar demonstration project presents an opportunity to expand the available offerings.
In addition to the benefits already identified,Idaho Power is required to build a 500-kilovolt (kV)solar PV project within the next several years under the State of Oregon’s Solar PV Pilot Program.The company is currently working with the OPUC to determine ifthis facility would have to be built inOregon,which may impact the structure of the RFP.Additional details on the Oregon Solar PV PilotProgramcanbefoundinChapter3.
2011 IRP
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1.Summary Idaho Power Company
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2011 IRP
Idaho Power Company 2.Political,Regulatory,and Operational Issues
2.POLITICAL,REGULATORY,AND OPERATIONAL ISSUES
Idaho Power is a regulated utility.On the federal level,
Idaho Power is subject to the rules and regulation of
FERC.On the state level Idaho Power is subject to the
IPUC and OPUC because the company has customers
in both Idaho and Oregon,with approximately
95 percent of Idaho Power’s customers located in the
state of Idaho.The following sections describe some of
the federal and state regulatory issues facing
Idaho Power.
Idaho Energy Plan
In 2006,the Idaho State Legislature directed the
Interim Committee on Energy,Environment,
and Technology to develop a state energy plan that provides for the state’s power generation needs andprotectsthehealthandsafetyofIdahocitizens.In January 2007,the committee completed the 2007IdahoEnergyPlanandconcludedthatallIdahoenergysystemshaveperformedverywell,with retailelectricandnaturalgaspricesremainingsomeofthelowestinthecountry.
The committee also recognized that Idaho’s reliance on low-cost coal plants may become a source of
risk in the future due to the economic impact of potential federal regulation of carbon and mercury (Hg)emissions.To address these concerns,the committee recommended increasing investments in energyconservationandin-state renewable resources.In a resource priority policy statement,the committee
stated,“When acquiring resources,Idaho and Idaho utilities should give priority to:1)conservation,
energy efficiency,and demand response;and 2)renewable resources;recognizing that these alone may
not fulfill Idaho’s growing energy requirements.”The committee further stated,“...energy suppliersmustcontinuetohaveaccesstoconventionalenergyresourcestokeepIdaho’s energy costs as low
as possible.”
Idaho Strategic Energy Alliance
In 2007,Governor C.L.“Butch”Otter established the Idaho Office of Energy Resources (IOER)
to oversee energy planning,policy,and coordination in Idaho.Under the umbrella of this office,
the Idaho Strategic Energy Alliance was established to respond to rising energy costs and other energychallengesfacingthestate.The governor’s philosophy is that there should be a joint effort between allstakeholdersindevelopingoptionsandsolutionsforIdaho’s energy future.
HghIights
Idaho Power continues to operate the Hells Canyon Complex under annual licenses
issued by FERC until a new license is issued.
The 2011 IRP assumes a federal RES will be enacted in the future.
Idaho Power is preparing an updated wind integration study in association with the
2011 IRP.
The IPUC regulates Idaho Power in Idaho.
2011 IRP Page 13
2.Political,Regulatory,and Operational Issues Idaho Power Company
The alliance promotes the development of a sound energy portfolio for Idaho that diversifies energy
resources and provides stewardship of the environment.The alliance consists of a board of directors and
13 volunteer task forces working in the following areas:
•Conservation and energy efficiency •Forestry
•Wind •Biogas
•Geothermal •Biofuel
•Hydroelectric power •Solar
•Carbon issues •Transmission
•Baseload resources .Communication and outreach
•Economic/financial development
Idaho Power representatives serve on many of these task forces.The alliance is governed by a board of
directors comprised of representatives from Idaho stakeholders and industry experts.The workings of
the alliance are overseen by the Governor’s Council,a group of the governor’s cabinet members.
FERC Relicensing
Like other utilities that operate non-federal hydroelectric projects on qualified waterways,Idaho Power
obtains licenses from FERC for its hydroelectric projects.The licenses last for 30 to 50 years,depending
on the size,complexity,and cost of the project.Idaho Power is actively pursuing the relicensing of the
Hells Canyon Complex and the Swan Falls hydroelectric project.
Idaho Power’s most significant ongoing relicensing effort is the Hells Canyon Complex.The Hells
Canyon Complex provides approximately two-thirds of Idaho Power’s hydroelectric generating capacity
and 40 percent of the company’s total generating capacity.The current license for the Hells Canyon
Complex expired at the end of July 2005.Until the new,multi-year license is issued,Idaho Power
continues to operate the project under an annual license issued by FERC.
The Hells Canyon Complex license application was filed in July 2003 and accepted by FERC for filing
in December 2003.FERC is now processing the application consistent with the requirements of the
Federal Power Act of 1920,as amended (FPA);the National Environmental Policy Act of1969,as
amended (NEPA);the Endangered Species Act of1978 (ESA);and other applicable federal laws.
The license for the Swan Falls project expired in June 2010.In March 2005,Idaho Power issued a
Formal Consultation Package (FCP)to the public relating to environmental studies designed to
determine project effects for the relicensing of the project.In September 2007,Idaho Power submitted a
draft license application to FERC for public review and comment.The draft application was based on
the results of environmental studies along with agency and public consultation.Idaho Power filed a final
license application for the Swan Falls hydroelectric project with FERC in June 2008,and FERC issued
its Final Environmental Impact Statement (FEIS)in August 2010.
Relicensing costs of $134 million and $5 million for the Hells Canyon Complex and Swan Falls
projects,respectively,were recorded by Idaho Power as of March 2011.Administrative work on
relicensing is expected to continue until new licenses are issued in 2012 for Swan Falls and 2014 for the
Hells Canyon Complex.Once new licenses are issued,further costs will be incurred to comply with the
terms of the new licenses.Given the new licenses for Swan Falls and the Hells Canyon Complex have
not been issued,and discussions on the PM&E packages are still being conducted,it is not possible to
estimate the final total cost.
Page 14 2011 IRP
Idaho Power Company 2.Political,Regulatory,and Operational Issues
Relicensing activities include:1)coordination of the relicensing process;2)consulting with regulatoryagencies,tribes,and interested parties;3)preparing studies and gathering environmental data on fish,wildlife,recreation,and archaeological sites;4)preparing studies and gathering engineering data onhistoricalflowpatterns,reservoir operation and load shaping,forebay and river sedimentation,reservoircontoursandvolumes;5)study and data analysis;6)preparing all necessary reports,exhibits,and filings;7)responding to requests for additional information from FERC;and 8)legal consultation.This estimate includes costs for all areas of Idaho Power related to the relicensing effort.
Failure to relicense any of the existing hydroelectric projects at a reasonable cost will create upwardpressureonthecurrentelectricratesofIdahoPowercustomers.The relicensing process also has thepotentialtodecreaseavailablecapacityandincreasethecostofaproject’s generation through additionaloperatingconstraintsandrequirementsforenvironmentalprotection,mitigation,and enhancement(PM&E)measures imposed as a condition for relicensing.Idaho Power’s goal throughout the relicensingprocessistomaintainthelowcostofgenerationatthehydroelectricfacilitieswhileimplementingnon-power measures designed to protect and enhance the river environment.
No reduction of the available capacity or operational flexibility of the hydroelectric plants to berelicensedwasassumedaspartofthe2011IRP.If capacity reductions or reductions in operationalflexibilitydooccurasaresultoftherelicensingprocess,Idaho Power will adjust future resource planstoreflecttheneedforadditionalgenerationresources.
Idaho Water Issues
Power generation at Idaho Power’s hydroelectric projects on the Snake River is dependent on the statewaterrightsheldbythecompanyfortheseprojects.The long-term sustainability of the Snake RiverBasinstreamflows,including tributary spring flows and the regional aquifer system,is crucial forIdahoPowertobeabletomaintaingenerationfromtheseprojects,and the company is dedicated to thevigorousdefenseofitswaterrights.None of the pending water-management issues are expected toimpactIdahoPower’s hydroelectric generation in the near term,but the company cannot predict theultimateoutcomeofthelegalandadministrativewater-rights proceedings.Idaho Power’s ongoingparticipationinwater-rights issues is intended to guarantee that sufficient water is available for use atthecompany’s hydroelectric projects on the Snake River.
Idaho Power is engaged in the Snake River Basin Adjudication (SRBA),a general streamfiowadjudicationprocessstartedin1987todefinethenatureandextentofwaterrightsintheSnake RiverBasin.Idaho Power filed claims for all of its hydroelectric water rights in the SRBA,is activelyprotectingthosewaterrights,and is objecting to claims that may potentially injure or affect those waterrights.The initiation of the SRBA resulted from the Swan Falls Agreement entered into by Idaho PowerandthegovernorandattorneygeneralofIdahoinOctober1984.
In 1984,the Swan Falls Agreement resolved a struggle between the state of Idaho and Idaho Power overthecompany’s water rights at the Swan Falls hydroelectric facility.The agreement stated Idaho Power’swaterrightsatitshydroelectricfacilitiesbetweenMimerDamandSwanFallsentitledthecompanytoaminimumflowatSwanFallsof3,900 cubic feet-per-second (cfs)during the irrigation season and5,600 cfs during the non-irrigation season.
The agreement placed the portion of the company’s water rights beyond those minimum flows in a trustestablishedbytheIdahoLegislatureforthebenefitofIdahoPowerandthecitizensofthestate.Legislation establishing the trust granted the state authority to allocate trust water to future beneficialusesinaccordancewithstatelaw.Idaho Power retained the right to use water in excess of the minimumflowsatitsfacilitiesforhydroelectricgenerationuntilitwasreallocatedtootheruses.
2011 IRP Page 15
2.Political,Regulatory,and Operational Issues Idaho Power Company
Idaho Power filed suit in the SRBA in 2007,as a result of disputes about the meaning and application of
the Swan Falls Agreement.The company asked that the court resolve issues associated with
Idaho Power’s water rights and the application and effect of the trust provisions of the Swan Falls
Agreement.In addition,Idaho Power asked the court to determine whether the agreement subordinated
the company’s hydroelectric water rights to aquifer recharge.
A settlement signed in 2009 reaffirmed the Swan Falls Agreement and resolved the litigation by
clarifying that the water rights held in trust by the state are subject to subordination to future upstream
beneficial uses,including aquifer recharge.It also committed the state and Idaho Power to further
discussions on important water-management issues concerning the Swan Falls Agreement and the
management of water in the Snake River Basin.Idaho Power and the state are actively involved in those
discussions.The settlement also recognizes water-management measures that enhance aquifer levels,
springs,and river flows—such as aquifer-recharge projects—that benefit both agricultural development
and hydroelectric generation.Both parties anticipate water-management measures will be developed in
the implementation of the Eastern Snake River Plain Aquifer,Comprehensive Aquifer Management
Plan (ESPA CAMP)as approved by the Idaho Water Resource Board.
Idaho Power actively participates in proceedings associated with the ESPA CAMP.Given the high
degree of interconnection between ESPA and the Snake River,Idaho Power recognizes the importance
of aquifer-management planning in promoting the long-term sustainability of the Snake River.
The company hopes implementation of the ESPA CAMP will restore aquifer levels and tributary spring
flows to the Snake River.It is assumed in the 2011 IRP that CAMP measures specified under Phase I of
the plan are implemented.Phase I recommendations,to be implemented over a 5—10-year period,consist
of a combination of ground-water to surface-water conversions,managed aquifer recharge,demand
reduction programs,and weather-modification programs designed to produce an increase in average
annual aquifer discharge between 200,000 and 300,000 acre feet.Additional funding mechanisms are
being explored to implement measures outlined in the ESPA CAMP.
Further discussion of the ESPA CAMP is included in Appendix C—Technical Appendix.The Phase I
measures with associated target water volumes are shown in Table 2.1.
Table 2.1 Phase I measures
Measure Target (acre-feet)
Ground water to surface water conversions 100,000
Managed aquifer recharge 100,000
Demand reduction 0
Surface-water conservation 50,000
Crop mix modification 5,000
Rotating fallowing,dry-year lease,conservation reserve enhancement program (CREP)40,000
Weather modifications 50,000
Wind Integration Study
Total installed wind-generation capacity continues to expand in Idaho and the Pacific Northwest.
A recent surge in wind development in southern Idaho by independent power producers has heightened
concerns over Idaho Power’s ability to integrate additional wind resources beyond the 395 MW
currently online.The cost of integrating additional intermittent wind resources and the potential impact
on system reliability is of primary concern.As a result of these concerns,Idaho Power is updating its
study in association with the 2011 IRP.
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Idaho Power Company 2.Political,Regulatory,and Operational Issues
The objective of the updated study is to assess the costs incurred in modifying operations of dispatchablegeneratingresourcesinordertoallowthemtorespondtothevariableandintermittentnatureofwindresourcessuchthatthereliabledeliveryofelectricalpowertocustomersisunaffected.Idaho PowerconsiderstheassessmentofthesecostsanimportantpartofeffortstoensurethepricepaidtoacquirewindenergyisfairtoindependentdevelopersandIdahoPowercustomers.Although the purpose of thestudyistoestimatethecostofintegratingwind,the actual impact of integrating large amounts of windgenerationonaday-to-day basis will create ongoing operational and reliability issues for Idaho Power’ssystemdispatchers.
Idaho Power has been concerned about wind integration issues since late 2010 when 771 MW ofrequestsforPPAsbywinddevelopersweremadeunderPURPA.Initial efforts were focused ondeterminingthevalueoftheenergyfromthesePURPAcontracts,and in early 2011,Idaho PowerenteredintoacontractwithPLEXOSSolutions,LLC,for technical support in determining the cost ofintegratingwindandtheimpactonsystemreliability.
The study is designed to investigate the impact and cost of integrating wind on Idaho Power’s system bymodelingarangeofwindbuild-out cases (600 MW,800 MW,1,200 MW,and 1,600 MW)and comparing the system operation and cost of these cases against a base case.The concept behind thisapproachisthatasetofdispatchablegeneratingresourcesisoperateddifferentlyinthewindbuild-outcasestoprovidebalancingreservesnecessaryforrespondingtotheintermittencyandvariabilityassociatedwithwindgeneration.These reserves,necessary to maintain system reliability,are providedatacost.
An important consideration for the study,as well as wind integration in practice,is the designation ofthesetofresourcesresponsibleforintegratingwind.For the updated study,Idaho Power’s existingresourcescapableofprovidingbalancingreservesincludesthehydroelectricunitsoftheHellsCanyonComplex,the coal-fired units at the Jim Bridger and North Valmy power plants,the company’s fleet ofSCCTslocatedinMountainHome,Idaho,and the Langley Gulch CCCT expected to be commerciallyavailableinJuly2012.In addition,the study will evaluate the benefits of the proposed Boardman toHemingwaytransmissionlineproject(planned for 2016)on the cost of integrating wind generation.
In March 2011,Idaho Power held a public workshop for interested stakeholders where the proposedstudymethodologywasexplainedandinputonthedesignofthestudywassolicited.The companyanticipatesholdingasecondpublicworkshopinconjunctionwiththecompletionofthestudyinJuly2011,and a final study report is expected to be released shortly thereafter.
Fixed Cost Adjustment
Under the fixed cost adjustment (FCA),rates are annually adjusted up or down to recover or refund thedifferencebetweenthefixedcostsauthorizedbytheIPUCandthefixedcoststhatIdahoPoweractuallyreceivedthepreviousyearthroughenergysales.This mechanism removes the financial disincentive thatexistswhenIdahoPowerinvestsinDSMresources.The FCA Pilot is currently limited to the residentialandsmallcommercialclassesinrecognitionofthefactthat,for these customers,a high percentage offixedcostsarerecoveredthroughenergycharges.
On October 1,2009,the company filed an application with the IPUC to convert the FCA to an ongoingandpermanentrateschedule.On April 29,2010,the IPUC issued Order No.31063 extending theoriginal3-year FCA Pilot for an additional two years,effective January 1,2010.
During the 4-year period that the FCA (Schedule 54)has been in effect,Idaho Power has made progressinpromotingenergyefficiencyandDSMactivities.During the term of the FCA Pilot,the company hasincreasedthenumberofDSMprogramsitoffersandsubstantiallyincreasedbothitsinvestmentinDSMactivitiesandtheMWhsavingsobtainedviaDSM.Results from the first four years of the pilot indicate
2011 IRP Page 17
2.Political,Regulatory,and Operational Issues Idaho Power Company
the true-up mechanism is working as intended and operating to mitigate the unintended adverse effects
of DSM by ensuring that the fixed costs the IPUC authorized the company to recover are being
recovered via the FCA mechanism.
As part of a general rate case filed with the 1PUC on June 1,2011,the company has again requested to
convert the FCA to an ongoing and permanent rate schedule.The company believes the FCA has proved
to be an effective rate mechanism for removing the financial disincentives that exist when Idaho Power
invests in DSM resources and ifmade permanent will continue to serve in the best interests of
its customers.
Renewable Energy Certificates
To promote the construction of renewable resources,a system was created that separates
renewable generation into two parts,1)the electrical energy produced by a renewable resource,
and 2)the renewable attributes ofthat generation.These renewable attributes are referred to as RECs
or green tags.The entity that holds a REC has the right to make claims about the environmental benefits
associated with the renewable energy from the project.One REC is issued for each MWh of electricity
generated by a qualified resource.Electricity that is split from the REC is no longer considered
renewable and cannot be marketed as renewable by the entity that purchases the electricity.
A REC must be retired once it has been used for either regulatory compliance or to substantiate a claim
regarding renewable energy.Once a REC is retired,it cannot be sold or transferred to another party.
The same REC may not be claimed by more than one entity,including any environmental claims made
pursuant to electricity coming from renewable energy resources,environmental labeling,or disclosure
requirements.State renewable portfolio standards (RPS)also typically specify a “shelf life”for RECs so
they cannot be banked indefinitely.
Renewable Portfolio Standards
Under the state of Oregon’s RPS,Idaho Power is classified as a “smaller utility”because the company’s
Oregon customers represent less than 3 percent of Oregon’s total retail electric sales.As a smaller
utility,Idaho Power will have to meet a 10 percent RPS requirement beginning in 2025.
While the state ofIdaho does not have an RPS,Idaho Power believes a federal RES,
requiring Idaho Power to retire RECs for compliance,will be passed by Congress in the future.
Idaho Power believes it is prudent to continue acquiring RECs associated with renewable resources
to minimize the impact when a federal RES is implemented.
For the 2011 IRP,the portfolios being analyzed are designed to substantially comply with the
Renewable Electricity Promotion Act of2OlO (S.3813)introduced in Congress in September 2010,
by Senator Jeff Bingaman (D—New Mexico).Under the proposed bill,an initial renewable requirement
of 3 percent would begin in 2012 and would increase to 15 percent by 2021.
REC Management Plan
Idaho Power’s acquisition of RECs has created an issue regarding the disposition of the RECs until
either a state RPS or federal RES requirement exists.Two options exist:1)retire RECs,which would
allow Idaho Power to represent to customers that renewable energy is being delivered to them,or 2)sell
RECs and use the proceeds to reduce customer rates.
This issue was debated by the IRPAC during the preparation of both the 2009 IRP and the 2011 IRP.
In general,environmental representatives felt future RECs should be retired while customer
representatives felt they should be sold so that the value could be returned to customers.
Page 18 2011 IRP
Idaho Power Company 2.Political,Regulatory,and Operational Issues
In December 2009,Idaho Power filed with the IPUC a REC Management Plan that detailed thecompany’s plans to continue to acquire long-term rights to RECs in anticipation of a federal RES,but tosellRECsintheneartermandreturntocustomerstheirshareoftheproceedsthroughthepowercostadjustment(PCA)mechanism.Public comments regarding the plan mirrored the positions expressed byIRPACmembers,many of whom filed comments with the IPUC.In June 2010,the IPUC acceptedIdahoPower’s REC Management Plan.
Federal Energy Legislation
Idaho Power is subject to a broad range of federal,state,regional,and local laws and regulationsdesignedtoprotect,restore,and enhance the quality of the environment,including air,water,and solidwaste.Current and pending legislation relates to,among other items,climate change,GHG emissionsandairquality,RES,Hg and other emissions,hazardous wastes,and polychlorinated biphenyls (PCB).Environmental laws and regulations may,among other things,increase the cost of operating powergenerationplantsandconstructingnewfacilities,require that Idaho Power install additional pollutioncontroldevicesatexistinggeneratingplants,or require that Idaho Power discontinue operating certainpowergenerationplants.
Federal Climate Change Legislation
For the past several years,Congress has consideredcomprehensivefederalenergylegislationrequiringreductionsinGHGemissions.Proposed GHGregulationstargetthereductionofcarbonandotherGHGemissionsnationwide.The most recent andprominentbillsthathavebeenproposedare1)the American Clean Energy and Security Act of2009(Waxman—Markey),sponsored byRepresentativesHenryA.Waxman and Edward J.Markey;2)the Clean Energy Jobs andAmericanPowerActof2009(Boxer—Kerry),sponsored bySenatorsBarbaraBoxerandJohnKerryintheSenate;and 3)the American Power Act of2OlO (Kerry—Lieberman),sponsored by Senators John KerryandJoeLieberman.
In June 2009,the US House of Representatives narrowly passed the Waxman—Markey bill.The draft billincludedaGHGemissionsreductiongoalof3percentbelow2005levelsby2012,17 percent by 2020,42 percent by 2030,and more than 80 percent by 2050.The Waxman—Markey bill proposed toaccomplishthereductionsunderacap-and-trade system that would establish a limit or cap on the totalamountofGHGemissions.Although the Waxman—Markey bill passed in the House of Representatives,it did not pass in the Senate.
Under a cap-and-trade system,utilities would be allocated emissions allowances that would bedecreasedovertimetoachieveatotalemissionsreductiongoal.A certain amount of allowances wouldalsobeauctionedaspartofestablishingamarketwhereallowancescouldbeboughtandsold.In effect,a buyer would be paying a charge for polluting,while a seller would be rewarded for having reducedemissionsbymorethanwasrequired.The theory is those who can reduce emissions most economicallywilldoso,achieving the pollution reduction at the lowest possible cost to society.
In September 2009,the Boxer—Kerry bill was introduced in the Senate.The draft bill included a GHGemissionsreductiongoalof20percentbelow2005levelsby2020.The Boxer—Kerry bill did not includeafederalRESprovision.
Future federal climate-change legislation could affectregulatedutilities,such as Idaho Power.
2011 IRP
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2.Political,Regulatory,and Operational Issues Idaho Power Company
In May 2010,the Kerry—Lieberman bill was introduced in the Senate.The proposed legislation included
a cap-and-trade system for reducing GHG emissions by 17 percent in 2020 and by over 80 percent in
2050.None of the proposed federal climate change legislation has been able to gain enough support to
be passed by both the House of Representatives and the Senate.
In the summer of 2011,the Environmental Protection Agency (EPA)plans to begin regulating GHG
emissions.However,some members ofCongress are currently working to remove EPA’s authority to
regulate GHGs through legislative action and budget cuts.
Environmental Protection Agency
Idaho Power co-owns three coal-fired power plants and owns two natural gas-fired combustion turbine
power plants that are subject to air-quality regulation.The coal-fired plants are Jim Bridger
(one-third interest)located in Wyoming;Boardman (10 percent interest)located in Oregon;and Valmy
(50 percent interest)located in Nevada.The natural gas-fired plants,Danskin and Bennett Mountain,are
located in Idaho.In addition,Idaho Power is currently in the process of constructing the Langley Gulch
power plant,a natural gas-fired CCCT generating plant with a nameplate capacity of approximately
300 MW.
The Clean Air Act (CAA)establishes controls on the emissions from stationary sources like those owned
by Idaho Power.The EPA adopts many of the standards and regulations under the CAA,while states
have the primary responsibility for implementation and administration of these air-quality
programs.Idaho Power continues to actively monitor,evaluate,and work on air-quality issues
pertaining to federal and state Hg emissions rules,possible legislative amendment of the CAA,
Regional Haze—Best Available Retrofit Technology (RH BART),National Ambient Air Quality
Standards (NAAQS),and New Source Review (NSR)permitting.
Regional Haze—Best Retrofit Technology
In accordance with federal regional haze rules,coal-fired utility boilers are subject to RH BART if they
were built between 1962 and 1977 and affect any Class I areas.This includes all four units at the
Jim Bridger plant and the Boardman plant.The two units at the Valmy plant were constructed after 1977
and are not subject to the federal regional haze rule.The Wyoming Department of Environmental
Quality (WDEQ)and the Oregon Department of Environmental Quality (ODEQ)have conducted
assessments of the Jim Bridger and Boardman plants pursuant to the RH BART process.These states
have also evaluated the need for additional controls at Jim Bridger and Boardman to achieve reasonable
progress toward a long-term strategy beyond RH BART to reduce regional haze in Class I areas to
natural conditions by the year 2064.
On November 3,2010,PacifiCorp,the majority owner and operator of the Jim Bridger plant,and the
WDEQ signed a settlement agreement under which PacifiCorp agreed to install selective catalytic
reduction (SCR)technology,alternative add-on nitrogen oxide (NOr)controls,or otherwise achieve a
0.07 pounds-per-million British thermal units (MMBtu)30-day rolling average NO emissions rate
by December 31,2015,for Unit 3 and December 31,2016,for Unit 4.In addition,PacifiCorp has
agreed to install SCR technology,alternative add-on NO controls,or otherwise achieve a
0.07 pounds-per-MMBtu 30-day rolling average NO emissions rate by December 31,2021,for Unit 2
and December 31,2022,for Unit 1.The settlement agreement is conditioned on the EPA ultimately
approving those portions of the Wyoming Regional Haze State Implementation Plan that are consistent
with the terms of the settlement agreement.In light of the settlement agreement,WDEQ issued a revised
RH BART permit for Jim Bridger on November 24,2010.
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2011 IRP
Idaho Power Company 2.Political,Regulatory,and Operational Issues
In August 2010,Portland General Electric (PGE),the majority owner and operator of the Boardmanplant,submitted a new plan to the ODEQ that would cease coal-fired operations at the Boardman plantin2020,but contemplated additional emissions reductions relative to PGE’s previous 2020 closure plan.
Following an extensive public process,in December2010,the Oregon Environmental QualityCommissionapprovedPGE’s August and October 2010 plan to cease coal-fired operations at theBoardmanplantnolaterthanDecember31,2020.The new rules implementing the plan are expected tocontainthefollowingmeasures:
•Install new 1ow-NO burners and modified overfire air ports by July 2011 to comply with BARTstandardsforNO
•Conduct pilot studies for the dry sorbent-injection system to verify that set sulfur dioxide (SO2)limits for 2014 and 2018,are achievable
•Install a dry sorbent-injection system by July 2014,to comply with BART standards for SO2
•Repeal the ODEQ’s 2009 BART rule,which would have allowed continued operation of theBoardmanplantthroughatleast2040withinstallationofamoreexpensivesuiteofemissionscontrols
•Permanent cessation of coal-fired operation no later than December 31,2020
National Ambient Air Quality Standards
In July 1997,the EPA adopted new NAAQS for ozone (8-hour ozone standard)and fine particulatematteroflessthan2.5 micrometers in diameter (PM2.5 standard).In December 2006,the EPA revisedtheNAAQSforPM2.5.This new standard is the subject of a legal challenge by a number of groups.However,all counties in Idaho,Nevada,Oregon,and Wyoming—where Idaho Power’s power plantsoperatecurrently—were designated as meeting attainment with the revised PM2.5 NAAQS.
In January 2010,the EPA adopted a new NAAQS for NO2 at a level of 100 parts-per-billion averagedovera1-hour period.In addition,in June 2010,the EPA adopted a new NAAQS for SO2 at a level of75parts-per-billion averaged over a 1-hour period.The EPA has not yet designated areas as attaining ornotattainingthesenewstandards.Idaho Power is unable to predict what impact the adoption andimplementationofthesestandardsmayhaveonitsoperations.
Hazardous Air Pollutants—Maximum Achievable Control Standard
On March 16,2011,EPA issued proposed rules to reduce emissions of Hazardous Air Pollutants (HAP)from coal-and oil-fired electric utility steam-generating units.These rules target certain heavy metals,acid gases,organics,dioxins,and furans.EPA grouped these HAPs into the following categories;Hg,non-Hg HAP metals,acid gases,organics,and dioxins/furans.Of these groups,all but organics anddioxinlfuranhavenumericallimitsthatmustbemet.Two of the groups (non-Hg HAP metals and acidgases)allow for “surrogate”pollutants to be used to demonstrate compliance with the limits.To demonstrate compliance with organic HAPs and dioxin!furans,the EPA has proposedWorkPracticeStandards.
Continuous emissions-monitoring systems of Hg have been installed on all the coal-fired units at the JimBridger,Boardman,and Valmy plants,and tests to confirm the accuracy of the data being collected areunderway.In 2008,the state of Oregon adopted an Hg rule requiring the Boardman plant to reduceHgemissionsby90percentormeetanemissionsrateof0.6 pounds-per-trillion Btus by July 2012.Idaho Power continues to monitor Wyoming and Nevada actions related to Hg emissions.Idaho PowerisunabletopredictatthistimewhatactionstheEPAortheotherstatesmaytaketoreduceHgemissionsfromtheircoal-fired power plants.In April 2010,the US District Court for the District of
2011 IRP Page 21
2.Political,Regulatory,and Operational Issues Idaho Power Company
Columbia approved,by consent decree,a timetable that would require the EPA to propose a standard to
control Hg emissions from coal-fired power plants by May 2011 and to finalize it by November 2011.
Clean Air Transport Rule
In July 2009,the EPA proposed its Clean Air Transport Rule (Transport Rule),which would require
new reductions in SO2 and NO emissions from large stationary sources,including power plants,located
in 31 states and the District of Columbia beginning in 2012.The Transport Rule is intended to help
states attain NAAQS set in 1997 for ozone and fine particulate-matter emissions.This rule replaces the
Bush administration’s Clean Air Interstate Rule (CAIR),which was vacated in July 2008 and rescinded
by a federal court because it failed to effectively address pollution from upwind states that is hampering
efforts by downwind states to comply with ozone and PM NAAQS.
Idaho Power does not own generating units in states identified by the Transport Rule and thus will not
be directly impacted;however,the company intends to monitor amendments to the Transport Rule
closely,particularly since there is some indication that the 2014 revisions to the Transport Rule will
extend the geographic scope of impacted states.
Coal Combustion Residuals
Coal Combustion Residuals (CCR5),including coal ash,are the byproducts from the combustion of coal
in power plants.CCRs are currently considered exempt wastes under an amendment to the Resource
Conservation andRecovery Act of]976 (RCRA);however,in 2010,the EPA proposed to regulate
CCRs for the first time.The EPA is considering two possible options for the management of CCRs.
Both options fall under the RCRA.
Under the first option,the EPA would list these residual materials as special wastes subject to regulation
under Subtitle C of RCRA with requirements from the point of generation to disposition,including the
closure of disposal units.Under the second option,the EPA would regulate CCRs as nonhazardous
waste under Subtitle D of RCRA and establish minimum nationwide standards for the disposal of CCRs.
A final ruling is expected in 2012.
Page 22 2011 IRP
Idaho Power Company
3.Idaho Power Today
3.IDAHO POWER TODAY
Customer Load and Growth
In 1990,Idaho Power served approximately
292,000 general business customers.Today,Idaho Power serves more than 492,000 generalbusinesscustomersinIdahoandOregon.Firmpeak-hour load has increased from 2,052 MW in1990toover3,000 MW in 2006—2009.In June 2008,the peak-hour load reached 3,214 MW,which is thesystempeak-hour record.Idaho Power’s successfuldemandreductionprograms,along with weatherconditionsandthegeneraldeclineineconomicactivity,lowered Idaho Power’s peak demand in both2009and2010.
Average firm load (excluding Astaris/FMC)increased from nearly 1,200 aMW in 1990 to over1,800 aMW in 2008.Additional details of Idaho Power’s historical load and customer data are shown inFigure3.1 and Table 3.1.
Since 1990,Idaho Power’s total nameplate generation has increased from 2,635 MW to 3,276 MW.The 641-MW increase in capacity represents enough generation to serve approximately100,000 customers at peak times.Table 3.1 shows Idaho Power’s changes in reported nameplatecapacitysince1990.
Idaho Power’s newest resource addition is the 300-MW Langley Gulch CCCT.The highly efficient,natural gas-fired power plant is being constructed in the western Treasure Valley in Payette County,Idaho.Construction began in August 2010,and the plant is expected to be operational in July 2012.The data in Table 3.1 suggests each new customer adds approximately 6.5 kW to the peak-hour load andabout1.5 average kilowatts (akW)to average load.In actuality,residential,commercial,and irrigationcustomersgenerallycontributemoretothepeak-hour load,whereas industrial customers contributemoretoaverageload.Industrial customers generally have a more consistent load shape,whereasresidential,commercial,and irrigation customers have a load shape with greater daily and seasonalvariation.
Since 1990,Idaho Power has added about 200,000 new customers.The simple peak-hour andaverage-energy calculations mentioned earlier suggest the additional 200,000 customers require over1,100 MW of additional peak-hour capacity and about 600 aMW of energy.
Highlights
Idaho Power had over 492,000 retail customers at the end of 2010.
The 300-MW Langley Gulch natural gas-fired CCCT is expected to begin operating inJuly2012.
Since 2003,Idaho Power has been operating a cloud-seeding program that increasessnowaccumulationandprovidesincreasedgenerationatthecompany’shydroelectricfacilities.
An Idaho Power employee installs a new Smart Meter.
2011 IRP
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3.Idaho Power Today
Idaho Power Company
5,500
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
550,000
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
Idaho Power anticipates adding approximately 8,000 customers each year throughout the planning
period.The expected-case load forecast predicts that summer peak-hour load requirements are expected
to grow at about 69 MW per year,and the average energy requirement is forecast to grow at 29 aMW
——
—---‘-----
1990 1992 1994
—.---—I————I ——I -I I I I I
1996 1998 2000 2002 2004 2006 2008 2010
—Total Nameplate Generation (MW)Peak Firm Load (MW)—Average Firm Load (aMW)Customers
Figure 3.1 Historical capacity,load,and customer data
Table 3.1 Historical capacity,load,and customer data
--------
-Total Nameplate Peak Firm Average Firm
Year Generation (MW)Load (MW)Load (aMW)Customers
1990 2,635 2,052 1,205 290,492
1991 2,635 1,972 1,206 296,584
1992 2,694 2,164 1,281 306,292
1993 2,644 1,935 1,274 316564
1994 2,661 2,245 1,375 329,094
1995
2,703 2,224 1,324 339,450
1996 2,703 2,437 1,438 351,261
1997 2,728 2,352 1,457 361,838
1998 2,738 2,535 1,491 372,464
1999 2,738 2,675 1,552 383,354
2000 2,738 2,765 1,653 393,095
2001 2,851 2,500 1,576 403,061
2002 2,912 2,963 1,622 414,062
2003 2,912 2,944 1,657 425,599
2004 2,912 2,843 1,671 438,912
2005 3,085 2,961 1,660 456,104
2006 3,085 3,084 1,745 470,950
2007 3,093 3,193 1,808 480,523
2008 3,276 3,214 1,815 486,048
2009 3,276 3,031 1,744 489,927
2010 3,276 2,930 1,680 492,073
Page 24
2011 IRP
Idaho Power Company 3.Idaho Power Today
per year.More detailed customer and load forecast information is presented in Chapter 6 and inAppendixA—Sales and Load Forecast.
The simple peak-hour load growth calculation indicates Idaho Power would need to add peakingcapacityequivalenttothe173-MW Bennett Mountain plant every 3 years throughout the entire planningperiod.The peak calculation does not include the expected effects of demand response programs,and Idaho Power intends to continue working with customers and applying demand response programsduringtimesofpeakenergyconsumption.The near-term and long-term action plans to meet therequirementsofIdahoPower’s load growth are discussed in Chapter 10.
The generation costs per kW included in Chapter 6 help put forecast customer growth in perspective.Load research data indicates the average residential customer requires about 1.5 kW of baseloadgenerationand5.0—5.5 kW ofpeak-hour generation.Baseload generation capital costs are about$1,200 per kW for a natural gas-fired CCCT,such as Idaho Power’s Langley Gulch plant,and peak-hourgenerationcapitalcostsareabout$750 per kW for a natural gas-fired SCCT,such as the Danskin andBennettMountainprojects.The capital costs do not include fuel or any other operation andmaintenanceexpenses.
Based on the capital cost estimates,each new residential customer requires about $1,800 of capitalinvestmentfor1.5 kW of baseload generation,plus an additional $4,000 for 5.0—5.5 kW of peak-hourcapacity,leading to a total generation capital cost of $5,800.Other capital expenditures for transmission,distribution,customer systems,and other administrative costs are not included in the $5,800 capitalgenerationrequirement.A residential customer growth rate of 8,000 new customers per year translatesintonearly$50 million of new generation plant capital each year to serve the baseload and peak energyrequirementsofthenewresidentialcustomers.
2010 Energy Sources
Idaho Power relies primarily on company-owned hydroelectric and coal-fired generation facilities andlong-term PPAs to supply the energy needed to serve customers.Idaho Power’s annual hydroelectricgenerationvariesdependingonwaterconditionsintheSnakeRiver.Market purchases and sales areusedtobalancesupplyanddemandthroughouttheyear.The next sections provide specific details onIdahoPower’s sources of energy in 2010 followed by a description of Idaho Power’s existing andcommittedresources.
In 2010,86 percent of Idaho Power’s supply of electricity came from company-owned generationresources.In above-average water years,Idaho Power’s low-cost hydroelectric plants are typically thecompany’s largest source of electricity.Figure 3.2 shows Idaho Power’s electricity sources for 2010,including generation from company-owned resources and purchased power.Market purchases areelectricpowerpurchasesfromotherutilitiesinthewholesaleelectricmarket.
Long-term power purchases are electric power contracts with independent power producers and firmPPAswithotherutilitiesandcantypicallybeidentifiedbyresourcetype.In 2010,Idaho Powerpurchased1,399,661 MWh of electricity through long-term PPAs that are shown by resource type inFigure3.3.Long-term power purchases that cannot be identified by resource type are shown as “other”in the chart.
2011 IRP
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3.Idaho Power Today Idaho Power Company
Biomass Geothermal
5%5%
Natural gas [1Landfill gases
6%2%
Other
-
L
Figure 3.2 2010 energy sources Figure 3.3 2010 long-term power purchases by
resource type
Electricity delivered to retail customers includes electricity generated by Idaho Power-owned resources
and energy purchased from others.Electricity produced by resources typically considered to be
renewable,such as wind,biomass,geothermal,etc.,is not counted as renewable energy delivered to
retail customers in a given year,unless Idaho Power retires an equivalent number of RECs in that year.
In December 2009,Idaho Power filed with the IPUC a REC Management Plan that detailed
Idaho Power’s plans to continue to acquire long-term rights to RECs in anticipation of a federal
RES,but to sell RECs in the near-term and return the customers’share of the proceeds through the
PCA mechanism.
Table 3.2 shows Idaho Powers’energy sources and the subsequent electricity delivered to retail
customers in 2010.Because Idaho Power sells electricity to other utilities and to retail customers,not all
electricity purchased or generated by Idaho Power is delivered to its retail customers.Table 3.2 shows
that no wind or geothermal generation was delivered to retail customers in 2010,the RECs associated
with this generation were sold to others who have purchased the right to claim the renewable attributes
of that generation.However,if Idaho Power had retired the RECs associated with this generation,
the company would have been able to claim the renewable energy had been delivered to customers.
Idaho Power also has several small hydroelectric projects that qualify under the state ofNevada’s RPS,
and RECs from these projects were sold to NV Energy in 2010.Idaho Power’s Green Power Program
retired 23,056 RECs in 2010,this energy can be reported as renewable energy delivered to customers.
Table 3.2 Electricity delivered to customers (2010)
RECs Purchased Delivered to
Resource by Type (MWh)Generation RECs Sold1 and Retired2 Customers
Hydroelectric 7,344,433 -188,336 7,156,097
Coal 6,863,870 6,863,870
Natural Gas &Diesel 159,586 159,586
Purchased Power 1,992,584 573,438 -23,056 2,542,966
Wind 313,256 -313,256 0
Geothermal 71,846 -71,846 0
Renewable (Green Power Program)0 23,056 23,056
Total 16,745,575 0 0 16,745,575
‘When RECs are sold,Idaho Power can no longer claim the environmental attributes associated with the renewable resource.Therefore,
the energy from REC sales is reclassified as Purchased Power.
2 Idaho Power’s Green Power Program retired 23,056 RECs in 2010:this energy is reported as renewable energy delivered to customers
enrolled in the Green Power Program.
Market purchased
power
6%
Long-term power
purchasesj8%
Hydroelectric
resources
/44%
Coal resources
41%
Wind
“—37%
Natural gas and
diesel
1%
Industrial waste
6%Hydroelectric
32%
Page 26
2011 IRP
Idaho Power Company 3.Idaho Power Today
Existing Supply-Side Resources
To identify the need and timing of future resources,Idaho Power prepares a load and resource balancethataccountsforforecastloadgrowthandgenerationfromallofthecompany’s existing resources andplannedpurchases.The load and resource balance worksheets showing Idaho Power’s existing andcommittedresourcesforaverageenergyandpeak-hour load are presented in Appendix C—Technical Appendix.Table 3.3 shows all of Idaho Power’s existing resources,nameplate capacities,and general locations.
Table 3.3 Existing Resources
Generator
NameplateResourceTypeCapacity(MW)Location
American Falls Hydro 92.3 Upper SnakeBlissHydro75.0 Mid-Snake
Brownlee Hydro 585.4 Hells CanyonC.J.Strike Hydro 82.8 Mid-Snake
Cascade Hydro 12.4 North Fork Payette
Clear Lake Hydro 2.5 South Central IdahoHellsCanyonHydro391.5 Hells CanyonLowerMaladHydro13.5 South Central Idaho
Lower Salmon Hydro 60.0 Mid-Snake
Mimer Hydro 59.4 Upper Snake
Oxbow Hydro 190.0 Hells Canyon
Shoshone Falls Hydro 12.5 Upper Snake
Swan Falls Hydro 27.2 Mid-Snake
Thousand Springs Hydro 8.8 South Central IdahoTwinFallsHydro52.9 Mid-Snake
Upper Malad Hydro 8.3 South Central IdahoUpperSalmonAHydro18.0 Mid-Snake
Upper Salmon B Hydro 17.0 Mid-Snake
Boardman Coal 64.2 North Central OregonJimBridgerCoal770.5 Southwest Wyoming
Valmy Coal 283.5 North Central Nevada
Bennett Mountain Natural Gas 172.8 Southwest Idaho
Danskin Natural Gas 270.9 Southwest IdahoSalmonDieselDiesel5.0 Eastern IdahoTotalExistingNameplateCapacity3,276.4
The following sections describe Idaho Power’s existing supply-side generation resources andlong-term PPAs.
Hydroelectric Facilities
Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries.Together,these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and annual generationequaltoapproximately970aMW,or 8.5 million MWh under median water conditions.
Hells Canyon Complex
The backbone of Idaho Power’s hydroelectric system is the Hells Canyon Complex in the Hells CanyonreachoftheSnakeRiver.The Hells Canyon Complex consists of Brownlee,Oxbow,and Hells Canyon
2011 IRP Page 27
3.Idaho Power Today Idaho Power Company
dams and the associated generation facilities.In a normal water year,the three plants provide
approximately 68 percent of Idaho Power’s annual hydroelectric generation and approximately
35 percent of the total energy generated.Water storage in Brownlee Reservoir also enables the
Hells Canyon Complex projects to provide the major portion ofIdaho Power’s peaking and
load-following capability.
Idaho Power operates the Hells Canyon Complex to comply with the existing FERC license as well as
voluntary arrangements to accommodate other interests,such as recreational use and environmental
resources.Among the arrangements are the fall Chinook plan,voluntarily adopted by Idaho Power in
1991 to protect spawning and incubation of fall Chinook below Hells Canyon Dam.The fall Chinook
species is listed as threatened under the ESA.
Brownlee Reservoir is the only Hells Canyon Complex reservoir—and Idaho Power’s only reservoir—
with significant active storage.Brownlee Reservoir has 101 vertical feet of active storage capacity,
which equals approximately one million acre-feet of water.Both Oxbow and Hells Canyon reservoirs
have significantly smaller active storage capacities—approximately 0.5 percent and 1.0 percent of
Brownlee Reservoir’s volume,respectively.
Brownlee Reservoir is a year-round,multiple-use resource for Idaho Power and the Pacific Northwest.
Although the primary purpose is to provide a stable power source,Brownlee Reservoir is also used for
flood control,recreation,and for the benefit of fish and wildlife resources.
Brownlee Dam is one of several Pacific Northwest dams that are coordinated to provide springtime
flood control on the lower Columbia River.Idaho Power operates the reservoir in accordance with flood
control directions received from the US Army Corps of Engineers (ACOE)as outlined in Article 42 of
the existing FERC license.
After flood-control requirements have been met in late spring,Idaho Power attempts to refill the
reservoir to meet peak summer electricity demands and provide suitable habitat for spawning bass
and crappie.The full reservoir also offers optimal recreational opportunities through the
Fourth of July holiday.
The US Bureau ofReclamation (BOR)periodically releases water from BOR storage reservoirs in the
upper Snake River in an effort to augment flows in the lower Snake River to help anadromous fish
migrate past the Federal Columbia River Power System (FCRPS)projects.The periodic releases are part
of the flow augmentation implemented by the 2000 FCRPS biological opinion.The flow augmentation
water travels through Idaho Power’s Mid-Snake projects and eventually through the Hells Canyon
Complex before reaching the FCRPS projects.
Brownlee Reservoir’s releases are managed to maintain constant flows below Hells Canyon Dam in the
fall as a result of the fall Chinook plan adopted by Idaho Power in 1991.The constant flow is set at a
level to protect fall Chinook spawning nests,or redds.During the fall Chinook plan operations,
Idaho Power attempts to refill Brownlee Reservoir by the first week of December to meet wintertime
peak-hour loads.The fall Chinook plan spawning flows establish the minimum flow below
Hells Canyon Dam throughout the winter until the fall Chinook fry emerge in the spring.
Maintaining constant flows to protect the fall Chinook spawning contributes to the need for additional
generation resources during the fall months.The fall Chinook operations result in lower reservoir
elevations in Brownlee Reservoir,which reduce the power production capability of the project.
The reduced power production may necessitate Idaho Power’s acquisition of power from other sources
to meet customer load.
Page 28 2011 IRP
Idaho Power Company 3.Idaho Power Today
Mid-Snake Projects
Idaho Power’s hydroelectric facilities upstream from the Hells Canyon Complex include theAmericanFalls,Mimer,Twin Falls,Shoshone Falls,Clear Lake,Thousand Springs,Upper and LowerMalad,Upper and Lower Salmon,Bliss,C.J.Strike,Swan Falls,and Cascade projects.Although theMid-Snake projects of Upper and Lower Salmon,Bliss,and C.J.Strike typically follow run-of-riveroperations,the Lower Salmon,Bliss,and C.J.Strike plants provide a limited amount of peaking andload-following capability.When possible,the projects are operated within FERC license requirements tocoincidewiththedailysystempeakdemand.All of the other upstream plants are operated asrun-of-river projects.
Idaho Power has completed a study to identify the effects of load-following operations at theLowerSalmonandBlisspowerplantsontheBlissRapidssnail,a species listed as threatened undertheESA.
The study was part of a 2004 settlement agreement with the US Fish and Wildlife Service (FWS)tolicensetheUpperSalmon,Lower Salmon,Bliss,and C.J.Strilce hydroelectric projects.During thestudy,Idaho Power operated the Bliss and Lower Salmon facilities under both run-of-river andload-following operations.Study results indicated that while load following operations had the potentialtoharmindividualsnails,the operations were not a threat to the viability or long-term persistence ofthespecies.
A Bliss Rapids Snail Protection Plan developed in consultation with FWS was completed inMarch2010.The plan identifies appropriate protection measures to be implemented by Idaho Power,including monitoring snail populations in the Snake River and associated springs.By implementing theprotectionandmonitoringmeasures,the company will be able to operate the Lower Salmon and Blissprojectsinload-following mode while protecting the stability and viability ofthe Bliss Rapids snail.Idaho Power has filed license amendment applications with FERC for both projects that would allowload-following operations to resume.
Water Lease Agreements
Idaho Power views the lease of water for delivery through its hydroelectric system as a potentiallycost-effective power-supply alternative.This approach is particularly attractive for water-leaseagreementsthatallowthecompanytorequestdeliveryasneeded.Acquiring water through leases alsohelpsthecompanytoimprovewaterqualityandtemperatureconditionsintheSnakeRiveraspartofongoingrelicensingeffortsassociatedwiththeHellsCanyonComplex.
The company signed rental agreements in 2009 and 2010 with Water District 63 in the Boise Riversystemtolease13,500 and 15,400 acre feet of storage water released in December 2009 andJanuary2011,respectively.
In 2011,Idaho Power signed a lease agreement with Water District 1 (WD 1)in the upper Snake Riversystemfor25,000 acre feet of storage water for release during summer 2011.The company isparticipatingindevelopmentdiscussionswiththeWD1RentalPoolCommitteeandtheupper Snakeadvisorycommittee,the Committee ofNine,regarding a supplemental rental pooi for use by thecompanyforreleasesbelowMimerDam.
Tn August 2009,Idaho Power also entered into a five-year (2009—20 13)water-lease agreement with theShoshone—Bannock Tribal Water Supply Bank for 45,716 acre feet of American Falls storage water.Under the terms of this agreement,the company can schedule the release of the water to maximize thevalueofthegenerationfromtheentiresystemofmainstemSnakeRiverhydroelectricprojects.
Tn 2011,the company is pursuing an extension of the Shoshone—Bamiock lease for two additional years,2014 and 2015.The company plans to schedule delivery ofthe water between July and October of each
2011 IRP Page 29
3.Idaho Power Today Idaho Power Company
year during the term of the lease.The Shoshone—Bannock agreement was executed in part to offset the
impact of drought and changing water-use patterns in southern Idaho and to provide additional
generation in summer months when customer demand is high.Idaho Power intends to continue to pursue
water-lease opportunities as part of its regular operations.
Cloud Seeding
In 2003,Idaho Power implemented a cloud-seeding program to increase snow accumulation in the south
fork of the Payette River watershed.Tn 2008,Idaho Power expanded its program by enhancing an
existing program operated by a coalition of counties and other stakeholders in the upper Snake River
system above Mimer Dam.
Idaho Power seeds clouds by introducing silver iodide into winter storms.This process increases
precipitation from passing winter storm systems.If a storm has a combination of an abundance of
super-cooled liquid water vapor and appropriate temperatures,the conditions are optimal for cloud
seeding to increase precipitation.
Idaho Power uses two methods to seed clouds:1)install ground generators at high elevations,
or 2)attach special flares to modified airplanes.Either method successfully releases silver iodide into
passing storms.Minute water particles within the clouds freeze on contact with the silver iodide particles
and eventually grow and fall to the ground as snow.
Silver iodide has been used as a seeding agent in
numerous western states for decades without any
known harmful effects.Analyses conducted by
Idaho Power since 2003,indicate the annual
snowpack in the Payette River basin increased
between 5 and 15 percent (depending on the year).
Idaho Power estimates cloud seeding will provide an
additional 120,000 to 180,000 acre-feet ofwater for
the Hells Canyon Complex.Studies conducted by the
Desert Research Institute from 2003 to 2005 support
the effectiveness of Idaho Power’s program.
For the 2010—2011 winter season,the program ..
included 10,remote-controlled,ground-based Cloud seeding station in the Payette basin.
generators and one airplane for operations in the
Payette Basin.The program in the Upper Snake River Basin included 15,remote-controlled,
ground-based generators operated by Idaho Power and 25,manual,ground-based generators operated
by the coalition.Idaho Power provides meteorological data and weather forecasting to guide the
coalition’s operations.
Thermal Facilities
Jim Bridger
Idaho Power owns one-third,or 706 MW (net dependable capacity),of the Jim Bridger coal-fired power
plant located near Rock Springs,Wyoming.The plant consists of four generating units.After adjustment
for routine scheduled maintenance periods and estimated forced outages,the annual energy generating
capability of Idaho Power’s share of the plant is approximately 625 aMW.PacifiCorp has two-thirds
ownership and is the operator of the Jim Bridger facility.
.1
p
Page 30 2011 IRP
Idaho Power Company 3.Idaho Power Today
North Valmy
Idaho Power owns 50 percent,or 260.5 MW (net dependable capacity)ofthe North Valmy coal-firedpowerplantlocatednearWinnemucca,Nevada.The plant consists of two generating units.After adjusting for routine scheduled maintenance periods and estimated forced outages,the annualenergygeneratingcapabilityofIdahoPower’s share of the North Valmy plant is approximately220aMW.NV Energy has 50 percent ownership and is the operator of the North Valmy facility.
Boardman
Idaho Power owns 10 percent,or 58.5 MW (net dependable capacity),of the Boardman coal-fired powerplantlocatednearBoardman,Oregon.The plant consists of a single generating unit.After adjusting forroutinescheduledmaintenanceperiodsandestimatedforcedoutages,the annual energy generatingcapabilityofIdahoPower’s share ofthe Boardman plant is approximately 50 aMW.PGE has 65 percentownership,Bank of America Leasing has 15 percent ownership,and Power Resources Cooperative(PRC)has 10 percent ownership.As the majority partner of the plant,PGE is the operator of theBoardmanfacility.
The 2011 IRP assumes Idaho Power’s share of Boardman plant will not be available after December 31,2020.The estimated date is the result of an agreement reached between the ODEQ and PGE,related tocompliancewithRHBARTrulesonparticulatematter,SO2,and NO emissions.Both ODEQ and PGEarewaitingforformalapprovalfromtheEPA.
At the end of 2010,the net-book value of Idaho Power’s share of the Boardman facility wasapproximately$19.3 million.In order to continue operating the plant until 2020,the addition of newemissionscontrolswilllikelyberequired.Idaho Power’s share of the additional capital cost for the newequipmentisestimatedtorangefrom$1 million to $37 million depending on the final ruling from theEPA.Until the EPA formally approves the agreement,it would be difficult to estimate the net bookvalueofIdahoPower’s share of the plant in 2020.
Peaking Facilities
Danskin
Idaho Power owns and operates the Danskin plant,a 271-MW natural gas-fired project.The plantconsistsofone,179-MW Siemens 501F SCCT and two,46-MW Siemens—Westinghouse W251B12Acombustionturbines.The 12-acre facility was initially constructed in 2001,and is located northwest ofMountainHome,Idaho.The two smaller turbines were installed in 2001,and the larger turbine wasinstalledin2008.The Danskin plant operates as needed to support system load.
Bennett Mountain
Idaho Power owns and operates the Bennett Mountain plant,which consists of a 173-MW Siemens—Westinghouse 501F natural gas-fired SCCT located near the Danskin plant in Mountain Home,Idaho.The Bennett Mountain plant also operates as needed to support system load.
Salmon Diesel
Idaho Power owns and operates two diesel generation units located in Salmon,Idaho.The Salmonunitshaveacombinedgeneratornameplateratingof5MWandareoperatedprimarilyduringemergencyconditions.
2011 IRP Page 31
3.Idaho Power Today Idaho Power Company
Solar Facilities
In 1994,a 25-kW solar PV array with 90 individual panels was installed on the rooftop of Idaho Power’s
corporate headquarters in Boise,Idaho.The company also maintains a remote,off-grid,80-kW solar PV
array for the US Air Force near Grasmere,Idaho.
Idaho Power uses small PV panels in its daily operations to supply power to equipment used for
monitoring water quality,measuring stream flows,and operating-cloud seeding equipment.In addition
to these solar PV installations,Idaho Power participates in the Solar 4R Schools Program;owns a
mobile solar trailer that can be used to supply power for concerts,radio remotes,and other events;
and has a 200-watt (W)solar water pump used for demonstrations and the promotion of solar
PV technology.
Net Metering Program
Idaho Power’s net metering program allows customers to install small-scale,renewable generation
projects on their property and connect to Idaho Power’s system.Under the program,net energy
generated beyond what the customer uses is sold back to Idaho Power.A majority of the program’s
participants are solar projects.Currently,there are 130 solar PV installations under this program with a
total capacity of 607 kW.
Oregon Solar Photovoltaic Pilot Program
In 2009,the Oregon Legislature passed ORS 757.365 as amended by House Bill 3690,which mandated
the development of pilot programs for electric utilities operating in Oregon to demonstrate the use and
effectiveness of volumetric incentive rates for electricity produced by solar PV systems.
As required by the OPUC in Order Nos.10-200 and 11-089,Idaho Power established the Oregon Solar
Photovoltaic Pilot Program in 2010,offering volumetric incentive rates to its customers in Oregon.
Under the pilot program,Idaho Power will acquire up to 400 kW of installed capacity from solar PV
systems with a nameplate capacity of less than or equal to 10 kW.In July 2010,approximately 200 kW
was allocated,and the remaining 200 kW will be offered during the next enrollment period in
October 2011.
In addition to the smaller facilities under the pilot program,Idaho Power is required to either own or
purchase the generation from a 500-kW,utility-scale solar PV facility by 2020.Under the rules,if the
utility-scale facility is operational by 2016,the RECs from the project would be doubled for purposes of
complying with the state of Oregon RPS.
Power Purchase Agreements
Elkhorn Valley Wind Project
In February 2007,the IPUC approved a PPA with Telocaset Wind Power Partners,LLC,a subsidiary of
Horizon Wind Energy,for 101 MW of nameplate wind generation from the Elkhom Valley Wind
Project located in northeastern Oregon.The Elkhorn wind project was constructed during 2007 and
began commercial operations in December 2007.Under the PPA,Idaho Power receives all the RECs
from the project.
Raft River Geothermal Project
In January 2008,the IPUC approved a PPA for 13 MW of nameplate generation from the Raft River
Geothermal Power Plant (Unit 1)located in southern Idaho.The Raft River project began commercial
operations in October 2007 under a PURPA contract with Idaho Power that was canceled when the new
PPA was approved by the IPUC.For the first 10 years (2008—20 17)of the agreement,Idaho Power is
entitled to 75 percent of the RECs from the project for generation that exceeds 10 aMW monthly.
Page 32 2011 IRP
Idaho Power Company 3.Idaho Power Today
For the second 10 years of the agreement (2018—2027),Idaho Power is entitled to 51 percent of the totalRECsgeneratedbytheproject.
Neal Hot Springs Geothermal Project
In May 2010,the IPUC approved a PPA for approximately 22 MW ofnameplate generation from theNealHotSpringsGeothermalProjectlocatedineasternOregon.The Neal Hot Springs project is underdevelopmentandisexpectedtobegincommercialoperationsin2012.Under the PPA,Idaho PowerreceivesalltheRECsfromtheproject.
Clatskanie Energy Exchange
In September 2009,Idaho Power and the Clatskanie People’s Utility District (Clatskanie PUD)in Oregon entered into an energy exchange agreement.Under the agreement,Idaho Power receives theenergyasitisgeneratedfromthenewlyconstructed18-MW power plant at Arrowrock Dam on theBoiseRiver;and in exchange,Idaho Power provides Clatskanie PUD energy of equivalent valuedeliveredseasonally—primarily during months when Idaho Power expects to have surplus energy.An energy bank account is maintained to ensure a balanced exchange between the parties where theenergyvaluewillbedeterminedusingtheMid-Columbia market price index.The Arrowrock projectbegangeneratinginJanuary2010,and the agreement term extends through 2015.Idaho Power alsoretainstherighttorenewtheagreementthrough2025.The Arrowrock project is expected to produceapproximately81,000 MWh annually.
Public Utility Regulatory Policies Act
In 1978,Congress passed PURPA requiring investor-owned electric utilities to purchase energy fromanyqualifyingfacility(QF)that delivers energy to the utility.A QF is defined by FERC as a smallrenewable-generation project or small cogeneration project.Individual states were tasked withestablishingthePPAtermsandconditions,including price,that each state’s utilities are required to payaspartofthePURPAagreements.Because Idaho Power operates in both Idaho and Oregon,the company must adhere to both the IPUC rules and regulations for all PURPA facilities located in thestateofIdaho,and the OPUC rules and regulations for all PURPA facilities located in the state ofOregon.The rules and regulations are similar,but not identical,for the two states.Because Idaho PowercannotaccuratelypredicttheleveloffuturePURPAdevelopment,only signed contracts are accountedforinIdahoPower’s resource planning process.
Generation from PURPA contracts has to be forecasted early in the IRP planning process to update theloadandresourcebalance.The forecast used in the 2011 IRP was completed in September 2010 and didnotincludeapproximately500MWofwindcontractsthatweresignedinlate2010.BecauseIdahoPower’s future resource needs are driven by capacity requirements and not energy,the exclusionofthesenewcontractsdoesnothaveamaterialimpactonthe2011IRP.At the 5-percent peak-hourcapacityfactorusedforwindresourcesforplanningpurposes,the 500 MW of PURPA wind contractsrepresentonly25MWofcapacityforpeak-hour planning.
As of March 31,2011,Idaho Power had 127 PURPA contracts with independent developers forapproximately1,190 MW of nameplate capacity.The PURPA generation facilities consist of low-headhydroelectricprojectsonvariousirrigationcanals,cogeneration projects at industrial facilities,windprojects,anaerobic digesters,landfill gas,wood-burning facilities,solar projects,and various othersmall,renewable-power projects.Ofthe 127 contracts,91 were on line as of March 31,2011,with acumulativenameplateratingofapproximately491MW.Figure 3.4 shows the total nameplate capacityofeachresourcetypeundercontract.Figure 3.4 includes 294 MW from 13 PURPA wind contracts thatwererecentlydisapprovedbytheIPUC.Additional details on these contracts are presented in thenextsection.
2011 IRP Page 33
3.Idaho Power Today Idaho Power Company
Hydro (141 MW)
_____I
(37 MW)
E’_Biomass (40 MW)
Wind (948 MW).]’
Figure 3.4 PURPA contracts by resource type
Published Avoided Cost Rates
A key component of PURPA contracts is the energy price contained within the agreements.The federal
PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided cost.
Subsequently,the IPUC and OPUC have established specific rules and regulations to calculate the
published avoided cost rate that Idaho Power is required to include in PURPA contracts.
In November 2010,Idaho Power and other investor-owned utilities in Idaho filed a joint petition asking
the IPUC to examine certain issues related to PURPA (IPUC Case No.GNR-E-l0-04 and
GNR-E-11-01).These issues include the disaggregation of larger,utility-scale projects in order to
qualify for the published avoided cost rate and the methods used to calculate the published rate.As of
June 2011,this case was not resolved,and the outcome may impact some of the existing PURPA
contracts for projects not yet constructed as well as future PURPA project development.
On June 8,2011,the IPUC issued Order 32262 in this case.The order recognized that the disaggregation
issue could not be solved without simultaneously addressing pricing and other issues related to PURPA.
In addition,the order established that the published avoided cost rate is available for only wind and solar
projects with a nameplate rating of less than 100 kW.For all other resource types,the eligibility cap will
remain at 10 aMW.The order goes on to state that the next phase of the case will be a thorough review
ofthe energy pricing methods to be used for PURPA.The order requests the parties in the case meet no
later than July 8,2011,to establish a schedule to process the next phase of the case.
In addition to Order 32262,on June 8,2011,the IPUC issued separate orders disapproving 13 PURPA
wind contracts that Idaho Power had filed requesting IPUC approval.Idaho Power expects some of the
counterparties to these contracts to request the IPUC reconsider these orders.The parties have 21 days
from the date of the order to file the request for reconsideration,at which time the IPUC will take
requests under consideration and issue additional rulings.Rulings on the reconsideration process and
other orders in the case will not be complete by the June 30,2011,IRP filing deadline.
Wholesale Contracts
Idaho Power currently has one,fixed-term,off-system sales contract to supply 6 aMW to the Raft River
Rural Electric Cooperative.The Raft River Cooperative is the electric distribution utility serving
Idaho Power’s former customers in Nevada.The agreement was established as a full-requirements
contract after being approved by FERC and the Public Utilities Commission of Nevada.This contract
has been renewed annually for several years;however,it is expected to expire at the end of
September 2011.
Idaho Power continues to use its transmission capacity on the Jefferson line to import power from
Montana during the summer months.At present,Idaho Power purchases 83 MW during summertime
heavy-load hours from PPL EnergyPlus,LLC.Although the purchase agreement expires in 2012,
Solar (20 MW),
Page 34 2011 IRP
Idaho Power Company 3.Idaho Power Today
Idaho Power plans to continue to use the available transmission capacity during the summer months asneededuntiltheBoardmantoHemingwaytransmissionlineiscompleted.
Market Purchases and Sales
Idaho Power relies on regional markets to supply a significant portion of energy and capacity needsduringcertaintimesoftheyear.Idaho Power is especially dependent on the regional markets duringpeak-load periods,and the existing transmission system is used to import these purchases.Reliance onregionalmarketshasbenefitedIdahoPowercustomersduringtimesoflowpricesasthecostofpurchases,revenue from surplus sales,and fuel expenses are shared with customers through the PCA.
Committed Supply-Side Resources
Committed supply-side resources are generation facilities that have been evaluated and selected inpreviousIRPs.Committed resources are assumed to be in Idaho Power’s resource portfolio on theexpectedoperationaldateofthefacilityandaretreatedlikeexistingresourcesintheIRPanalysis.
Langley Gulch
The need for a new baseload power plant was identified in Idaho Power’s 2004 and 2006 LRPs.The initial decision was to construct a coal-fired baseload resource,but regulatory,price,and environmental issues led Idaho Power to reconsider the coal resource and instead select a naturalgas-fired CCCT.Idaho Power completed the competitive bidding process in early 2009 and selected a300MWCCCTprojectnearNewPlymouth,Idaho to meet the resource need.
The Langley Gulch project is expected to begin delivering energy in time to meet summer peaking needsinJuly2012.The Langley Gulch project will require the construction of short segments of 138-ky and230-ky transmission lines to connect to the existing system in order to deliver energy and providecapacitysupporttoIdahoPowercustomersinIdahoandOregon.
Shoshone Falls Upgrade Project
In August 2006,Idaho Power filed a license amendment application with FERC to upgrade theShoshoneFallsHydroelectricProjectfrom12.5 MW to 61.5 MW.The project currently hasthreegenerator/turbine units with nameplate capacities of 11.5 MW,0.6 MW,and 0.4 MW.The upgrade project involves replacing the two smaller units with a single,50-MW unit that willresultinanetupgradeof49MW.
In July 2010,FERC issued a license amendment for the project.This amendment allows two years tobeginconstructionandfiveyearstocompletetheproject.For the 2011 IRP,Idaho Power is planning ontheadditionalcapacityfromtheShoshoneFallsupgradebeingavailableinOctober2015.When theprojectiscompleted,Idaho Power expects the additional generation from the upgrade will qualify forRECsthatcanbeusedtosatisfyfederalRESrequirements.
While previous evaluations of the Shoshone Falls upgrade have been done under median waterconditions,some uncertainty exists regarding future Snake River streamfiows that would not onlyimpacttheShoshoneFallsproject,but all of Idaho Power’s Snake River hydroelectric projects.Because of the benefits and additional value provided by the Shoshone Falls Upgrade Project,it isincludedinthe2011LRPasacommittedresource.Idaho Power will continue to pursue this project inconjunctionwiththeresolutionofwaterissuesinthestateofIdaho.Prior to filing for a CPCN with theIPUC,Idaho Power plans to update the economic analysis of the project,taking into account the mostcurrentforecastsofforwardmarketprices,REC prices,and any unresolved water issues.
2011 IRP Page 35
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Page 36 2011 IRP
Idaho Power Company 4.Demand-Side Resources
4.DEMAND-SIDE RESOURCES
DSM customer programs are an essential
component of Idaho Power’s resource
strategy.Idaho Power works with customers
to promote energy efficiency and produce
the same output or provide the same level of
service with lower energy consumption.
Through demand response programs,
Idaho Power provides incentives to
customers to identifi applications where a
short-term load reduction can be timed to
coincide with peak energy consumption
when all other resources,including
transmission capacity to purchase energy,
are at their maximum capacity.
Energy efficiency programs target year-
round energy and demand reduction and are the demand-side alternatives to supply-side base loadresources.Energy efficiency and demand response programs are offered to all four major customerclasses:residential,irrigation,commercial,and industrial.
Market transformation,an additional program category,targets energy savings through engaging andinfluencinglargenationalandregionalorganizationstopromoteenergyefficiency.Idaho Power hascollaboratedwithotherregionalutilitiesandorganizationsinfundingtheNorthwestEnergyEfficiencyAlliance(NEEA)market transformation promotional activities since 2001.Due to the indirect nature ofsavingsfrommarkettransformation,NEEA impacts are not accounted for in resource planning.
Cost-effectiveness analyses,which indicate whether the benefits of avoided power generation costsexceedthecostsofofferinganenergyefficiencyordemandresponseprogram,are published annually,and the most recent analysis can be found in the Demand-Side Management 2010 Annual ReportSupplement1:Cost Effectiveness.Each program in the existing portfolio of demand-side resources arereviewedaspartoftheIRPprocessfortheirpotentialimpactoverthe20-year IRP planning horizon.The resulting forecast of energy savings and demand-reduction potential,along with prior programperformance,is then incorporated into the load forecast process.For a description of this process,see Appendix A—Sales and Load Forecast.
In addition to reviewing the existing portfolio of DSM resources,new opportunities for demand-sideresourcesareevaluatedforinclusionintotheexistingportfolioofprogramsandtheirimpactsare
Highlights
Energy Efficiency efforts from both the existing portfolio and program expansion willprovide233aMWofsystemreductionoverthe20-year planning period avoiding over$1.1 billion in power supply costs in 2011 dollars.
Total peak summer capacity of the demand response program portfolio is targeted at330MWin2011andincreasesto351MWby2016.
Demand response programs will cost $48 per kW,and new energy efficiency will cost5.1 cents per kWh over the IRP planning period.
Idaho Power’s Long Valley Operations Center in Lake Fork wasgrantedLEEDgoldstatusdueinparttoitsenergy-efficient design.
2011 IRP Page 37
4.Demand-Side Resources Idaho Power Company
forecasted.Idaho Power adopts all new demand-side resources when they are determined to be
cost-effective.Energy efficiency resources are consistently one of the least-cost resources available for
Idaho Power’s resource stack.
All cost-effectiveness analyses for DSM forecasts for both the existing portfolio and new acquisition
accounted for in the 2011 IRP are either presented as a summary in the IRP or in more detail in
Appendix C—Technical Appendix.Appendix B—Demand-Side Management 2010 Annual Report contains
a detailed description of Idaho Power’s 2010 energy efficiency program portfolio along with historical
program performance.
Energy Efficiency Program Portfolio Analysis
Each energy efficiency program currently offered to customers as part of the existing portfolio is
reviewed to forecast average demand reduction.The forecast ofpotential programs over the IRP
planning horizon considers where the program is in its life cycle (i.e.,ramping up or ramping down).
Also,recent program participation trends,future changes in codes and standards that will affect program
measures,along with program design changes are taken into consideration.
Idaho Power placed primary emphasis on the first five years (2011—2015)when reviewing program
potential;then future program performance was assumed to be held constant at 2015 levels unless
known codes and standards or other mitigating circumstances justified ramping the program down early.
Many unknown factors may affect program participation for the second 10 years,including multiple
changes in codes and standards or technology.Therefore,programs included in the 2020 portfolio are
ramped down by the end ofthe 20-year IRP planning period.
Historical demand-side reductions are assumed to influence customer energy-usage behavior and are
accounted for in the 2011 IRP load forecast methodologies.Therefore,the current portfolio is analyzed
starting in 2011 and looks at 20 11—2030 impacts only.The program performance forecast assumes
customers will not replace existing efficiency measures with less-efficient measures once useful life
expires,and the forecasted impact of energy efficiency programs accumulates from year-to-year.
For example,in 2015,Idaho Power assumes all efficient measures installed during 2011—2014 are still
in place,along with incremental 2015 energy savings.
Annual savings are measured in MWh;for the IRP analysis they are divided by 8,760 hours (hours in a
year),or corresponding monthly hours,to convert to average annual or monthly demand reduction
(aMW)to compare with supply-side resources.All forecasts are prepared in terms of generation
equivalency and include line losses of 10.9 percent,which accounts for energy lost as a result of
transmitting energy between the generation source and the customer.
Table 4.1 shows the forecast impact of the current portfolio of energy efficiency programs for 2011,
2015,2020,and 2030,in terms of average demand reduction (aMW)by customer class.In 2015,
the forecast reduction for 2011—2015 programs will be 69 aMW;by the year 2020,the reduction across
all customer classes increases to 133 aMW.By the end of the IRP planning horizon in 2030,191 aMW
of reduction is forecast to come from the current energy efficiency portfolio,with 80 percent of that
reduction coming from programs serving commercial and industrial customers.Detailed year-by-year
forecast values can be found in Appendix C—Technical Appendix.
Page 38 2011 IRP
Idaho Power Company 4.Demand-Side Resources
Table 4.1 Energy efficiency current portfolio forecasted impacts (2011—2030)
2015 (aMW)2020 (aMW)2025 (aMW)2030 (aMW)
Industrial 23 46 61 66Irrigation581111Commercial30608086Residential11202628Total69133178191
Table 4.2 shows the forecast cost-effectiveness of the current portfolio of energy efficiency programs.The table shows the net-present-value analysis of the 20-year forecast of utility costs,resource costs,and avoided energy.Utility costs are the costs to administer the energy efficiency programs,while totalresourcecostsaccountforboththeutilitycostsandthecustomerinvestmentinefficiencytechnologiesandmeasuresofferedthroughtheprograms.Utility costs and total resource costs were estimated basedon2010programperformanceforindustrial,commercial,and residential classes and a three-yearaverageperformanceforirrigationtoallowforannualfluctuationsbetweencustom-and menu-drivenirrigationefficiency.Avoided energy is the benefit of the programs calculated by valuing energy savingsagainsttheavoidedgenerationcostsofIdahoPower’s existing portfolio of generation resources.
Table 4.2 Existing energy efficiency portfolio cost-effectiveness summary
Total
Total Resource
Resource CostAvoidedEnergyUtilityCost:Utility Cost:Levelized2030LoadUtilityCostsResourceCostsCostsBenefit/Cost Levelized Benefit/Cost CostsImpact(aMW)(20-Year NPV*)(20-Year NPV)(20-Year NPV)Ratio Costs ($IkWh)Ratio ($/kWh)
Industrial 66 $49,398,586 $96,635,806 $257,704,824 5.2 $0.015 2.7 $0.028Irrigation11$14,229,458 $38,651,984 $43,667,373 3.1 $0.023 1.1 $0061Commercial86$60,885,631 $119,966,128 $335,208,357 5.5 $0.014 2.8 $0027Residential28$60,023,978 $103,519,281 $181,086,911 3.0 $0040 1.7 $0069Total191$184,537,652 $358,773,200 $817,667,465 4.4 $0.019 2.3 $0.036*Net present value (NPV)
The value of avoided energy over the 20-year investment in the energy efficiency measures was morethantwicethetotalresourcecostwhencomparingbenefitsandcosts.This resulted in an overall benefitcostratioof2.3.The levelized cost to reduce energy demand by 191 aMW is 3.6 cents per kWh from atotalresourcecostperspective.Figure 6.9 in Chapter 6 compares energy efficiency program costs withIdahoPower’s other supply-side resource options from an energy perspective.
New Energy Efficiency Resources
During each IRP planning period,Idaho Power uses various resources,including existing portfolioprogramexpansion,new program development,potential studies,Northwest Power and ConservationCouncil(NPCC)research,and Idaho Power’s Energy Efficiency Advisory Group (EEAG),to determinehowfutureenergyefficiencyanddemandresponseprogramscanfulfillfutureresourceneeds.New energy efficiency opportunities are evaluated through a cost-effectiveness analysis similar to theexistingprograms.Forecasting assumptions for new residential efficiency for the 2011 IRP were aidedbytheplanningmodelthatwasdevelopedbyNexantInc.,from the 2009 Demand Side ManagementPotentialStudy.
Along with identifying new opportunities for energy efficiency it is also important to identify thebarriersthatmayfacenewprogrammeasuresandexpansions.One challenge the company will continue
2011 IRP Page 39
4.Demand-Side Resources Idaho Power Company
to face going forward is to increase the understanding ofbehaviors and decisions that residential
customers make in regards to energy efficiency investments and providing the correct level of
incentive to motivate them while maintaining cost-effectiveness.Much of the expansion to residential
programs analyzed for the 2011 IRP include measures requiring increased customer investments,such as
improved weatherization in electric home and multi-family housing.It will become increasingly
important to understand the purchasing decisions of prior participants and continue forward with
Idaho Power’s efforts of targeted marketing and demographic analysis to work to overcome customers’
investment barriers.Ongoing process evaluations of energy efficiency programs will also continue to be
an important source of information for understanding customer participation in programs and for
developing strategies to increase participation and program delivery.Examples ofpast process
evaluations for energy efficiency programs can be found in the Demand-Side Management 2010 Annual
Report Supplement 2:Evaluation.
Industrial Efficiency
Efficiency projects,through the Custom Efficiency program,which provides efficiency projects to large
commercial and industrial customers continues to exceed expectations and has performed well since the
program began providing incentives in 2004.Projects can include any combination of approved custom
measures and process improvements that show energy efficiency enhancements.Some of the most
common projects include measures,such as higher-efficiency lighting,fans,compressed air,and pumps.
Program changes,including moving some smaller lighting projects of less than 100,000 annual kWh of
savings to other programs,will allow increased capacity for more custom projects over the next few
years.This will lead to an increased expansion of 13 aMW over the 20-year IRP planning horizon.
The increased efficiency will cost approximately 2.6 cents per kWh.
Commercial Efficiency
Program changes in the commercial and industrial efficiency programs in 2011 will shift some lighting
projects into the Easy Upgrades prescriptive program that previously would have paid through the
Custom Efficiency program.These potential savings were not accounted for in the original commercial
program portfolio forecast and will result in an additional 6.6 aMW of average demand reduction
potential over the IRP planning horizon.
Residential Efficiency
New residential efficiency includes expanded weatherization measures identified in the Idaho Power
Demand-Side Management Potential Study,published in 2009,along with growth in incentives for heat
pumps for electrically heated homes,and expansion of existing programs into the multi-family sector.
During 2011 and 2012,plans are being made to add additional weatherization measures to
Idaho Power’s Home Improvement Program,which currently provides incentives for increasing levels
of attic insulation.The additional measures are also expected to be made available to multi-family
housing and will focus on windows,infiltration,and HVAC duct sealing.These program additions for
electrically heated homes are forecasted to add 20.1 aMW of savings to the program over the IRP
planning horizon.
Increased incentives for air-source heat pumps in 2011 will encourage customers to transition from
electric,forced-air furnaces and will add 0.3 aMW of average demand reduction to the program.
Weatherization Solutions for Eligible Customers,a weatherization program for income-qualified
customers,will be expanded to eastern Idaho in 2011.Idaho Power forecasts the new targeted area will
provide 2 aMW of increased program reduction over the JRP planning horizon.
Page4O 2011 IRP
Idaho Power Company 4.Demand-Side Resources
Table 4.3 shows the forecast combined contribution in reduced average consumption over the IRPplanninghorizon.In 2015,the new and expanded energy efficiency programs will reduce average loadsby13aMW;in 2020,average loads will be reduced by 25 aMW.The full 20-year capacity of theprogramadditionsandchangesis42aMWofaveragedemandreduction.
Table 4.3 New energy efficiency portfolio forecasted impacts (2011—2030)
2015 (aMW)2020 (aMW)2025 (aMW)2030 (aMW)
Industrial 7 10 12 13Commercial2567Residential4101623Total13253542
Table 4.4 presents a summary ofthe cost and cost-effectiveness of new energy efficiency efforts.The overall benefit/cost ratio for all new energy efficiency measures is 3.2 at a levelized total resourcecostof5.1 cents per kWh.Additional details on annual costs and benefits can be found in Appendix C—Technical Appendix.
Table 4.4 New energy efficiency portfolio cost-effectiveness summary
Total
Total Resource
Resource Cost:
Avoided Energy Utility Cost:Utility Cost:Levelized2030LoadUtilityCostsResourceCostsCostsBenefit/Cost Levelized Benefit/Cost CostsImpact(aMW)(20-Year NPV)(20-Year NPV)(20-Year NPV)Ratio Costs ($/kWh)Ratio ($/kWh)Industrial 13 $10,293,124 $20,135,886 $56,034,905 5.4 $0013 2.8 $0.026Commercial7$4,468,872 $8,607,815 $25,770,482 5.8 $0.013 3.0 $0025Residential23$35,582,870 $69,027,549 $228,851,046 6.4 $0045 3.3 $0.086Total42$50,344,865 $97,771,250 $310,656,434 6.2 $0.026 3.2 $0.051
Demand Response Resources
The goal of demand response programs at
Idaho Power is to reduce summer peak load during
periods of extremely high demand and minimize or
delay the need to build new supply-side resources.
Demand response programs were first implemented
in summer 2004 when a 6.1-MW peak-hour load
reduction was measured.Idaho Power’s demand
response portfolio has grown since that time,
and 330 MW of peak-hour load reduction has been
targeted for summer 2011.Three programs 1)A/C
Cool Credit,2)Irrigation Peak Rewards,and 3)
FlexPeak Management allow residential,irrigation,
commercial,and industrial customers to participate
in potential peak-hour load reduction efforts.
A complete description of the demand response programs can be found in Appendix B—Demand-SideManagement2010AnnualReport.
An analysis that focused on the optimal level of demand response resources along with the costs and themosteffectivemethodofutilizationwasconductedaspartofthe2011IRP.The conclusions drawn fromthisanalysiswerethat1)there is a defined optimal amount of demand response for Idaho Power’s
An Idaho Power customer representative discussestheIrrigationPeakRewardsprogramwithafarmer.
2011 IRP Page 41
4.Demand-Side Resources Idaho Power Company
system;2)in conjunction with each IRP,Idaho Power will update the targets for demand response;
3)the program managers will work to align program design with system needs;4)stakeholders will be
involved in this process;and 5)program designs and pricing options will be reassessed.In this analysis,
the costs from an energy perspective for demand response was compared to the energy costs of owning
and operating an SCCT.The results of this analysis indicated actual program energy costs were
inherently more because ofthe limitations on the number of hours the programs could be operated
(60 hours)and the limited time ofthe year when the programs were available.The program continues to
be less expensive than an SCCT from a capacity perspective,which is how the program cost-
effectiveness is determined.However,from an energy perspective,it is among the most expensive
resources evaluated in the IRP.
Because of the results of the analysis,Idaho Power filed with the IPUC Case No.IPC-E-10-46 asking
for significant changes to the Irrigation Peak Rewards program,including a method of paying
participants with a variable component based on the level of use.The levels of demand response
determined for the 2011 IRP analysis is 330 MW for summer 2011,310 MW in 2012 when the Langley
Gulch plant comes on line,and 315 MW in 2013 and 2014.In 2015,the demand response level used in
the IRP analysis is 321 MW and then 351 MW from 2016 through the end of the planning period.
Demand response,because of its limited availability,cannot continually satisfy all of the load and
resource balance deficits throughout the IRP planning period;rather,the goal of setting the appropriate
levels of demand response is to delay the addition of new supply-side resources.
Table 4.5 presents a summary of the cost-effectiveness of the demand response programs.The Irrigation
Peak Rewards program is forecast to provide 260 MW of peak-hour load reduction.The A/C Cool
Credit program is expected to have 40,000 residential customer participants and is expected to provide a
peak-hour load reduction of 51 MW.The FlexPeak Management program is forecast to provide 40 MW
of reduction and is controlled by EnerNoc,Inc.,a third-party program administrator.
Table 4.5 Demand response cost-effectiveness summary
2030 Load Resource Costs Avoided Energy Costs Total Resource Cost:Total Resource Cost:
Impact (MW)(20-Year NPV)(20-Year NPV)Benefit/Cost Ratio Levellzed Costs ($IkW)
Commercial/Industrial 40 $29,797,258 $46,640,850 1.6 $65
Irrigation 260 $122,250,426 $238,224,468 2.0 $45
Residential 51 $25,242,292 $52,905,340 2.1 $46
Total/Summary 351 $177,289,977 $337,770,659 1.9 $48
Across the demand response portfolio,the value ofreduced demand compared with building a
supply-side capacity resource is nearly twice the value of the cost to run the programs.The benefit/cost
ratio is 1.9 with a levelized cost of $48 per kW.Detailed annual forecast costs and benefits of demand
response resources are presented in Appendix C—Technical Appendix.
Page 42 2011 IRP
Idaho Power Company 5.Supply-Side Resources
5.SUPPLY-SIDE RESOURCES
Supply-side resources are traditional generation
resources.Early TRP utility commission orders
directed Idaho Power and other utilities to give
equal treatment to both supply-side and
demand-side resources.The company has done that;
today,demand-side programs are an essential
component of Idaho Power’s resource strategy.
The following sections describe the supply-side
resources considered when Idaho Power developed
the resource portfolios for the 2011 IRP.Not all
supply-side resources described in this section were
included in the preliminary resource portfolios,
but every resource described was considered.
Renewable Resources
Renewable resources are the foundation of Idaho Power,and the company has a long history ofrenewableresourcedevelopmentandoperation.In the 2011 IRP,renewable resources were included inallportfoliosanalyzedtomeetproposedfederalRESlegislation.Renewable resources are discussed ingeneraltermsinthefollowingsections.
Geothermal
Potential commercial geothermal generation in the Pacific Northwest includes both flashed steam andbinary-cycle technologies.Based on exploration to date in southern Idaho,binary-cycle geothermaldevelopmentismorelikelythanflashedsteamwithinIdahoPower’s service area.Most optimallocationsforpotentialgeothermaldevelopmentarebelievedtobeinthesoutheasternpartofthe state.However,the potential for geothermal generation in southern Idaho is somewhat uncertain.The timerequiredtodiscoverandprovegeothermalresourcesitesishighlyvariableandcantakeyears,or even decades.
The overall cost of a geothermal resource varies with resource temperature,development size,and wateravailability.Flashed steam plants are applicable for geothermal resources where the fluid temperature is300°Fahrenheit (F)or greater.Binary-cycle technology is used for lower-temperature geothermalresources.In a binary-cycle geothermal plant,geothermal water is pumped to the surface and passedthroughaheatexchangerwherethegeothermalenergyistransferredtoalowboilingpointfluid
Hig hi ights
The cost of solar PV technology has continued to decline as technology improvementshaveimprovedefficiencyandthesupplyofPVpanelshasincreased.The 2011 IRP costestimateforsolarPVis$3,750 per kW.
Idaho Power continues the permitting process for the Boardman to Hemingway andGatewayWesttransmissionprojectsthatwillprovideadditionalaccesstotheregionalelectricitymarket.
The 2011 IRP assumes advanced nuclear,IGCC,and carbon capture and sequestrationtechnologieswillnotbeavailableuntilthe2020s.
A vintage generator still in operation at
Idaho Power’s Thousand Springs power plant.
2011 IRP Page 43
5.Supply-Side Resources Idaho Power Company
(the secondary fluid).The secondary fluid is vaporized and used to drive a turbine/generator.
After driving the generator,the secondary fluid is condensed and recycled through a heat exchanger.
The secondary fluid is in a closed system and is reused continuously in a binary-cycle plant.
The primary fluid (the geothermal water)is returned to the geothermal reservoir through injection wells.
Cost estimates and operating parameters used for binary-cycle geothermal generation in the IRP are
based on data from independent geothermal developers and cost information from a PPA Idaho Power
has with U.S.Geothermal,Inc.,for the generation from the Neal Hot Springs geothermal project located
in eastern Oregon.The capital cost estimate used in the TRP for geothermal resources is $6,250 per kW,
and the 30-year levelized cost of production is $117 per MWh.
Wind
A typical wind project consists of an array of wind turbines ranging in size from 1—3 MW each.
The majority of potential wind sites in southern Idaho lie between the south central and the most
southeastern part of the state.Areas that receive consistent,sustained winds greater than
15 miles-per-hour are prime locations for wind development.
The Pacific Northwest and Intermountain regions are good areas for the development of wind resources,
as evidenced by the number of existing and planned projects.However,wind resources present
challenges for utilities due to the variable and intermittent nature of the generation.Therefore,planning
new wind resources requires estimates of the expected annual energy and peak-hour capacity.For the
2011 IRP,Idaho Power used an annual average capacity factor of 32 percent and a capacity factor of
5 percent for peak-hour planning.
Cost estimates and operating parameters used for wind generation in the IRP are based on data from
independent developers and cost information obtained from the 2012 Wind RFP issued by Idaho Power.
The 2012 Wind RFP did not ultimately result in the identification of a successful bidder due in large part
to a recent surge in PURPA wind development in southern Idaho.The capital cost estimate used in the
IRP for wind resources is $1,450 per kW,and the 30-year levelized cost of production is $89 per MWh,
which includes a cost for wind integration.In 2008,the IPUC approved a settlement stipulation
establishing a wind integration cost of $6.50 per MWh,which was less than Idaho Power’s estimated
cost to integrate wind.
Hydroelectric
Hydroelectric power is the foundation of Idaho Power’s generation fleet.The existing generation is low
cost and does not emit potentially harmful pollutants.Idaho Power believes the development of new
large hydroelectric projects is unlikely because few appropriate sites exist and because of environmental
and permitting issues associated with new,large facilities.However,small hydroelectric sites have been
extensively developed in southern Idaho on irrigation canals and other sites,many of which have
PURPA contracts with Idaho Power.
Small Hydroelectric
Because small hydroelectric,such as run-of-river and projects requiring small or no impoundments,does
not have the same level of environmental and permitting issues as large hydroelectric,the TRPAC
expressed an interest in evaluating small hydroelectric in the 2011 IRP.The potential for new,small
hydroelectric projects was studied by the Idaho Strategic Energy Alliance’s Hydropower Task Force,
and the results released in May 2009 indicate between 150 MW to 800 MW of new hydroelectric
resources could be developed in the state of Idaho.These figures are based on potential upgrades to
existing facilities,undeveloped existing impoundments and water delivery systems,and in-stream flow
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Idaho Power Company 5.Supply-Side Resources
opportunities.The capital cost estimate used in the IRP for small hydroelectric resources is $4,000 perkWandthe30-year levelized cost ofproduction is $144 per MWh.
Pumped Storage
Pumped storage is a type of hydroelectric power generation used to change the “shape”or timing whenelectricityisproduced.The technology stores energy in the form of water,pumped from a lowerelevationreservoirtoahigherelevation.Lower-cost,off-peak electricity is used to pump water from thelowerreservoirtotheupperreservoir.During higher-cost periods of high electrical demand,the waterstoredintheupperreservoirisusedtoproduceelectricity.
For pumped storage to be economical,there must be a significant differential in the price of electricitybetweenpeakandoff-peak times in order to overcome the costs incurred due to efficiency and otherlossesthatmakepumpedstorageanetconsumerofenergyoverall.Historically,the differential betweenpeakandoff-peak energy prices in the Pacific Northwest has not been sufficient to make pumpedstorageaneconomicallyviableresource;however,with the recent increase in the number of windprojects,the amount of intermittent generation provided,and the ancillary services required,this maychange.The capital cost estimate used in the JRP for pumped storage is $5,000 per kW,and the 30-yearlevelizedcostofproductionis$155 per MWh.
Solar
The primary types of solar technology are solar thermal and PV.Solar thermal technologies use mirrorstofocusthesun’s rays onto a central receiver or a “collector”to collect thermal energy that can be usedtomakesteamandpoweraturbinethatcreateselectricity.PV panels absorb solar energy collected fromsunlightshiningonpanelsofsolarcells,and a percentage of the solar energy is absorbed into thesemiconductormaterial.The energy accumulated inside the semiconductor material energizes theelectronsandcreatesanelectriccurrent.
On cloudy days,solar thermal generation will not produce power.However,thermal storage usingmoltensaltfunctionsasanenergystoragesystemallowingsolarthermalgenerationplantstogenerateelectricityafterthesunsetsorduringbriefcloudyperiods,generally for 3—7 hours.PV technology usespanelsthatconvertthesun’s rays directly to electricity.Even on cloudy days,a PV system can stillprovide15percentofthesystem’s rated output.
Insolation is a measure of solar radiation reaching the earth’s surface and is used to evaluate the solarpotentialofanarea.Typically,insolation is measured in kWh per m2 per day (daily insolation averageoverayear).The higher the insolation number,the better the solar power potential for an area.NationalRenewableEnergyLaboratory(NREL)insolation charts show the Desert Southwest has the highestsolarpotentialintheUnitedStates.
There are several types of solar thermal technologies,including power tower,parabolic dish engine,and parabolic trough.In designing initial portfolios that included solar resources,Idaho Power chose thepowertowertechnologybecauseofitsloweroverallcost.The company also selected the solar PVtechnologybecauseoftheincreasedavailabilityofPVpanelsandtherecentdecliningcosttrend.
Power Tower
Power tower technology uses thousands of small,flat,two-axis mirrors,called heliostats,to reflect thesun’s rays onto a boiler at the top of a central tower.The concentrated sunlight strikes the boiler’s pipes,heating the water inside to 1,000°F.The high-temperature steam is then piped from the boiler to aturbinewhereelectricityisgenerated.The power tower technology can use molten salt as a storagemediumtostoreenergy.It has a storage time of 6.9 hours that has been used to evaluate this resource
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5.Supply-Side Resources Idaho Power Company
in the IRP.The capital cost estimate used in the IRP for the power tower technology with storage is
$3,220 per kW,and the 30-year levelized cost of production is $109 per MWh.
Photovoltaic
Solar PV panels absorb solar energy collected from sunlight shining on panels of solar cells,and a
percentage of the solar energy is absorbed into the semiconductor material.The energy accumulated
inside the semiconductor material energizes the electrons,creating an electric current.The solar cells
have one or more electric fields that force electrons to flow in one direction as a direct current (DC).
The DC energy is passed through an inverter,converting it to alternating current (AC)that can then be
used on-site or sent to the grid.
Solar PV technology has existed for a number of years but has historically been cost prohibitive.
Recent improvements in technology and manufacturing,combined with increased demand due to
state RPS requirements,have made PV resources more cost competitive with other renewable and
conventional generating technologies.The capital cost estimate used in the IRP for PV resources is
$3,750 per kW,and the 30-year levelized cost of production,based on a 17-percent annual capacity
factor,is $150 per IvlWh.Idaho Power will continue to closely follow the decreasing price trend of
solar PV as this technology continues to become more cost competitive with more traditional
resource alternatives.
Natural Gas-Fired Resources
Natural gas-fired resources bum natural gas in a combustion turbine to generate electricity.CCCTs are
typically used for baseload energy,while less-efficient SCCTs are used to generate electricity during
peak load periods.Additional details on the characteristics of both types of natural gas resources are
presented in the following sections.
CCCT and SCCT resources are typically sited near existing gas pipelines,which is the case for
Idaho Power’s existing gas resources.However,the capacity of the existing gas pipeline system is
almost fully allocated.Therefore,the 2011 IRP assumes new natural gas resources would require
building additional pipeline capacity.This additional cost is accounted for in portfolios containing new
gas resources and not in the resource stack cost estimate for CCCTs or SCCTs.
Combined-Cycle Combustion Turbines
CCCT plants have been the preferred choice for new commercial power generation in the region.
CCCT technology carries a low initial capital cost compared to other baseload resources,has high
thermal efficiencies,is highly reliable,offers significant operating flexibility,and emits fewer emissions
when compared to coal,thus requiring fewer pollution controls.
A traditional CCCT plant consists of a gas turbine/generator equipped with a heat recovery steam
generator (HRSG)to capture waste heat from the turbine exhaust.The HRSG uses waste heat from the
combustion turbine to drive a steam-turbine generator to produce additional electricity.In a CCCT plant,
heat that would otherwise be wasted is used to produce additional power beyond that typically produced
by an SCCT.New CCCT plants can be built or existing SCCT plants can be converted to combined-
cycle units by adding an HRSG.
Several CCCT plants,including Idaho Power’s Langley Gulch project,are planned in the region due to
recently declining natural gas prices,the need for baseload energy,and additional operating reserves
needed to integrate wind resources.While there is no current shortage ofnatural gas,fuel supply is a
critical component of the long-term operation of a CCCT.At the time the natural gas price forecast was
prepared for the IRP,natural gas prices were considerably higher than they are today.In fact,the low
natural gas price case is a more accurate reflection of the current forward market for natural gas.
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The capital cost estimate used in the LRP for CCCT resources is $1,120 per kW,and the 30-yearlevelizedcostofproductionata65-percent annual capacity factor is $108 per MWh with the carbonadderand$98 per MWh without the adder.If a CCCT were run at a 90-percent annual capacity factor,the 30-year levelized cost would be $100 per MWh with the carbon adder and $90 per MWh withouttheadder.
Simple-Cycle Combustion Turbines
Simple-cycle,natural gas-turbine technology involves pressurizing air that then heats by burning gas infuelcombustors.The hot,pressurized air expands through the blades of the turbine that connects by ashafttotheelectricgenerator.Designs range from larger,industrial machines at 80—200 MW to smallermachinesderivedfromaircrafttechnology.SCCTs have a lower thermal efficiency than CCCTresourcesandarenottypicallyeconomicaltooperateotherthantomeetpeak-hour load requirements.
Several natural gas-fired SCCTs have been brought on line in the region in recent years,primarily inresponsetotheregionalenergycrisisof2000—2001.High electricity prices combined with persistentdroughtconditionsduring2000—2001,as well as continued summertime peak load growth createdinterestingenerationresourceswithlowcapitalcostsandrelativelyshortconstructionleadtimes.
Idaho Power currently has approximately 430 MW of SCCT capacity.Peak summertime electricitydemandcontinuestogrowsignificantlywithinIdahoPower’s service area,and SCCT generatingresourceshavebeenbuilttomeetpeakloadduringcriticalhigh-demand times when the transmissionsystemhasreachedfullimportcapacity.The plants may also be dispatched for financial reasons duringtimeswhenregionalenergypricesareattheirhighest.
The 2011 IRP evaluated two different SCCT technologies,1)a 47-MW small,aeroderivative unit and2)a 170-MW industrial-frame unit.The capital cost estimate used in the IRP for the small,aeroderivative unit is $1,050 per kW,and an industrial-frame unit is $610 per kW.Because of the higherefficiencyoftheaeroderivativeunit,it is assumed to have an annual capacity factor of 8 percent,while the industrial-frame unit is expected to have an annual capacity factor of only 6 percent.
Based on these annual capacity factors,the 30-year levelized cost ofproduction (including the estimatedcostofcarbonemissions)is $319 per MWh for the small,aeroderivative unit and $3 16 per MWh for theindustrial-frame unit.These levelized costs are nearly identical as the higher efficiency of the smallaeroderivativeunitoffsetstheslightlyhighercapitalcost.If an SCCT resource is identified in the IRPpreferredportfolio,Idaho Power would evaluate these two technologies in greater detail prior to issuinganRFPinordertodeterminewhichtechnologyprovidedthegreatestbenefit.
Combined Heat and Power
Combined Heat and Power (CHP),or cogeneration,typically refers to simultaneous production ofbothelectricityandusefulheatfromasingleplant.CHP plants are typically located at,or near,commercial or industrial facilities capable ofusing the heat generated in the process.These facilitiesaresometimesreferredtoasasteamhost.Generation technologies frequently used in CI{P projects aregasturbinesorengineswithaheat-recovery unit.
The main advantage of CHP is that higher overall efficiencies can be obtained because the steam host isabletousealargeportionoftheheatthatwouldotherwisebelostinatypicalgenerationprocess.Because CHP resources are typically located near load centers,building additional transmission capacitycanalsooftenbeavoided.In addition,reduced costs for the steam host provides a competitive advantagethatwillultimatelyhelpthelocaleconomy.
In the evaluation of CHP resources,it became evident that CHP could be a relatively high-cost additiontoIdahoPower’s resource portfolio if the steam host’s need for steam forced the electrical portion of the
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project to run at times when electricity market prices were below the dispatch cost of the plant.To find
ways to make CHP more economical,Idaho Power is committed to working with individual customers
to design operating schemes that allow power to be produced when it is most valuable,while still
meeting the needs of the steam host’s production process.This would be difficult to model for the IRP
because each potential CHP opportunity could be substantially different.
Although a ClIP resource was not identified in the 2011 JRP preferred portfolio,Idaho Power is
committed to continuing its investigation into CHP opportunities on a case-by-case basis.While the
actual cost of a ClIP resource may be less as previous discussed,the capital-cost estimate used in the
IRP for CHP is $1,860 per kW,and the 30-year levelized cost of production,evaluated at an annual
capacity factor of 93 percent,is $111 per MWh,which also accounts for the assumed cost of
carbon emissions.
Several IRPAC members noted that,when considering the total societal benefit of a project,using ClIP
projects to produce both electrical energy and useful heat results in an overall reduction of CO2 and
other emissions.The 2011 IRP assumes emissions costs are associated with a new facility because it
would be owned and operated by Idaho Power.For the next IRP,Idaho Power plans to raise this issue
with the JRPAC early in the process to determine if it would be appropriate to remove some or all of the
emissions cost adders from CHP resources.
Idaho Power’s commitment to continue investigating CHP projects is evidenced by an agreement signed
in October 2009 with the IOER and the Amalgamated Sugar Company (TASCO),one of Idaho Power’s
large industrial customers.The agreement establishes the framework for a feasibility study for a ClIP
resource as large as 100 MW to be performed at TASCO’s Nampa,Idaho facility.The TASCO facility
currently uses coal to produce steam,and switching to natural gas as a fuel source would result in
reduced CO2 emissions and improve air quality in the Treasure Valley.The results of the first phase of
the study looks promising,and a second,more detailed study is expected to be completed by June 2011.
Distributed Generation
In September 2010,Idaho Power received a proposal to implement and manage a distributed generation
program that would use existing emergency generators owned by some of Idaho Power’s largest
customers.The proposal included a load-shed option and a grid-synchronized option.Both options were
analyzed as part ofthe 2011 IRP.
In the resource stack cost analysis,the load-shed option had a cost of almost $8,500 per MWh,and the
grid-synchronized option was over $10,000 per MWh.These costs are high due to the limited amount of
generation these programs are expected to produce and,therefore,must also be analyzed to determine
the value they provide when included with Idaho Power’s other generation resources.
The load-shed option was evaluated for the first 10-year period in the IRP (201 1—2020).In portfolio 1-9,
this program was assumed to be available beginning in 2012.To ascertain the marginal value of the
program,the other resources in portfolio 1-9 were identical to portfolio 1-4 which contained
simple-cycle peaking resources.It was not necessary to evaluate the grid synchronization option because
ofthe higher costs associated with the program.
The results of the analysis of the load-shed option showed that the distributed generation portfolio
(portfolio 1-9)had a higher NPV cost of $5.6 million for the 10-year period compared to the
simple-cycle portfolio under the base case assumptions used in the IRP.Idaho Power will continue to
evaluate distributed generation programs in the future;however,at this time the company does not
intend to pursue the implementation of a distributed generation program.
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Conventional Coal Resources
Conventional coal-fired generation is a mature technology and has been the primary source ofcommercialpowerproductionintheUnitedStatesformanydecades.Traditional pulverized-coal plantshavebeenasignificantpartofIdahoPower’s generation mix since the early 1970s.Idaho Powercurrentlyhasover1,100 MW of coal resources that are jointly owned with other utility partners whooperatethefacilities.Idaho Power’s coal resources are located in the neighboring states of Wyoming(Jim Bridger),Nevada (Valmy),and Oregon (Boardman).
A pulverized-coal facility uses coal ground into a dust-like consistency and burned to heat water andproducesteamtodriveasteamturbineandgenerator.Emissions controls at coal plants have becomeincreasinglyimportantinrecentyears,and many units in the region have been upgraded to include thelatestscrubberandlow-NO burner technology to help reduce harmful emissions and particulates.Coal has the highest ratio of carbon-to-hydrogen of all fossil fuels,and significant research is being donetodevelopcarboncaptureandsequestrationtechnologythatcanbeeconomicallyaddedtoexistingcoalfacilities.
Though coal-fired power plants require significant capital commitments to develop,coal resources takeadvantageofalow-cost fuel and provide reliable and dispatchable energy.Coal supplies are abundant intheIntermountainRegionandaresufficienttofuelIdahoPower’s existing plants for many years tocome.
In 2007,Idaho Power decided not to pursue the development of a coal-fired resource identified in the2006IRP.In addition to considering the cost of a coal-based resource,the company considered theuncertaintysurroundingtheregulationofcarbonemissionsandtheabilitytopermitanewcoalresource.Idaho Power continues to evaluate other coal-fired resource opportunities,including efficiencyimprovementsatitsjointlyownedfacilitiesaswellasmonitoringthedevelopmentofcleancoaltechnologies.However,due to the uncertainty regarding future carbon regulations,conventional coalresourceswerenotincludedinanyoftheportfoliosanalyzedinthe2011IRP.
Integrated Gasification Combined-Cycle and
Carbon Sequestration
10CC is an evolving coal-based technology designed to substantially reduce CO2 emissions.If the costofCO2emissionseventuallymakesconventionalcoalresourcesobsolete,the commercialization of thistechnologymayallowthecontinueduseofthecountry’s coal resources.10CC technology is alsodependentonthedevelopmentofcarboncaptureandsequestrationtechnologythatwouldallowCO2 tobestoredundergroundforlongperiodsoftime.
Coal gasification is a relatively mature technology,but it has not been widely adapted as a resource togenerateelectricity.10CC technology involves turning coal into a synthetic gas or “syngas”that can beprocessedandcleanedtoapointthatitmeetspipelinequalitystandards.To produce electricity,the syngas is burned in a conventional combustion turbine that drives a generator.
The addition of CO2-capture equipment decreases the overall efficiency of an IGCC plant by as much as15percent.hi addition,once the carbon is captured,it must either be used or stored for long periods oftime.CO2 has been injected into existing oil fields to enhance oil recovery;however,if 10CCtechnologywerewidelyadoptedbyutilitiesforpowerproduction,the quantities of CO2 produced wouldrequirethedevelopmentofundergroundsequestrationmethods.
Carbon sequestration involves taking captured CO2 and storing it away from the atmosphere bycompressingandpumpingitintoundergroundgeologicformations.If compression and pumping costsarechargedtotheplant,the overall efficiency of the plant is reduced by an additional 15 to 20 percent.
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Sequestration methods are currently being developed and tested;however,commercialization of the
technology is not expected to happen for some time.For the 2011 IRP,Idaho Power is assuming this
technology will not be available until the year 2024.The capital cost estimate used in the IRP for IGCC
with carbon sequestration is $3,776 per kW,and the 30-year levelized cost of production,evaluated at
an annual capacity factor of 85 percent,is $191 per MWh.
Advanced Nuclear
The nuclear power industry has been working to develop and improve reactor technology for some time.
In Idaho Power’s 2006 IRP,an advanced nuclear resource was included in the preferred portfolio in the
year 2023,based on the assumption that an advanced-design reactor would be built on the Idaho
National Laboratory (INL)site in eastern Idaho.Updated information from INL suggests the plant,
ifbuilt,would be located near an industrial manufacturing hub with a high baseload energy need,
most likely outside of Idaho.High capital cost coupled with a great amount of uncertainty in the actual
cost of building an advanced reactor prevented a nuclear resource from being included in the preferred
portfolio in Idaho Power’s 2011 IRP.
The recent earthquake and tsunami in Japan,and the impact on the nuclear reactors located there,
have created a global concern over the safety of nuclear power generation.While there will undoubtedly
be new design and safety measures implemented,it is difficult to know the impact this disaster will have
on the future of nuclear power generation.
For the 2011 IRP,an advanced nuclear resource was assumed to not be commercially available until
2023.Additionally,if the IRP identified a nuclear resource in the preferred portfolio,Idaho Power
would plan to partner with other utilities in a plant built around a smaller modular design with
Idaho Power’s share being approximately 250 MW.Similar to the 2009 IRP,the capital cost of an
advanced nuclear reactor is considerable,and the IRP risk analysis continues to account for a great
amount of uncertainty in the actual cost.The capital cost estimate used in the IRP for an advanced
nuclear resource is $3,820 per kW,and the 30-year levelized cost of production,evaluated at an annual
capacity factor of 85 percent,is $229 per MWh.
Transmission
Idaho Power is responsible for providing safe and
reliable electrical service to its service area,
which includes most of southern Idaho and a portion of
eastern Oregon.In addition to operating under the
regulatory oversight of the IPUC and the OPUC,
Idaho Power is a public utility under the jurisdiction of
FERC,and under its Open Access Transmission Tariff
(OATT),is required to expand its transmission system
to provide requested firm transmission service and to
construct and place in service sufficient capacity to
reliably deliver electrical resources to customers.
Idaho Power’s transmission system is currently limited in its ability to transmit energy from markets or
new resources to load centers in Idaho and eastern Oregon.Because of the need to access markets,
improve reliability,integrate new resources,and facilitate renewable resource development in the
region,Idaho Power has considered two major transmission projects for a number of years ;they are
both included in the 2011 IRP—Boardman to Hemingway and Gateway West.These two projects were
The Hemingway Substation is located
in southwestern Idaho.
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Idaho Power Company 5.Supply-Side Resources
also evaluated in Idaho Power’s 2009 IRP and sub-regional and regional transmissionplanningprocesses.
For the 2011 IRP,one portfolio requiring Boardman to Hemingway capacity was analyzed for the first10yearsoftheplanninghorizon(2011—2020).Tn the second 10 years (202 1—2030),one portfolioincludedadditionalcapacitytothePacificNorthwestandanotherincludedadditionalcapacitytothe eastsideofIdahoPower’s system.These two portfolios were designed to evaluate the cost of marketpurchasesoneithersideofIdahoPower’s system.The Gateway West project was included in portfoliosforthesecond10-year period when current constraints required the addition of new transmissioncapacityforresourcestobeaddedinsouthernIdaho,east of the Treasure Valley load center.However,the amount of Gateway West capacity is different in each portfolio,depending on other includedresources.
Idaho Power faces increasing demands for transmission capacity in the coming decade.Additionalrequirementsincludetheforecastgrowthofexistingnetworkcustomers,including Bonneville PowerAdministration’s (BPA)southern Idaho contracts.The development of wind and other renewableresourcesinresponsetostateRPSrequirementsisanticipatedtofurtherincreasethedemandfortransmissioncapacitybetweentheIntermountainRegionandthePacificNorthwest.
The concept of “right sizing”a transmission project,or building the project to an appropriate potential,has been carefully considered.There are many factors involved in the decision process prior toproposingasolutiontotheidentifiedrequirements,including planning horizon perspectives.The Boardman to Hemingway and Gateway West projects have been designed to appropriately size thetransmissionlineandallowphasedconstructiontomeetIdahoPower’s needs as well as satisfy requestsfromthirdpartiesforcapacityonthesamepath.A more detailed description of each project is presentedinthefollowingsections.
Boardman to Hemingway
The proposed Boardman to Hemingway project involves constructing,operating,and maintaining anew,single-circuit,500-kV transmission line approximately 300 miles in length.The proposed route isbetweennortheastOregonandsouthwestIdaho.The new line will provide many benefits,including1)greater access to the Pacific Northwest electric market to serve homes,farms,and businesses inIdahoPower’s service area;2)improved system reliability and reduced capacity limitations on thePacificNorthwest’s transmission system as demand for energy continues to grow;and 3)assurance ofIdahoPower’s ability to meet customers’existing and future energy needs in Idaho and Oregon.
The project is expected to be completed and in service in 2016.The overhead,500-kV,high-voltagetransmissionlinewillconnectafuturesubstationnearBoardman,Oregon,to the HemingwaySubstation,located near Melba,Idaho.The proposed transmission line will connect with othertransmissionlinesoneitherendoftheprojecttoconveyelectricityonaregionalscale.Figure 5.1 showsamapoftheregionwiththeproposedrouteofthenewline.
In the 2006 IRP,Idaho Power anticipated the new line would interconnect at the McNary substation;however,there is insufficient room at the existing McNary substation for major transmission expansionoptions.A number of utilities are also considering a northeast Oregon (NEO)substation to providefutureinterconnectivityofregionalprojects.The exact location and in-service date for the NEOsubstationisunknownatthistime.The proposed Boardman to Hemingway project is not dependent oncompletionoftheNEOsubstationprojectoranyoftheothertransmissionproposalstosatisfyIdahoPower’s load-serving need or other existing service requests.
The Boardman to Hemingway project will use a bundled-conductor design capable of a thermalcontinuousratingofabout3,000 MW.However,due to reliability standards and the Western Electricity
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5.Supply-Side Resources Idaho Power Company
Coordinating Council’s (WECC)rating process,the initial implementation of the Boardman to
Hemingway project is likely to result in an Idaho to Northwest path increase of 1,300 MW from
east-to-west (exports into the Pacific Northwest),on completion of the Gateway West Project and about
850 MW from west-to-east (imports into Idaho Power’s balancing authority area).The ratings are
subject to technical peer review and will be revisited as other regional projects continue to develop.
As additional projects reinforce the transmission network,additional capacity rating increases of the
Boardman to Hemingway project may occur.
Figure 5.1 Boardman to Hemingway line project map
The Boardman to Hemingway project capacity or sizing considerations and termination locations were
developed in the public review process conducted by the Northern Tier Transmission Group (NTTG)
and the regional planning phase of the project’s WECC rating process.During the review process,it was
determined a 230-ky project was too small to meet Idaho Power’s overall resource planning needs and
would underuse a substantial and valuable transmission corridor.A project operating voltage of 500 kV
was selected to match the existing Pacific Northwest transmission grid.A 765-ky line designed with a
thermal capacity of approximately 7,000 MW would not achieve a greater rating than the proposed
500-ky project,but would be nearly twice the cost.Because of the higher cost,no further consideration
was given to a 765-ky transmission line.
Idaho Power received more than 4,000 MW of requests to commence transmission service between
2005 and 2014 on the Idaho—Northwest transmission path.Of the 4,000 MW of service requests,
only 133 MW were granted up through 2007 due to the limited available transmission capacity of the
existing system.In the 2006 IRP,Idaho Power identified a need for 225 MW of energy imports from the
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Idaho Power Company 5.Supply-Side Resources
Pacific Northwest to Idaho Power’s system.The 2009 IRP analyzed various levels of imports,and the
final preferred portfolio included 425 MW of capacity on Boardman to Hemingway.The updated
analysis in the 2011 IRP indicates 450 MW of capacity is needed on the line to meet
Idaho Power’s needs.
The Boardman to Hemingway project is important for the development of renewable resources as
northeast Oregon has the potential for both wind and geothermal resource development.In 2007,
Idaho Power and Horizon Wind Energy developed the first phase of the 101-MW Ellchorn Valley Wind
Project in Union County,Oregon,and Idaho Power purchases the output from the facility under a
long-term PPA.Firm transmission capacity existed for the first 66 MW of the wind project.
The remaining 34 MW of output from the Elkhorn project may face curtailment during times of
transmission congestion.Further renewable resource development in northeast Oregon will require
additional transmission resources.
Idaho Power is committed to working with communities to identify proposed and alternate routes for the
Boardman to Hemingway project.The initial process of identifying a route began in late 2007 when
Idaho Power submitted documents to the Bureau of Land Management (BLM),the US Forest Service
(USFS),and the Oregon Department of Energy (ODOE).
Following public scoping meetings held in October 2008,the agencies received public input requesting
Idaho Power conduct more extensive outreach as part of identifying a route for the new transmission
line.In response,Idaho Power initiated the Community Advisory Process (CAP)to engage communities
from Boardman,Oregon to Melba,Idaho in siting the Boardman to Hemingway project.The CAP
enlisted project advisory team members in five geographic regions within the project area.The members
were familiar with the local areas and issues and understand the topography,recreation,wildlife,
and view-shed issues;they collaboratively worked with Idaho Power to identify and recommend
potential line routes.Idaho Power has been working with communities in the CAP since spring 2009.
The CAP process was completed in July 2010;however,Idaho Power continues to meet with
landowners and work with local communities as the project moves forward through the local-,state-,
and federal-review processes.
Additional information about the Boardman to Hemingway project can be found at
http://www.boardmantohemingway.com.
Updated Cost Estimate
The 2011 IRP contains an updated cost estimate for the Boardman to Hemingway line.Idaho Power
worked with two primary contractors,Pike Energy Solutions and Tetra Tech EC,Inc.,to prepare the
updated estimate.The new estimate also updates Idaho Power’s internal costs in addition to the
estimates provided by Pike Energy Solutions and Tetra Tech EC,Inc.As a result of the analysis,
the updated cost estimate increased from the 2009 IRP estimate of $634 million to $820 million.
Pike Energy Solutions provided the line and stations engineering and construction costs for the project
and Tetra Tech EC,Inc.provided the environmental permitting and mitigation cost estimates for the
project.In addition,Idaho Power included estimated costs for internal labor hours,right-of-way
overheads,property taxes,allowance for funds used during construction (AFUDC),and contingency
estimates in support of the entire project.The detailed estimate included in Appendix C—Technical
Appendix shows the combination of third-party cost estimates provided by Pike Engineering Solutions,
Tetra Tech EC,Inc.,and estimates for Idaho Power’s internal costs.
The updated costs show significant increases in material prices and construction costs,primarily due to
increased material and labor prices and line-route modifications to move the routing away from
agricultural land.The AFUDC estimate has also increased due to a projected rate increase of 5 percent
2011 IRP Page 53
5.Supply-Side Resources Idaho Power Company
to 7.5 percent.Property taxes were not included in the 2009 IRP estimate and have now been included in
the updated estimate.
For the 2011 IRP,the contingency estimate has been reduced from 30 percent to 20 percent because of
the higher level ofproject definition and detail and increased level of confidence in the line location and
the engineering and design aspects of the project.The contingency estimate is consistent with
Idaho Power’s estimating practices and industry standards for contingency estimating.The updated cost
estimate does not include any estimated impacts of future inflation that may occur following the date of
the estimate;however,the IRP analysis assumes a general inflation rate of 3 percent,which is applied
consistently to all resources.
The results of the 2011 IRP analysis indicate the Boardman to Hemingway transmission line will be a
well-used resource that benefits Idaho Power’s retail and transmission customers,as well as consumers
and generators in both the Pacific Northwest and the Intermountain Region.The capital cost of the
Boardman to Hemingway project,as measured on a dollars-per-kW-of-capacity basis,has the lowest
capital cost of any supply-side resource alternative.
Gateway West
The Gateway West transmission line project is a joint project between Idaho Power and
Rocky Mountain Power to build and operate approximately 1,150 miles of new transmission lines from
the planned Windstar substation near Glenrock,Wyoming to the Hemingway substation near
Melba,Idaho.The project is being designed so multiple construction phases can provide transmission
segments as needs materialize.Some segments of the Gateway West project are planned to be in service
in the 2015—2017 timeframe.Numerous routes under consideration are shown in Figure 5.2.
The two transmission projects,Boardman to Hemingway and Gateway West,are complementary and
will provide an upgraded transmission path from the Pacific Northwest across Idaho and into eastern
Wyoming with an additional transmission connection to the population center along the Wasatch Front
in Utah through Rocky Mountain Power’s Gateway South project.
Significant renewable resource development potential exists in Wyoming and southern and eastern
Idaho.Idaho Power’s transmission system is currently limited in its ability to transmit energy from new
resources from the east to the major load centers in Idaho.Gateway West will provide new transmission
capacity to integrate and deliver any such selected resources in addition to meeting third-party
transmission service requests under Idaho Power’s OATT.
The Gateway West project is currently undergoing an extensive and ongoing public involvement process
to identify proposed and alternate routes.The outreach work is being done in conjunction with the
NEPA process related to environmental studies,as well as local jurisdictions for permitting.The project
as proposed in Idaho includes two separate 500-ky lines between the Populus substation in southeast
Idaho,and the Hemingway Substation in southwestern Idaho,with connection in central Idaho between
the Midpoint Substation and the proposed Cedar Hill substation.
Phase 1 is expected to provide between 700 MW and 1,500 MW of additional transfer capacity across
Idaho.The fully completed project would provide a total of 3,000 MW of additional transfer capacity.
Similarly,the project extending east from the Populus substation into eastern Wyoming is expected to
provide Phase 1 capacity improvements of approximately 700 to 1,500 MW,with the full build-out
capacity increase being greater than 2,000 MW east of Jim Bridger and 3,000 MW between the
Populus substation and Jim Bridger.
The project cost and capacity is expected to be shared between Idaho Power and Rocky Mountain Power
based on load service requirements and third-party transmission service request obligations.Additional
information about the Gateway West project can be found at www.gatewaywestproject.com.
Page 54 2011 IRP
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Page 56 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
6.PLANNING PERIOD FORECASTS
The IRP process requires Idaho Power prepare
numerous forecasts that can be grouped into
four main categories,1)load forecasts,
2)a generation forecast,3)fuel price forecasts,
and 4)fmancial assumptions.The load and
generation forecasts—including supply-side
resources,DSM,and transmission import
capability—are used to estimate surplus and deficit
positions in the load and resource balance.
The identified deficits are used to develop resource
portfolios evaluated using financial tools and
forecasts.The following sections provide details on
the forecasts prepared as part of the 2011 IRP.
Load Forecast
Historically,Idaho Power has been a summer peaking utility with peak loads driven by irrigation pumpsandairconditioninginthemonthsofJune,July,and August.For a number of years,the growth rate ofpeak-hour load has exceeded the growth of average monthly load.However,both measures areimportantinplanningforfutureresourcesandarepartoftheloadforecastpreparedforthe2011 LRP.
The expected-case (median)load forecasts for peak-hour and average energy represent Idaho Power’smostprobableoutcomeforloadgrowthduringtheplanningperiod.However,the actual path of futureelectricitysaleswillnotpreciselyfollowthepathsuggestedbytheexpected-case forecast.Therefore,Idaho Power prepared four additional load forecasts,two that provide a range of possible load growthsduetoeconomicuncertainty,and two that address the load variability associated with abnormal weather.
The high-growth and low-growth scenarios provide boundaries on each side of the expected-caseforecastandhistoricalloadvariabilitypotentialonfutureloadduetodemographic,economic,and othernon-weather-related influences.The 70th percentile and 90th percentile load forecast scenarios weredevelopedtoassistIdahoPower’s review of the resource requirements that would result from higherloadsduetoadverseweatherconditions.
Idaho Power prepares a sales and load forecast each year as part of the company’s annual financialforecast.The economic forecast is based on a forecast of national and regional economic activitydevelopedbyMoody’s Analytics,Inc.,a national econometric consulting firm.Moody’s Analytics,
Highlights
Idaho Power’s summer peak load record of 3,214 MW was set in June 2008.
Idaho Power’s customers set a new winter system peak record of 2,528 MW onDecember10,2009,during several days of below-normal temperatures.
The 2011 IRP assumes an expected-case carbon adder of $20 per ton starting in 2015.
For the first time,the IRP load forecast includes the expected impact of electric vehicles.
The 2011 IRP average system load forecast is lower than the 2009 IRP average systemloadforecastinallyearsoftheforecastperiod.
Forecasting load growth is essential for Idaho Power
to meet the future needs of customers.
2011 IRP Page 57
6.Planning Period Forecasts Idaho Power Company
Inc.’s July 2010 macroeconomic forecast strongly influenced the 2011 IRP load forecast.The national,
state,metropolitan statistical area (MSA),and county econometric projections are tailored to
Idaho Power’s service area using an economic database developed by an outside consultant.
Specific demographic projections are also developed for the service area from national and local census
data.National economic drivers from Moody’s Analytics,Inc.,are also used in developing the 2011 JRP
load forecast.The forecast of the number of households,employment projections,and retail electricity
prices,along with historical customer consumption patterns,are used to develop customer forecasts and
load projections.
Weather Impacts
The expected-case load forecast assumes median temperatures and median precipitation,which means
there is a 50 percent chance that loads will be higher or lower than the expected-case load forecast due
to colder-than-median or hotter-than-median temperatures and wetter-than-median or drier-than-median
precipitation.Since actual loads can vary significantly depending on weather conditions,two alternative
scenarios are analyzed to address load variability due to weather.Idaho Power has generated load
forecasts for 70th percentile and 90th percentile weather.Seventieth percentile weather means that,
in 7 out of 10 years,load is expected to be less than forecast and,in 3 out of 10 years,load is expected to
exceed the forecast.Ninetieth percentile load has a similar definition with a 1 in 10 likelihood that the
load will be greater than the forecast.
Idaho Power’s system load is highly dependent on weather.The three scenarios allow careful
examination of load variability and how the load variability may impact resource requirements.It is
important to understand how the probabilities associated with the load forecasts apply to any given
month.For example,an extreme month may not necessarily be followed by another extreme month.
In fact,a typical year likely contains some extreme months as well as some mild months.
Weather conditions are the primary factor affecting the load forecast on the hourly,daily,weekly,
monthly,and seasonal time horizon.Economic and demographic conditions affect the load forecast over
the long-term time horizon.
Economic Impacts
The national recession that began in 2008 underscores the effects of the national and local economy on
energy use in Idaho Power’s service area.The severity of the recession resulted in a collapse in new
residential customer growth from the addition of 15,000 new residential customers each year prior to the
recession,to approximately 2,000 new customers added each year at the present.Commercial and
industrial customer energy use contracted and overall system energy use declined by 3.5 percent in
2009,followed by a 1.2 percent decline in 2010—the first time overall energy use has declined since the
energy crisis of 2001.
Increased population in Idaho Power’s service area—due to migration to Idaho from other states—
is expected to continue throughout the planning period and has been included in the load forecast model.
Idaho Power also continues to receive requests from prospective new large-load customers attracted to
southern Idaho due to the relatively low electric rates.In addition,the economic conditions in
surrounding states may encourage some manufacturers to consider moving operations to Idaho.
The number of households in Idaho is projected to grow at an annual average rate of 1.2 percent during
the 20-year forecast period.Growth in the number ofhouseholds within individual counties in
Idaho Power’s service area differs from statewide household growth patterns.Service area household
projections are derived from individual,county-specific household forecasts.Growth in the number of
households within Idaho Power’s service area,combined with estimated consumption per household and
considerations made for DSM measures,results in a 1.5-percent residential load growth rate.
Page 58 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
The number of residential customers in Idaho Power’s service area is expected to increase 1.4 percentannuallyfromapproximately409,000 at the end of 2010 to nearly 536,000 by the end of the planningperiodin2030.
The expected-case load forecast represents the most probable projection of load growth during theplanningperiod.The forecast for system load growth is determined by summing the load forecasts forindividualclassesofservice,as described in Appendix A—Sales andLoad Forecast.For example,the expected annual average system load growth of 1.4 percent (over the period 2011 through 2030)is comprised of residential load growth of 1.5 percent,commercial load growth of 1.3 percent,irrigation load growth of 0.3 percent,industrial load growth of 1.7 percent,and additional finn loadgrowthof2.0 percent.
The 2011 IRP average system load forecast is lower than the 2009 IRP average system load forecast inallyearsoftheforecastperiod.The slowdown in the national and service-area economy caused loadgrowthtoslowsignificantly.In addition,the significant increase in assumed DSM combined with retailelectricitypriceassumptionsthatincorporateestimatesofassumedcarbonlegislationservetodecreasetheforecastofaverageloads.Significant factors and considerations that influenced the outcome of the2011IRPloadforecastincludethefollowing:
The electricity price forecast used to prepare the sales and load forecast in the 2009 JR.P reflectedthefixedandvariablecostsofintegratingtheresourcesidentifiedinthe2006IRPpreferredportfolio,including the expected costs of carbon emissions.When compared to the electricitypriceforecastusedtopreparethe2011IRPsalesandloadforecast,the 2009 IRP price forecastyieldedsignificantlyhigherfutureprices.The price forecast difference is primarily the result ofdifferingcarboncostassumptionsbetweenthetwoforecasts.The 2009 IRP retail electricitypriceforecastassumedacarbontaxscenario(from the 2006 IRP)and the 2011 IRP electricitypriceforecastassumedacap-and-trade carbon scenario (from the 2009 IRP).Under thecap-and-trade carbon scenario in the 2009 IRP,Idaho Power curtailed coal resources to complywithtargetemissionslevels.
•The sales and load forecast reflects the increased expected demand for energy and peak capacityofIdahoPower’s newest special-contract customer,Hoku Materials,located in Pocatello,Idaho.At the time this forecast was completed (August 2010),Hoku Materials was planning to beginoperationinJanuary2011andreachfullcapacitybyApril2011.The IRP sales and load forecastassumesthatHokuMaterialswillconsume74aMWofenergyeachyearandhaveapeakdemandof82MW(each measure excluding line losses)once continuous operation is reachedin2013.
•The load forecast used for the 2011 IRP reflects a recovery in the service-area economyfollowingasevererecessionin2008and2009,as well as a much smaller impact of carbonregulationonfutureenergyrateschargedtoIdahoPowercustomers.The collapse in the housingsectorin2008and2009dramaticallyslowedthegrowthinthenumberofnewhouseholdsandresidentialcustomersbeingaddedtoIdahoPower’s service area.In addition,the number ofcommercialcustomersbeingaddedalsosloweddramaticallyasaresultoftheeconomicdownturn.However,by 2012,residential and commercial customer growth is expected to slowlyrecover;by 2015,customer additions are forecast to approach the growth that occurred prior tothehousingbubble(2000—2004).The cost of carbon impact on the 2011 IRP load forecast wasnotmaterialbecauseofthecap-and-trade assumption used in the 2009 IRP,which was the basisforcarboncostsinthe2011IRPloadforecast.
•In this year’s forecast,an additional customer referred to as “Special”was included in theadditionalfirmloadcategoryeventhoughalong-term contract had not yet been fully executed.
2011 IRP Page 59
6.Planning Period Forecasts Idaho Power Company
At the time this forecast was prepared (August 2010),several interested parties had taken
significant steps toward the ultimate development and location oftheir businesses within
Idaho Power’s service area.It was determined that the real possibility of the new large load was
significant enough for it to be imprudent ofthe company to ignore the possible impact.
The anticipated load of the new “Special”contract has been included in this forecast based on
discussions with the interested parties.The existing special contracts and the new “Special”
contract together make up the additional firm load category.
•There continues to be significant uncertainty associated with the industrial and special contract
sales forecasts.The forecast uncertainty is due to the number ofparties that contact Idaho Power
and express interest in locating production operations within Idaho Power’s service area and the
unknown magnitude of the energy and peak demand requirements.The current sales and load
forecast reflects only those customers that have a high probability of locating in the service area
or have made financial commitments and whose facilities are actually being constructed at this
time.Therefore,the large numbers of businesses that have contacted Idaho Power and shown
interest,but have not made commitments,are not included in the current sales and load forecast.
•In another improvement to this year’s forecast,Idaho Power used Itron,Inc.’s residential
Statistically Adjusted End-Use (SAE)model to prepare the long-term residential sales forecast.
Recently,many utilities have adopted Itron,Inc.’s SAE modeling approach to include greater
end-use information into the forecast process.
•Existing energy efficiency program performance is estimated and included in the sales and load
forecast base,lowering the energy and peak demand forecast.However,the impact of demand
response programs is accounted for in the load and resource balance.The amount of committed
and implemented DSM programs for each month of the planning period is shown in the load and
resource balance in Appendix C—Technical Appendix.
•A somewhat higher irrigation sales forecast compared to earlier forecasts (prior to 2009 IRP)
due to a substantial increase in weather-adjusted irrigation sales in 2007 and 2008 (6%in 2007
and 8%in 2008).High commodity prices appear to be the primary reason behind the irrigation
sales increase.Farmers have taken advantage of the commodities market by planting all available
acreage.In addition,the conversion of hand-lines to electrically operated pivots may explain a
part of the increased energy consumption.In recent years,the increased labor costs associated
with moving hand-lines has triggered the substitution of labor with electrically operated pivots.
Peak-Hour Load Forecast
The system peak-hour load forecast includes the sum of the individual coincident peak demands of
residential,commercial,industrial,and irrigation customers,as well as special contracts (including
Astaris historically)and the Raft River Rural Electric Cooperative wholesale agreement.Idaho Power
uses the 95th percentile forecast as the basis for peak-hour planning in the IRP.The 95th percentile
forecast is based on 95 percentile average peak-day temperatures to forecast monthly peak-hour load.
Idaho Power’s system peak-hour load record,3,214 MW,was recorded on Monday,June 30,2008,
at 3:00 p.m.The previous year’s summer peak demand was 3,193 MW and occurred on Friday,
July 13,2007,at 4:00 p.m.Summertime peak-hour load growth accelerated in the previous decade as air
conditioning became standard in nearly all new residential home construction and new commercial
buildings.The growth in peak demand slowed considerably in 2008 and 2009 due to a severe recession
that brought new home and new business construction to a standstill.Demand response programs
operating in the summertime have also served to reduce peak demand.The 2011 IRP load forecast
projects peak-hour load to grow by approximately 69 MW per year throughout the planning period.
Page 60 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
The peak-hour load forecast does not reflect the company’s demand response programs,which are
accounted for in the load and resource balance.
Figure 6.1 and Table 6.1 summarize three forecast outcomes of Idaho Power’s estimate of annual system
peak load considering median,90th percentile,and 95th percentile weather impacts on the expected
(median)peak forecast.The 95th percentile forecast uses the 95th percentile peak-day average
temperature to determine monthly peak-hour demand.The planning criteria for determining the need for
peak-hour capacity assumes the 95th percentile peak-day temperature conditions.
5,200
4,800
4,400
4,000
3,600
3,200
2,800
2,400
2,000
1,600 .‘
1,200
Figure 6.1 Peak-hour load growth forecast (MW)
Table 6.1 Load forecast—peak-hour (MW)
Year
2010 (Actual)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Growth Rate (2011—2030)
Median 90th Percentile
2,930 2,930
3,334 3,494
3,392 3,555
3,496 3,662
3,577 3,747
3,657 3,831
3,725 3,902
3,787 3,967
3,847 4,031
3,911 4,098
3,973 4,164
4,034 4,229
4,098 4,296
4,165 4,367
4,229 4,435
4,291 4,501
4,358 4,571
4,419 4,635
4,498 4,718
4,569 4,792
4,643 4,870
1.8%1.8%
95th Percentile
2,930
3,515
3,577
3,684
3,770
3,854
3,925
3,991
4,056
4,123
4,190
4,254
4,323
4,394
4,462
4,529
4,599
4,664
4,747
4,822
4,901
1.8%
1975 1980 1985 1990 1995 2000
Actual less Astaris —Actual —50th Percentile —90th Percentile
2005 2010 2015 2020 2025 2030
95th Percentile
2011 IRP Page 61
6.Planning Period Forecasts Idaho Power Company
The median or expected-case peak-hour load forecast predicts peak-hour load will grow from 3,334 MW
in 2011 to 4,643 MW in 2030,an average annual compound growth rate of 1.8 percent.The projected
average annual compound growth rate of the 95th percentile peak forecast is 1.8 percent.In the
95th percentile forecast,summer peak-hour load is expected to increase from 3,515 MW in 2011 to
4,901 MW in 2030.Historical peak-hour loads as well as the three forecast scenarios are shown in
Figure 6.1.
Idaho Power’s winter peak-hour load record was 2,528 MW,recorded on Thursday,December 10,2009,
at 8:00 a.m.Historical winter peak-hour load is much more variable than summertime peak-hour load.
The winter peak variability is due to the variability ofpeak day temperatures in winter months,which is
far greater than the variability of peak-thy temperatures in summer months.
Average-Energy Load Forecast
Potential monthly average energy use by customers in Idaho Power’s service area is defined by a series
of four load forecasts that reflect a range of load uncertainty resulting from differing economic growth
and weather-related assumptions.Figure 6.2 and Table 6.2 show the results of the four forecasts used in
the 2011 IRP to estimate the boundaries of annual system load growth over the planning period.There is
approximately a 90-percent probability that Idaho Power’s load growth will exceed the low-load growth
forecast,a 50-percent probability of load growth exceeding the expected-case forecast,a 30-percent
probability of load growth exceeding the 70th percentile forecast,and approximately a 10-percent
probability that load growth will exceed the high-growth forecast.The projected 20-year average annual
compound growth rate in the expected-load forecast is 1.4 percent.
2,800
2,500 --__________
____________________________________________________
2,200
1,900
1,600
1,300
1,000
700
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
WA less Astaris —Weather Adjusted Expected Case 70th Percentile —90th Percentile
Figure 6.2 Average monthly load growth forecast (aMW)
Page 62 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
Table 6.2 Load forecast—average monthly energy (aMW)
Year Median 7oth Percentile Low High
2011 1,819 1,860 1,793 1,878
2012 1,852 1,893 1,814 1,936
2013 1,890 1,931 1,836 1,987
2014 1,932 1,974 1,866 2,043
2015 1,970 2,013 1,894 2,094
2016 1,998 2,042 1,913 2,135
2017 2,023 2,067 1,927 2,170
2018 2,045 2,090 1,940 2,203
2019 2,070 2,115 1,956 2,238
2020 2,090 2,136 1,970 2,271
2021 2,114 2,160 1,983 2,303
2022 2,139 2,186 2,000 2,338
2023 2,166 2,214 2,019 2,375
2024 2,189 2,237 2,036 2,410
2025 2,214 2,263 2,051 2,443
2026 2,241 2,290 2,070 2,480
2027 2,263 2,313 2,084 2,511
2028 2,298 2,349 2,113 2,560
2029 2,329 2,380 2,133 2,598
2030 2,362 2,414 2,158 2,642
Growth Rate (2011—2030)1.4%1.4%1.0%1.8%
Idaho Power uses the 70th percentile forecast as the basis for monthly average energy planning in
the IRP.The 70th percentile forecast is based on 70thi percentile weather to forecast average monthly
load,70t1 percentile water to forecast hydroelectric generation,and 95t1 percentile average peak-day
temperature to forecast monthly peak-hour load.
Additional Firm Load
The additional firm load category consists of Idaho Power’s largest customers.Idaho Power’s tariff
requires the company serve requests for electric service greater than 20 MW under a special-contract
schedule negotiated between Idaho Power and each individual,large-power customer.The contract
and tariff schedule are then approved by the appropriate commission.A special contract allows for
customer-specific cost-of-service analysis and consideration of unique operating characteristics to be
accounted for in the agreement.
A special contract also allows Idaho Power to provide requested service consistent with system
capability and reliability.Idaho Power currently has four special-contract customers recognized as
firm-load customers.These special-contract customers are Micron Technology,Simplot Fertilizer,INL,
and Hoku Materials.In addition,the company has a term sales contract with Raft River Rural Electric
Cooperative.Raft River is not required to meet the 20-MW electric service minimum.
It is difficult to predict when a new special-contract customer will begin taking service from
Idaho Power.However,because of the magnitude of their load and subsequent impact on system
resources,it is important to anticipate such load if a customer of that size is considered imminent.In this
year’s forecast,the company has included the anticipated load of an additional special-contract customer
referred to as “Special”in the additional firm load category even though a long-term special contract had
2011 IRP Page 63
6.Planning Period Forecasts Idaho Power Company
not yet been fully executed.At the time this forecast was prepared (August 2010),several interested
parties had taken significant steps toward the ultimate development and location of their businesses
within Idaho Power’s service area.It was determined that the real possibility of the new large load was
significant enough that it would be imprudent of the company to ignore the possible impact.
The anticipated load of the new “Special”contract has been included in this forecast based on
discussions with the interested parties.The existing special-contract customers and the new “Special”
contract together make up the additional firm-load category.
Micron Technology
Micron Technology is currently Idaho Power’s largest individual customer and employs approximately
5,000 workers in the Boise MSA.Electricity sales to Micron Technology moved considerably
downward in 2009 and 2010 as Micron phased out its 200-millimeter (mm)dynamic random access
memory (DRAM)operations at its Boise facility.The company continues to operate its 300-mm
research and development fabrication facility in Boise and performs a variety of other activities,
including product design and support,quality assurance,systems integration and related manufacturing,
corporate,and general services.Once establishing a new floor for energy consumption at the facility at
about a quarter less energy use than in recent years,Micron Technology’s electricity use is expected to
increase based on the market demand for their products.
Simplot Fertilizer
The Simplot Fertilizer plant is the largest producer ofphosphate fertilizer in the western United States.
The future electricity usage at the plant is expected to grow at a slow pace throughout the planning
period (20 11—2030).The primary driver of long-term electricity sales growth at Simplot Fertilizer is
Moody’s Analytics,Inc.,forecast of gross product in the pesticide,fertilizer,and other agricultural
chemical manufacturing segment for the Pocatello MSA.
Hoku Materials
The sales and load forecast reflects the increased expected demand for energy and peak capacity of
Idaho Power’s newest special-contract customer,Hoku Materials,located in Pocatello,Idaho.At the
time this forecast was completed (August 2010)Hoku Materials was planning to begin operation in
January 2011 and reach full capacity by April 2011.The IRP sales and load forecast assumes that
Hoku Materials will consume 74 aMW of energy each year and have a peak demand of 82 MW
(each measure excluding line losses)once continuous operation is reached in 2013.In the time since the
IRP load forecast was prepared,Hoku Materials has delayed the ramp up of its operations;however,
this delay is not expected to impact the results of the 2011 IRP.
“Special”Contract
In this year’s forecast,an additional customer referred to in this document as “Special”was included in
the additional firm-load category even though a long-term contract had not yet been fully executed.
At the time this forecast was prepared (August 2010),several interested parties had taken significant
steps toward the ultimate development and location of their businesses within the Idaho Power service
area.It was determined that the real possibility of the new large load was significant enough that it
would be imprudent of the company to ignore the possible impact.
Planning Scenarios
The timing and necessity of future generation resources are based on a 20-year forecast of surpluses and
deficits for monthly average load (energy)and peak-hour load.For both of these areas,one set of criteria
has been chosen for planning purposes;however,additional scenarios have been analyzed to provide
a comparison.
Page64 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
Table 6.3 provides a summary of the six planning scenarios analyzed for the 2011 LRP,and the criteria
used for planning purposes are shown in bold.Median water and median load forecast scenarios were
included to enable comparison of the 2011 IRP with plans developed during the 1990s.The median
forecast is no longer used for resource planning,although the median forecast is used to set retail rates
and avoided cost rates during regulatory proceedings.The planning criteria used to prepare
Idaho Power’s 2011 IRP are consistent with the criteria used in the 2009 IRP.
Table 6.3 Planning criteria for average monthly and peak-hour load
Average monthly load/energy (aMW)50th Percentile Water,5011)Percentile Average Load
70th Percentile Water,70t)Percentile Average Load
90th Percentile Water,Percentile Average Load
Peak-hour load (MW)50th Percentile Water,90hI Percentile Peak-Hour Load
70th Percentile Water,95th Percentile Peak-Hour Load
90th Percentile Water,9511)Percentile Peak-Hour Load
The planning criteria used for energy or average load are 70th percentile water and 70th percentile
average load.In addition,50th percentile water and 50th percentile average load conditions are analyzed
to represent a median condition,and 90th percentile water and 70th percentile average load are analyzed
to examine the effects of low water conditions.
Peak-hour load planning criteria consist of 90t1 percentile water and 95t1 percentile peak-hour load
conditions,coupled with Idaho Power’s ability to import additional energy on its transmission system.
A median condition of 50th percentile water and 50t1 percentile peak-hour load are also analyzed,as well
as 70th percentile water and 95th percentile peak-hour load.Peak-hour load planning criteria are more
stringent than average load planning criteria because Idaho Power’s ability to import additional energy is
typically limited during peak-hour load periods.Surpluses and deficits for the average and peak-hour
load scenarios can be found in Appendix C—Technical Appendix.
Existing Resources
To identify the need and timing of future
resources,Idaho Power prepares a load and
resource balance,which accounts for forecast
load growth and generation from all of the
company’s existing resources and planned
purchases.Updated load and resource balance
worksheets showing Idaho Power’s existing and
committed resources for average energy and
peak-hour load are shown in Appendix C—
Technical Appendix.The following sections
describe recent events or changes accounted for
in the load and resource balance regarding
Idaho Power’s hydroelectric,thermal,
and transmission resources.
Hydroelectric Resources
For the 2011 IRP,Idaho Power continues the practice of using 70th percentile streamfiow conditions for
the Snake River Basin as the basis for the projections of monthly average hydroelectric generation.
The 70th percentile means that basin streamfiows are expected to exceed the planning criteria 70 percent
of the time and are expected to be worse than the planning criteria 30 percent of the time.
Brownlee Dam is part of the Hells Canyon Complex.
2011 IRP Page 65
6.Planning Period Forecasts Idaho Power Company
Likewise,for peak-hour resource adequacy,Idaho Power continues to assume 90th percentile streamfiow
conditions to project peak-hour hydroelectric generation.The 90th percentile means that streamfiows are
expected to exceed the planning criteria 90 percent of the time and to be worse than the planning criteria
only 10 percent of the time.
The practice of basing hydroelectric generation forecasts on worse than median streamfiow conditions
was initially adopted in the 2002 IRP in response to suggestions that Idaho Power use more conservative
water planning criteria as a method of encouraging the acquisition of sufficient firm resources to reduce
reliance on market purchases.However,Idaho Power continues to prepare hydroelectric generation
forecasts for 50th percentile (median)streamfiow conditions because the median streamfiow condition is
still used for rate-setting purposes and other analyses.
The 50th,70th,and 90th percentile streamfiow forecasts used in the IRP are derived from a streamfiow
planning model developed by the Idaho Department of Water Resources (IDWR).The IDWR
streamfiow planning model is used by Idaho Power to produce a normalized hydrologic record for the
Snake River Basin from 1928 through 2009.The normalized model accounts for current hydroelectric
conditions and historical hydroelectric development with regard to groundwater discharge to the river,
water management facilities,irrigation facilities,and operations.
Prior to the 2009 IRP,Idaho Power assumed the representative streamfiow conditions calculated from
the normalized record were static through the IRP planning period.For example,the practice was to
assume that a 70th percentile year in 2010 is identical to a 70th percentile year in 2015.A review of
Snake River Basin streamfiow trends suggests that persistent decline documented in the ESPA is
mirrored by downward trends in total surface water outflow from the river basin.The ESPA CAMP
includes demand reduction and weather modification measures that will add new water to the basin
water budget.However,Idaho Power hydrologists believe the positive effect of the new water associated
with the CAMP measures is likely to be temporary,and,over time,the water-use practices driving the
steady decline over recent years is expected to resume and result in a return to declining basin outflows
that is assumed to persist through at least the first 10 years of the 2011 IRP planning horizon.The
declining basin outflows for this IRP are assumed to continue through 2023,with no further decline
assumed for the remainder of the planning period through 2030.The expected year-to-year decline in
annual hydroelectric generation is less than 0.5 percent.Idaho Power plans to revisit assumptions on the
projected date at which basin hydrologic conditions equilibrate as a standard part of forecasting
hydroelectric generation for future IRPs.
River temperature is an important concern that can affect the timing of Snake River streamfiows.
Various federal agencies involved in salmon migration studies continue to support efforts to shift
delivery of flow augmentation water from the Upper Snake River and Boise River basins from the
traditional months of July and August to the spring months of April,May,and June.The objective of the
streamfiow augmentation is to more closely mimic the timing of the naturally occurring flow conditions.
Reported biological opinions indicate the shift in water delivery is most likely to take place during
worse-than-median water years.
Because worse-than-median water is assumed in the IRP,and the importance of July as a
resource-constrained month,Idaho Power incorporated the shifted delivery of flow augmentation water
from the Upper Snake River and Boise River basins for the 2009 IRP and continues to incorporate the
modified flow augmentation for the 2011 IRP.Augmentation water delivered from the Payette River
Basin is assumed to remain in July and August.Based on resource planning analyses,monthly average
hydroelectric generation for July under the 70th percentile streamfiow condition is projected to decline
by approximately 115 aMW as a result of the water being shifted out of the month of July.
Page 66 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
Monthly average generation for Idaho Power’s hydroelectric resources is calculated with a generation
model developed internally by Idaho Power.The generation model treats the projects upstream of the
Hells Canyon Complex as run-of-river plants.The generation model mathematically manages reservoir
storage in the Hells Canyon Complex to meet the remaining system load,while adhering to the
operating constraints on the level of Browrilee Reservoir and outflows from the Hells Canyon project.
For peak-hour analysis,a review of historical operations was performed to yield relationships between
monthly energy production and achieved one-hour peak generation.The projected peak-hour capabilities
for the IRP were derived to be consistent with the observed relationships.
A representative measure of the streamfiow condition for any given year is the volume of inflow to
Brownlee Reservoir during the April—July runoff period.Figure 6.3 shows historical April—July
Brownlee inflow as well as forecast Brownlee inflow for the 50th,70th,and 90th percentiles.
The historical record demonstrates the variability of inflows to Brownlee Reservoir.The forecast
inflows do not reflect the historical variability,but do include reductions related to declining base flows
in the Snake River.As noted previously in this section of the report,these declines are assumed to
equilibrate beyond 2023.
13 -
12 ——--_____—-----—--—----—---------—________
11 —_________
10 -————-————-----.-—————————————-
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6
5
4 —--——-—-----
3 -
2
1-
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1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
—50th Percentile —70th Percentile 90th Percentile HistoiicaI
Figure 6.3 Brownlee historical and forecast inflows
Idaho Power recognizes the need to remain apprised of scientific advancements concerning climate
change on the regional and global scale.Idaho Power believes there is too much uncertainty to predict
the scale and timing of hydrologic effects due to climate change.Therefore,no adjustments related to
climate change have been made in the 2011 IRP.
Coal Resources
Idaho Power’s coal-fired generating facilities have operated typically as fully dispatched baseload
resources.Monthly average-energy forecasts for the coal-fired projects are based on typical baseload
output levels,with seasonal reductions occurring primarily during spring months for scheduled
maintenance activities.Idaho Power schedules periodic maintenance to coincide with periods of high
hydroelectric generation,seasonally low-market prices,and moderate customer load.With respect to
peak-hour output,the coal-fired projects are forecast to generate at the full-rated,maximum dependable
2011 IRP Page 67
6.Planning Period Forecasts Idaho Power Company
capacity,minus 6 percent to account for forced outages.A summary of the expected coal price forecast
is included in Appendix C—Technical Appendix.
Plant modifications required to maintain compliance with air-quality standards are projected for the
Boardman plant in 2011,2014,and 2018,and for the Jim Bridger plant in 2015,2016,2021,and 2022.
The total effect of the air-quality modifications is a reduction in coal-fired generation of less than
1 percent.
The 2011 LRP assumes Idaho Power’s share of the Boardman plant will not be available after
December 31,2020.The estimated date is the result of an agreement reached between the ODEQ and
PGE,related to compliance with RH BART rules on particulate matter,SO2,and NO emissions.Both
ODEQ and PGE are waiting for formal approval from the EPA.
Planned Upgrades at Jim Bridger
Turbine upgrades are continuing at the Jim Bridger plant with the replacement of the high-pressure!
intermediate-pressure turbine on unit 2 planned for 2013.The high-pressure/intermediate-pressure
turbine on unit 1 was upgraded in 2010.Upgrades of the high-pressure/intermediate-pressure turbines on
units 3 and 4 and upgrades to the low-pressure turbines on all four units are currently being evaluated.
Natural Gas Resources
Idaho Power owns and operates four natural gas-fired SCCTs.These resources are typically operated
during high-load occurrences in summer and winter months.The monthly average energy forecast for
the SCCTs is based on the assumption that the generators are operated at full capacity for heavy-load
hours during the months of January,June,July,August,and December,producing on average
approximately 230 aMW of gas-fired generation for the selected months.With respect to peak-hour
output,the SCCTs are assumed capable ofproducing on-demand peak capacity of 416 MW.While this
dispatchable capacity is assumed achievable for all months,it is most critical to system reliability during
summer and winter peak-load months.
Idaho Power is currently constructing the Langley Gulch CCCT,which is expected to be commercially
available in July 2012.Because of its higher efficiency rating,Langley Gulch is expected to be
dispatched more frequently and for longer runtimes than the existing SCCTs.For the 2011 IRP,
Langley Gulch is forecast to contribute 251 aMW of energy per month,with on-demand pealcing
capacity of 300 MW.
Transmission Resources
Transmission capacity limitations are an important factor in Idaho Power’s ability to reliably serve peak-
hour load.Idaho Power uses spot-market purchases when the company’s generating resources and firm
purchases are inadequate to meet peak-hour load requirements,and transmission capacity limitations
restrict Idaho Power’s ability to import additional energy.
From the load and generation forecasts,a determination can be made regarding the need for,and the
magnitude of,the off-system market purchases needed to serve system load.The projected off-system
market purchases are added to all other committed transmission obligations to determine if the
additional imported energy will exceed the operational limits of the transmission system.The analysis
assumes that all off-system market purchases will come from the Pacific Northwest.
During Idaho Power’s peak-hour load periods,off-system market purchases from the east and south
have historically proven to be unavailable or very expensive.Many of the utilities to the east and south
of Idaho Power also experience a summer peak,and the weather conditions that drive Idaho Power’s
summer peak-hour load are often similar across the Intermountain Region.Therefore,Idaho Power does
not typically rely on imports from the Intermountain Region for planning purposes.
Page 68 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
For the 2011 JRP,Idaho Power has restricted its transmission analysis to the scenario assuming90thpercentilestreamfiows,70th percentile load,and 95th percentile peak-hour load.The 95th percentile
peak-hour load planning criterion means that there is a 1-m-20 chance that Idaho Power will be required
to initiate more drastic measures,such as curtailing load,if attempts to acquire energy and transmission
access from the spot market are unsuccessful.
Idaho Power used the results of the transmission analysis to establish a capacity target for planning
purposes.The capacity target identifies the amount of additional generation,demand response programs,
or transmission resources that must be added to Idaho Power’s system to avoid capacity deficits.
On a yearly basis,Idaho Power’s transmission capacity is reserved for the company’s retail customers
based on annual load and resource forecasts.Although transmission resources are owned by
Idaho Power,the unreserved transmission capacity may be purchased by other parties due to FERC’s
open access requirements.Idaho Power must reserve the use of its own transmission system under
FERC’s open access rules.Often,Snake River flow forecasts for the remainder of the year are not
known with a high degree of accuracy until May or June,and late spring is often too late to acquire firm
transmission capacity for the summer months.
Natural Gas Price Forecast
Future natural gas price assumptions significantly influence the financial results of the operational
modeling used to evaluate and rank resource portfolios.The 2011 IRP natural gas price forecast uses
several outside public and private forecast sources to develop a composite future yearly Henry Hub price
curve.The forecast sources include the NPCC,the New York Mercantile Exchange (NYMEX),
the Natural Gas Exchange,the Energy Information Administration (EIA),and Moody’s Analytics,Inc.
The individual annual forecasts from the outside sources are evaluated and weighted to calculate the
composite forecast.The weighting is based on a combination of Idaho Power’s expectation ofprice,
the reasonableness ofthe forecasts when compared with others,and the current forward price of actual
contracts being executed on various exchanges.In the near-term forecast horizon,greater weight is
given to actual commitment contracts being executed on the NYMEX compared to longer-term forecasts
that are weighted more heavily towards projected prices without underlying financial trades
(EIA,Moody’s,Inc.).
Regional price variability from the Henry Hub can be significant.Idaho Power uses a price adjustment
(basis)based on the cost of delivering natural gas from the Sumas trading hub to model natural gas
prices in southwest Idaho.The Sumas price adjustment incorporates the Pacific Northwest regional price
variation from Henry Hub and the transportation charges from Northwest Pipeline Corporation to
deliver natural gas to Idaho Power’s service area.The 2011 IRP assumes existing pipeline transport
capacity is sufficient to serve only existing demand.The cost of new gas resources includes an
additional transportation cost to account for the cost of constructing new pipeline capacity.
This additional cost is approximately twice the current tariff rate.Figure 6.5 shows the major natural gas
pipeline transportation paths in the Pacific Northwest.
The Henry Hub price,including the Sumas Basis,is shaped monthly to reflect the normal seasonal
supply and demand price variation.The gas price forecast in all future years receives the same monthly
price shaping.Sumas gas prices can have high seasonal spot price variability,especially in the winter
months,and the Sumas price volatility is not included in the regional adjustment.Idaho Power’s
geographic position between Sumas gas and Rockies gas allows Idaho Power to access two independent
gas markets that may not have high-price correlation.Also,Idaho Power hedges a portion of its short
and mid-term gas planned for use in the resource portfolio.This hedging activity is intended to reduce
the spot and seasonal-price volatility of natural gas costs incurred by customers.
2011 IRP Page 69
6.Planning Period Forecasts Idaho Power Company
The 2011 IRP analyzes three gas price scenarios as shown in Figure 6.4.The expected-case forecast has
a 20-year levelized cost of $7.92 per MMBtU,while the high case is $9.82 per MMBtu and the low case
is $6.01 per MMBtu.At the time the natural gas price forecast was prepared for the IRP,natural gas
prices were considerably higher than they are today.In fact,the low natural gas price case is a more
accurate reflection of the current forward market for natural gas.
$17
$16
$15
$14
$13
$12
$11
$10
I:
—IRP Expected (Sumas)——IRP Low Case (Sumas)—IRP High Case (Sumas)
Figure 6.4 Natural gas price forecast
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Page 70 2011 IRP
Idaho Power Company
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6.Planning Period Forecasts
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2011 IRP Page 71
6.Planning Period Forecasts Idaho Power Company
Resource Cost Analysis
The costs of a variety of supply-side and demand-side resources were analyzed for the 2011 JRP.
Cost inputs and operating data used to develop the resource cost analysis were derived from various
sources,including,but not limited to,the NPCC,the US Department of Energy (DOE),independent
consultants,and regional energy project developers.Resource costs are presented as follows:
•Levelized fixed cost-per-kW of installed (nameplate)capacity per month
•Total levelized cost-per-MWh of expected plant output or energy saved,given assumed capacity
factors and other operating assumptions
The levelized costs for the various supply-side alternatives include capital costs,O&M costs,fuel costs,
and other applicable adders and credits.The cost estimates used to determine capital cost of the
supply-side resources include engineering development costs,generating and ancillary equipment
purchase costs,installation,applicable balance of plant construction,and the costs for a generic
transmission interconnection to Idaho Power’s network system.More detailed interconnection and
transmission system upgrade costs were estimated by Idaho Power’s transmission planning group and
were included in the total portfolio cost.The capital costs also includes AFUDC (capitalized interest).
The O&M portion of each resource’s levelized cost includes general estimates for property taxes and
property insurance premiums.The value of RECs is not included in the levelized cost estimates but is
accounted for when analyzing the total cost of each resource portfolio.
The levelized costs for each of the demand-side resource options include annual administrative and
marketing costs of the program,annual incentive,and annual participant costs.The demand-side
resource costs do not reflect the financial impact to Idaho Power as a result of these load
reduction programs.
Specific resource cost inputs,fuel forecasts,key financing assumptions,and other operating parameters
are shown in Appendix C—Technical Appendix.
Emissions Adders for Fossil Fuel-Based Resources
All resource alternatives have potential environmental and other social costs that extend beyond just the
capital and operating costs included in the cost of electricity.Fossil fuel-based generating resources are
particularly sensitive to some of the environmental and social costs.It is likely that further emissions
regulations will be implemented during the period covered in the 2011 IRP.
In the analysis,Idaho Power incorporated estimates for the future cost of certain emissions into the
overall cost of the various fossil fuel-based resources.Within the resource cost analysis ranking,
the levelized costs for the various fossil fuel-based resources include emissions adders for C02,NON,
Hg,and SO2.The additional costs are assumed to begin in 2015.Table 6.4 provides the emissions
intensity rates assumed in the analysis and the emissions adder costs shown in Table 6.5 were used to
calculate the total emissions costs of the various fossil fuel-based resources that were analyzed.
Additional information regarding the cost of carbon emissions is provided in the next section.
In addition to including the emission adders in the levelized resource cost analysis,Idaho Power
estimates the regulatory environmental compliance costs the company expects for C02,NOR,Hg,
and SO2 emissions for each portfolio in the first 10-year and second 10-year planning periods.
The expected case regulatory environmental compliance costs for each planning period is shown in
Appendix C—Technical Appendix.A sensitivity analysis (low-case and high-case)for these compliance
costs can also be found in Appendix C—Technical Appendix.
Page 72 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
Table 6.4 Emissions intensity rates (lbsIMWh)
Adder CO2 NO Hg SO2
Pulverized Coal 1901 3.38 0.000050 8.5339
IGCC 2279 0.21 0.000006 0.1490
IGCC with Carbon Sequestration 420 0.43 0.000006 0.1833
Distributed Generation Natural Gas 1,115 1.07 N/A 0.0096
SCCT 1413 1.36 N/A 0.0122
CCCT 809 0.08 N/A 0.0070
Table 6.5 Emissions adder cost assumptions
Adder Emission Adder Cost First Year Applied Annual Escalation
GHG $20 per ton 2015 5.0%
NO $2,600 per ton1 2015 2.5%
Hg $1,443 perounce1 2015 2.5%
SO2 $1.75 per ton 2011 2.5%
‘2011 doflars
Cost of Carbon Emissions
Although Idaho Power believes a cap-and-trade system is more likely than a carbon tax to be
implemented in the future,regulatory requirements dictate the analysis be performed using a carbon
adder or tax,which Idaho Power has done for the 2011 IRP.The purpose of a carbon adder is to account
for all of the costs in the price of energy produced by carbon-emitting resources.
Four carbon-adder scenarios were analyzed as part of the 2011 IRP:1)the expected case starting at
$20 per ton in 2015 and escalating at 5 percent annually,2)the high case starting at $25 per ton in
2015 and escalating at 7.5 percent annually,3)the low case starting at $15 per ton and escalating at
2.5 percent annually,and 4)the zero-cost case where there is no future cost associated with carbon
emissions.The carbon adder assumptions used in the 2011 IRP are shown in Figure 6.6.A discussion of
the analysis results of the cost of carbon emissions is contained in Chapter 9.
$75 ——--—--——————.———-——-—————.————-—--_
$70 ———-—————————---——--—.-———————-—
$65 -—-——-————————--—--————————-—--————------———-----—-——-—----—
$60 ——-—--—--————-————-—-————-----—--—---------—----.-------.---—--.------
—--------------------.----—----------
(N ().It)(0 (..(0 0)0 (N C’)It)(0 r-0)0(N (N (N (‘4 (‘4 (N (N (N (N (N C’)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0(N (N (‘4 (N (‘4 (N (N (N (N (N (N (N (N (N (‘4 (N (N (N CN (N
—Expected Case ——High Case ——Low Case ——$0 Cost
Figure 6.6 Carbon-adder assumptions
—$55
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_______
2011 IRP Page 73
6.Planning Period Forecasts Idaho Power Company
Production Tax Credits for Renewable Generating Resources
Various federal tax incentives for renewable resources were extended and/or renewed within the
Emergency Economic Stabilization Act of2008.This legislation requires most projects be on line by
December 31,2016,to be eligible for the federal production tax credits (PTC)identified in Section 45 of
the Internal Revenue Code.The credit is earned on power produced by the project during the first
10 years of operation.The credit,adjusted annually for inflation,is currently valued at $21 per MWh.
Renewable Energy Credits
While the state of Idaho does not have an RPS requirement,Idaho Power believes a federal RES
requiring Idaho Power to retire RECs for compliance will be passed by Congress in the near future.
Idaho Power believes it is prudent to continue acquiring RECs associated with renewable resources to
minimize the impact when a federal RES is implemented.
For the 2011 IRP,the portfolios being analyzed are designed to substantially comply with the
Renewable Electricity Promotion Act of2OlO (S.3813)introduced in Congress in September 2010 by
Senator Jeff Bingaman (D—New Mexico).Under the proposed bill,an initial renewable requirement of
3 percent would begin in 2012 and would increase to 15 percent by 2021.
Three different scenarios for the future value of RECs were analyzed as part of the 2011 IRP:
1)the expected-case scenario where RECs are valued at $7 in 2013 and escalated at 3 percent annually,
2)a high-case scenario where RECs are valued at $21 in 2013 and escalated at 3 percent annually,
and 3)a low-case scenario where RECs have no value beginning in 2013.The three REC price
assumptions used in the 2011 IRP are presented in Figure 6.7.A discussion of the analysis of the value
of RECs in each of the portfolios analyzed in the 2011 IRP is presented in Chapter 9.
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Expected Case ——High Case ——Low Case
Figure 6.7 REC price assumptions
Page 74 2011 IRP
Idaho Power Company 6.Planning Period Forecasts
Levelized Capacity (Fixed)Cost
The annual fixed revenue requirements in nominal dollars for each resource were summed and levelized
over a 30-year operating life and are presented as dollars-per-kW of plant nameplate capacity per month.
Included in these costs were the cost of capital and fixed O&M estimates.Figure 6.8 provides a
combined ranking of all the various resource options,in order of lowest to highest levelized fixed
cost-per-kW-per-month.The ranking shows distributed generation and natural gas peaking resources are
the lowest capacity cost alternatives.Distributed generation and gas peaking resources have high
operating costs,but the operating costs are not as important when the resource is used only a limited
number of hours-per-year to meet peak-hour demand.
Levelized Cost of Production
Certain resource alternatives carry low fixed costs and high variable operating costs,while other
alternatives require significantly higher capital investment and fixed operating costs but have low
variable operating costs.The levelized cost of production measurement represents the estimated annual
cost-per-MWh in nominal dollars for a resource based on an expected level of energy output (capacity
factor)over a 30-year operating life.
The nominal,levelized cost of production assuming the expected capacity factors for each
resource-type is shown in Figure 6.9.Included in these costs are the cost of capital,non-fuel O&M,
fuel,and emissions adders;however,no value for RECs was assumed in this analysis.Resources,
such as DSM measures,geothermal,wind,and certain types of thermal generation,appear to be the
lowest cost for meeting baseload requirements.
When evaluating a levelized cost for a project and comparing it to the levelized cost of another project,
it is important to use consistent assumptions for the computation of each number.The levelized cost of
production metric represents the annual cost ofproduction over the life of a resource converted into an
equivalent annual annuity.This is similar to the calculation used to determine a car payment;only,
in this case,the car payment would also include the cost of gasoline to operate the car and the cost of
maintaining the car over its useful life.
An important input into the levelized cost of production calculation for a generation resource is the
assumed level of annual capacity utilization over the life of the resource,referred to as capacity factor.
A capacity factor of 50 percent would suggest that a resource would be expected to produce output at
full capacity 50 percent of the hours during the year.Therefore,at a higher capacity factor,the levelized
cost will be less because the plant would generate more MWh over which to spread the fixed costs.
Conversely,lower capacity factor assumptions reduce the MWh and the levelized cost would be higher.
Resource capital costs are annualized over a 30-year period for each resource and are applied only to the
years of production within the IRP planning period,thereby accounting for end effects.
2011 IRP Page 75
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Page 78 2011 IRP
Idaho Power Company 7.Transmission Planning
7.TRANSMISSION PLANNING
Past and Present Transmission
High-voltage transmission lines have been vital to
the development of energy resources to serve
Idaho Power customers.Transmission lines have
facilitated the development of southern Idaho’s
network of hydroelectric projects that have served the
electric customers of southern Idaho and eastern
Oregon.Regional transmission lines that stretch from
the Pacific Northwest to the Hells Canyon Complex
and on to the Treasure Valley were central to the
development of the Hells Canyon Complex in the
1950s and 1960s.In the 1970s and 1980s,
transmission lines were instrumental in the
development of partnerships in the three,coal-fired
power plants located in neighboring states,which supply approximately 40 percent of the energy
consumed by Idaho Power customers.Finally,transmission lines allow Idaho Power to economically
balance the variability of its hydroelectric resources with access to wholesale energy markets.
The regional transmission interconnections improve reliability by providing the flexibility to move
electricity between utilities and also provide economic benefits based on the ability to share operating
reserves.Historically,Idaho Power has been a summer peaking utility,while most other utilities in the
Pacific Northwest experience system peak loads during the winter.Because of this,Idaho Power
purchases energy from the Mid-Columbia energy trading market to meet peak summer load and sells
excess energy to Pacific Northwest utilities during the winter and spring.This practice benefits the
environment and Idaho Power’s customers because the construction of additional peaking resources to
serve summer peak load is delayed or avoided,revenue from off-system sales during the winter and
spring is credited to customers through the PCA,and revenue from others’use of the transmission
system is credited to customers in general rates.
Transmission Planning Process
In recent years,FERC has mandated several aspects of the transmission planning process.
One regulation requires Idaho Power to participate in transmission planning on a local,sub-regional,
and regional basis,as described in Attachment K of the Idaho Power OATT and summarized in the
following sections.
Highlights
Regional transmission interconnections improve reliability by providing the flexibility to
move electricity between balancing authorities.
Restrictions on the Brownlee East Total and Idaho—Northwest transmission paths limit
the import of Hells Canyon Complex generation and off-system purchases from the
Pacific Northwest.
The 500-ky Boardman to Hemingway project,expected to be in service in
2016,will significantly increase the capacities of the Brownlee East Total and
Idaho—Northwest paths.
High-voltage transmission lines are necessary to deliver
electricity to load and connect with other regional utilities.
2011 IRP Page 79
7.Transmission Planning Idaho Power Company
Local Transmission Planning Process
The expansion planning of Idaho Power’s transmission network occurs through a local area transmission
advisory process,and the biennial local transmission planning process.
Local Area Transmission Advisory Process
Idaho Power develops long-term local area transmission plans with community advisory committees.
These committees consist ofjurisdictional planners;mayors;council members;commissioners;
and large industry,commercial,residential,and environmental representatives.The plans identify the
transmission and substation infrastructure required for full development of the area limited by the
land-use plan and other resources of the local area.The plans identify the approximate year the project
will be placed in service.Local area plans have been created for four load centers in southern Idaho,
1)eastern Idaho,2)Magic Valley,3)Wood River Valley,and 4)Treasure Valley.Development of a
fifth plan for the western Treasure Valley and eastern Oregon is in progress.
Biennial Local Transmission Planning Process
The biennial local transmission plan (LTP)identifies the transmission required to interconnect the load
centers,integrate planned generation resources,and incorporate regional transmission plans.The LTP is
a 20-year plan that incorporates the transmission upgrades identified in the Local Area Transmission
Advisory Process,the forecasted network customer load (e.g.,BPA customers in eastern Oregon and
southern Idaho),Idaho Power’s retail customer load,and point-to-point transmission customer
requirements.By identifying potential resource areas and load-center growth,the required transmission
capacity expansions are identified to safely and reliably provide service to customers.The LTP is shared
with the sub-regional transmission planning process.
Sub-Regional Transmission Planning
Idaho Power is active in sub-regional transmission planning through the NTTG.NTTG was formed in
early 2007 with an overall goal of improving the operation and expansion of the high-voltage
transmission system that delivers power to consumers in seven western states.In addition to
Idaho Power,other members include Deseret Power Electric Cooperative,NorthWestern Energy,PGE,
PacifiCorp (Rocky Mountain Power and Pacific Power),and the Utah Associated Municipal Power
Systems (UAMPS).NTTG also relies on a biennial process to develop the sub-regional transmission
plan and incorporates the member’s biennial local transmission plans.A public stakeholder process
evaluates transmission needs as determined by state-mandated IRPs and load forecasts,proposed
resource development and generation interconnection queues,and forecast uses of the transmission
system by wholesale transmission customers.
Regional Transmission Planning
WECC’s Transmission Expansion Planning Policy Committee (TEPPC)serves as the regional
transmission planning facilitator in the western United States.Specifically,TEPPC has three distinct
functions,1)oversee data management for the western interconnection,2)provide policy and
management of the planning process,and 3)guide the analyses and modeling for Western
Interconnection economic transmission expansion planning.In addition to providing the means to model
the transmission implications of various load and resource scenarios at a regional level,these functions
serve to fulfill the requirement to coordinate planning between transmission owners/operators and
sub-regional planning entities.
The WECC Planning Coordination Committee manages additional transmission planning and
reliability-related activities on behalf of electric-industry entities in the West.These activities include
Page 80 2011 IRP
Idaho Power Company 7.Transmission Planning
regional resource adequacy analyses and corresponding North American Electric Reliability Corporation
(NERC)reporting,transmission security studies,and the transmission-line rating process.
Existing Transmission System
Idaho Power’s transmission system spans southern Idaho from eastern Oregon to western Wyoming and
is composed of 115-,138-,161-,230-,345-,and 500-ky transmission facilities.The sets of lines that
transmit power from one geographic area to another are known as “transmission paths.”There are
defined transmission paths to other states and between the southern Idaho load centers mentioned earlier
in this chapter.Idaho Power’s transmission system and paths are shown in Figure 7.1.
The transmission paths identified on the map are described in the following sections,along with
descriptions of the conditions that result in capacity limitations.
Idaho—Northwest Path
The Idaho—Northwest transmission path consists of the 500-ky Hemingway—Summer Lake line,
the three,230-ky lines between the Hells Canyon Complex and the Pacific Northwest,and the
115-ky interconnection at Harney substation near Bums,Oregon.The Idaho—Northwest path is
most likely to be capacity-limited during summer months in low-to-normal water years due to
transmission-wheeling obligations for BPA’s eastern Oregon and south Idaho loads and energy
Figure 7.1 Idaho Power transmission system map
2011 IRP Page 81
7.Transmission Planning Idaho Power Company
imports from the Pacific Northwest to serve Idaho Power’s retail load.If new resources,including
market purchases,are located west of the path,additional transmission capacity will be required to
deliver the energy to eastern Oregon and southern Idaho.
Brownlee East Path
The Brownlee East transmission path is on the east side of the Idaho—Northwest Interconnection shown
in Figure 7.1.Brownlee East is comprised of the 230-kV and 138-ky lines east of the Hells Canyon
Complex,and Quartz substation,near Baker City,Oregon.When the Hemingway—Summer Lake
500-ky line is included with the Brownlee East path,the path is typically referred to as the Brownlee
East Total path.The capacity limitation on the Brownlee East transmission path is located between
Brownlee and the Treasure Valley.
The Brownlee East transmission path has different capacity limitations than the Northwest path.
The Brownlee East path is most likely to face capacity limitations in the summer during normal-to-high
water years.The capacity limitations result from a combination of Hells Canyon Complex hydroelectric
generation flowing east into the Treasure Valley,concurrent with transmission-wheeling obligations for
BPA’s eastern Oregon and southern Idaho loads and Idaho Power energy imports from the Pacific
Northwest.Capacity limitations on the Brownlee East path limit the amount of energy Idaho Power can
import from the Hells Canyon Complex,as well as off-system purchases from the Pacific Northwest.
If new resources,including market purchases,are located west of the path,additional transmission
capacity will be required to deliver the energy to the Treasure Valley load center.
Idaho—Montana Path
The Idaho—Montana transmission path consists of the Antelope—Anaconda 230-kV and Jefferson—Dillon
161-ky transmission lines.The Idaho—Montana path is also capacity-limited during the summer months
as Idaho Power and others move energy south from Montana into Idaho.
Borah West Path
The Borah West transmission path is internal to the Idaho Power system.The path is comprised of
345-kV,230-kV,and 138-kV transmission lines west ofthe Borah substation,located near
American Falls,Idaho.Idaho Power’s share of energy from the Jim Bridger plant flows over this path,
as well as east-side hydroelectric and energy imports from Montana,Wyoming,and Utah.The Borah
West path is capacity limited during summer months due to transmission-wheeling obligations
coinciding with high eastern thermal and wind production.Heavy path flows are also likely to exist
during the light-load hours of the fall and winter months as high eastern thermal and wind production
moves east-to-west across the system.Additional transmission capacity will likely be required if new
resources,including market purchases,are located east of the path to deliver the energy to the Treasure
Valley load center.
Midpoint West Path
The Midpoint West path is an internal path comprised of the 230-kV and 138-kV transmission lines
west of Midpoint substation,located near Jerome,Idaho.Capacity on the Midpoint West path is fully
subscribed with east-side Idaho Power resources and energy imports.Similar to the Borah West path,
the heaviest path flows are likely to exist during the fall and winter when significant wind and thermal
generation is present east of the path.Additional transmission capacity will likely be required if new
resources (or market purchases),are located east of the path to deliver the energy to the Treasure Valley
load center.
Page 82 2011 IRP
Idaho Power Company 7.Transmission Planning
Idaho—Nevada Path
The Idaho—Nevada transmission path is comprised ofthe 345-ky Midpoint—Humboldt line.Idaho Power
and NV Energy are co-owners of the line,which was developed at the same time the Valmy power
plant was built in northern Nevada.Idaho Power is allocated 100 percent of the northbound capacity,
while NV Energy is allocated 100 percent of the southbound capacity.The available import,or
northbound,capacity on the transmission path is fully subscribed with Idaho Power’s share of the
Valmy generation plant.
Idaho—Utah Path
The Idaho—Utah path,referred to as Path C,is comprised of 345-,230-,161-,and 138-ky transmission
lines between southeastern Idaho and northern Utah.PacifiCorp is the path operator and owner of all of
the transmission lines;however,several of the lines terminate at Idaho Power-owned substations.
The path effectively feeds into the Borah West path when power is moving from east-to-west and,
consequently,the import capability of Path C is limited by Borah West path capacity limitations.
Table 7.1 Available transmission import capacity
Transmission Path
Idaho—Northwest West-to-East
Idaho—Nevada South-to-North
Idaho—Montana North-to-South
Brownlee East West-to-East
Midpoint West East-to-West
Borah West East-to-West
Idaho—Utah South-to-North
Idaho Power makes resource location
assumptions in order to determine the
transmission requirements as part of the IRP
development process.Regardless of the location,
supply-side resources included in the resource
stack require local transmission improvements
for integration into Idaho Power’s system.
Additional transmission improvement
requirements are dependent on the location and
size of the resource.The transmission
assumptions and transmission upgrade
requirements are summarized in Table 7.2.
Total Transmission Capacity
Import Direction Capacity (MW)
1,200
262
166
1,915
1027
2,557
1,250
Available Transmission
Capacity (MW)
0
0
0
0
0
0
198
*Total transmission capacity and available transmission capacity as of May 1,2011.
ldaho Power estimated value,actual available transmission capacity managed by PacifiCorp.
Transmission Assumptions in the IRP Portfolios
The Hemingway substation in southern Idaho is a major hub for
power running through Idaho Power’s transmission system.
2011 IRP Page 83
7.Transmission Planning Idaho Power Company
Table 7.2 Transmission assumptions
Resource levels
Resource Type Geographic Area (per portfolio)
Gas Turbines*Elmore County 0 MW—I 50 MW
150 MW—325 MW
>325 MW
Solar*Elmore County 0 MW—I 50 MW
150 MW—325 MW
>325 MW
CHP Treasure Valley 0 MW—I 00 MW
Magic Valley 100 MW—200 MW
Geothermal Northern Nevada 0 MW—26 MW
Cassia County 26 MW—52 MW
Pumped Storage Anderson Ranch Reservoir 0 MW—80 MW
80 MW—240 MW
Additional Transmission Requirements
No upgrades required
New 230-kV line into Treasure Valley
Additional 230-kV line into Treasure Valley
No upgrades required
New 230-kV line into Treasure Valley
Additional 230-kV line into Treasure Valley
No upgrades required
No upgrades required
No upgrades required
No upgrades required
No upgrades required
New 230-kV line into Treasure Valley
*Because gas and solar resources are assumed to be in the same geographic area,the resource levels and corresponding transmission
requirements are cumulative.
The assumptions about the geographic area where particular supply-side resources develop determine
the transmission upgrades required.For example,the location of a pumped storage resource listed in
Table 7.2 will require a new 230-ky transmission line if sized greater than 80 MW,where other
resources of that size may not require such improvements when located in another geographic area.
An additional analysis of the transmission requirements was undertaken when these supply-side
resources were arranged into portfolios.A transmission plan that provided the required transmission
capacity from the new resources to the growing Treasure Valley load center was developed for each
portfolio.This analysis of the first 10-year portfolios resulted in each portfolio requiring at least one new
230-kV transmission line into the Treasure Valley.
Page 84 2011 IRP
Idaho Power Company 8.Planning Criteria and Portfolio Selection
8.PLANNING CRITERIA AND PORTFOLIO SELECTION
Many utilities plan to median,or expected,conditions
and then include a reserve margin to cover the
50 percent of the time when conditions are less
favorable than median.Idaho Power discussed
planning criteria with IPUC and OPUC staff members
and the public as part of the 2002 IRP.Out of these
discussions came the company’s practice of using
more stringent planning criteria than median
conditions.The planning criteria and planning
scenarios are discussed in the following section.
Planning Scenarios and Criteria
The timing and necessity of future generation
resources are based on a 20-year forecast of surpluses
and deficits for monthly average load and peak-hour load.The 20-year forecast is further divided into
two,10-year periods that coincide with the near-term action plan and the long-term action plan.
The planning criteria for monthly average load planning are 70th percentile water and 70th percentile
average load conditions.For peak-hour load conditions,the planning criteria used are 90th percentile
water and 95th percentile peak-hour load.The peak-hour analysis is coupled with Idaho Power’s ability
to import additional energy on its transmission system.Peak-hour load planning criteria are more
stringent than average-load planning criteria because Idaho Power’s ability to import additional energy
is typically limited during peak load periods.The median forecast is no longer used for resource
planning but it is used to set retail rates and avoided-cost rates during regulatory proceedings.
Load and Resource Balance
Idaho Power has adopted the practice of assuming drier-than-median water conditions and
higher-than-median load conditions in its resource planning process.Targeting a balanced position
between load and resources,while using the conservative water and load conditions,is considered
comparable to requiring capacity margin in excess of load while using median load and water
conditions.Both approaches are designed to result in a system having generating capacity in reserve
for meeting day-to-day operating reserve requirements.
To identify the need and timing of future resources,Idaho Power prepares a load and resource balance,
which accounts for generation from all the company’s existing resources and planned purchases.
The updated load and resource balance showing Idaho Power’s existing and committed resources for
Highlights
Idaho Power uses 70th percentile average load and 70th percentile water conditions for
energy planning.
For peak-hour capacity planning,Idaho Power uses 90th percentile water conditions and
95th percentile peak-hour loads.
Growth in summertime peak-hour demand continues to drive Idaho Power’s needs for
additional resources.
Idaho Power relies on a collaborative process to
develop the IRP.
2011 IRP Page 85
8.Planning Criteria and Portfolio Selection Idaho Power Company
average energy and peak-hour load is shown in Appendix C—Technical Appendix.
Average Monthly Energy Planning
Average energy surpluses and deficits are determined using 70th percentile water and 70th percentile
average load conditions,coupled with Idaho Power’s ability to import energy from firm market
purchases using reserved network capacity.Figure 8.1 shows the monthly average energy surpluses and
deficits with existing and committed resources.The energy positions shown in Figure 8.1 also include
the forecast impact of existing DSM programs,the current level of PURPA development,existing PPAs,
firm Pacific Northwest import capability,and the expected generation from all Idaho Power-owned
resources,including Langley Gulch and the Shoshone Falls upgrade once they are available.Figure 8.1
illustrates that,starting in July 2018,monthly average energy deficit positions grow steadily in
magnitude and number of months affected.By July 2030,these energy deficits exceed 600 aMW.
1400 —
1,200
1,000800 i II L
600
400200 Hh lD Hhh 1hdH .wil Wili
(200;I I’I II
(400;
(600;
(800;
—.C’J C’)L1)CC’F’.C C C’)‘)CS)CL’F...CL.L’Cl C’S Cl C’l Cl Cl Cl Cl C.l C’S C’)
C C C C C C C C C C C C C C C C C C C C
CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO
-,-,-,-,-3 -3 -,-3 -3 _)-3 -3 -3 -3 -3 -3 -,-3 -3 -3
Figure 8.1 Monthly average energy surpluses and deficits with existing and committed resources and
existing DSM (70th1 percentile water and 70th percentile load)
Idaho Power is committed to implementing all cost-effective energy efficiency programs in the IRP
prior to evaluating supply-side resource options.Figure 8.2 shows the monthly average energy surplus
and deficit data from Figure 8.1 with the addition of all new cost-effective energy efficiency.With the
new energy efficiency programs accounted for,monthly average energy deficits in 2030 are reduced to
approximately 550 aMW.
Energy deficits are eliminated by designing portfolios containing new resources that are analyzed in the
IRP.However,Idaho Power’s resource needs have historically been driven by the need for additional
summertime peak-hour capacity rather than additional energy,as this is the case in the 2011 IRP.
II II
Page 86 2011 IRP
-._
iz
(400)-----—-
(600)-—
(800)-
CN C U)CD CD 0)0ClCC
C C C C C C C C CcccwCo-)-,_,-,-,-,-,-)-,-)
Figure 8.2 Monthly average energy surpluses and deficits with new DSM (70th percentile water and70thpercentileload)
Peak-Hour Planning
Peak-hour load deficits are determined using 90th percentile water and 95th percentile peak-hour load
conditions.In addition to these criteria,70th percentile average load conditions are assumed,but the
hydrologic and peak-hour load criteria are the major factors in determining peak-hour load deficits.
Peak-hour load planning criteria are more stringent than average-energy criteria because Idaho Power’s
ability to import additional energy is typically limited during peak-hour load periods.
Idaho Power’s customers reach a maximum energy demand in the summer.Idaho Power’s existing and
committed resources are insufficient to meet the projected peak-hour growth,and the company’s
customers in Oregon and Idaho face significant capacity deficits in the summer months if additional
resources are not added.
At times of peak summer load,Idaho Power is fully using all available transmission capacity from the
Pacific Northwest.If Idaho Power were to face a significant outage at one of its main generation
facilities,or a transmission interruption on one of the main import paths,the company would fail to meet
reserve requirement standards.If Idaho Power is unable to meet reserve requirements,the company is
then required to shed load by initiating rolling blackouts.Although infrequent,Idaho Power has initiated
rolling blackouts in the past during emergencies.Idaho Power has committed to a build program,
including demand-side programs,generation,and transmission resources,to reliably meet customer
demand and minimize the likelihood of events that would require the implementation of
rolling blackouts.
Figure 8.3 shows the monthly peak-hour deficits with existing and committed resources.The capacity
positions shown in Figure 8.3 also include the forecast impact of existing DSM programs,the current
level of PURPA development,existing PPAs,firm Pacific Northwest import capability,and the
expected generation from all Idaho Power-owned resources,including Langley Gulch and the
Shoshone Falls upgrade once they are available.
A deficit of approximately 100 MW in September 2011 highlights the need for the Langley Gulch
CCCT plant as demand response programs are not available in the month of September.Idaho Power is
actively managing this near-term deficit in accordance with its Energy Risk Management Policy and
Idaho Power Company 8.Planning Criteria and Portfolio Selection
1,400 ---——--—--—---------------—--——--—-—---—-——-------------—-——--------------—-----
1,200
1,000
800
600
400
10 200
0
(200)
?dEfrEi;II1FD
CD 0)0 C’C’)U)CD(N (N (N (N C C’l Cl
C C C C C C C C C CCOCOCOCOCOCOCOCOCOCO-,-,-,-C )))-C )
2011 IRP Page 87
8.Planning Criteria and Portfolio Selection Idaho Power Company
Standards.Starting in July 2015,monthly peak-hour deficit positions grow steadily in magnitude and
number of months affected.By July 2030,these capacity deficits are approximately 1,300 MW.
C4 C)U)CD C.-CD 0)0 —C1 C’)U)CD CD 0)0ciC(N CI CJ C C C I C
C C C C C C C C C C C C C C C C C C C C
CO CO CO CO CO CO Co CO Co Co CO Co CO Co CO CO CO CO CO CO
zzzpizpj:E 1 L I-F:
(200)—-—-
-——
(300)-—---—---—-----—---
(400)—-—--—--——
------——---
(500)—-----------------
---—-------------------------
(600)—-—--------------——----------------------—-------—-------------------
(700)—--------------------
--—-----—-—-----------—---——-—---------—--——--—--—---
(800)--—-——----—-—-—-----—-—--------—-----—--—-—--—--—-——-—-—-----—-----—--
(900)fl—------—---—------—-—---—-—-—-—-—------------——----—
(1,000)-—-------—--————--—-—------------—-——----------———-------—-
(1,100)——----—--——-—----—-
(1,200)—-—--—----------
--—-----------—-------—-—--——-—-—-—--—-—--—-—-—----———
(1,300)—-----—-—-——-———--—-_—---——----—----—----
Figure 8.3 Monthly peak-hour deficits with existing and committed resources and existing DSM
(g0th percentile water and 95th percentile load)
As discussed in Chapter 4,the evaluation of demand response programs was switched from an “all
cost-effective DSM”approach to a “needs-based”approach in the 2011 IRP.The new method was
designed to identify annual levels of demand response needed to delay the addition of new supply-side
peaking resources until the capacity of a SCCT would be greater than the seasonal limitations on
demand response programs.Figure 8.4 shows the monthly peak-hour deficit data from Figure 8.3 with
the addition of all new DSM under this methodology.With the new DSM accounted for,monthly
peak-hour deficits in 2030 are reduced to approximately 1,230 MW.
—(N C’)U)CD C..CD 0)0 —(N C’)U)CD F’-CD 0)0—1 C?
C C C C C C C C C C C C C C C C C C C CCoCoCOCoCOCOCOCoCOCoCOCOCoCOCoCOCOCoCoCo
-,_,-,-,-,-,-,-,-,-,-,-,-,-,-,-,-,-,-,-,
(100)I
(200)—-
(300)
--
—---------—--————---
(400)
(500)--—-----——---—----—-—---—
(600)—----------------
(700)--
--—----——
(800)—
(900)f------—--—1
(1,000)-I
(1,100)----—-———--------—-—-—---—-—------——--——----------—---
(1,200)—----—---
(1,300)—-
Figure 8.4 Monthly peak-hour deficits with new DSM (g0th percentile water and 95th percentile load)
Capacity and energy deficits are eliminated by designing portfolios containing new resources that are
analyzed in the IRP.Because Idaho Power’s resource needs are driven by the need for additional
Page 88 2011 IRP
Idaho Power Company 8.Planning Criteria and Portfolio Selection
summertime peak-hour capacity rather than additional energy,the deficits identified in Figure 8.4 were
used to design the portfolios analyzed in the 2011 IRP.In addition to eliminating the peak-hour deficits
identified in Figure 8.4,the initial resource portfolios described in the next section also eliminated the
energy deficits identified in Figure 8.2.
Portfolio Design and Selection
The 2011 LRP portfolio development strategy divides the study period into two,10-year periods,
2011—2020 and 202 1—2030.Resource portfolios in each 10-year period are designed to satisfy the
energy and peak-hour deficits shown in the load and resource balance.
Idaho Power also believes a federal RES will be enacted in the near future,and each portfolio is
designed to substantially comply with the RES provisions contained in the Renewable Elecfricity
Promotion Act of2O]O (S.3813)introduced in Congress in September 2010,by Senator Jeff Bingaman
(D—New Mexico).Under the proposed bill,an initial renewable requirement of 3 percent would begin in
2012 and would increase to 15 percent by 2021.
First 10 Years (2011—2020)
The first 10-year planning period has significant committed resources,including the Langley Gulch
CCCT and the Shoshone Falls upgrade.These committed resources are treated as existing resources for
the purpose of analyzing each portfolio ofnew resources.The capital cost of these committed resources
is not included in the comparison between portfolios.
For the first 10-year period,the 2011 IRP analyzed nine different resource portfolios.The new resources
shown are designed to reduce previously discussed deficits and to meet proposed RES requirements.
A summary of the resource portfolios analyzed for the first 10 years of the planning horizon is shown in
Figure 8.5,and a description of each portfolio follows.
I-I Sun &Steam 1-2 Solar 1-3 B2H 1-4 SCCT 1-5 CCCT
2011 2011 2011 2011 2011
2012 Solar PV-1 2012 2012 2012 2012
2013 Solar PV-5 2013 2013 2013 2013
2014 CHP-75 2014 Solar PV-5 2014 2014 2014
2015 SolarPV-30 2015 SolarPT-100 2015 EastsidePurchase 2015 SCCTFrame 2015 CCCT
2016 CHP-100 2016 Solar PT-100 2016 B2H-450 2016 2016
2017 Geothermal-52 2017 Solar PT-125 2017 2017 SCCT Frame 2017
2018 SolarPT-125 2018 SolarPV-50 2018 2018 2018
2019 Solar PV-30 2019 Solar PT-100 2019 2019 SCCT S Aero-94 2019 SCCT Frame
2020 Solar PT-75 2020 Solar PV-50 2020 2020 2020
MW 493 MW 530 MW 450 MW 434 MW 470
1-6 CHP 1-7 Balanced 1-8 Pumped Storage 1-9 Distributed Gen
2011 2011 2011 2011
2012 2012 2012 2012 DistGen-10
2013 2013 2013 2013
2014 2014 2014 2014
2015 CHP-100 2015 CHP-100 2015 Pump St-80 2015 SCCT Frame
2016 SCCT Frame 2016 SCCT Frame 2016 SCCT Frame 2016
2017 2017 SolarPV-10 2017 2017 SCCTFrame
2018 CHP-50 2018 SolarPT-100 2018 PumpSt-80 2018
2019 CHP-50 2019 Geothermal-26 2019 SCCT S Aero-47 2019 SCCT S Aero-94
2020 SCCT S Aero-94 2020 SCCT S Aero-47 2020 Pump St-80 2020
MW 464 MW 453 MW 457 MW 444
Figure 8.5 Initial resource portfolios (2011—2020)
•1-1 Sun and Steam—This resource portfolio was designed by IRPAC members as a result of a
portfolio design workshop held by Idaho Power.The portfolio consists of a mixture of solar PV and
2011 IRP Page 89
8.Planning Criteria and Portfolio Selection Idaho Power Company
power tower resources with geothermal and CHP.The purpose of this portfolio is to evaluate the
cost of an all-renewable portfolio.The total nameplate capacity of this portfolio is 493 MW.
•1-2 Solar—This resource portfolio includes a mixture of solar PV and power tower resources and is
designed to test the performance of a portfolio consisting entirely of solar resources.The total
nameplate capacity of this portfolio is 530 MW.
•1-3 Boardman to Hemingway—This resource portfolio includes the Boardman to Hemingway
transmission line project is anticipated to be available in 2016.A more expensive market purchase
on the east side of Idaho Power’s system was needed to meet a peak-hour deficit in the summer of
2015 prior to the Boardman to Hemingway line becoming available.The total nameplate capacity of
this portfolio is 450 MW.
•1-4 SCCT—This resource portfolio includes three SCCT’s—two industrial-frame units and two
small aeroderivative units (47 MW each).The purpose ofthis portfolio is to compare the cost of
market purchases on the Boardman to Hemingway line against building gas-peaking capacity near
load.The total nameplate capacity of this portfolio is 434 MW.
•1-5 CCCT—This resource portfolio includes one CCCT and one SCCT.Like portfolio 1-4,
the purpose of this portfolio is to compare the cost of market purchases on the Boardman to
Hemingway line against building baseload gas capacity near load.The total nameplate capacity of
this portfolio is 470 MW.
•1-6 CHP—This resource portfolio includes a mixture of CHP resources with two SCCTs.
The purpose of this portfolio is to compare the cost of CHP resources to the cost of CCCT and
SCCT technologies.The total nameplate capacity of this portfolio is 464 MW.
•1-7 Balanced—This resource portfolio includes a mixture of CHP,SCCTs,geothermal,and solar
resources.The purpose of this portfolio is to evaluate the cost of a balanced and diversified portfolio.
The total nameplate capacity of this portfolio is 453 MW.
•1-8 Pumped Storage—This resource portfolio includes a mixture of pumped storage resources and
SCCTs.The purpose of this portfolio is to compare the cost of pumped storage to other resource
alternatives.The total nameplate capacity of this portfolio is 457 MW.
•1-9 Distributed Generation—This resource portfolio is identical to portfolio 1-4 SCCT with the
exception that it includes a 10-MW distributed generation resource.The purpose of this portfolio is
to evaluate the cost and value of the proposed distributed generation program.Additional details on
the distributed generation program can be found in Chapter 5.The total nameplate capacity of this
portfolio is 444 MW.
Second 10 Years (2021-2030)
For the second 10-year period,the 2011 IRP analyzed 10 different resource portfolios.The second
10-year planning period is more of an academic exercise than the first 10-year period,where resources
are identified that will require a financial commitment.The new resources shown are designed to reduce
previously discussed deficits and to meet proposed RES requirements.A summary of the resource
portfolios analyzed for the second 10 years of the planning horizon is shown in Figure 8.6,and a
description of each portfolio follows.
Page 90 2011 IRP
Idaho Power Company 8.Planning Criteria and Portfolio Selection
2-1 Nuclear
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Solar PT-I 00
Pump St-50
Solar PT-i 00
Nuclear
Nuclear
Pump St-50
MW 800
2-2 IGCC
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Geothermal-52
SCCT Frame
CHP-50
Solar PT-75
IGCC wICS
Solar PT-75
MW 802
2-3 SCCTIW1nd
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
SCCT S Aero-141
Wind-100
SCCT S Aero-14i
Wind-I 00
SCCT S Aero-94
Wind-I 00
SCCT S Aero-141
SCCT S Aero-141
SCCT S Aero-94
MW 1.052
2-4 CCCTIW1nd
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
CCCT
Wind-I 50
CCCT
Wind-i 50
SCCT Frame
MW 1,070
2-5 HydroICHP
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Hydro Sm-60
CHP-75
Pump St-80
CHP-1 00
Hydro-40
Pump St-80
Hydro Sm-i 00
SCCT S Aero-141
Hydro Sm-80
Hydro Sm-60
MW 816
2-6 Balanced 1 2-7 Balanced 2 2-8 PNW Transmission 2-9 EIS Transmission 2-10 Renewable
2021 Geothermal-52 2021 Geothermal-52 2021 Geothermal-52 2021 Geothermal-52 2021 CHP-75
2022 SCCT Frame 2022 CHP-75 2022 PNW Purchase 2022 EIS Purchase 2022 Pump St-80
2023 2023 SCCT Frame 2023 2023 2023 Solar PT-I 50
2024 Solar PT-50 2024 2024 2024 2024
2025 CCCT 2025 Geothermal-52 2025 2025 2025 CHP-75
2026 2026 CHP-75 2026 2026 2026 Solar PT-150
2027 2027 Hydro Sm-60 2027 Solar PV-20 2027 Solar PV-20 2027 Solar PV-150
2028 Hydro Sm-60 2028 CCCT 2028 Geothermal-52 2028 Geothermal-52 2028 Geothermal-52
2029 SCCT Frame 2029 2029 SCCT Frame 2029 SCCT Frame 2029 Hydro Sm-i 00
2030 2030 2030 2030 2030 Solar PV-200
MW 802 MW 784 MW 794 MW 794 MW 1,032
Figure 8.6 Initial resource portfolios (2021—2030)
•2-1 Nuclear—This resource portfolio includes a mixture of pumped storage and solar resources
combined with 500 MW of nuclear resources.The purpose of this portfolio is to evaluate the cost of
the advanced nuclear technology against other resource alternatives.The total nameplate capacity of
this portfolio is 800 MW.
•2-2 IGCC—This resource portfolio includes a mixture of geothermal,solar,CHP,and SCCT
resources combined with a 380-MW IGCC resource.The purpose of this portfolio is to evaluate the
cost of the IGCC technology against other resource alternatives.The total nameplate capacity of this
portfolio is 802 MW.
•2-3 SCCT/Wind—This resource portfolio includes a combination of wind and SCCT resources.
The purpose of this portfolio is to evaluate the cost of a portfolio that contains wind resources that
supply energy and RECs and gas peaking units that provide capacity.The total nameplate capacity
of this portfolio is 1,052 MW.
•2-4 CCCT/Wind—This resource portfolio includes a combination of wind and CCCT resources.
The purpose of this portfolio is to evaluate the cost of a portfolio that contains wind resources that
supply energy and RECs and gas baseload resources that provide capacity and energy.The total
nameplate capacity of this portfolio is 1,070 MW.
•2-5 Hydro/CHP—This resource portfolio includes a combination of small hydroelectric,pumped
storage,CHP and SCCT resources.The purpose of this portfolio is to evaluate the cost of a portfolio
that contains hydroelectric and CHP resources.The total nameplate capacity of this portfolio is
816 MW.
•2-6 Balanced 1—This resource portfolio includes a mixture of geothermal,solar,
small hydroelectric,and SCCT resources.The purpose of this portfolio is to evaluate the cost of a
balanced and diversified portfolio.The total nameplate capacity of this portfolio is 802 MW.
2011 IRP Page 91
8.Planning Criteria and Portfolio Selection Idaho Power Company
•2-7 Balanced 2—This resource portfolio includes a mixture of geothermal,CHP,small
hydroelectric,and SCCT resources.The purpose of this portfolio is to evaluate the cost of a balanced
and diversified portfolio.The total nameplate capacity of this portfolio is 784 MW.
•2-8 PNW Transmission—This resource portfolio includes a mixture of geothermal,solar,and an
SCCT resource combined with an additional 500 MW oftransmission capacity to the Pacific
Northwest.The purpose of this portfolio is to evaluate the cost of a portfolio that substantially relies
on increased market purchases from the Pacific Northwest.The total nameplate capacity ofthis
portfolio is 794 MW.
•2-9 Eastside Transmission—This resource portfolio includes a mixture of geothermal,solar,and an
SCCT resource combined with an additional 500 MW oftransmission capacity across southern
Idaho and into Wyoming.The purpose of this portfolio is to evaluate the cost of a portfolio that
substantially relies on market purchases from the east side of Idaho Power’s system.The total
nameplate capacity of this portfolio is 794 MW.
•2-10 Renewable—This resource portfolio was designed by IRPAC members as a result of a
portfolio design workshop held by Idaho Power.The portfolio consists of a mixture of solar PV and
power tower resources,geothermal,CHP,small hydroelectric,and pumped-storage resources.The
purpose of this portfolio is to evaluate the cost of an all-renewable portfolio.The total nameplate
capacity of this portfolio is 1,032 MW.
Details on how the portfolios were modeled and the assumptions used in the analysis are provided in
Chapter 9.Chapter 9 also presents the risk analysis and the process that lead to the selection of a
preferred and alternate portfolio for each 10-year period.
Page 92 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
9.MODELING ANALYSIS AND RESULTS
Idaho Power uses the AURORAxmp®
(AURORA)electric market model as the primary
tool for modeling resource operations and
determining operating costs for the 20-year
planning horizon.AURORA modeling results
provide detailed estimates of wholesale market
energy pricing and resource operation and
emissions data.
The AURORA software applies economic
principles and dispatch simulation to model the
relationships between generation,transmission,
and demand to forecast market prices.
The operation of existing and future resources is
based on forecasts of key fundamental elements,
such as demand,fuel prices,
hydroelectric conditions,and operating characteristics of new resources.Various mathematical
algorithms are used in unit dispatch,unit commitment,and regional pool pricing logic.The algorithms
simulate the regional electrical system to determine how utility generation and transmission resources
operate to serve load.
Multiple electricity markets,zones,and hubs can be modeled using AURORA.Idaho Power models the
entire WECC when evaluating the various resource portfolios for the IRP.A database of WECC data is
maintained and regularly updated by the software vendor EPIS,Inc.Prior to starting the IRP analysis,
Idaho Power updates the AURORA database based on available information on generation resources
within the WECC and calibrates the model to ensure it provides realistic results.Updates to the database
generally add additional hourly operational detail and move away from flat generation output,de-rates,
and fixed-capacity factors.The updates also incorporate detailed generating resource scheduling,
which results in a model that is more deterministic in character and provides a more specific operational
view of the WECC.
Economic Evaluation Components and Assumptions
The total cost of each portfolio analyzed for the IRP is determined by four components:1)variable
operating costs (determined with AURORA),2)the capital cost of new resources in each portfolio,
Highlights
Idaho Power uses the AURORA Electric Market Model as the primary tool for determining
future resource build out of operations and portfolio cost impacts for the 20-year IRP
planning period.
The 2011 IRP incorporates anticipated federal RES legislation and plans for the resources
necessary to comply with the legislation.
Quantitative risk factors analyzed in the 2011 IRP include the cost of carbon emissions,
natural gas prices,capital cost,load growth,DSM program performance,REC prices,
electric market prices,and third-party transmission subscription.
computer modeling is an essential part of preparing the IRP.
2011 IRP Page 93
9.Modeling Analysis and Results Idaho Power Company
3)the cost oftransmission upgrades necessary for each portfolio,and 4)the value of RECs generated by
renewable resources in each portfolio.In addition,numerous financial assumptions are necessary to
calculate the total portfolio cost.The financial assumptions used in the 2011 IRP are shown in Table 9.1.
Table 9.1 Financial assumptions
Plant Operating (Book)Life 30 Years
Discount rate (weighted average cost of capital)7.00%
Composite tax rate 39.10%
Deferred rate 35.00%
General O&M escalation rate 3.00%
Emissions adder escalation rate 2.50%
Carbon adder escalation rate 5.00%
Annual property tax escalation rate (%of investment)0.29%
Property tax escalation rate 3.00%
Annual insurance premium (%of investment)0.31%
Insurance escalation rate 2.00%
AFUDC rate (annual)7.00%
Production tax credit escalation rate 3.00%
AURORA Modeling
Idaho Power uses the AURORA model to evaluate the variable cost of production for existing and
committed resources along with the new resources proposed in the portfolios.Operational constraints
are approximated along with energy purchases and sales in the regional market.While more extreme
planning criteria are used to determine the average energy and peak-hour capacity of existing resources
in the load and resource balance,median or 50th percentile conditions are used in AURORA for
modeling load and hydroelectric generation.The following sections describe additional variable
operating costs also included in the analysis.
Carbon Cost
The potential cost of carbon emissions is accounted for in the IRP by applying a carbon adder or tax.
The carbon adder is applied to all carbon-emitting resources within the WECC starting in 2015.
Including the carbon adder cost for all carbon-emitting resources in the AURORA model results in
market prices that reflect the anticipated future cost of carbon emissions.Therefore,the cost of carbon
emissions is captured for specific resources and in the price of market purchases and sales.
The carbon adder increases the dispatch cost of each carbon-emitting resource in AURORA,
which affects how the model economically dispatches resources.Once a unit is dispatched,the carbon
adder can also affect how much generation is produced from each unit.Past experience shows the
carbon adder has to be very large to completely curtail units;however,smaller carbon adders reduce
generation compared to a similar unit with no carbon adder.Additional details on the carbon adder and
the values used for the high,expected,low and no carbon scenarios can be found in Chapter 6.
Transmission Modeling
The need for additional power from new resources or market purchases will require additional
transmission.Idaho Power faces severe transmission capacity limitations when evaluating additional
supply-side resources.These transmission limitations were a major factor in evaluating supply-side
resources,such as Bennett Mountain,Danskin,the Elkhorn Valley Wind Project,and Langley Gulch in
previous JRPs.
Page 94 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
The 2011 IRP uses different transmission assumptions for each of the 10-year periods.For the first
1 0-year period,transmission capacity is increased only to the extent necessary to deliver the energy from
the new resources to the Treasure Valley in southwest Idaho.Idaho Power has adopted a conservative
approach for the first 10 years and includes additional transmission capacity for market purchases only
when market-need is specifically identified in a resource portfolio.
For the second 10-year period,transmission capacity identified in the preferred portfolio from the first
10-year period is included,plus any additional transmission necessary for each resource portfolio in the
second 10-year period.
Natural Gas Transportation Cost
For the 2011 IRP analysis,the cost of gas transportation for existing resources,including the
Langley Gulch project,is based on the cost of existing pipeline capacity.Because existing pipeline
capacity is close to being fully utilized,the transportation cost for new gas resources reflects the cost of
adding additional pipeline capacity for delivery to Idaho Power’s service area.
The increased cost for new pipeline capacity is approximately twice the current tariff rate.For the IRP,
the additional cost for new pipeline capacity was added to the cost of each new gas resource outside the
AURORA model.Additional details on transportation costs can be found in Appendix C—Technical
Appendix.The natural gas price forecast described in Chapter 6 is based on a Sumas hub price and does
not include any transportation cost.
Capital Cost
Idaho Power uses an internal financial analysis model to evaluate the capital cost of new resources and
to estimate the associated revenue requirements.Estimated construction costs are escalated at the base
inflation rate of 3 percent per year and included in the model.
Estimated capital costs are translated into an annual revenue requirement that corresponds to the size
and timing of the investment required for each resource.The annual revenue requirement for each
resource portfolio is then discounted and summed.The annual revenue requirement analysis has the
benefit of matching the annual revenue requirements with the corresponding annual energy benefits.
The annual revenue requirement analysis eliminates the need to estimate resource values beyond the
study period because resource capital costs and resource benefits are matched annually within the
study period.
Transmission Cost
For the IRP,the total estimated transmission cost of each resource portfolio is used to determine the
annual transmission revenue requirement,and the NPV of the cost is included in the portfolio
evaluation.A more detailed presentation of the transmission assumptions for each portfolio can be found
in Appendix C—Technical Appendix.
The degree of Idaho Power’s investment participation differs between the portfolios,and the costs are
included according to the transmission subscription in each resource portfolio.Each transmission
subscription represents an Idaho Power equity investment in the project.Each equity investment
translates into a revenue requirement,and the revenue requirements for the transmission investments are
estimated and included in the portfolio total cost comparisons.Idaho Power’s investment defines the
revenue requirement,and the NPV of the revenue requirement is included as part of the expected-case
cost of each resource portfolio.The NPV of any possible transmission capacity sales to third parties are
included in the risk analysis as project benefits.
Two categories of transmission are accounted for in the IRP.The first is the transmission that integrates
resources and allows energy to flow from a generation resource to Idaho Power’s load centers.
2011 IRP Page 95
9.Modeling Analysis and Results Idaho Power Company
An example of this type oftransmission are the transmission lines that deliver generation from the
Hells Canyon Complex to the load center in the Treasure Valley.
Interstate transmission is the second transmission type and is generally higher voltage and covers greater
distances.Interstate transmission is planned on a regional basis to meet the needs of electric utilities and
the needs of third parties requesting transmission service.Very little interstate transmission has been
constructed in the last 30 years.Examples of interstate transmission include the proposed Gateway West
and Boardman to Hemingway projects.
In the first 10-year portfolios (2011—2020),only portfolio 1-3 Boardman to Hemingway included a
proposed interstate transmission project.This was the Boardman to Hemingway project with an on-line
date of 2016 and Idaho Power’s share of the line at 450 MW.For the second 10-year period
(202 1—2030),all the portfolios assume that the preferred portfolio 1-3 Boardman to Hemingway is built,
and only portfolios 2-8 Pacific Northwest Transmission and 2-9 Eastside Transmission included
additional interstate transmission projects.In portfolio 2-8 Pacific Northwest Transmission,Idaho Power
adds 500 MW of additional capacity between Idaho and the Pacific Northwest in 2022.In portfolio
2-9 Eastside Transmission,the Gateway West project is built in 2022,allowing Idaho Power to have an
additional 500 MW of transmission capacity for market purchases from the east side of Idaho Power’s
service area.
Renewable Energy Certificates
For the 2011 IRP analysis,each portfolio is designed to substantially comply with the Renewable
Electricity Promotion Act of2O]O (S.3813)introduced in Congress in September 2010,by Senator
Jeff Bingaman (D—New Mexico).Under the proposed bill,an initial renewable requirement of 3 percent
would begin in 2012 and would increase to 15 percent by 2021.
Because it is impossible to exactly match the number ofRECs Idaho Power would need to meet this
requirement with the amount of RECs created by individual resources,the value of additional RECs and
the cost of purchasing RECs if short is captured in the total cost of each portfolio.With the exception of
portfolio 2-4 CCCT &Wind,all the portfolios analyzed had a net benefit from the value of surplus
RECs.This value is shown as a negative cost in Tables 9.2 and 9.3.The forward price curve for RECs
used in the analysis is presented in Chapter 6.
Expected-Case Portfolio Analysis Results
The NPV total portfolio cost is calculated by summing the variable operating costs calculated
in AURORA,the capital and transmission costs,and the value of RECs from each portfolio.
The expected-case NPV total portfolio cost of each of the portfolios analyzed for the first 10-year period
are shown in Table 9.2.
Under expected case conditions,for the first 10-year period,portfolio 1-3 Boardman to Hemingway is
the lowest cost portfolio at $3.18 billion,while portfolio 1-4 SCCT is the second lowest at $3.22 billion.
These results are similar to the results ofthe 2009 IRP analysis where the Boardman to Hemingway
project was evaluated against a portfolio of SCCT resources that could be built close to load centers.
Page 96 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
Table 9.2 Expected case total portfolio cost (2011—2020)
NPV Portfolio Costs (2011 dollars,000’s)
Variable
Base Case (AURORA)Capital Transmission RECs Total
1-1 Sun &Steam $3,041,735 $552,164 $17,925 ($24,396)$3,587,428
1-2 Solar $2,924,308 $683,497 $20,865 ($32,033)$3,596,637
1-3 Boardman to Hemingway $3,088,318 $0 $98,929 ($9,940)$3,177,308
1-4 SCCT $3,099,029 $108,835 $22,748 ($9,940)$3,220,672
1-5 CCCT $3,115,384 $188,415 $19,546 ($9,940)$3,313,406
1-6 CHP $3,162,397 $190,436 $15,798 ($9,940)$3,358,691
1-7 Balanced $3,085,533 $293,344 $16,349 ($15,384)$3,379,843
1-8 Pumped Storage $3,093,051 $416,887 $23,099 ($15,206)$3,517,831
1-9 Distributed Generation $3,099,323 $114,153 $22,748 ($9,940)$3,226,284
Portfolio 1-3 Boardman to Hemingway capital cost is included in the transmission column.
Table 9.3 shows the NPV total cost of each portfolio analyzed for the second 10-year period.
Under expected-case conditions,the NPV cost of portfolios 2-8 Pacific Northwest Transmission and
2-9 Eastside Transmission are close at $3.30 billion and $3.32 billion respectively.Portfolio 2-6
Balanced 1 is the next lowest-cost portfolio at $3.50 billion.
Table 9.3 Expected case total portfolio cost (2021-2030)
NPV Portfolio Costs (2011 dollars,000’s)
Variable
Base Case (AURORA)Capital Transmission RECs Total
2-1 Nuclear $2,548,176 $1,806,082 $25,300 ($713)$4,378,845
2-2 IGCC $2,665,714 $958,555 $59,523 ($2,908)$3,680,885
2-3 SCCT &Wind $3,079,453 $515,846 $27,147 ($2,545)$3,619,901
2-4 CCCT &Wind $3,095,043 $498,966 $26,688 $246 $3,620,943
2-5 Hydro &CHP $3,014,673 $880,443 $27,622 ($6,669)$3,916,069
2-6 Balanced I $2,937,689 $555,581 $10,646 ($2,646)$3,501,270
2-7 Balanced 2 $2,952,566 $668,771 $10,849 ($8,840)$3,623,346
2-8 Pacific Northwest Transmission*$2,933,037 $335,516 $29,278 ($1,773)$3,296,059
2-9 Eastside TransmissionS $2,929,353 $335,516 $53,373 ($1,773)$3,316,469
2-10 Renewable $2,910,691 $1,112,624 $10,504 ($11,537)$4,022,282
2-8 Pacific Northwest Transmission and 2-9 Eastside Transmission capital costs are included in the transmission column.
Portfolio Carbon Emissions
Figure 9.1 shows the average CO2 intensity for each portfolio analyzed for the first 10-year period.
The average intensity for each portfolio includes emissions from new resources in addition to emissions
from Idaho Power’s existing and committed resources.The intensity rates range from approximately
775 lbs-per-MWh to 805 lbs-per-MWh and are all well below Idaho Power’s 2005 intensity rate of
1,194 lbs-per-MWh.
2011 IRP Page 97
9.Modeling Analysis and Results Idaho Power Company
Figure 9.1 Average CO2 intensity by portfolio (2011—2020)
Figure 9.2 shows similar information for the portfolios analyzed for the second 10-year period,
which assumes portfolio 1-3 Boardman to Hemingway is built.The intensity rates range from
approximately 660 lbs-per-MWh to 745 lbs-per-MWh,which shows a further reduction from the
portfolios analyzed in the first 10-year period.
760
740
720
—700
680
.0_J
660 —
640
620 -—
600
2-1 Nuclear 2-2 IGCC 2-9 EIS 2-8 PNW 2-6 Balanced 2-3 SCCT &2-4 CCCT &2-10 2-7 Balanced 2-5 Hydro &
TransmissionTransmission 1 Wind Wind Renewable 2 CHP
Figure 9.2 Average CO2 intensity by portfolio (2021—2030)
The lower emissions intensity rates presented in Figures 9.1 and 9.2 are the result of the carbon adder
used in the IRP analysis in addition to the reduced operation of Idaho Power’s coal resources at times
when market prices are lower than the dispatch cost of the coal resources.These results also indicate a
majority of the risk associated with the future regulation of carbon is related to Idaho Power’s
existing resources.
Risk Analysis and Results
Idaho Power evaluated all the resource portfolios identified in the 2011 IRP for both qualitative and
quantitative risks.Risk analysis identifies resource portfolios that perform well in a variety of possible
future scenarios and to reduce total risk.
One of the major risks is load-growth uncertainty associated with the present economic conditions.
Economic growth has slowed considerably in Idaho Power’s service area,and there has been extensive
speculation regarding the duration ofthe economic downturn.A quick return to the economic growth
rates of the past 20 years will require additional generation resources to meet load.
.0-J
805 --
800 --
795
790
785
780
775
770
765 —
760 —
755
__
———
______E-____
————
__1—_
—.—..—
__
———————————————————————
1-2 Solar 1-1 Sun 1-3 B2H 1-7 1-5 CCCT 1-8 1-4 SCCT 1-9 1-6 CHP
and Steam Balanced Pumped Distributed
Storage Gen
T
Page 98 2011 IRP
Idaho Power Company 9.Modeiing Analysis and Results
The other factor affecting load growth is the effectiveness of Idaho Power’s DSM programs.
Idaho Power projects continued success with DSM programs,but the success is dependent on overall
economic conditions as well as program funding and consumer preferences.A lower realization factor
for DSM programs will increase load and require additional generation resources.
Electric vehicles are another factor having the potential to increase load.Study reports completed by the
Electric Power Research Institute (EPRI)and Oak Ridge National Laboratory were used to estimate load
impacts associated with electric-vehicle charging.The impact on the load forecast is assumed to be
relatively small—about 9 aMW in 2020,reaching 43 aMW at the end of the forecast period in 2030.
Further discussion on electric vehicles is contained inAppendixA—Sales andLoad Forecast.
Many of the other risk factors are regulatory in nature.Idaho Power faces regulatory uncertainty
associated with carbon regulation and a federal RES.Idaho Power is planning for a resource future that
restricts the quantity of carbon that can be released into the earth’s atmosphere.The proposed carbon
legislation is anticipated to restrict the quantity of carbon emissions and increase the price of RECs.
Limited or ineffective carbon legislation could lead Idaho Power and other utilities to continue to
generate from traditional,fossil-fuel plants.
Natural gas prices are primarily affected by supply and demand;however,economic growth,
load growth,carbon legislation,and transmission availability will also influence prices.Presently,
natural gas prices are relatively low.However,Idaho Power analyzed the portfolio costs under a
scenario where natural gas is considerably more expensive.
Qualitative Risk Analysis
Qualitative analysis preferences are chosen through judgment and do not lend themselves to the
deterministic quantitative metrics.Idaho Power discussed the qualitative factors in public forums,
including the IRPAC meetings,as well as in regulatory workshops and proceedings.Some of the
qualitative risks,such as planning for new large loads,may be considered policy issues and are
discussed in Chapter 1.The qualitative risk of schedule delays and siting issues associated with the
Boardman to Hemingway transmission project are addressed by identifying both a preferred and
alternate resource portfolios.Many of the qualitative risks,such as carbon policy,resource technology,
and market price risk,are covered in the quantitative analysis through variations in carbon emissions
prices,capital cost,and natural gas prices.In general,Idaho Power addresses the qualitative risks
through policy discussions with the IRPAC and regulatory agencies or by associating the risk with proxy
variables in the quantitative analysis.
Quantitative Risk Analysis
For the 2011 IRP,Idaho Power analyzed high,low,and expected cases for the following risk factors:
1)carbon,2)natural gas prices,3)capital cost,4)DSM variability,5)load variability,and 6)REC
prices.In addition to the high,low,and expected cases for carbon,a no-carbon cost case was
also analyzed.
The results of the quantitative risk analysis show a change from the expected cost of each portfolio for
each risk factor analyzed.The results of the quantitative risk analyses are presented in terms of NPV
total portfolio cost resulting in a side-by-side comparison of the range of potential costs for each
risk factor.
Carbon Risk (2011—2020)
Four carbon adder scenarios,an expected case and three alternate cases,were analyzed as part of the
2011 IRP.A description of the four cases is contained in Chapter 6.With respect to the cost of carbon,
the nine portfolios perform relatively similarly for the three alternate levels of carbon cost considered.
2011 IRP Page 99
9.Modeling Analysis and Results Idaho Power Company
As expected—given their renewable focus,the 1-1 Sun and Steam and 1-2 Solar portfolios are not as
adversely affected by high carbon costs (costs estimated to increase slightly less than costs for other
portfolios),nor are they benefitted as much by lower or zero carbon costs.However,the modest
differences between portfolios in comparing the estimated cost effects associated with the levels of
carbon cost suggest that much of the cost of carbon is driven by the operation of Idaho Power’s existing
and committed resources.Thus,based on the varying levels of carbon cost risk considered,none of the
portfolios are likely to lead to a catastrophic financial outcome occurring as a result of carbon costs
deviating from expected costs.
1-3 B2H 1-4 SCCT 1-5 CCCT 1-6 CHP 1-7 Balanced 1-8 Pumped 1-9
Storage Distributed
Generation
No Carbon (Net of Low Carbon)CI High Carbon
Figure 9.3 Carbon risk analysis results (201 1—2020)
Natural Gas Price Risk (2011—2020)
Three natural gas price scenarios were analyzed for the 2011 IRP—high,expected,and low.Additional
details of the natural gas price scenarios are presented in Chapter 6,and the results are presented in
Figure 9.4.As expected,portfolios having SCCT,CCCT,or CHP resources show a greater range of risk
associated with natural gas prices.The portfolios having elevated risk related with higher-than-expected
natural gas prices include 1-1 Sun and Steam,1-6 CHP,and 1-7 Balanced.Conversely,these portfolios
are likely to experience greater cost decreases in the event of lower-than-expected natural gas prices.
The risk analysis also indicates that the 1-5 CCCT portfolio is projected to benefit disproportionately
from lower-than-expected natural gas prices,because the CCCT is economically dispatched more
frequently under the low natural gas price scenario.
$150 ———.—-——---______
___________
$100
.!$50
0
2 so
0
($50)
0
($100)
($150)
($200)
1-3 B2H 1-4 SCCT 1-5 CCCT 1-6 CHP 1-7 Balanced 1-8 Pumped 1-9
Storage Distributed
Generation
0 Low Natural Gas Prices U High Natural Gas Prices
Figure 9.4 Natural gas price risk analysis results (2011—2020)
$200
0
$0
C0
($200)
($400)
($600)
s9s85F62s5sm8s168
($149)($147)($158)($157)($154)($152)($152)($156)($156)
——
4>($519y ç>3)()6)554)
1-1 Sun &1-2 Solar
Steam
0 Low Carbon
1-1 Sun &1-2 Solar
Steam
Page 100 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
Capital Cost Risk (2011—2020)
For the 2011 IRP,Idaho Power introduced asymmetry into the estimates of capital cost risk.
The introduction of this bias is consistent with comments received from the IRPAC suggesting that
development costs for particular resources do not have equal increase/decrease potential.Figure 9.5
illustrates the assumed range in capital costs for considered generating resources,where the horizontal
dash for each resource is the expected-case cost in dollars per kW,and the vertical bar reflects the
potential capital cost risk for each resource relative to its expected-case cost.Figure 9.5 includes
resources used in portfolios for both the first and second 10-year periods of the analysis.
$8,000
$7,000
$6,000
$5,000
$4,000
$3,000
$2,000
$1,000
$0
H
r ——
0 0)0)0)2 F-H >9 a)tC E a Ci .Z 0.0.$0)
•3 >,a-2 -a <C-)C.)it -0 a)x 0.Cl)C’)zC
ci)C.))-0zIiC’)Cl)a0_D
0.
Figure 9.5 Capital cost risk analysis
The results of the capital cost risk analysis demonstrate that resource portfolios comprised of
high-capital-cost resources have the greatest potential for deviating from expected-case portfolio cost
estimates.The asymmetry in the capital-cost risk is particularly evident for portfolio 1-1 Sun and Steam,
1-2 Solar,and 1-8 Pumped Storage.Solar resources (thermal and PV)are expected to have a greater
potential for capital cost decrease versus cost increase;consequently,the two,solar-based portfolios are
likely to have the greatest cost-reduction potential.Solar-powered resources are also estimated to have
substantial potential for increased capital costs.Consequently,the potential cost increase for portfolios
containing solar resources either matches or exceeds that of other portfolios.The results of the capital-
cost risk analysis are presented in Figure 9.6.
$150
$100
$50
0
•($50)
($100)
($150)
($200)
($250)
1-5 CCCT 1-6 CHP 1-7 Balanced 1-8 Pumped 1-9
Storage Distnbuted
Generation
DLow Capital Cost High Capital Cost
Figure 9.6 Capital-cost risk analysis results (201 1—2020)
1-1 Sun &1-2 Solar 1-3 B2H 1-4 SCCT
Steam
2011 IRP Page 101
9.Modeling Analysis and Results Idaho Power Company
High DSM (%Change in Load)
——-j —-Low DSM (%Change in Load)———----——
—-
—-
—-.---
--N:EzzZz:zzz
-10.0%
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Figure 9.7 DSM variability risk analysis
Figure 9.8 indicates that deviations of DSM program performance from the expected-case forecast have
a relatively small impact on total portfolio costs,and the estimated impacts are relatively uniform
across portfolios.
$100 --____________________
_______________
.$50 $58 $60 $59 —-$58 $60
o
($118)($116)($118)($118 ($119)
($150)——-———-——---———--
1-1 Sun &1-2 Solar 1-3 B2H 1-4 SCCT 1-5 CCCT 1-6 CHP 1-7 Balanced 1-8 Pumped 1-9
Steam Storage Distributed
Generation
HighDSM DL0wDSM
Figure 9.8 DSM variability risk analysis results (201 1—2020)
Risk Due to Load Variability (2011—2020)
For the 2011 IRP,high-and low-load risk scenarios were derived to analyze the impact of deviations in
the IRP load forecast.Figure 99 shows the range in load analyzed as a percentage of the expected-case
load forecast.For the high-case,loads are approximately 10 percent higher than the expected-case
forecast by the end of the planning period in 2030.For the low-case,loads are nearly 10 percent lower
than the expected-case forecast in 2030.
Risk Due to DSM Variability (2011—2020)
The 2011 IRP risk analysis also evaluated the costs associated with higher-than-expected and
lower-than-expected levels of DSM.For the high-DSM case,DSM levels resulting in load being
8 percent lower than expected are reached by the mid-2020s.For the low-DSM case,lower than
expected DSM levels resulting in load being 4 percent higher-than-expected are reached by the
mid-2020s.The DSM risk scenarios analyzed are shown in Figure 9.7.
6.0%
0.0%
4.0%
2.0%
-i
0
0
xU.’
-2.0%
0
-4.0%
-6.0%
-8.0%
Page 102 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
15%
10%
-10%
—EHigh Load %Change
Low Load %Change —-——--—-----————---H
I j L_
_____________
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Figure 9.9 Load variability risk analysis
Figure 9.10 indicates that load deviations from the expected-case forecast have the potential to
significantly impact portfolio costs.However,the estimated impacts are fairly uniform across portfolios,
suggesting equal exposure with respect to load risk for the portfolios.Furthermore,the analysis accounts
only for power supply costs and does not include revenues associated with retail sales being higher orlowerthanexpected.
$400
—
$300
(I)
cu $200
0
$100
0
U,C0
($100)
($200)
($300)—-—-—--—-
_____—-—
—-——-—-———-——--—————
_____
———
1-2 Solar 1-3 B2H 1-4 SCCT 1-5 CCCT 1-6 CHP 1-7 Balanced 1-8 Pumped 1-9
Storage Distributed
Generation
DLow Load DI-hgh Load
Figure 9.10 Load risk analysis results (201 1—2020)
REC Price Risk (2011—2020)
In addition to an expected case for REC prices,high-and low-price scenarios were also analyzed.
Additional details on the REC price scenarios is presented in Chapter 6.The results of the analysis
indicate none of the portfolios are exposed to severe risk potential with respect to REC price.This isexpectedbecauseeachportfoliowasdesignedtohaveapproximatelythenumberofRECsneededto becompliantwithafederalRES.
Because a majority of the portfolios have surplus RECs,high REC prices result in lower portfolio costsrelativetotheexpectedRECpricecase.Similarly,RECs having little or no value leads to higher
portfolio costs.The small differences between portfolios follow expected trends.For example,portfolios
that generate more RECs (1-1 Sun and Steam and 1-2 Solar)will see a greater cost decrease as aconsequenceofhighRECprices.Conversely,the cost of these portfolios increases more under the lowRECpricescenario.
1-1 Sun &
Steam
2011 IRP Page 103
9.Modeling Analysis and Results Idaho Power Company
$40
$20Is
$0
($20)
($40)
($60)
($80)
1-2 Solar 1-3 B2H 1-4 SCCT 1-5 CCCT 1-6 CHP 1-7 Balanced 1-8 Pumped 1-9
Storage Distributed
Generation
DHighREC Price DL0wREC Price
Figure 9.11 REC price risk analysis results (2011—2020)
Quantitative Risk Analysis Summary (2011—2020)
Several conclusions can be drawn from the quantitative risk analysis performed for the first 10-year
period.Those conclusions include the following:
•Portfolios with solar resources (1-1 Sun and Steam and 1-2 Solar)could have substantially
lower-than-expected capital costs,and therefore lower total portfolio costs.However,this lower
cost potential is insufficient to overcome the disparity between the expected costs of these
portfolios and the expected cost ofportfolio 1-3 Boardman to Hemingway.
•The portfolios are designed for REC compliance,and,consequently,carry minimal exposure to
REC price risk.
•Portfolio 1-3 Boardman to Hemingway has minimal potential for cost increases or decreases
associated with capital costs deviating from expected costs.
•A substantial portion of the carbon cost risk is driven by Idaho Power’s existing and
committed resources.
The following sections present a similar analysis for the second 10 year period (2021—2030).
Carbon Risk (2021—2030)
Portfolio 2-1 Nuclear,with no incremental carbon-producing resources,has the least potential for cost
deviations as a result of the high,low,and no carbon cost scenarios.However,the differences between
this portfolio and the other portfolios,with respect to the cost of carbon,are relatively modest.Again,
this suggests that carbon risk is primarily due to Idaho Power’s existing and committed resources.
Figure 9.12 shows the results of the carbon risk analysis for the second 10-year period.
$600
a $400:
($200)
a ($400)
($600)
($800)
Figure 9.12 Carbon risk analysis results (2021—2030)
1-1 Sun &
Steam
($1000)----------—---—--
-—-——-—
2-1 Nuclear 2-2 IGCC 2-3 SCCT &2-4 CCCT &2-5 Hydro &2-6 Balanced 1 2-7 Balanced 2 2-8 PNW 2-9 East Side 2-10
Wind Wind CHP Transmission Transmission Renewable
0Low Carbon 0 No Carbon (Net of Low Carbon)0High Carbon
Page 104 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
Natural Gas Price Risk (2021—2030)
Lower-than-expected natural gas prices lead to portfolio costs that are lower than those occurring
under expected natural gas price conditions.The portfolio cost reductions are greatest for the portfolios
containing new gas resources.Under higher-than-expected natural gas prices,portfolio 2-5 Hydro
and CHP and portfolio 2-7 Balanced 2 have the highest risk under a high-gas-price scenario.
These portfolios contain CHP resources,which are typically operated at high-capacity factors to meet
the needs of the steam host.Portfolio 2-6 Balanced 1 has a modest potential for cost deviations
occurring in response to different-than-expected natural gas prices.Figure 9.13 shows the results of the
natural gas price risk analysis for the second 10-year period.
$100
$50
$0
($50)
($100)
($150)
($200)
($250)
DLow Natural Gas 0HIgh Natural Gas
1n portfolio 2-1 Nuclear,high natural gas prices results in a reduced portfolio cost of ($3).
Figure 9.13 Natural Gas price risk analysis results (2021—2030)
Capital Cost Risk (2021—2030)
Figure 9.14 shows the range of costs for portfolios due to capital cost risk.The results of the analysis
shows that nuclear generating facilities have considerably greater potential for capital-cost increases
versus their potential for cost decrease.This is evident in the potential cost increase of portfolio
2-1 Nuclear,which could have an NPV cost of $1.3 million more than expected under the high
capital-cost scenario.Portfolio 2-2 IGCC also has a substantially greater risk for cost increases relative
to other portfolios.Portfolio 2-6 Balanced 1 is among the group ofportfolios having the lowest exposure
to capital cost risk.
$1,300
$1,100
$900
$700
$500
$300
$100
($100)
($300)
Figure 9.14 Capital cost risk analysis results (2021—2030)
Risk Due to DSM Variability (2021—2030)
The 10 resource portfolios considered for the second 10 years contain the same energy efficiency
and demand response programs.The potential for portfolio costs to deviate as a result of
different-than-expected DSM program performance is very similar between the portfolios.
ci,
cci
00
0
a00
2-1 Nuclear 2-2 IGCC 2-3 SCCT &2-4 ccci a 2-5 Hydra &2-6 Balanced 1 2-7 Balanced 2 2-8 PNW 2-9 East Side 2-10WindWindCHPTransmissionTransmissionRenewable
2-1 Nuclear 2-2 IGCC 2-3 sccT &2-4 cccT &2-5 Hydra &2-6 Balanced 1 2-7 Balanced 2 2-8 PNW 2-9 East Side 2-10WindWindCHPTransmissionTransmissionRenewable
CLow CapItal Cost D High CapItal Cost
2011 IRP Page 105
Idaho Power Company9.Modeling Analysis and Results
Thus,the DSM risk is not a characteristic that can be used to discriminate between the different
resource portfolios.
$300 ——-—-——————-—-—---——--—--—__________
$200
•$100
$0
‘($100)
($200)
($300)
($400)
($500)
HighDSM LowDSM
Figure 9.15 DSM risk analysis results (2021—2030)
Risk Due to Load Variability (2021—2030)
Different-than-expected load conditions also increase or decrease costs similarly between the portfolios
considered for the second 10 years.This suggests that the portfolios have equal exposure to load
variability risk.
$600
$400 -
$200 —00
$0a
5°($200)
($400)-
....,
$583
—
($429)
$586
($434)
...
$591
($437)
—
$584
($434)
$585
—
($435)
$586
($434)
$584
—
($433)
—.-..-.
$586
—
($437)
($600)
2-1 Nuclear 2-2 10CC 2-3 SCCT &2-4 CCCT &2-5 Hydro &2-6 Balanced 1 2-7 Balanced 2 2-8 PNW 2-9 East Side 2-10
Wind Wind CHP Transmission Transmission Renewable
DLow Load 0 High Load
Figure 9.16 Load variability risk analysis results (2021—2030)
REC Price Risk (2021—2030)
As seen in the analysis for the first 10-year period,REC prices have a minimal impact on total portfolio
costs.Portfolio 2-10 Renewable produces the greatest amount of surplus RECs and,consequently,
has the highest potential for a cost decrease as a result of higher-than-expected REC prices.Conversely,
this portfolio has the greatest risk for increased costs due to lower-than-expected REC prices.However,
the potential cost changes due to the high-and low-REC price scenarios are similar between portfolios
and relatively small compared to other risk factors.This suggests the portfolios are similarly exposed to
REC price risk,which is minimal.Figure 9.17 shows the results of the REC price risk analysis for the
second 10-year period.
____
$20 ——-——-—-—-—————--—--——--.—.-———---_______-
$15 —--—-——--—--——--——_________
$10
$5
$0
($5)
($10)
($15)
($20)
($25)
DHi9hREC Price DLowREC Pnce
ln portfolio 2-4 CCCT &Wind,a low REC price results in a reduced portfolio cost of ($02).
Figure 9.17 REC price risk analysis results (2021 —2030)
$583
—
($435)
$582
—
($44)
2-1 Nuclear 2-2 10CC 2-3 SCCT &2-4 CCCT &2-5 Hydra &2-6 Balanced 1 2-7 Balanced 2 2-8 PNW 2-9 East Side 2-10
Wind Wind CHP Transmission Transmission Renewable
2-1 Nuclear 2-2 10CC 2-3 SCCT &24 CCCT &2-5 Hydra &2-6 Balanced 1 2-7 Balanced 2 2-8 PNW 2-9 East Side 2-10
Wnd Wind CHP Transmission Transmission Renewable
Page 106 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
Quantitative Risk Analysis Summary (2021—2030)
Under higher-than-expected capital costs,portfolios 2-1 Nuclear and 2-2 IGCC have the greatest
exposure to higher costs relative to the other portfolios.With this exception,the differences between the
portfolios with respect to the risk factors considered are generally modest,suggesting that the portfolios
contain a similar amount of risk exposure.Other conclusions from the 2021—2030 risk analysis include
the following:
•All portfolios are designed to be compliant with a federal RES and,consequently,carry minimal
exposure to REC price risk.
•A substantial portion of the carbon cost risk is driven by Idaho Power’s existing and committed
resources.However,there is some incremental carbon risk associated with all the portfolios
except portfolio 2-1 Nuclear.This incremental exposure is evidenced by the greater potential for
cost increase/decrease of the other portfolios relative the nuclear portfolio.
•Portfolio 2-10 Renewable has the greatest potential for total cost decrease occurring as a result of
lower-than-expected capital costs,reflecting the expectation that solar-powered resources have a
greater potential for capital cost decreases than increases.
•The 2-6 Balanced 1,2-8 PNW Transmission,and 2-9 Eastside Transmission portfolios are
among the group of portfolios having the lowest exposure to capital cost risk.
Stochastic Analysis
Stochastic analysis is a statistical technique often used in resource planning.The OPUC recognized the
benefits of stochastic analysis and included stochastic analysis as part of its Resource Planning
Guidelines (Oregon Docket UM 1056,Order 07-047,February 9,2007,Appendix A,page 4,
Guideline 4 b).The entire Oregon order listing the resource planning guidelines is included in Appendix
C—Technical Appendix.Idaho Power has used a probabilistic analysis to model loss of load in the 2011
IRP as well as in previous resource plans.Idaho Power applied a stochastic analysis to the natural gas
price forecast in the 2009 IRP,and the 2011 JRP is Idaho Power’s first application of a stochastic
analysis to the expected cost ofthe various resource portfolios.
Idaho Power modeled the combined effects of the risk variables on the resource portfolio costs for each
of the 10-year periods.The results of the stochastic analysis were then used as the determining factor in
identifying the preferred and alternate portfolios.
To complete the stochastic analysis,Idaho Power identified six risk variables,calculated the incremental
resource portfolio cost at the extremes of the range for each risk variable,divided the cost range for each
risk variable into five sections,and randomly sampled from the five sections to calculate a distribution
of resource portfolio costs.The key points for the analysis of the first 10-year period include
the following:
•Nine resource portfolios
•Six risk variables
•Five quintile segments for the range of each risk variable
•100,000 random samples
•One distribution of costs for each resource portfolio
2011 IRP Page 107
9.Modeling Analysis and Results Idaho Power Company
Risk Variables
Idaho Power identified six risk variables that are included in the stochastic analysis,1)natural gas price,
2)REC price,3)carbon cost,4)load variation,5)DSM variation,and 6)capital cost.Idaho Power and
the IRPAC identified a range for each of the six variables,and Idaho Power applied the range to each
risk variable and calculated the range ofportfolio costs for the risk variable using the AURORA model.
For example,in the year 2020 natural gas prices were expected to be within the approximate range of
$6.50 to $10.50 per MMBtU.Idaho Power then used AURORA and the identified range to calculate the
cost of each resource portfolio at the two natural gas price extremes.For portfolio 1-3 Boardman to
Hemingway the values are—base cost:$86 million;high natural gas price:$96 million;and low natural
gas price:$108 million.
Portfolio 1-3 Boardman to Hemingway shows an interesting result.Ofthe three possibilities analyzed,
the base cost with intermediate natural gas prices had the lowest overall cost.Under high gas prices,
Idaho Power paid more for energy,and the costs increase;under low gas costs,off-system energy sales
were not as profitable for Idaho Power and its customers.
In the case ofnatural gas prices,the range used in the stochastic analysis was from the low value of
$86 million to the high value of $108 million,or a range of $22 million.Similarly,a range was
calculated for each of the six risk variables for all nine resource portfolios in the first 10 years.
The low value for most of the risk variables in most of the resource portfolios was lower than the
base portfolio cost.
After determining the high and low values for each risk variable,the portfolio cost range was divided
into five equal segments.For the Boardman to Hemingway portfolio example,the range from
$86 million to $108 million was divided into five segments with each segment equal to $4.4 million.
Similarly,the range was divided into five equal segments for each of the six risk variables.The entire
process was repeated for each ofthe nine resource portfolios.Five possible states for each of the six risk
variables create over 15,000 possible combinations.
Stochastic Modeling
The objective of the stochastic modeling was to estimate the distribution of the incremental portfolio
costs.The distribution was calculated by randomly sampling from the range for each risk value,
combining the effects of the six risk values,and calculating the resulting resource portfolio cost.
The sampling process was repeated 100,000 times for each resource portfolio to estimate the distribution
ofthe resource portfolio costs.
Each risk variable was assumed to be uniformly distributed over the range of values.The uniform
distribution means that there is an equal chance of sampling from each of the five segments of the range.
For natural gas prices and the 1-3 Boardman to Hemingway portfolio,the uniform distribution means
that each $4.4-million segment was equally likely to be sampled.In 100,000 draws,each segment is
expected to be sampled 20,000 times.
Three of the six risk variables were considered independent:load variation,DSM variation,and capital
cost.For capital costs,independence means that the result of any other risk variable is presumed to have
no,or only minor,influence on the capital cost.
The first three risk variables were assumed to show some level of coincidence:natural gas price,
REC price,and carbon cost.Specifically,carbon cost was assumed to be the primary risk factor.
REC prices were assumed to be 80-percent coincident with carbon cost,and natural gas price was
assumed to be 60-percent coincident with carbon cost.The coincidence means that if the sample for
carbon cost is from the highest segment in the risk range,there is an 80-percent chance that the sample
Page 108 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
0C,C.,
C3C.)0
‘I
0
I..C).0E
z
C.,
C
C.)C.)0
I.0
IC).0
E
z
of the REC price will also be in the highest segment,with a 60 percent chance that the sample of thenaturalgaspricewillalsobeinthehighestsegment.Likewise for a sample from any ofthe other four
segments in the carbon cost range.The coincidence was added to the model to reflect the thought that
the three variables may be correlated.Even though each ofthe six risk variables was uniformly
distributed,Idaho Power assumed that there is a coincidence factor between three of the six risk
variables.
Stochastic Analysis Results and Portfolio Selection (2011—2020)
The results of 100,000 samples for portfolio 1-3 Boardman to Hemingway are shown in the histogram inFigure9.18.
10,000
8,000
6,000
4,000
2,000
0
Incremental Portfolio Cost (millions)
Figure 9.18 Sampling results from portfolio 1-3 Boardman to Hemingway
Based on the sampling of the stochastic analysis,the incremental cost of the Boardman to Hemingway
portfolio is expected to range from approximately $1 million to $276 million,with a median value of
$133 million.The green bars show the lowest 10 percent and the highest 10 percent of the distribution,
and the purple bars represent the middle 80 percent of the distribution.The distribution for portfolio 1-3BoardmantoHemingwayappearstobeanormaldistribution;however,other resource portfolios had
distributions that appear less like a normal distribution.The histogram for portfolio 1-4 SCCT is shown
in Figure 9.19.The stochastic cost range for the SCCT portfolio does not appear to be normally
distributed;the histogram is roughly flat from an incremental portfolio cost of $100 million up to $200
million and declines on either end.The summary data for all of the resource portfolios,including thedistributioncharts,is included in Appendix C—Technical Appendix.
8,000
6,000 IIwIiIIII
4,000
2,000
0
14fJEHZ
CCDC0.
Incremental Portfolio Cost (millions)
Figure 9.19 Sampling results from portfolio 1-4 SCCT
Table 9.4 compares the nine resource portfolios during the 2011—2020 time period.The table shows the
base cost of each resource portfolio,the rank of the base cost in the stochastic analysis,the median of
the stochastic analysis,some values defining the range of the stochastic analysis.The base rank is the
percentile in the stochastic analysis representing the base cost of the resource portfolio.For example,the
2011 IRP Page 109
9.Modeling Analysis and Results Idaho Power Company
base cost of 1-3 Boardman to Hemingway is approximately $86 million,and $86 million would fall at
the 19th percentile in the stochastic distribution—19 percent ofthe draws have a cost less than the 1-3
Boardman to Hemingway base cost of $86 million,and 81 percent of the draws have a higher cost than
the base cost of $86 million.
Table 9.4 Stochastic analysis results (2011—2020)
Portfolio Cost Calculations (000)Risk Analysis Range (000)
Base Stochastic
Base Rank Median Difference Lower 10th Median g0th Upper
1-1 Sun &Steam $496,198 54%$488,367 -$7,831 $201,786 $356,662 $488,367 $612,505 $808,750
1-2 Solar $505,407 58%$478,897 -$26,510 $162,718 $321,382 $478,897 $628,336 $805,521
1-3 Boardman to Hemingway $86,079 19%$133,582 $47,503 $1,143 $67,712 $133,582 $198,852 $276,164
1-4 SCCT $129,443 36%$148,643 $19,200 $46,060 $88,149 $148,543 $210,860 $256,889
1-5 CCCT $222,177 60%$208,242 -$13,935 $66,345 $138,884 $208,242 $277,954 $368,603
1-6 CHP $267,462 44%$277,183 $9,721 $104,783 $195,179 $277,183 $361,535 $486,767
1-7 Balanced $288,613 44%$299,237 $10,624 $115,778 $217,378 $299,237 $381,340 $507,002
1-8 Pumped Storage $426,601 31%$462,254 $35,653 $287,183 $376,777 $462,254 $550,862 $645,560
1-9 Distributed Generation $135,055 39%$151,697 $16,542 $49,879 $91,196 $151,697 $212,500 $259,478
Figure 9.20 shows an overview of the stochastic analysis for all of the resource portfolios for the
2011—2020 time period.
-$152
1-9 Dist Gen I LII I
1-8 Pumped Storage
1-7 Balanced
1-6 CHP
$463
I I.
$300
[
$277
I
1-5 CCCT
$208
1-4 SCCT
1-3B2H r
$149
I i:i
$134
1-2 Solar
1-1 Sun &Steam
$479
$488
0 100 200 300 400 500 600 700 800 900 1,000
NPV of Incremental Portfolio Cost (Millions)
Figure 9.20 Stochastic analysis results (2011—2020)
The length of the bars in Figure 9.20 show the stochastic range of the incremental portfolio costs.
The purple portion of the bar represents the middle 80 percent of the distribution,and the green bars at
either end represent the 10-percent tails of the distribution similar to the colors in the histogram
presented in Figure 9.19.The upper and lower limits,median,10th,and 90th percentile values
represented in Figure 9.20 are also shown in Table 9.4.
Page 110 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
The capital cost risk variable seems to have the greatest effect on the stochastic range for a resource
portfolio and the stochastic range of a resource portfolio increases as the capital cost of the portfolio cost
increases.Portfolio 1-4 SCCT has the lowest capital cost,and 1-1 Sun and Solar and 1-2 Solar have the
highest capital cost.
The link between the stochastic range and the capital cost is a direct result of Idaho Power’s summer
capacity deficit as described in Chapter 8 and Figure 8.1.The effect of the summer capacity deficits is
that Idaho Power needs energy during a limited number of summer hours each year to meet customers’
peak demand.Limited operation of a generation resource leads to low total operating costs,even if thehourlyoperatingcostsarehigh,because the resource operates only during a limited number of hours
each year to meet peak demand.
Limited operation means that variations in the capital costs can overshadow any variations in operating
costs when the corresponding capital costs are high,even for resources with extremely low operating
costs.An example is a solar PV resource where the operating costs are very low,but the capital costs are
high.What the range also indicates is if the capital costs of a resource,such as solar,decline sufficiently,
both the overall portfolio cost and the stochastic range will be reduced.
The conclusion of the stochastic analysis indicates that the two resource portfolios with SCCT
generation,1-4 SCCT and 1-9 Distributed Generation have the smallest stochastic price risk range.
Portfolio 1-3 Boardman to Hemingway has the lowest expected cost and a slightly larger risk range.
Capital costs overshadow the operating costs for the other resource portfolios,especially for the resource
portfolios with a large amount of solar generation,1-1 Sun and Solar and 1-2 Solar.The resource
portfolios with the lowest capital cost have the smallest stochastic price range.
The stochastic analysis is a key part of the portfolio selection process used by Idaho Power in the
2011 1RP.Based on the expected low cost,and the limited risk spread,Idaho Power selected
two resource portfolios for the first 10 years of the planning period (201 1—2020),1-3 Boardman to
Hemingway (preferred)and 1-4 SCCT (alternate).
Stochastic Analysis Results and Portfolio Selection (202 1—2030)
Idaho Power followed the same process to analyze the second 10 years of the planning period:
•Ten resource portfolios
•Six risk variables
•Five quintile segments for the range of each risk variable
•100,000 random samples
•One distribution of costs for each resource portfolio
The 2011 IRP also identifies a preferred portfolio and an alternate portfolio for the 202 1—2030
time period.However,the selection of these two portfolios is not as straightforward as the selection for
the first 10-year period.The preferred portfolio is 2-6 Balanced 1,which incorporates geothermal,solar,
small hydroelectric,and natural gas resources.The alternate portfolio for the second 10-year period is
2-8 Pacific Northwest Transmission which substantially relies on additional market purchases fromthePacificNorthwest.An explanation of the rationale for the selection of these portfolios follows.
Figure 9.21 shows the incremental cost distribution for portfolio 2-6 Balanced 1,and Figure 9.22 shows
the same information for the 2-8 Pacific Northwest Transmission portfolio.
2011 IRP Page 111
9.Modeling Analysis and Results Idaho Power Company
12,000 —10,000 -
_____________________
8,000-—________
6,000-——
__________
0
4,000-——
________
2,000-
cOcDOCJ
Incremental Portfolio Cost (millions)
Figure 9.21 Sampling results from portfolio 2-6 Balanced I
10,000U,
8,000
a,
6,000
‘4,000
2,000
E
=z EunrffiJE0
Incremental Portfolio Cost (millions)
Figure 9.22 Sampling results from portfolio 2-8 Pacific Northwest Transmission
Like the first 10 years of the planning period,the distribution of the results from stochastic analysis of
some resource portfolios more closely approximates a normal distribution than for other resource
portfolios.Having a normal distribution is an interesting finding,but the normal distribution is not
critical to the analysis or to the selection of a preferred portfolio.The main information resulting from
the stochastic analysis is the cost range for the resource portfolio.
Table 9.5 shows the cost distribution for all 10 resource portfolios considered in the stochastic analysis
of the second 10 years of the planning period,and Figure 9.23 shows the graphical results ofthe
stochastic analysis for all of the resource portfolios for the 202 1—2030 time period.
The nuclear resource portfolio has the highest expected cost and the broadest cost range.Like the
analysis of the first 10 years,the cost distribution is driven by capital costs,and nuclear generation has a
very high capital cost.The preferred and alternate portfolios,2-6 Balanced 1 and 2-8 Pacific Northwest
Transmission,both have relatively low-expected costs and a narrow range ofpossible costs.
Although the results of the stochastic analysis show portfolios 2-8 Pacific Northwest Transmission and
2-9 Eastside Transmission have a lower expected total portfolio cost,neither was selected as the
preferred portfolio.Because ofuncertainty regarding the ability to build new long-distance,high-voltage
transmission projects in the second 10-year planning period,Idaho Power does not believe either
portfolio presents the best option.In addition,the low cost of these portfolios is contingent on long-term,
low market prices that are currently the result of a surplus of energy in the Pacific Northwest for
portfolio 2-8,and the anticipation of low market prices on the east side of Idaho Power’s system due to
considerable amounts of wind generation being built in Wyoming.
Page 112 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
Table 9.5 Stochastic analysis results (2021—2030)
Portfolio Cost Calculations (000)Risk Analysis Range (000)
Base Stochastic
Base Rank Median Difference Lower 10th Median Upper
2-1 Nuclear $1,323,279 13%$1,906,067 $582,788 $937,479 $1,258,961 $1,906,067 $2,558,841 $2,826,562
2-2 IGCC $625,319 25%$774,304 $148,985 $355,848 $524,204 $774,304 $1,024,405 $1,200,846
2-3 SCCT &Wind $564,334 35%$591,640 $27,306 $460,369 $516,699 $591,640 $667,135 $725,935
2-4 CCCT &Wind $565,377 78%$511,684 -$53,693 $332,030 $421,411 $511,684 $599,584 $722,088
2-5 F-lydro &CHP $860,503 44%$879,828 $19,325 $586,902 $720,494 $879,828 $1,042,838 $1,221,484
2-6 Balanced 1 $445,704 63%$421,349 -$24,355 $236,458 $326,718 $421,349 $513,673 $626,463
2-7 Balanced 2 $567,780 59%$546,270 -$21,510 $283,996 $412,351 $546,270 $674,989 $855,880
2-8 Pacific Northwest
Transmission $240,492 53%$234,915 -$5,577 $104,988 $169,359 $234,915 $300,819 $373,437
2-9 Eastside
Transmission $260,903 50%$261,081 $178 $125,155 $192,356 $261,081 $328,692 $401,798
2-10 Renewable $966,716 63%$904,983 -$61,733 L $523,823 $692,378 $904,983 $1,121,324 $1,333,728
$261
2-7 Balanced 2
2-6 Balanced 1
2-5 Hydro &CHP
2-4 CCCT &Wind
2-3 SCCT &Wind
$546
$421
I I
I 1.I.i I
$512
I I Ii
$592
IJl
$774
I I
500 1,000 1,500 2,000 2,500 3,000
Figure 9.23 Stochastic analysis results (2021—2030)
Although it has a slightly higher expected cost,portfolio 2-6 Balanced 1 was selected as the preferred
portfolio because it contains a diversified set of resources that are low risk,it does not rely on substantial
technology improvements,and Idaho Power is confident it could be implemented.
Tipping Point Analysis—Market Risk
Idaho Power examined the effect of wholesale market prices on the cost of portfolio 1-3 Boardman to
Hemingway relative to the cost of the less-market-dependent 1-4 SCCT portfolio.While the cost ofpurchasedpowerriseswithincreasedmarketprices,the revenues associated with surplus power sales
2-10 Renewable
2-9 Eastside Transmission
$904
I I.
$235
2-8 PNW Transmission I I
$880
2-2 IGCC
2-1 Nuclear
0
$1,906
NPV of Incremental Portfolio Cost (Millions)
2011 IRP Page 113
9.Modeling Analysis and Results Idaho Power Company
also increase.Therefore,the Boardman to Hemingway portfolio remains the lower-cost portfolio under
all elevated market price scenarios,and a tipping point does not exist.
However,further investigation into just the purchased power component of these two portfolios provides
some useful information related to market price risk.The NPV total cost of the Boardman to
Hemingway portfolio is approximately $43 million less than the cost of the SCCT portfolio.
The Boardman to Hemingway portfolio also has an additional 62,000 MWh of market purchases when
compared to the SCCT portfolio.
To make up the difference in total portfolio cost,average market prices for the additional 62,000 MWh
of purchases in the Boardman to Hemingway portfolio would need to be more than $700 per MWh.
While this analysis ignores the benefit of surplus sales at higher market prices,it offers insight on the
level market prices would have to rise to in order to make the Boardman to Hemingway portfolio no
longer the least-cost option.
Tipping Point Analysis—Boardman to Hemingway
The 2011 IRP analysis assumes Idaho Power has 28-percent equity ownership in the Boardman to
Hemingway project.If third-party equity interest in the project is less than expected,the company’s
share of the capital cost for the project will be higher,and the total cost ofportfolio 1-3 Boardman to
Hemingway will also be higher.Therefore,a tipping point analysis was performed to determine how
great of an ownership share Idaho Power could take in the project in order for the total cost of portfolio
1-3 Boardman to Hemingway to be equivalent to the next best alternative,portfolio 1-4 SCCT.
The results of the analysis indicate Idaho Power’s share of the project could go as high as 42 percent
before the cost of the two portfolios were equal.This analysis assumes that Idaho Power’s use ofthe
Boardman to Hemingway line is the same as it was under the expected 28-percent ownership scenario,
and the incremental capital cost associated with a greater equity share is not offset by economic
utilization of the additional capacity.Figure 9.24 presents the graphical results of the analysis and
additional details of the calculations can be found in Appendix C—TechnicalAppendix.
$3260000
$3,250,000
$3,240,000
a
$3,230,0000
$3,220,000
$3,210,000
•$3,200,000
I-
$3,190,000
$3,180,000
$3,170,000
1-3 B2H Total Portfolio Cost with
42%Idaho Power Ownership
1CCT
1
HhOPOJZh1
,I,
25%30%35%40%45%50%
Idaho Power Ownership %in B2H
Figure 9.24 Boardman to Hemingway ownership tipping point analysis
Page 114 2011 IRP
Idaho Power Company 9.Modeling Analysis_and Results
Tipping Point Analysis—Cost of Solar Resources versus Market Purchases
Recent trends in the decreasing cost of solar PV technology generated significant interest from members
of the IRPAC If this trend continues,solar PV will become more cost competitive with other available
resource options.A tipping point analysis was performed to determine how low the cost of solar PV
would have to be in order to be competitive with portfolio 1-3 Boardman to Hemingway,which relies on
market purchases.
For the tipping point analysis,Idaho Power investigated the capital cost decrease necessary to make the
total cost of portfolio 1-2 Solar equivalent to the total cost of portfolio 1-3 Boardman to Hemingway.
Figure 9.25 shows the results of the tipping point analysis.The figure notes that average solar costs
(average of solar thermal and PV)are expected to be $3,614 per kW and would need to decrease by
72 percent to $1,012 per kW to match the total cost of portfolio 1-3 Boardman to Hemingway.
This analysis assumes that capital cost decreases affecting the solar resources are specific to these
resources,and would not place downward pressure on the capital cost of the Boardman to Hemingway
transmission project or on wholesale power market prices.If wholesale power market prices rise,
a smaller reduction in solar capital costs is necessary for the portfolio costs to be equal.Current federal
tax incentives available for solar technologies are included in this analysis.
$3,600,000
1-2 Solar expected total
portfoliocostwithanaverage
capital cost of $3,6l4IkW
1-2 Solar total portfolio cost
with an average capital cost
of $1,012/kW(a 72%
decrease in ca ital cost
13B2H
$500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500
Solar Capital Cost $IkW
Figure 9.25 Cost of solar tipping point analysis
Capacity Planning Margin
Idaho Power discussed planning criteria assumptions with state utility commissions and the public in the
early 2000s before adopting the present planning criteria.Idaho Power’s future resource requirements
are not based directly on the need to meet a specified reserve margin.The company’s long-term resource
planning is driven instead by the objective to develop resources sufficient to meet higher-than-expected
load conditions under lower-than-expected water conditions,which effectively provides a
reserve margin.
$3,500,000
C
000
$3,400,000
0
•$3,300,000
C.)
0
&$3,200,000
0I-
$3,100,000
$3,000,000
2011 IRP Page 115
9.Modeling Analysis and Results Idaho Power Company
As part of preparing the 2011 IRP,Idaho Power has calculated the capacity planning margin resulting
from the resource development identified in the preferred resource portfolio.When calculating the
planning margin,the total resources available to meet demand consist of the additional resources
available under the preferred portfolio plus the generation from existing and committed resources
assuming expected-case (50th percentile)water and load conditions.The generation from existing
resources also includes expected firm purchases from regional markets.The resource total is then
compared with expected-case (50th percentile)peak-hour load,with the excess resource capacity
designated as planning margin.The calculated planning margin provides an alternative view of the
adequacy of the preferred portfolio,which was formulated to meet more stringent load conditions under
less favorable water conditions.
Idaho Power maintains 330 MW of transmission import capacity above the forecast peak load to cover
the worst single planning contingency.The worst single planning contingency is defined as an
unexpected loss equal to Idaho Power’s share of two units at the Jim Bridger coal facility.The reserve
level of 330 MW translates into a reserve margin of approximately 10 percent and the reserved
transmission capacity allows Idaho Power to import energy during an emergency via the NWPP.
A 330-MW reserve margin is also roughly equivalent to a Loss of Load Expectation (LOLE)of 1 day in
10 years,a standard industry measurement.Capacity planning margin calculations for July of each year
through the planning period are shown in Tables 9.6 and 9.7.
Page 116 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
Table 9.6 Capacity planning margin (2011—2020)
Capacity Planning Margin I
Load and Resource Balance Jul-li Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jul-19 Jul-20
Load Forecast (5Oth%)-Aug 2010 w/No DSM (3,367)(3,440)(3,560)(3,656)(3,750)(3,832)(3,908)(3,982)(4,060)(4,136)
Existing DSM (Energy Efficiency)33 48 64 79 93 107 121 135 149 163
Load Forecast (5Oth%w/EE)(3,334)(3,392)(3,496)(3,577)(3,657)(3,725)(3,787)(3,847)(3,911)(3,973)
Existing Demand ResDonse 330 310 315 315 321 351 351 351 351 j.
Peak-Hour Forecast w/DR (3,004)(3,082)(3,181)(3,262)(3,336)(3,374)(3,436)(3,496)(3,560)(3,622)
Existing Resources
Coal
Gas (Langley Gulch)
Hydro (5Oth%)—HCC
Hydro (SOth%)—Other
Shoshone Falls Upgrade
Sho-Ban Water Lease
Total Hydro (5Oth%)
CSPP (PURPA)
Power Purchase Agreements
Elkhorn Valley Wind
Raft River Geothermal
Neal Hot Springs Geothermal
Clatskanie Exchange -Take
Clatskanie Exchange -Return
Eastside Purchase (83 MW)
Mead Purchase
Total Power Purchase Agreements
Firm Pacific NW Import Capability
Gas Peakers
963 963 963
300 300 300
1,120 1,120 1,120
281 281 280
4 4 4
2 2 2
1,405 1,405 1,404
166 166 166
S 5 5
10 10 10
20 20 20
0 0 0
0 0 0
0 0 0
2 2 2
35 35 35
209 205 201
416 416 416
3,494 3,489 3,484
(3)(71)(138)
Jul-18 Jul-19 Jul-20
963 963 963 963 963 963 963
0 300 300 300 300 300 300
1,120 1,120 1,120 1,120 1,120 1,120 1,120
286 286 286 285 284 283 282
0 0 0 0 0 4 4
47 48 48 48 48 0 0
1,453 1,454 1,454 1,453 1,452 1,407 1,406
160 161 166 166 166 166 166
5 5 5 5 5 5 5
10 10 10 10 10 10 10
0 0 20 20 20 20 20
12 12 12 12 12 0 0
0 0 0 0 0 0 0
83 83 0 0 0 0 0
2 2 2 2 2 2
185 110 47 47 47 35 35
126 233 229 225 222 218 214
416 416 416 416 416 416 416
Existing Resource Subtotal 3,302 3,637 3,574 3,569 3,565 3,504 3,499
Monthly Surplus/Deficit 0 0 0 0 0 0 0
Jul-il Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-172011IRPDSM
Industrial 2 3 5 6 7 8 8 9 10 10
Commercial 0 1 1 2 2 3 3 3 4 4
Residential 1 2 4 6 8 10 12 15 17 20
Total New DSM Peak Reduction 3 6 10 14 17 20 24 27 31 34
Remaining Monthly Surplus/Deficit 0 0 0 0 0 0 0 0 (40)(103)
2009 IRP Resources Jul-li Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jul-19 Jul-20
2015 Eastside Purchase 0 0 0 0 83 0 0 0 0 0
2016 B2H 0 0 0 0 0 450 450 450 450 450
2021 Geothermal 0 0 0 0 0 0 0 0 0 0
2O22SCCTFrame 0 0 0 0 0 0 0 0 0 0
2024 Solar Power Tower 0 0 0 0 0 0 0 0 0 0
2O25CCCT 0 0 0 0 0 0 0 0 0 0
2O28SmallHydro 0 0 0 0 0 0 0 0 0 0
2029SCTFrame 2 2 2 2 2 2 2 2 2 2
New Resource Subtotal 0 0 0 0 83 450 450 450 450 450
Remaining Monthly Surplus/Deficit 302 561 403 321 329 600 537 475 410 347
Planning Margin 10.0%18.2%12.7%9.8%9.9%17.8%15.6%13.6%11.5%9.6%
2011 IRP Page 117
9.Modeling Analysis and Results Idaho Power Company
Table 9.7 Capacity planning margin (2021—2030)
Icapacitv Planning Margin I
Load and Resource Balance Jul-21 Jul-22 Jul-23 Jul-24 Jul-25 Jul-26 Jul-27 Jul-28 Jul-29 Jul-30
Load Forecast (5Oth%)-Aug 2010 w/No DSM (4,211)(4,289)(4,370)(4,448)(4,524)(4,605)(4,680)(4,773)(4,858)(4,918)
Existing DSM (Energy Efficiency)177 191 205 219 233 247 261 275 289 275
Load Forecast (SOth%w/EE)(4,034)(4,098)(4,165)(4,229)(4,291)(4,358)(4,419)(4,498)(4,569)(4,643)
Existing Demand Response 351 351 351 351 351 351 351 351 351 351
Peak-Hour Forecast w/DR (3,683)(3,747)(3,814)(3,878)(3,940)(4,007)(4,068)(4,147)(4,218)(4,292)
Existing Resources
Coal 908 908 908 908 908 908 908 908 908 908
Gas (Langley Gulch)300 300 300 300 300 300 300 300 300 300
Hydro (SOth%)—HCC 1,120 1,120 1,120 1,120 1,120 1,120 1,120 1,120 1,120 1,120
Hydro (SOth%)—Other 280 280 280 280 280 280 280 280 280 280
Shoshone Falls Upgrade 4 4 4 4 4 4 4 4 4 4
Sho-Ban Water Lease 0 0 0 0 0 0 0 0 0 0
Total Hydro (5Oth%)1,404 1,404 1,404 1,404 1,404 1,404 1,404 1,404 1,404 1,404
CSPP (PURPA)166 166 166 166 166 166 166 101 63 93
Power Purchase Agreements
Elkhorn Valley Wind 5 5 5 5 5 5 5 5 5 5
Raft River Geothermal 10 10 10 10 10 10 10 10 10 10
Neal Hot Springs Geothermal 20 20 20 20 20 20 20 20 20 20
Clatskanie Exchange -Take 0 0 0 0 0 0 0 0 0 0
Clatskanie Exchange -Return 0 0 0 0 0 0 0 0 0 0
Eastside Purchase (83 MW)0 0 0 0 0 0 0 0 0 0
Mead Purchase 0 0 0 0 0 0 0 0 0 0
Total Power Purchase Agreements 35 35 35 35 35 35 35 35 35 35
Firm Pacific NW Import Capability 257 254 250 246 243 238 234 231 227 224
Gas Peakers 416 416 416 416 416 416 416 416 416 416
Existing Resource Subtotal 3,485 3,482 3,478 3,474 3,471 3,466 3,462 3,394 3,352 3,379
Monthly Surplus/Deficit (198)(265)(336)(404)(469)(541)(606)(753)(866)(913)
2011 IRP DSM Jul-21 Jul-22 Jul-23 Jul-24 Jul-25 Jul-26 Jul-27 Jul-28 Jul-29 Jul-30
Industrial 11 11 12 12 13 13 13 13 13 13
Commercial 5 5 5 6 6 6 6 6 6 6
Residential 22 24 27 30 32 35 38 40 43 45
Total New DSM Peak Reduction 38 41 44 48 51 54 57 59 62 65
Remaining Monthly Surplus/Deficit (160)(224)(292)(357)(419)(487)(550)(694)(804)(848)
2009 IRP Resources Jul-21 Jul-22 Jul-23 Jul-24 Jul-25 Jul-26 Jul-27 Jul-28 Jul-29 Jul-30
2015 Eastside Purchase 0 0 0 0 0 0 0 0 0 0
2016 B2H 450 450 450 450 450 450 450 450 450 450
2021 Geothermal 52 52 52 52 52 52 52 52 52 52
2022 SCCT Frame 0 170 170 170 170 170 170 170 170 170
2o24SolarPowerTower 0 0 0 44 44 44 44 44 44 44
2025 CCCT 0 0 0 0 300 300 300 300 300 300
2028 Small Hydro 0 0 0 0 0 0 0 52 52 52
2029 SCCT Frame 0 0 0 0 0 0 0 0 170 170
New Resource Subtotal 502 672 672 716 1,016 1,016 1,016 1,068 1,238 1,238
Remaining Monthly Surplus/Deficit 342 448 380 360 598 529 467 374 434 390
Planning Margin 9.3%11.9%10.0%9.3%15.2%13.2%11.5%9.0%10.3%9.1%
Page 118 2011 IRP
Idaho Power Company 9.Modeling Analysis and Results
2.00
1.50
1.00
0.00
Loss of Load Expectation
Idaho Power used a spreadsheet model3 to calculate the LOLE for the preferred and alternate portfolios
identified in the 2011 IR.P.The assessment assumes critical water conditions at the existing
hydroelectric facilities and the planned additions for the preferred and alternate portfolios.As mentioned
in previous chapters,Idaho Power uses a capacity benefit margin (CBM)of 330 MW in transmission
planning to provide the necessary reserves for unit contingencies.The CBM capacity is reserved in the
transmission system and is sold on a non-firm basis until forced unit outages require use of the
transmission capacity.The 2011 IRP analysis assumes CBM transmission capacity is available to meet
deficits due to forced outages.
The model uses the IRP forecasted hourly load profile,generator/purchase outage rates (EFORd),
and generation and transmission capacities to compute a LOLE for each hour of the 20-year planning
period.Demand response programs were modeled as a reduction in the hourly load during the mid-week
peak hours rather than as a dispatchable resource due to the limited energy of the demand response
programs.The LOLE analysis is performed on a monthly basis to permit capacity de-rates for
maintenance or lack of fuel (water).
The typical metric used in the utility industry to assess probability-based resource reliability is a LOLE
of 1 day in 10 years.Idaho Power has chosen to calculate LOLE on an hourly basis to evaluate the
reliability at a more granular level.The 1-day-in-10-years metric is roughly equivalent to 0.5—1.0 hours
per year.The results of the loss of load probability analysis are shown in Figure 9.26,and additional
data can be found in Appendix C—Technical Appendix.
2.50
0.50 -
_________________________________________________
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
—s—Preferred Portfolio (1-3 and 2-6)—Alternate Portfolio (1-4)Alternate Portfolio (2-8)
Figure 9.26 Loss of load expectation
In performing the analyses,there were several instances where extending purchases of east-side energy
similar to the purchases contemplated in 2010—2012 were necessary to achieve the results shown in
Figure 9.26.
Based on Roy Billinton “Power System Reliability Evaluation”Chapter 2&3,Copyright 1970.
2011 IRP Page 119
9.Modeling Analysis and Results Idaho Power Company
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Page 120 2011 IRP
Idaho Power Company 10.Action Plans
10.ACTION PLANS
Once the final preferred portfolio has been selected,
an action plan is necessary to identify the steps that
must be taken to implement the plan.Like the
portfolio analysis,the action plan is split into two,
10-year periods.The near-term action plan addresses
the years 20 11—2020,and the long-term action plan
covers the years 202 1—2030.The two action plans
represent the culmination of the IRP process.
Near-Term Action Plan
(2011—2020)
The near-term action plan describes the actions
Idaho Power plans to take over the next 10 years to
implement the preferred portfolio (2011—2020).No long-lead-time generation resources,such asadvancednuclearorIGCCareconsideredinthenear-term plan.However,Idaho Power intends tocontinueitseffortstoparticipateinregionalutilityplanningforumsandtoexploreregionalalliances asgenerationresource,energy storage,energy efficiency,and transmission technologies develop.
Table 10.1 presents a list of the resources Idaho Power expects to add to its generation portfolio over thenext10yearsforboththepreferredportfolioandanalternateportfolio.An alternate portfolio is alsoidentifiedintheIRPintheeventsubstantialchangesimpacttheassumptionsusedtoselectthepreferredportfolio.
Table 10.1 Near-term action plan (2011—2020)
Preferred Resource Portfolio Alternative Resource PortfolioYear1-3 Boardman to Hemmingway 1-4 SSCT
2011
2012
2013 Solar Demonstration Project (500kw—i MW)Solar Demonstration Project (500kw—i MW)2014
2015 Eastside PPA (83 MW)SCCT (170 MW)
2016 Boardman to Hemingway (450 MW)
2017 SCCT(17OMW)
2018
2019 SCCT (94 MW)
2020
High lights
The Boardman to Hemingway transmission line is the primary resource in the near-termactionplan,and the long-term action plan includes a diverse set of renewable andgas-fired resources.
Idaho Power is proposing a solar demonstration project as part of the 201 1 IRP.
IRPAC members and members of the public made significant contributions through theninepublicmeetingsconductedwhilepreparingthe2011IRP.
j
1..
—.-.
-
Action plans describe how Idaho Power
will implement the results of the IRP.
2011 IRP Page 121
10.Action Plans Idaho Power Company
Preferred Portfolio Near-Term Action Plan
The Boardman to Hemingway transmission line and associated market purchases is the primary resource
addition in the near-term action plan preferred portfolio.The new transmission line was first identified
in Idaho Power’s 2006 IRP,and the company continues working to acquire the necessary regulatory
approvals and permits necessary to begin construction.Construction ofthe Boardman to Hemingway
transmission line is expected to start in early 2014,after completing the permitting,regulatory,
and engineering work.If the Boardman to Hemingway project is substantially delayed,Idaho Power will
have to consider implementing the alternate portfolio.
The preferred portfolio also includes a market purchase from the east side of Idaho Power’s system.
The purchase is necessary to cover a summer peak-hour deficit in 2015 that exists before the Boardman
to Hemingway line becomes available in 2016.Idaho Power has used the east side for market purchases
in the past,but prices have historically been higher than the prices at the Mid-C hub in the Pacific
Northwest.A purchase on the east side does not require substantial lead time,and Idaho Power will
continue to monitor market prices,load growth,and the status of the Boardman to Hemingway project
prior to committing to this purchase.
As part of the 2011 IRP,Idaho Power is proposing to construct a solar demonstration project.Details of
this proposal are explained in Chapter 1 and the project could be on line as early as late 2012.
Alternate Portfolio Near-Term Action Plan
The alternate portfolio presents the actions Idaho Power will take if the Boardman to Hemingway
transmission line is significantly delayed or canceled.In the alternate resource portfolio,Idaho Power
anticipates adding natural gas-fired SCCTs to meet capacity deficits.The company expects to acquire
the generation resources identified in the alternate portfolio through a competitive RFP process meeting
the requirements of Oregon Order 06-446 issued on August 10,2006,as well as any revisions to the
requirements resulting from Oregon Docket UM 1182.
Although the alternate portfolio identifies the first 170-MW SCCT in 2015,in the event the alternate
portfolio is implemented,Idaho Power will continue to evaluate resource needs and may alter the size,
timing,and technology of the combustion turbine depending on market conditions at the time an RFP
is issued.
Should the permitting,regulatory,engineering work,or construction of the Boardman to Hemingway
project be delayed,Idaho Power will face the decision to acquire the first resource identified in the
alternate portfolio.To meet the competitive procurement guidelines,Idaho Power would need to initiate
the resource procurement process by issuing an RFP as early as 2012.Beginning the procurement
process in 2012 is necessary to achieve an on-line date in 2015.The resource procurement process
would most likely begin prior to the completion of Idaho Power’s 2013 IRP,which is scheduled to be
filed in June 2013.
Long-Term Action Plan (202 1—2030)
The long-term action plan describes Idaho Power’s planned resource acquisitions during the second
10 years of the planning period (202 1—2030).The long-term action plan assumes that the near-term
action plan is completed with only minor variations.If the Boardman to Hemingway project is
significantly delayed or canceled and Idaho Power implements the alternate resource plan in the first 10
years of the planning period,Idaho Power may reconsider its concerns about over-reliance on market
purchases and select the alternate resource portfolio relying on a regional transmission project for the
second 10 years of the planning period.
Page 122 2011 IRP
Idaho Power Company 10.Action Plans
It is important to note that the Gateway West project was included in each resource portfolio for only the
second 10-year period when current transmission constraints required the addition of new transmission
capacity for resources to be added in southern Idaho east of the Treasure Valley load center.The amount
of Gateway West capacity is different in each portfolio,depending on other included resources.
Although the resources in the preferred portfolio for the second 10-year period were analyzed without
the addition of the Gateway West transmission project,Idaho Power pians to continue permitting the
Gateway West project because ofuncertainty associated with the location of resources planned so far in
the future and the long lead time required to permit high-voltage transmission projects.
With the exception of the Gateway West transmission project,both the preferred and alternate resource
portfolios for the second 10 years of the planning period include a combination of renewable and natural
gas-fired resources.The long-term action plan for both the preferred and alternate portfolios is shown in
Table 10.2.
Table 10.2 Long-term action plan (2021—2030)
Preferred Resource Portfolio Alternative Resource Portfolio
Year 2-6 Balanced 1 2-7 PNW Transmission
2021 Geothermal (52 MW)Geothermal (52 MW)
2022 SCCT (170 MW)Pacific NW Purchase (500 MW)
2023
2024 Solar Power Tower (50 MW)
2025 CCCT (300 MW)
2026
2027 Solar PV (20 MW)
2028 Small Hydro (60 MW)Geothermal (52 MW)
2029 SCCT (170 MW)SCCT (170 MW)
2030
Preferred Portfolio Long-Term Action Plan
The preferred portfolio selected for the second 10 years consists of a diverse mixture of renewable and
natural gas resources.With the possible exception of the solar power tower technology,none of the
identified resources present a technological challenge.The longest lead-time resource in the preferred
portfolio is the CCCT identified to come on line in 2025,which would require approximately four years
to design,permit,and construct.Therefore no significant actions are required in the next two years to
pursue this portfolio.
After the 2011 IRP,Idaho Power’s next IRP will be completed in June 2013.Idaho Power will continue
to evaluate “balanced”portfolios,as they have historically performed well in the IRP analysis.
Alternate Portfolio Long-Term Action Plan
The alternate portfolio for the second 10 years presents a dilemma.Although this portfolio performed
well,as covered in Chapter 9,concerns regarding an over-reliance on market purchases and the future
ability of utilities to permit and construct long-distance,high-voltage transmission raise questions
regarding the viability of this portfolio.
Idaho Power will continue to monitor forward market prices and the progress that can be made on the
Boardman to Hemingway and Gateway West projects between now and the completion of the 2013 IRP.
Based on recent experience,new long-distance,high-voltage transmission projects require a lead time of
8—10 years.If additional transmission capacity to either the Pacific Northwest or to the east side of
2011 IRP Page 123
10.Action Plans Idaho Power Company
Idaho Power’s system continues to perform well in the IRP analysis,Idaho Power will need to begin
work on permitting and initial designs for new transmission projects shortly after the completion of the
2013 IRP.
Conclusion
Each Idaho Power IRP builds on the foundation of earlier resource plans,and each plan includes
incremental changes due to forecasts of future events.The 2011 IRP is no exception.
Idaho Power and other utilities in the West face major regional transmission decisions.No significant
interstate transmission has been built in the region for many years.Idaho Power’s 2006 IRP was the first
of the company’s resource plans where Idaho Power made a significant commitment to new interstate
transmission projects.Idaho Power continues its commitment to regional transmission with the
2011 IRP.
The Boardman to Hemingway transmission line and associated market purchases is the primary resource
addition in the near-term preferred resource portfolio,and Idaho Power is currently acquiring the
necessary regulatory approvals and permits to begin construction.As part of acknowledging the
2009 IRP,the OPUC requested Idaho Power treat the Boardman to Hemingway project as an
uncommitted resource in the 2011 IRP.And,once again,the Boardman to Hemingway transmission
project has outperformed other alternatives.
In the 2011 plan,Idaho Power conducted a thorough analysis of resource alternatives,including
generation,transmission,demand-response,and energy efficiency.The only committed resources not
yet constructed but included in the 2011 IRP are the Langley Gulch CCCT and an upgrade at the
company’s Shoshone Falls hydroelectric project.The Boardman to Hemingway transmission project
was analyzed using the same methods as other uncommitted resources.After the analysis,the Boardman
to Hemingway transmission line is again the preferred resource to meet customer needs in Idaho
and Oregon.
Idaho Power strongly supports public involvement in the planning process.Idaho Power thanks the
IRPAC members and the public for their contributions to the 2011 IRP.The IRPAC discussed many
technical aspects of the 2011 resource plan along with a significant number of politicallsocietal topics at
nine meetings conducted during the second half of 2010 and the first half of 2011.Idaho Power’s
resource planning process is better because of the contributions from the LRPAC members and
the public.
Idaho Power prepares an IRP biennially.At the time of the next plan in 2013,Idaho Power will have
additional information regarding supply-side resources,demand-side management programs,fuel prices,
economic conditions,and load growth.In addition,Idaho Power hopes to have better information
regarding potential carbon regulations,the development of a federal RES,and the feasibility of
advanced nuclear,IGCC,and other resource options that currently face technological challenges.
One of the key strengths of Idaho Power’s planning process is that the IRP is updated every two years.
Frequent planning allows Idaho Power,the IRPAC,the IPUC,the OPUC,and concerned customers to
revisit the IRP and make periodic adjustments and corrections to reflect changes in technology,
economic conditions,and regulatory requirements.During the two years between resource plan filings,
the public and regulatory oversight of the activities identified in the near-term action plan allows for
discussion and adjustment of the IRP as warranted.
Page 124 2011 IRP
Idaho Power Company Lists of Tables,Figures,and Appendices
LIST OF TABLES
Table 1.1 Preferred portfolios 7
Table 1.2 Near-term action plan milestones 8
Table 2.1 Phase I measures 16
Table 3.1 Historical capacity,load,and customer data 24
Table 3.2 Electricity delivered to customers (2010)26
Table 3.3 Existing Resources 27
Table 4.1 Energy efficiency current portfolio forecasted impacts (2011—2030)39
Table 4.2 Existing energy efficiency portfolio cost-effectiveness summary 39
Table 4.3 New energy efficiency portfolio forecasted impacts (2011—2030)41
Table 4.4 New energy efficiency portfolio cost-effectiveness summary 41
Table 4.5 Demand response cost-effectiveness summary 42
Table 6.1 Load forecast—peak-hour (MW)61
Table 6.2 Load forecast—average monthly energy (aMW)63
Table 6.3 Planning criteria for average monthly and peak-hour load 65
Table 6.4 Emissions intensity rates (lbs/MWh)73
Table 6.5 Emissions adder cost assumptions 73
Table 7.1 Available transmission import capacity 83
Table 7.2 Transmission assumptions 84
Table 9.1 Financial assumptions 94
Table 9.2 Expected case total portfolio cost (20 11—2020)97
Table 9.3 Expected case total portfolio cost (202 1-2030)97
Table 9.4 Stochastic analysis results (2011—2020)110
Table 9.5 Stochastic analysis results (202 1—2030)113
Table 9.6 Capacity planning margin (20 11—2020)117
Table 9.7 Capacity planning margin (2021—2030)118
Table 10.1 Near-term action plan (2011—2020)121
Table 10.2 Long-term action plan (202 1—2030)123
LIST OF FIGURES
Figure 1.1 Cost of existing and new supply-side resources 4
Figure 1.2 30-year levelized capital cost ofpeak-hour capacity 5
Figure 1.3 2010 fuel mix 7
2011 IRP Page 125
Lists of Tables,Figures,and Appendices Idaho Power Company
Figure 1.4 2030 fuel mix .7
Figure 3.1 Historical capacity,load,and customer data 24
Figure 3.2 2010 energy sources 26
Figure 3.3 2010 long-term power purchases by resource type 26
Figure 3.4 PURPA contracts by resource type 34
Figure 5.1 Boardman to Hemingway line project map 52
Figure 5.2 Gateway West line project map 55
Figure 6.1 Peak-hour load growth forecast (MW)61
Figure 6.2 Average monthly load growth forecast (aMW)62
Figure 6.3 Brownlee historical and forecast inflows 67
Figure 6.4 Natural gas price forecast 70
Figure 6.5 Pacific Northwest natural gas transportation paths 71
Figure 6.6 Carbon-adder assumptions 73
Figure 6.7 REC price assumptions 74
Figure 6.8 30-year levelized capacity (fixed)costs 76
Figure 6.9 30-year levelized cost of production (at stated capacity factors)77
Figure 7.1 Idaho Power transmission system map 81
Figure 8.1 Monthly average energy surpluses and deficits with existing and committed resources
and existing DSM (70th percentile water and 70t1 percentile load)86
Figure 8.2 Monthly average energy surpluses and deficits with new DSM (70t1 percentile water
and 70th percentile load)87
Figure 8.3 Monthly peak-hour deficits with existing and committed resources and existing DSM
(90th percentile water and 95th percentile load)88
Figure 8.4 Monthly peak-hour deficits with new DSM (90th percentile water and
95th percentile load)88
Figure 8.5 Initial resource portfolios (2011—2020)89
Figure 8.6 Initial resource portfolios (202 1—2030)91
Figure 9.1 Average CO2 intensity by portfolio (201 1—2020)98
Figure 9.2 Average CO2 intensity by portfolio (202 1—2030)98
Figure 9.3 Carbon risk analysis results (201 1—2020)100
Figure 9.4 Natural gas price risk analysis results (2011—2020)100
Figure 9.5 Capital cost risk analysis 101
Figure 9.6 Capital-cost risk analysis results (2011—2020)101
Figure 9.7 DSM variability risk analysis 102
Figure 9.8 DSM variability risk analysis results (2011—2020)102
Figure 9.9 Load variability risk analysis 103
Page 126 2011 IRP
Idaho Power Company Lists of Tables,Figures,and Appendices
Figure 9.10 Load risk analysis results (2011—2020).103
Figure 9.11 REC price risk analysis results (2011—2020)104
Figure 9.12 Carbon risk analysis results (2021—2030)104
Figure 9.13 Natural Gas price risk analysis results (2021—2030)105
Figure 9.14 Capital cost risk analysis results (2021—2030)105
Figure 9.15 DSM risk analysis results (2021—2030)106
Figure 9.16 Load variability risk analysis results (2021—2030)106
Figure 9.17 REC price risk analysis results (202 1—2030)106
Figure 9.18 Sampling results from portfolio 1-3 Boardman to Hemingway 109
Figure 9.19 Sampling results from portfolio 1-4 SCCT 109
Figure 9.20 Stochastic analysis results (2011—2020)110
Figure 9.21 Sampling results from portfolio 2-6 Balanced 1 112
Figure 9.22 Sampling results from portfolio 2-8 Pacific Northwest Transmission 112
Figure 9.23 Stochastic analysis results (202 1—2030)113
Figure 9.24 Boardman to Hemingway ownership tipping point analysis 114
Figure 9.25 Cost of solar tipping point analysis 115
Figure 9.26 Loss of load expectation 119
LIST OF APPENDICES
Appendix A—Sales and Load Forecast
Appendix B—Demand-Side Management 2010 Annual Report
Appendix C—Technical Appendix
2011 IRP Page 127
Lists of Tables,Figures,and Appendices Idaho Power Company
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Page 128 2011 IRP
Idaho Power Company Glossary of Abbreviations
GLOSSARY OF ABBREVIATIONS
AC-Alternating Current
A/C—Air Conditioning
ACOE—United States Army Corps of Engineers
AFUDC—Allowance for Funds Used During Construction
akW—Average kilowatt
aMW—Average Megawatt
BLM—Bureau of Land Management
BOR—Bureau of Reclamation
BPA—Bonneville Power Administration
CAA—Clean Air Act
CAES—Center for Advanced Energy Studies
CAIR—Clean Air Interstate Rule
CAMP—Comprehensive Aquifer Management Plan
CAP—Community Advisory Process
CBM—Capacity Benefit Margin
CCCT—Combined-Cycle Combustion Turbine
CCR—Coal Combustion Residuals
CCX—Chicago Climate Exchange
CFI—Carbon Financial Instrument
cfs—Cubic-Feet-per-Second
CHP—Combined Heat and Power
Clatskanie PUD—Clatskanie People’s Utility District
CPCN—Certiflcate ofPublic Convenience and Necessity
C02—Carbon Dioxide
CPCN—Certificate of Public Convenience and Necessity
CREP—Conservation Reserve Enhancement Program
DC—Direct Current
DOE—Department of Energy
DRAM—Dynamic Random Access Memory
DSM—Demand-Side Management
EEAG—Energy Efficiency Advisory Group
ETA—Energy Information Administration
2011 IRP Page 129
Glossary of Abbreviations Idaho Power Company
EPA—Environmental Protection Agency
EPRI—Electric Power Research Institute
ESA—Endangered Species Act
ESPA—Eastern Snake River Plain Aquifer
F—Fahrenheit
FCA—Fixed-Cost Adjustment
FCP—Formal Consultation Package
FCRPS—Federal Columbia River Power System
FEIS—Final Environmental Impact Statement
FERC—Federal Energy Regulatory Commission
FPA—Federal Power Act
FWS—US Fish and Wildlife Service
GHG-Greenhouse Gas
HAP—Hazardous Air Pollutants
Hg—Mercury
HRSG—Heat Recovery Steam Generator
IDWR—Idaho Department of Water Resources
IGCC—Integrated Gasification Combined Cycle
INL—Idaho National Laboratory
IOER—Idaho Office of Energy Resources
IPUC—Idaho Public Utilities Commission
IRP—Integrated Resource Plan
IRPAC—IRP Advisory Council
kV—Kilovolt
kW—Kilowatt
kWh—Kilowatt Hour
lbs—Pounds
LOLE—Loss of Load Expectation
LTP—Local Transmission Plan
m2—square meters
mm—Millimeter
MMBtu—Million British Thermal Units
MSA—Metropolitan Statistical Area
MW—Megawatt
Page 130 2011 IRP
Idaho Power Company Glossary of Abbreviations
MWh—Megawatt Hour
NAAQS—National Ambient Air Quality Standards
NEEA—Northwest Energy Efficiency Alliance
NEO—Northeast Oregon
NEPA—National Environmental Policy Act
NERC—North American Electric Reliability Corporation
NTTG—Northem Tier Transmission Group
NPCC—Northwest Power and Conservation Council
NOR—Nitrogen Oxide
NPV—Net Present Value
NWPP—Northwest Power Pool
NREL—National Renewable Energy Laboratory
NSR-New Source Review
NYMEX—New York Mercantile Exchange
O&M—Operating and Maintenance
OATT—Open Access Transmission Tariff
ODEQ—Oregon Department of Environmental Quality
ODOE—Oregon Department of Energy
OPUC—Public Utility Commission of Oregon
PCA—Power Cost Adjustment
PCB—Polychlorinated Biphenyls
PM&E—Protection,Mitigation,and Enhancement
PGE—Portland General Electric Company
PPA—Power Purchase Agreement
PRC—Power Resources Cooperative
PTC—Production Tax Credit
PURPA—Public Utility Regulatory Policies Act of1978
PV—Photovoltaic
QF—Qualifying Facility
RCRA—Resource Conservation and Recovery Act of1976
REC—Renewable Energy Certificate
RES—Renewable Electricity Standard
RFP—Request for Proposal
RH BART—Regonal Haze Best Available Retrofit Technology
2011 IRP Page 131
Glossary of Abbreviations Idaho Power Company
RPS—Renewable Portfolio Standard
SCCT—Simple-Cycle Combustion Turbine
SCR—Selective Catalytic Reduction
S02—Sulfur Dioxide
SRBA—Snake River Basin Adjudication
TASCO—The Amalgamated Sugar Company
TEPPC—Transmission Expansion Planning Policy Committee
UAMPS—Utah Associated Municipal Power Systems
USFS—United States Forest Service
WDEQ—Wyoming Department of Environmental Quality
WECC—Western Electricity Coordinating Council
W—Watt
Page 132 2011 IRP