HomeMy WebLinkAbout20110401Integrated Resource Plan, Vol I.pdfPACIFICORP Rocky Mountn Powr
Paific Power
PacifiCorp Energ
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Let~s
PAC-E-II-IO
March 31, 201 I
This 2011 Integrated Resource Plan (IRP) Report is based upon the best available information at
the time of preparation. The IRP action. plan wil be implemented as described herein, but is
subject to change as new information becomes available or as circumstances change. It is
PacifCorp's intention to revisit and refresh the IRP action plan no less frequently than annually.
Any refreshed IRP action plan wil be submitted to the State Commissions for their information.
For more information, contact:
PacifCorp
IRP Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
(503) 813-5245
Ùp(êacificorp. com
http://www.pacificorp.com
This report is printed on recycled paper
Cover Photos (Left to Right):
Wind: McFadden Ridge I
Thermal-Gas: Lake Side Power Plant
Hydroelectric: Lemolo 1 on North Umpqua River
Transmission: Distribution Transformers
Solar: Salt Palace Convention Center Photovoltaic Solar Project
Wind Turbine: Dunlap I Wind Project
PACIFiCORP-2011 IR TABLE OF CONTENT
TABLE OF CONTENTS
TABLE OF CONTENTS ........................................ò...................................................................................................1
INDEX OF TABLES................................................................................................................................................ Vi
INEX OF FIGURES...........................................~............................................................................................... Viii
CHAPTER 1- EXECUTIVE SUMMAY ...............................................................................................................1
RESOURCE NEED..............................................ò..............................................................................ò........................3
TRASMISSION PLANNING ...........................................:....................................................................................ò......4
FUTUR RESOURCE OPTIONS AND PORTFOLIO MODELING ..................................................................................5
THE 2011 IRP PRFERRD PORTFOLIO..................................................................................................................8
THE 2011 IR ACTION PLAN.................................................................................................................................14
CHAPTER 2 - INTRODUCTION ...........................................................................................................................19
2011 INTEGRATED RESOURCE PLAN COMPONENTS.............................................................................................20
2011 IRPSUPPLEMENT.....................;....................................................................................................................21
THE ROLE OF PACIFICORP'S INTEGRATED RESOURCE PLANNING....................................................................21
PUBLIC PROCESS....................................................................................................................................................22
MmAMRICAN ENERGY HOLDINGS COMPANY IRP COMMITMENTS.................................................................23
CHATER 3 - THE PLANNING ENVIRONMENT ............................................................................................25
INTRODUCTION ......................................................................................................................................................25
WHOLESALE ELECTRICITY MARKTS..................................................................................................................26
Natural Gas Uncertainty..................................................................................;.................................................27
THE FuTUR OF FEDERAL ENVIONMENTAL REGULATION AND LEGISLATION ................................................30
Federal Climate Change Legislation.................................................................................................................31
EPA REGULATORY UPDATE - GREENHOUSE GAS EMISSIONS ............................................................................32
Guidancefor Best Available Control Technology (BACT) ................................................................................32
New Source Performance Standards (NSPS)................;...........................................................................:........33
EPA REGULATORY UPDATE _ NON-GREENHOUSE GAS EMISSIONS ...................................................................33
Clean Air Act Criteria Pollutants. ......... ....... .... ......... ..... ......... ............. ..... ..... ........ ... ........... ....... ...... ..... .... ........ 34
Clean Air Transport Rule...................................................................................................................:...............34
Regional Haze....................................................................................................................................................34
Mercury and Hazardous Air Pollutants ............................................................................................................. 35
Coal Combustion Residuals .... ....... .................... .... ..... .... ..... .... ... .... ........... ..... ........... ....... ....... ......... ..... .... .... .... 35
REGIONAL AND STATE CLIMATE CHANGE REGULATION ....................................................................................36
Regional Climate Change Initiatives .................................................................................................................36
Western Climate Initiative..................................................................................................................................36
State-Specifc Initiatives .... ......... .... ... ....... ....... .... ..... .... ..... .... ....... ....... ....... ....... .... ............... ............. ..... .... .... .... 3 7
California .... ...... .... .... ...... .... ...... ............. ........ .... .... ... ... ............ ...... .... ........ .... .... .... .... ... ...... .... ...... .......... ...... .................. 37
Oregon and Washington..................................................................................................................................................38
RENEWABLE PORTFOLIO STANDARDS ..................................................................................................................39
California.........................................................................................................,.................................................40
Oregon...............................................................................................................................................................40
Utah ...................................................................................................................................................................41
Washington ........................................................................................................................................................41
Federal Renewable Portfolio Standard..............................................................................................................41
Renewable Energy Certifcates and Renewable Generation Reporting.............................................................42
HYDROELECTRIC RELICENSING............................................................................................................................42
Potential Impact.................................................................................................................................................43
Treatment in the IRP ...... .... ....... ....... ...... ..... .... .... ... ...... .... ..... ..... ...... ....... .... ..... .... ....... ...... ......................... ..... ... 44
PacifCorp 's Approach to Hydroelectric Relicensing........................................................................................44
RECENT RESOURCE PROCUREMENT ACTIVITIES.................................................................................................44
1
PACIFICORP - 20 i i INTGRATED RESOURCE PLAN TABLE OF CONTENTS
All-Source Requestfor Proposals .................................................................................................................;....44
Demand-side Resources ...... .... .................. .................................................................................. ............... ........ 44
Oregon Solar Requestfor Proposal...................................................................................................................45
CHAPTER 4 - TRASMISSION PLANING......................................................................................................47
INTRODUCTION ......................................................................................................................................................48
PUROSE OF TRASMISSION .................................................................................................................................49
INTEGRATED RESOURCE PLANNING PERSPECTIVE ..............................................................................................49
INTERCONNECTION-WIDE REGIONAL PLANNING .............................................................:...................................50
Regional Planning.........................................................;....................................................................................50
Sub-Regional Planning Groups .........................................................................................................................51
Sub-regional Coordination Group (SCG)..........................................................................................................53
Regional Initiatives ............................................................................................................................................55
Joint Initiative (n)...........................................................................................................................................................55
Effcient Dispatch Toolkit (EDT) ................................................................................................................................... 56
Energy Gateway Origins....................................................................................................................................57
New Transmission Requirements .......................................................................................................................57
Customer Loads and Resources ............ ....... .... ....... ....... .................... ..... ....... ..... .... ....... ..... ...... ...... ..... ...... .... .... 58
Reliability...................................................... ..................................................................................................... 59
Resource Locations...................................................................................................................... ......................59
ENERGY GATEWAY PRIORITIES............................................................................................................................62
"Rightsizing" Energy Gateway..... .... ..... .... ....... ..... ...... ... .... ........... ..... .... ... .... ..... .... ...... ... ..... ...... .... ....... .... ........62
WECC Ratings Process......................................................................................................................................63
Regulatory Acknowledgement and Support .... .... ... ............ ........ ..... ....... .... .... ... ..... ....... .... ....... ....... ....... ...... ...... 65
TRASMISSION SCENARIO ANALySIS....................................................................................................................66
Additional Transmission Scenarios....................................................................................................................66
Green Resource Future .... .... ............ .... ...... ..... .............. .... ..... .... ....... ..... ...... ..... .... .............. ...... .... ....... .... .... ......66
Incumbent Resource Future. .... ....... ..... ........... .... ....... ........... ......... ....................... .... ... .... ....... ...... ....... .... ...... ....66
2011 IRP Transmission Analysis. ............. ..... ...... .............. .... ....... ..... ...... ....... ..... .... ....... .... ....... .............. ...... ....67
System Optimizer Assumptions ..........................................................................................................................74
Green Resource Future Results........ ..... ...... ..... .... ......... ..... ......... ............. ..... .... ..... .... ......... ..... ....... ........... ........ 75
Incumbent Resource Future Results...................................................................................................................79
Energy Gateway Treatment in the Integrated Resource Plan....................................,........................................82
CHAPTER 5 - RESOURCE NEEDS ASSESSMENT ...........................................................................................83
INTRODUCTION .....................................................................................................................................................83
COINCIDENT PEAK LOAD FORECAST ....................................................................................................................84
EXISTING RESOURCES ...........................................................................................................................................84
Thermal Plants...................................................................................................................................................85
Renewables ........................................................................................................................................................86
Wind...............................................................................................................................................................................86
Geothermal..... .... .... .... ........ .... .... ...... .... .... ..................... ...... .... .... .... .... ... ... .... ...... .... .... ............ .... .... ...... .... ...... .... .... ........ 88
Biomass / Biogas............................................................................................................................................................. 88
Renewables Net Meterig...............................................................................................................................................88
Hydroelectric Generation..................................................................................................................... .............88
Hydroelectric Relicensing Impacts on Generation..........................................................................................................89
Demand-side Management.................................................................................................................................90
Class 1 Demand-side Management .... .... .............. .... ...... .......... .... ........... .......... .... .... .... ........ .... .... ... ........... ...... .... ...... .... 92
Class 2 Demand-side Management. ... ...... .... .... .............. ...... .... .... .... .... ....... .......... .... ............ .... .... ... ...... ..... ...... .......... .... 92
Class 3 Demand-side Management ........ ...... .... .... .......... ...... .... .... .... ....... ........ ...... .... .... .... ...... ......... ............. .... ...... .... .... 92
Class 4 Demand-side Management.. ........ .... .... .... ...... .... ...... .... .... .... .... ........... .... ... ... .... .... .......... ..... .... ......... .... ...... .... .... 93
Power Purchase Contracts .... ..... .... ..... .... ............ .... ........... ... ...... ......... ... ...... ..... .... ....... ........ ... ... ... ........ ..... ...... 94
LOAD AND RESOURCE BALANCE ..........................................................................................................................96
Capacity and Energy Balance Overview.............................................................................'...............................96
Load and Resource Balance Components..........................................................................................................97
Existing Resources.......................................................................................................................................................... 97
Obligation .......................................................................................................................................................................98
11
PACIFiCORP-2011 IRP TABLE OF CONTENT
Reserves ........... .... ...... ........ ......................... .......... .... .... ...... .... .... ........ ...... ........ .......... ............ .... ...... ...... ...... .... .... .... ...... 99
Position .......................................................................................................................................;................................... 99
Reserve Margin............................................................................................................................................................... 99
Capacity Balance Determination.................................................................................................................. ...100
Methodology ... .... ...... ........ .......... .... ...... ........ .... .......... ...... .... .... ....... .... ........ .... .... ........... ............ .......... .... ............ ........ 100
Load and Resource Balance Assumptions .. ........... .... .... ...... .... .... ............... .... .... ...... ...... ...... .... ....... .... ..... ...... .............. 100
Capacity Balance Results..............................................................................................................................................101
Energy Balance Determination. ..... .... ..... ....... ..... .... ..... .... ....... ..... .... ... ........... ..... ....... ...... ....... ... .......... ......... ...1 04
Methodology.................................................................................................................................................................104
Energy Balance Results....... ....................... .... ....... .... ... .... ....... .... ..... .... ..... .... ..... .... ....... ....... ... .... ........... ..........1 05
Load and Resource Balance Conclusions .... ....... ..... ........... ................ ..... ....... ........... ......... ....... ........ ..............1 07
CHAPTER 6 - RESOURCE OPTIONS................................................................................................................109
INTRODUCTION ...................................................................................................................................................110
SUPPLY-SIDE RESOURCES....................................................................................................................................110
Resource Selection Criteria...................................................................................................................... ...... .11 0
Derivation of Resource Attributes................................................................................................................. ...11 0
Handling of Technology Improvement Trends and Cost Uncertainties ...........................................................111
Resource Options and Attributes...... .................................... ........................................................................... .113
Distrbuted Generation..................................................................................................................................................121
Resource Option Description. ..... .... ..... .... ....... ..... .... ..... ..... ...... ..... ....... .... ... .... ..... .............. ......... ....... ..... .........125
Coal...............................................................................................................................................................................125
Coal Plant Efficiency Improvements ............................................................................................................................126
Natural Gas ................................................................................................................................................................... 127
Wind.............................................................................................................................................................................128
Other Renewable Resources ......................................................................................................................................... 131
Combined Heat and Power and Other Distrbuted Generation Alternatives ....... .... ........... .......... ...... ............ ............... 134
Nuclear..........................................................................................................................................................................135
DEMAD-SIDE RESOURCES..................................................................................................................................135
Resource Options and Attributes......................................................................................................................135
Source of Demand-side Management Resource Data ................................................................................................... 135
Demand-side Management Supply Curves ................................................................................................................... 135
TRASMISSION RESOURCES ................................................................................................................................150
MARKT PURCHASES...........................................................................................................................................150
CHAPTER 7 - MODELING AND PORTFOLIO EV ALUA nON APPROACH ............................................153
INRODUCTION ....................................................................................................................................................154
GENERAL ASSUMPTIONS AND PRICE INPUTS ......................................................................................................155
Study Period and Date Conventions ................................................................................................................155
Escalation Rates and Other Financial Parameters..........................................................................................155
Inflation Rates............................................................................................................................................................... 155
Discount Factor............................................................................................................................................................. 156
Federal and State Renewable Resource Tax Incentives................................................................................................ 156
Asset Lives....................................................................................................................................................................156
Transmission System Representation ................................................................................................................157
CARON DIOXIE REGULATORY COMPLIANCE SCENARIOS ............................................................................159
Carbon Dioxide Tax Scenarios ........................................................................................................................159
Emission Hard Cap Scenarios .... .... ..... .... ....... ..... .......... ...... .... ..... ....... .... ..... ..... ........... ....... ....... .............. .... ...160
Oregon Environmental Cost Guideline Compliance..... .... ....... ..... ....... ........... ..... ......... ....... .... ... .... ... ...... ........162
CASE DEFIITION.................................................................................................................................................162
Case Specifcations................................................................................................................... ...................... .163
Case Definition Notes ..... .... ...... .... ....... ....... .......... .... ...... .... .... ...... .... .... ...... .......... .... ............ .......... ...... ...... .... .... ...... .... 166
SCENARIO PRICE FORECAST DEVELOPMENT .....................................................................................................170
Gas and Electricity Price Forecasts ................................................................................................................172
Price Projections Tied to the High Forecast.................................................................................................................. 173
Price Projections Tied to the Medium Forecast ............................................................................................................ 175
Price Projections Tied to the Low Forecast.................................................................................................................. 176
OPTIMIZED PORTFOLIO DEVELOPMENT ............................................................................................................178
11
P ACIFICORP - 20 i 1 INTEGRA TED RESOURCE PL TABLE OF CONTENTS
System Optimizer Customizations .......... ........... ..... ....... .... ............ .... .......... .... ......................... ... ....... .... ..... .....178
Representation and Modeling of Renewable Portfolio Standards .... ... ................ ........................... ...... ..... ......179
Modeling Front Offce Transactions and Growth Resources ............................... ...................... ....... ......... .....179
Modeling Wind Resources...... ..... .... ..... ............... ....... ..... .... .................. ..... ........... .... ..... ............. ....... ............. .180
Stochastic Production Cost Adjustment for Combined-cycle Combustion Turbines .... ......... ..... ......... ........... .180
Modeling Fossil Fuel Effciency Improvements.. ...... .... ..... .... ..... .... ..... .... ..... .... ....... ..... .... ..... .... ..................... .180
Modeling Coal Plant Utilization ..... .... ....... .... ............ .... ..... ........... ....... .... ..... ........... ..... .... ..... .... ............. ... .... .180
Modeling Energy Storage Technologies ..........................................................................................................182
MONTE CARO PRODUCTION COST SIMULATION.............................................................................................182
The Stochastic Model... .... ..... ...... ..... .... ... ............................. .... .............. .... ..... ....... .... ..... ........ ............. ..... ...... .183
Stochastic Model Parameter Estimation..........................................................................................................184
Monte Carlo Simulation...................................................................................................................................187
Stochastic Portfolio Performance Measures....................................................................................................196
Mean PVRR......................................................................................................................................................197
Risk-adjusted Mean PVR ...............................................................................................................................197
Ten-year Customer Rate Impact ......................................................................................................................198
~lil~~I~~ ~:~~~riýRi:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ~ ~~
Production Cost Standad Deviation .. ........ .... ...... .... ..... ...... .... ...... .... .... ...... ...... ........ .... .......... ........ .... ...... ...... .... .... ...... 199
Average and Upper-Tail Energy Not Served ................................................................................................................199
Loss of Load Probability...............................................................................................................................................199
Fuel Source Diversity......................................................................................................................;................200
TOP-PERFORMNG PORTFOLIO SELECTION .......................................................................................................200
Initial Screening...............................................................................................................................................200
Final Screening................................................................................................................................................201
DETERMINISTIC RISK ASSESSMENT ....................................................................................................................202
RESOURCE ACQUISITION AND REGULATORY POLICY RISK AsSESSMENT ........................................................202
Gas Plant Timing.............................................................................................................................................202
Geothermal Development Risk......................................................................................................................,..203
Regulatory Compliance Risk and Public Policy Goals.. ..... .... ....... ....... ..... ....... .... .......... ... ... ....... ....... ..... ..... ... 203
CHAPTER 8 - MODELING AND PORTFOLIO SELECTION RESUL TS.....................................................205
INTRODUCTION ....................................................................................................................................................206
PREFERRD PORTFOLIO SELECTION ..................................................................................................................206
Core Case Portfolio Development Results.......................................................................................................206
Resource Selection........................................................................................................................................................ 206
Carbon Dioxide Emissions............................................................................................................................................209
Initial Screening Results ..................................................................................................................................213
Final Screening Results........ ..... ............. ....... .... ......... ... .... ..... ...... ..... ............. ..... .... ....... ......... ...... ....... ..... .... ... 217
Risk-adjusted PVR .......... .... ..................... .... ...... .... .... ...... ...... .... .... .......... ...... .... .... .............. .... .... .... ................ .......... 2 I 7
10-year Customer Rate Impact.....................................................................................................................................217
Cumulative Carbon Dioxide Emissions ...... .... .............. ............ .... ............ .... .... .... .... ...... ........ .... ....... ..... .............. .... .... 218
Supply Reliability .........................................................................................................................................................218
Resource Diversity ...........................................................................................................................................219
Final Screening and Preliminary Preferred Portfolio Selection..................................................... .................219
Selection of the Top Three Portfolios ...........................................................................................................................219
Deterministic Risk Assessment .........................................................................................................................220
Preliminar Preferred Portfolio Selection ..... .............. .... ..... .... .................... ........ ....... .... .... .... .... ........ .... ...... .... .... ..... ... 223
Acquisition Risk Assessment ............................................................................................................................223
Combined-cycle Combustion Turine Resource Timing .............................................................................................. 223
Geothermal Resource Acquisition ... .... ...... ................... ........ .... .... .... ............ ........ .... ...... ........ .... ........ .... ...... .... .... ..... ... 224
Combined Economic Impact of the CCCT Deferrl and Geothermal Resource Exclusion ............ ........ ...... ........ .... .... 224
Government Compliance Risk Mitgation and Long Term Public Interest Considerations.............................225
Risk-Mitigating Renewables.........................................................................................................................................226
Wind Quantity Impact of Alternative Renewable Policy Assumptions .... .... ........ .... ............... .... .... .... ...... ...... ............. 226
Preferred Portfolio...........................................................................................................................................228
Preferred Portfolio Compliance with Renewable Portfolio Stadad Requirements.....................................................234
Preferred Portfolio Carbon Dioxide Emissions.............................................................................................................235
iv
PACIFiCORP-2011 IR TABLE OF CONTNT
SENSITIVY ANALYSES .......................................................................................................................................236
System Optimizer Sensitivity Cases..................................................................................................................236
Coal Utilization Cases................................................................................................................................................... 236
Out-year Optiization Impact Analysis........................................................................................................................240
Alternative Load Forecast Cases...................................................................................................................................242
Renewable Resource Cases...........................................................................................................................................243
Demand-side Management Cases ........ .............. .... ............ .... .... .... .... ...... .... .... ...... ...... ....... ........ ... ..... .... ................ ...... 246
Cost of Energy Not Served (ENS) Sensitivity Analysis.....................................................................................249
CHAPTER 9 - ACTION PLAN .............................................................................................................................251
INTRODUCTION ............................................................~......................................................................................252
THE INTEGRATED RESOURCE PLAN ACTION PLAN............................................................................................253
PROGRESS ON PREVIOUS ACTION PLAN ITEMS ..................................................................................................259
ACQUISITION PATH ANALYSIS ...................~........................................................................................................265
Resource Strategies.............................. .................. .................................... .............................:........................ 265
Acquisition Path Decision Mechanism ............................................................................................................266
Procurement Delays.........................................................................................................................................270
IRP ACTION PLAN LINKAGE TO BUSINESS PLANNING.......................................................................................271
RESOURCE PROCURMENT STRATEGY ...............................................................................................................272
Renewable Resources.................................................,......................................................................................273
Demand-side Management.... ..... .... ....... .... ..... .... ..... .... .......... ........ ... .... ....... .... ..... .... ... ......... ....... ......... ....... .....2 73
Thermal Plants and Power Purchases .............................................................................................................274
Distributed Generation ....................................................................................................................................274
ASSESSMENT OF OWNING ASSETS VERSUS PURCHASING POWER......................................................................274
MANAGING CARON RISK FOR EXISTING PLANS.............................................................................................275
MANAGING GAS SUPPLY RISK ...........................................................................................................................276
Price Risk.........................................................................................................................................................276
Availability Risk...............................................................................................................................................276
Deliverability Risk............................................................................................................................................276
TREATMNT OF CUSTOMER AND INVESTOR RISKS ............................................................................................278
Stochastic Risk Assessment ..............................................................................................................................278
Capital Cost Risks............................................................................................................................................278
Scenario Risk Assessment ......;.........................................................................................................................278
CHAPTER 10 - TRANSMISSION EXPANSION ACTION PLAN ...................................................................281
INTRODUCTION ....................................................................................................................................................282
TRANSMISSION ADDITIONS FOR ACKNOWLEDGEMENT .....................................................................................282
Wallula to McNary (Energy Gateway Segment A)...........................................................................................282
Mona to Oquirrh and Oquirrh to Terminal (Energy Gateway Segment C) .....................................................284
Sigurd to Red Butte (Energy Gateway Segment G)..........................................................................................285
TRANSMISSION ADDITIONS FOR INFORMATION ONLY .......................................................................................286
Segment D - Windstar to Populus (Gateway West) .........................................................................................286
Segment E - Populus to Hemingway (Gateway West) ...,.................................................................................286
Segment F -Aeolus to Mona (Gateway South) ...............................................................................................287
Segment H - Hemingway to Captain Jack .... .... .............. .... .... ..... .... ... .... ....... ...... ......... ........... .... ................. ... 288
v
P ACIFICORP - 2011 IRP INDEX OF TABLES
INDEX OF TABLES
TABLE ES.l- PACIFICORP IO-YE CAPACITY POSITON FORECAST (MEGAWATT) ...................................................3
TABLE ES.2 - 2011 IRP RESOURCE OPTIONS ........................................................... .................. ...... .............................. 6
TABLE ES.3 - 201 1 IRP PREFERRD PORTFOLIO ...........................................................................................................8
TABLEES.4-2011 IRP ACTION PLAN ........................................................................................................................14
TABLE 2.1 -201 1 IRPUBLICMEETINGS....................................................................................................................22
TABLE 3.1- SUMMARY OF STATE RENEWABLE GOALS (AS APPLICABLE TO PACIFICORP) ............................................39
TABLE 4. 1 - GREEN RESOURCE FUTURE, SELECTED WIN RESOURCES (MEGAWATTS) ..............................................77
TABLE 4.2 - GREEN RESOURCE FUTURE, PRESENT VALUE REVENU REQUIREMENT ($ MILLIONS)............................. 78
TABLE 4.3 - INCUMBENT RESOURCE FUT, SELECTED WIN RESOURCES (MEGAWATTS) .... .................................. 80
TABLE 4.4 - INCUMBENT RESOURCE FUT, PRESENT VALUE REVENU REQUIRMENT ($ MILLIONS).....................8 1
TABLE 5.1 - FORECASTED COINCIDENTAL PEAK LoAD IN MEGA WATTS, PRIOR TO ENERGY EFFICIENCY REDUCTIONS
...........................................................................................................................................................................84
TABLE 5.2 - CAPACITY RATIGS OF EXISTING RESOURCES ........................................................... ........... ................... 84
TABLE 5.3 - COAL FIRD PLANS ................................................................................................................................85
TABLE 5.4 - NATURA GAS PLANS ............................................................................................................................86
TABLE 5.5 - PACIFiCORP-OWND WIN RESOURCES...................................................................................................87
TABLE 5.6 _ WIN POWER PURCHASE AGREEMENTS AN EXCHANGES ......................... ............... .................. ....... ..... 87
TABLE 5.7 - HYDROELECTRIC CONTRACTS ... ........ ..... .... ..... ........ ....... ............. ................ .............................................89
TABLE 5.8 - PACIFICORP OWND HYDROELECTRC GENERATION FACILITIES - LOAD AN RESOURCE BALANCE
CAPACITIES.........................................................................................................................................................89
TABLE 5.9 - ESTIMATED IMPACT OF FERC LICENSE RENEWALS ON HYDROELECTRC GENERATION ..........................90
TABLE5.10-ExiSTING DSM SUMMARY, 2011-2020..................................................................................................93
TABLE 5.11 - SYSTEM CAPACITY LoADS AN RESOURCES WITOUT RESOURCE ADDITONS................... ................102
TABLE 6.1 - EAST SIDE SUPPLY-SIDE RESOURCE OPTIONS.......................................................................... ..............115
TABLE 6.2 - WEST SIDE SUPPLY-SIDE RESOURCE OPTIONS................................................ ........... ............................1 16
TABLE 6.3 - TOTAL RESOURCE COST FOR EAST SIDE SUPPLY-SIDE RESOURCE OPTIONS, $0 CO2 TAX ...... ..............1 17
TABLE 6.4 - TOTAL RESOURCE COST FOR WEST SIDE SUPPLY-SIDE RESOURCE OPTIONS, $0 CO2 TAX.................... 1 18
TABLE 6.5 - TOTAL RESOURCE COST FOR EAST SIDE SUPPLY-SIDE RESOURCE OPTIONS, $19 CO2 TAX.. .................1 19
TABLE 6.6 - TOTAL RESOURCE COST FOR WEST SIDE SUPPLY-SIDE RESOURCE OPTIONS, $19 CO2 TAX. .............. ...120
TABLE 6.7 - DISTRBUTED GENERATION RESOURCE SUPPLY -SIDE OPTIONS .. ................ ...........................................122
TABLE 6.8 - DISTRBUTED GENERATION TOTAL RESOURCE COST, $0 CO2 TAX........................................................123
TABLE 6.8A - DISTRBUTD GENERATION TOTAL RESOURCE COST, $ 1 9 CO2 TAX ................... ....... .... ............ ...... ...124
TABLE 6.9-REpRESENTATION OF WIN IN THE MODEL TOPOLOGY .........................................................................128
TABLE 6.10 - WIND RESOURCE CHARACTERISTICS BY TOPOLOGY BUBBLE ............ ......................... .........................130
TABLE 6.1 1 -2010 GEOTHERMAL STUY RESULTS.............................................. ....................................................133
TABLE 6.12 _ DISTRBUTD GENERATION RESOURCE ATTRUTES ........................................... ................................134
TABLE 6.13 - CLASS 1 DSM PROGRAM ATTRIBUTES WEST CONTOL ARA ............................................................137
TABLE 6.14 - CLASS 1 DSM PROGRAM ATTRBUTES EAST CONTROL ARA .................................... .........................138
TABLE 6.15 - CLASS 3 DSM PROGRA ATTBUTES WEST CONTOL AllA........... ......... ......... ............. ...................140
TABLE 6.16 - CLASS 3 DSM PROGRA ATTRIBUTES EAST CONTOL ARA................. .......................... ....... ............140
TABLE 6.17 - LOAD ARA ENERGY DISTRBUTION BY STATE........ ......................................................... ...................143
TABLE 6.18 - MAMUM AVAILABLE FRONT OFFICE TRSACTION QUANTTY BY MAT HUB .... .... ...................151
TABLE 7.1 - RESOURCE BOOK LiVES ................................................................................ .................. .... ....... ...... ......157
TABLE 7.2-C02 TAX SCENAROS .............................................................................................................................159
TABLE 7.3 - HA CAP EMISSION LIMITS (SHORT TONS) .................... ......................... .... ......... ............. ...................160
TABLE 7.4 - CO2 EMISSION SHADOW COSTS GENERA TED BY SYSTEM OPTIMIZER FOR EMISSION HAR CAP
SCENAROS .......................................................................................................................................................161
TABLE 7.5 - PORTFOLIO CASE DEFINITIONS ... ...................... ................................. ...................... .................. ............164
. TABLE 7.6 - COMPARISON OF RENEWABLE PORTFOLIO STANDAR TARGET SCENARIOS ............ ..............................167
TABLE 7.7 - ENERGY GATEWAY TRASMISSION SCENARIOS................................. .................................................... 169
TABLE 7.8 - HENRY HUB NATU GAS PRICE FORECAST SUMMARY (NOMINAL $/MTU).................................. 173
TABLE 7.9 - RESOURCE COSTS, EXISTING AN ASSOCIATED PLANT BETTERMNT COST CATEGORIES ....................181
VI
PACIFICORP - 2011 IR INDEX OF TABLES
TABLE 7.10-SHORTTERM STOCHASTIC PARETER COMPARSON, 2008 IRP VS. 2011 IR ..................................185
TABLE 7.1 1- PRICE CORRLATIONS..........................................................................................................................186
TABLE 7.1 2 ~ LOAD DRIRS BY TIME PERIOD. ............................. .... ..... ............................ ........... ......................... ...188
TABLE 7.13 - DETERMINSTIC RISK ASSESSMENT SèENAROS ................................................... ................................202
TABLE 8.1 - TOTAL PORTFOLIO CUMUATNE CAPACITY ADDITIONS BY CASE AND RESOURCE TYE, 2011 - 2030.207
TABLE 8.2 - INIIAL SCREENING RESULTS, STOCHASTIC COST VERSUS UPPER-TAIL RISK ............... ..........................21 6
TABLE 8.3 - PORTFOLIO COMPARSON, RISK-ADJUSTED PVR.................................................................................217
TABLE 8.4- PORTFOLIO COMPARSON, 10-YEAR CUSTOMER RATE IMPACT..............................................................217
TABLE 8.5 -PORTFOLIO COMPARISON, CUMATIVE GENERATOR CO2 EMISSIONS FOR 201 1-2030.........................218
TABLE 8.6- PORTFOLIO COMPARSON, ENERGY NOT SERVED ..................................................................................218
TABLE 8.7- GENERATION SHARES BY RESOURCE TYPE, 2020 ..... .................. .................... .......................................219
TABLE 8.8 - TOP-THREE PORTFOLIO COMPARISON, FINAL SCREENING PERFORMCE MEASURS ..........................219
TABLE 8.9 - DETERMINISTIC PVR COMPARISON FOR CASE 1 AND CASE 3 PORTFOLIOS .........................................221
TABLE 8.10 ~ PORTFOLIO RESOURCE DIFFERENCES, Top THE PORTFOLIOS ..........................................................222
TABLE 8.11 - DRY-COOLED CCCT, 2015 TO 2016 PVR DEFERR VALUE ............................................................224
TABLE 8.12 - PVR COMPARSON, PRELIMINARY PREFERRD PORTFOLIO VS. REVISED PREFERRD PORTFOLIO ....225
TABLE 8.13 - DERIVATION OF WIND CAPACITY FOR THE PREFERRD PORTFOLIO............... ........... ...........................226
TABLE 8.14- WIND ADDITIONS UNERALTERNATNE RENEWABLE POLICY ASSUMTIONS.....................................227
TABLE 8.15 -WIN CAPACITY SCHEDULE .................................................................................................................228
TABLE 8.16 - PREFERRD PORTFOLIO, DETAIL LEVEL..............................................................................................230
TABLE 8.17 - PREFERRD PORTFOLIO LOAD AN RESOURCE BALANCE (201 1-2020) ...............................................231
TABLE 8.18 - DISPOSITON OF COAL UNITS FOR THE COAL UTILIZATION CASES .... ....... ...........................................237
TABLE 8.19 - RESOURCE DIFFERENCES, FULL OPTIMIZATION PORTFOLIO LESS PARTIAL OPTIMIZATION PORTFOLIO,
CASE 9 ASSUMPTIONS......................................................................................................................................;241
TABLE 8.20 - RESOURCE DIFFERENCES, CASE 7 VS. Low AND HIGH EcONOMIC GROWTH PORTFOLIOS ........... ........242
TABLE 8.21 - RESOURCE DIFFERENCES, HIGH PEAK DEMA VS. HIGH ECONOMIC GROWT PORTFOLIOS .......... ...243
TABLE 8.22 - SOLAR PV RESOURCE COMPARSON, BUY -DOWN UTILIT COST VERSUS TOTAL RESOURCE COST
PVR...............................................................................................................................................................244
TABLE 8.23 - RESOURCE DIFFERENCES, RENEWABLE PORTFOLIO STANDAR AND ALTERNATE WIN INTGRATION
COST IMPACT ..........................................................................................................................;.........................245
TABLE 8.24 - RESOURCE DIFFERENCES, CLASS 3 DSM PORTFOLIO (CASE 31) LESS CASE 7 PORTFOLIO ................,.247
TABLE 8.25 - RESOURCE DIFFERENCES, TECHNICAL DSM POTENTIA VS. ECONOMIC DSM POTENTIAL .................248
TABLE 9.1 -IRP ACTION PLAN UPDATE........................................ ............................................................................254
TABLE 9.2 - NEAR-TERM AN LONG-TERM RESOURCE ACQUISITON PATHS.............................................................267
TABLE 9.3 - PORTFOLIO COMPARSON, 2011 PREFERRD PORTFOLIO VERSUS 2008 IRP UPDATE PORTFOLIO ..........272
Vll
PACIFiCORP-2011 IR INDEX OF FIGURS
INDEX OF FIGURES
FIGUR ES.1 - PRICE FORECAST COMPARSONS FOR RECENT IRs ...............................................................................2
FIGUR ES.2 - PACIFICORP CAPACIT RESOURCE GAP .................................................................................................3
FIGURE ES.3 - SYSTEM AVERAGE MONTLY AN ANAL ENERGY BALANCES .........................................................4
FIGUR ES.4 - ADDRESSING PACIFICORP'S PEAK CAPACIT DEFICIT, 201 1 THROUGH 2020 ........................................9
FIGUR ES.5 - CURNT AN PROJECTED P ACIFICORP RESOURCE CAPACITY Mix ............................ ........................ 10
FIGUR ES.6 - ANAL STATE AND FEDERA RPS POSITON FORECASTS ..................................................................11
FIGUR ES. 7 - ANAL AN CUMATIV REWABLE CAPACITY ADDITIONS, 2003-2030 .....................................12
FIGUR ES.8 - CARBON DIOXIDE GENERATOR EMISSION TRND, $19/TON CO2 TAX ........ ......................................... 12
FIGUR ES.9 - CURNT AN PROJECTEDPACIFICORP RESOURCE ENERGY Mix .......................................................13
FIGUR 3.1 - HENRY HUB DAY-AHEAD NATU GAS PRICE HISTORY ......................................................................27
FIGUR 3.2 - HISTORICAL NATUL GAS PRODUCTION BY TYPE ................................................................................28
FIGUR 3.3 - SHAE PLAYS IN LOWER 48 STATES .......................................................................................................28
FIGUR 3.4 - EPA REGULATORY TIMELINE FOR THE UTILITY INDUSTRY ...............................................................,....3 I
FIGUR 3.5 - REGIONAL CLIMTE CHANGE INITIATIVS .............................................................................................36
FIGURE 4.1 - SUB-REGIONAL TRSMISSION PLANING GROUPS IN THE WECC ........................................................53
FIGUR 4.2 - SUB-REGIONAL COORDINATION GROUP (SCG) FOUNATIONAL PROJECTS BY 2020 ..............................54
FIGUR 4.3 - SUB-REGIONAL COORDINATION GROUP (SCG) POTENTIA PROJECTS BY 2020......................................55
FIGURE 4.4- PACIFICORP SERVICE TERRORY, OWND GENERATION AN ENERGY GATEWAY OVERLAY..................61
FIGUR 4.5 - STAGES OF THE WECC RATINGS PROCESS .............................................................................................64
FIGURE 4.6 - SYSTEM OPTIMIZER ENERGY GATEWAY SCENARO 1 ...................................... ....... ................................68
FIGURE 4.7- SYSTEM OPTIMIZR ENERGY GATEWAY SCENARO 2 .............................................................................69
FIGURE 4.8 - SYSTEM OPTIMIZR ENERGY GATEWAY SCENARO 3 ............................................................................. 70
FIGUR 4.9 - SYSTEM OPTIMIZER ENERGY GATEWAY SCENARO 4. ....... .......................... ........................................ ... 7 I
FIGUR 4.1 0 - SYSTEM OPTIMIZER ENERGY GATEWAY SCENARO 5 ...... ............... .... ....... ........................................... 72
FIGUR 4. I I - SYSTEM OPTIMIZER ENERGY GATEWAY SCENARO 6.......... ............... ....... ........................................... 73
FIGURE4.12-SYSTEM OPTIMIZER ENERGY GATEWAY SCENARO 7 ...........................................................................74
FIGURE 5. I - CONTRACT CAPACITY IN THE 20 I I LOAD AND RESOURCE BALANCE .....................................................95
FIGUR 5.2 - CHAGES IN POWER CONTCT CAPACITY IN THE LOAD AN RESOURCE BALANCE .............................96
FIGURE 5.3 - SYSTEM CAPACITY POSITION TREND ........ ..... .... ....... ...... ... ........... .... .... ....... ........................... ..............103
FIGURE 5.4 - WEST CAPACITY POSITION TRD........................................................................................................1 03
FIGURE 5.5 - EAST CAPACITY POSITION TREND......................................................................................................... 104
FIGUR 5.6 - SYSTEM AVERAGE MONTHY AN ANAL ENERGY POSITONS.........................................................105
FIGUR 5.7 - WEST AVERAGE MONTHLY AND ANAL ENERGY POSITIONS ............................................................106
FIGURE 5.8 - EAST AVERAGE MONTHLY AND ANAL ENERGY POSITONS .............................................................106
FIGURE 6. I - WORLD CARBON STEEL PRICE TRENDS ......... .................... ......................................... .................. ........1 12
FIGUR 6.2 - COMMERCIALLY VIABLE GEOTHERM RESOURCES NEAR PACIFICORP'S SERVICE TERRTORY......... 132
FIGUR 6.3 - PACIFICORP CLASS 2 DSM POTENTIAL, AUG-2009 VS. AUG-201O CURVES.........................................I44
FIGURE 6.4 - CALIFORNIA .cLASS 2 DSM POTENTAL, AUG-2009 VS. AUG-20 I 0 CURVES .......... ..............................144
FIGURE 6.5 - OREGON CLASS 2 DSM POTENTIA, AUG-2009 VS. AUG-201O CURVES ..............................................145
FIGURE 6.6 - WASHINGTON CLASS 2 DSM POTENTIL, AUG-2009 VS. AUG-201O CURVES......................................145
FIGUR 6.7 - UTAH CLASS 2 DSM POTENTIAL, AUG-2009 VS. AUG-201O CURVES...................................................146
FIGUR 6.8 - IDAHO CLASS 2 DSM POTENTIAL, AUG-2009 VS. AUG-201O CURVES .................................................146
FIGUR 6.9 - WYOMING CLASS 2 DSM POTENTIL, AUG-2009 VS. AUG-201O CURVES ...........................................147
FIGUR 6.10 - CLASS 2 DSM COST BUNDLES AN BUNLE PRICES ................................. .... ............................. ........148
FIGUR 6. I I - SAMPLE DISTRIBUTION ENERGY EFFICllNCY LOAD SHAPE ........................... ............ .........................149
FIGUR 7. I - MODELING AND RISK ANALYSIS PROCESS .......................................................... ........ ....................... ...155
FIGUR 7.2 - TRSMISSION SYSTEM MODEL TOPOLOGY .........................................................................................158
FIGUR 7.3 - CARBON DIOXIDE PRICE SCENARIO COMPARSON ................................................................................160
FIGUR 7.4 - LOAD FORECAST SCENARIO COMPARISON ....... .... ......... .................. .................... .................................. 166
FIGURE 7.5 - MODELING FRAEWORK FOR COMMODITY PRICE FORECASTS. ..... .... ........................................ ..........17 I
FIGUR 7.6 - COMPARISON OF HENRY HUB GAS PRICE FORECASTS USED FOR RECEN IRPs..................................... 172
FIGUR 7.7 - COMPARSON OF ELECTRCITY PRICE FORECASTS USED FOR RECENT IRs .......................................... 173
V11
PACIFiCORP-2011 IRP INDEX OF FIGURS
FIGUR 7.8 - HENRY HUB NATUL GAS PRICES FROM THE HIGH UNDERLYING FORECAST ....................................174
FIGURE 7.9 - WESTERN ELECTRCITY PRICES FROM THE HIGH UNDERLYING GAS PRICE FORECAST...... ............ .......174
FIGUR 7.10 - HENRY HUB NATURL GAS PRICES FROM THE MEDIU UNDERLYING FORECAST .............................175
FIGUR 7.11 - WESTERN ELECTRCITY PRICES FROM THE MEDIU UNDERLYING GAS PRICE FORECAST .................176
FIGUR 7.12- HENRY HUB NATURA GAS PRICES FROM THE Low UNDERLYIG FORECAST ...................................177
FIGUR 7.i 3 - WESTERN ELECTRCITY PRICES FROM THE Low UNDERLYING GAS PRICE FORECAST ...... ................ .177
FIGUR 7.14 - FREQUENCY OF WESTERN (MID-COLUMBIA) ELECTRCITY MARKT PRICES FOR 2012 AND 2020 ..... 1 89
FIGUR 7.15 - FREQUENCY OF EASTERN (pALO VERDE) ELECTRICITY MAT PRICES, 2012 AN 2020 .................189
FIGUR 7.16 - FREQUECY OF WESTERN NATU GAS MAT PRICES, 2012 AN 2020................... ... ......... .......190
FIGUR 7.17 -FREQUENCY OF EASTERN NATU GAS MARKT PRICES, 2012 AN 2020.......................................191
FIGURE 7.18 - FREQUENCIES FOR IDAHO (GOSHEN) LOADS .... .... ..... ..................................... .................... .................192
FIGURE 7.19 - FREQUENCIES FOR UTAH LOADS .................................................................... .................... .................192
FIGUR 7.20 - FREQUENCIES FOR WASHINGTON LOADS ............................................................................................193
FIGUR 7.21 - FREQUECIES FOR CALIFORNIA AN OREGON LOADS ............................. .................... ............... ........193
FIGUR 7.22 - FREQUECIES FOR WYOMING LOADS ....... ......... .............. ........................ .... ................ ............... ........194
FIGUR 7.23 - FREQUENCIES FOR SYSTEM LOADS ....... ........................... ...... ......... ............................................ ........194
FIGUR 7.24 - FREQUENCIES FOR SYSTEM LOADS (WITH LONG-TERM VOLATIITY) ..... .... .........................................195
FIGUR 7.25 - HYDROELECTRIC GENERATION FREQUENCY, 201 1 AND 2020 ............................................................195
FIGUR 7.26 - ILLUSTRTIV STOCHASTIC MEAN VS.UPPER-TAIL MEAN PVR SCATTR-PLOT .............................201
FIGUR 8.1 - FRONT OFFICE TRANSACTION ADDITON TRs BY PORTFOLIO, 201 1 -2020......................................209
FIGURE 8.2 - ANAL CO2 EMISSIONS: MEDIU CO2 TAX SCENARIO......................................................................210
FIGUR 8.3 - ANAL CO2 EMISSIONS: HIGH CO2 TAX SCENARO .............. ..... .... ........... ........... ..............................211
FIGURE 8.4 - ANAL CO2 EMISSIONS: Low TO VERY HIGH CO2 TAX SCENARO....................................................211
FIGURE 8.5 - ANAL CO2 EMISSIONS: HARD CAP SCENARIOS ................................................................................212
FIGUR 8.6 - ANAL CO2 EMISSIONS: No CO2 TAX.... ......... .................. ...... ......... ...................... ........... .................212
FIGUR 8.7 - STOCHASTIC COST VERSUS UPPER-TAIL RISK, $0 CO2 TAX SCENARO ................................................213
FIGUR 8.8 - STOCHASTIC COST VERSUS UPPER~TAILRISK, MEDIUM CO2 TAX SCENARO.......................................214
FIGUR 8.9 - STOCHASTIC COST VERSUS UPPER-TAIL RISK, Low TO VERY HIGH CO2 TAX SCENARO ....................215
FIGURE 8.10 - STOCHASTIC COST VERSUS UPPER-TAIL RISK, AVERAGE OF CO2 TAX SCENAROS ............................216
FIGUR 8.11 - PREFERRD PORTFOLIO DERIVATION STEPS ...................... ........... .... ............. ..... ...................... ......... .228
FIGUR 8.12 - CURNT AN PROJECTED P ACIFICORP RESOURCE ENERGY MI FOR 2011 AN 2020......................232
FIGUR 8.13 - CURNT AN PROJECTED P ACIFICÒRP RESOURCE CAPACITY Mix FOR 2011 AN 2020...................233
FIGUR 8.14 - ADDRESSING P ACIFICORP'S PEAK CAPACITY DEFICIT, 2011 THOUGH 2020.....................................234
FIGUR 8.15 - ANNAL STATE AN FEDERAL RPS POSITION FORECASTS USING THE PREFERRD PORTFOLIO .........235
FIGUR 8.16 - CARON DIOXIDE GENERATOR EMISSION TRND, $ 19/TON CO2 TAX ... ......... ........... .........................236
FIGUR 8.17 - GAS AN COAL PLAN UTILIZATION TRENDS, CASE 20 ............... ........... ...........................................237
FIGUR 8.18 - GAS AN COAL PLANT UTILIZATION TRENDS, CASE 21 .....................................................................238
FIGURE 8.19 - GAS AN COAL PLAN UTILIZATION TRNDS, CASE 22 .....................................................................238
FIGUR 8.20 - GAS AN COAL PLAN UTILIZATION TRES, CASE 23 .....................................................................239
FIGURE 8.21 - GAS AN COAL PLANT UTILIZATION TRENDS, CASE 24 .......... ..... ...................... ................................239
FIGUR 9.1 - ANAL AN CUMULATIVE RENEWABLE CAPACITY ADDITONS, 2003-2030 ......................................253
FIGURE 10.1 -ENERGY GATEWAY TRANSMISSION EXPANSION PLAN ..... ...... ..... ........ .................................... ............289
FIGURE 10.2 - 2012-2014 ENERGY GATEWAY ADDITONS FOR ACKNOWLEDGEMENT ................................ ..... .........290
FIGURE 10.3 -2015-2018 ENERGY GATEWAY ADDITIONS FOR INFORMTION ONLY ................................................291
FIGUR 10.4 - 2017-2019 ENERGY GATEWAY ADDITIONS FOR INFORMATION ONLY ................................................292
iX
PACIFiCORP-2011 IRP CHAPTER 1- EXECUTNE SUMMARY
CHAPTER 1 - EXECUTIVE SUMMARY
PacifiCorp's 2011 Integrated Resource Plan (2011 IR), representing the 11th plan submitted to
state regulatory commissions, presents a framework of futue actions to ensure PacifiCorp
continues to provide reliable, reasonable-cost service with manageable risks to its customers. It
was. developed with participation from numerous public stakeholders, including regulatory staff,
advocacy groups, and other interested partes.
The key elements of the 2011 IRP include (1) a finding of resource need, focusing on the 10-year
period 2011-2020, (2) the preferred portfolio of incremental supply-side and demand-side
resources to meet this need, and (3) resource and transmission action plans that identify the steps
the Company wil take during the next two to four years to implement the plan. The process and
outcome of the .IRP-the prefeITed portfolio and action plans-meet applicable state IRP
standards and guidelines. PacifiCorp continues to plan on a system-wide basis while
accommodating state resource acquisition mandates and policies.
Development of the 2011 IRP involved balanced consideration of cost, risk, uncertainty, supply
reliability/deliverability, and long-ru public policy goals. The resulting preferred portfolio
reflects a significant increase in energy effciency relative to prior IRPs, new gas-fired
combined-cycle combustion tubines, and contiuous annual renewable resource additions
beginning in 2018, assumed to be wid for planingpuroses. Firm market purchases also are
relied upon, paricularly through 2015, taing advantage of favorable market prices.
As an evolving process, the IRP incorporates curent information and reflects continuous
improvements in system modeling capability required to address new issues and an expanding
analytical scope. For example, PacifiCorp recently implemented enhancements to its capacity
expansion optimization tool, System Optimizer; for tracking carbon dioxide emissions and
renewable energy production between load areas. Likewise, the preferred portfolio and action
plans are not static products reflecting resource acquisition commitments, but rather represent a
flexible framework for considering resource acquisition paths that may vary as market and
regulatory conditions change. The preferred portfolio and action plans are augmented by a
resource acquisition path analysis informed by extensive portfolio scenario modeling. As noted
in this and prior IRPs, specific resource acquisition decisions stem from PacifiCorp's
procurement process as supported by the IRP and business planing processes, as well as
compliance with then-curent laws and regulatory rules and orders.
Key drvers guiding the 2011 IRP process and its outcome include the following:
. Decreases in projected natual gas and wholesale electricity prices relative to the
forecasts prepared in 2008 and 2009, favor natural gas fueled resources and market
purchases. These price forecast decreases, shown graphically in Figue ES.l, are caused
mainly by the boom in nonconventional domestic natural gas discoveries and a robust
long-term supply outlook.
1
PACIFICORP - 2011 IR CHAPTER 1- EXECUTIVE SUMARY
Figure ES.l - Price Forecast Comparisons for Recent IRPs
$16.00
Henry Hub Natural Gas Prices
$14.00
$12.00
$10.00
aII
:0
:0 $8.00
..
õii $6.00.,Z
$4.00
$2.00
$0.00
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2010 2021 2022 2023 2024 2015 2026 2027 2018 2029 2030
-.2008 IRP (October 2008) "'"il'" 2008 IRP Update (Septem 2009) __ 20 II IRP (September 20 I 0)
180.00
Palo Verde Electricity Prices, 3rd Quarter Heavy Load Hour
160.00
140.00
120.00
100.00
~ 80.00
:0
;;"¡ 60.00
.~
.,Z 40.00' ..-.--........._- ---.------..-.
20.00
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
-+2008 IRP(Ociober 2(08) -w-'2008 IRPUpdaie(Selember 2(09) "'2011 IRP (September 2010)
· Loss of momentu in federal effort to develop comprehensive federal energy and
climate change compliance requirements contrbute to continued uncertainty regarding
the long-term investment climate for clean energy technologies. Nevertheless, public and
legislative support for clean energy policies at the state level remains robust.
· Continued aggressive efforts by the U.S. Environmental Protection Agency to regulate
electric utility plant emissions, including greenhouse gases, criteria pollutants, and other
emissions.
· Expectations for a more favorable economic environment than assumed in 2009
accompanied by load growth in such areas as data centers and natual resource extraction.
· Progress and challenges in planning for, permtting, and building the Energy Gateway
transmission project, coupled with the potential for state-specific cost recovery issues.
2
PAÇIFiCORP-2011 IRP CHAPTER 1 ~ EXECUTIVE SUMMARY
. Near-term procurement activities, including the planned acquisition of a gas-fired
combined-cycle combustion turbine plant in Utah with a 2014 in-service date.
(PacifiCorp treated this resource as an option in all scenarios analyzed, and was selected
by System Optimizer in every scenario.)
PacifiCorp is expected to need a significant amount of new resources to offset load growt and
the expiration of long-term purchase power contracts occuring over the next several years.
Resource need is determined by developing a capacity load and resource balance that considers
the coincident system peak load hour capacity contribution of existing resources, forecasted
loads and sales, and reserve requirements. Table ES.l shows the Company's annual capacity
position for 2011 through 2020, while Figure ES.2 graphically highlights the capacity resource
gap and contrbution of curently owned and contracted east and west-side resources. Without
new resources, the system experiences a capacity deficit of 326 MW in 2011 and 3,852 MW by
2020. Underlying the capacity position is system annual peak load growt of 2.1 percent on a
compounded average annual basis (prior to forecasted load reductions from energy effciency).
On an energy basis, PacifiCorp expects system-wide average load growth of 1.8 percent per year.
Table ES.l - PacifiCorp lO-year Capacity Position Forecast (Megawatts)~1 ~n ~3 ~4 ~5 ~6 ~7 ~8 ~9 ~
Total Resources 12,468 11,802 11,810 11,404 11,399 11,397 11,412 11,433 11,395 11,192
Sysem Obligation 11,497 11,973 12,264 12,256 12,403 12,595 12,728 12,961 13,145 13,376
Reserves (based on 13% target)1,297 1,430 1,470 1,522 1,542 1,569 1,582 1,611 1,633 1,668
Obligation + 13% Planning Reserves 12,794 13,403 13,735 13,778 13,945 14,164 14,310 14,572 14,777 15,04
Systm Position (326)(1,601)(1,925)(2,373)(2,546)(2,767)(2,898)(3,139)(3,383)(3,852)
Figure ES.2 - PacifiCorp Capacity Resource Gap
2,000
16,000
14,000
, ptan"i": Res \",.'~""'-""""
12.000
10,000
t 8,000'"ai::
6,000
4,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
3
PACIFiCORP-2011 IR CHAPTER 1 - EXECUTIVE SUMMAY
For capacity expansion planing, the Company uses a 13-percent planning reserve margin
applied to PacifiCorp's obligation (load plus sales obligations) less firm purchases and
dispatchable load control capacity. The 13-percent planing reserve margin is supported by a
stochastic loss of load probabilty study conducted in late 2010.
On an average monthly energy basis, the system begins to experience short positions for heavy
load hours! in 2011, while on an average annual basis, short positions occur by 2015 (Figue
ES.3).
Figure ES.3 - System Average Monthly and Annual Energy Balances
3,000
2,00
\
2,500
.1,500
1,000
:e~ 500
~I.. 0..t
~ (500)
(1,s00) .-- Ø( fØ Syste - Light Load Hours (LLH)
-- AnnuaBaJLight Load Hour (LL)
,. .. . Syste - Heavy Lo Hour (HLH)
-- Annua Balance-Heavy Load Hour (HLH)
I ,If I,II " HIf Ii: ---~'l i',
(1,000)
(2.00)
(2.500)
~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~$~ a ~$~a ~$~a ~ $~a ~$~a~ $~a ~ $~a ~$~a~$~a ~$~ a
PacifiCorp is obligated to plan for and meet its customers' future needs, and to manage
uncertainties suroundig regulation of carbon dioxide (C02) emissions, other criteria pollutants,
and potential new requirements for renewable resources. PacifiCorp's priority in building Energy
Gateway transmission is to meet these customer needs, also recognizing its belief that energy
policies wil continue to push toward renewable and low-carbon resource requirements.
Regardless of futue policy direction, the Energy Gateway projects are well aligned with rich and
diverse resources throughout the Company's service territory. Timely permitting by agencies and
regulatory support is critically important to these investments materializing in time to meet
PacifiCorp's need to serve load.
1 Heavy load hours constitute the daily time block of 16 hours, Hour-Ending 7 am - 10 pm, for Monday through
Satuday, excluding NERC-observed holidays.
4
PACIFiCORP-2011 IR CHAPTER 1 - EXECUTIVE SUMMAY
The cycle time to add significant new transmission facilities is often much longer than adding
generation or securing contractual resources. Transmission additions must be integrated into
regional plans before permitting and constrcting the physical assets. PacifiCorp plans and builds
its transmission system based on its network customers' 10-year load and resource forecasts. Per
FERC guidelines, the Company is able to reserve transmission network capacity based on this
1O-year forecast, but in PacifiCorp's experience, the lengty planning, . permitting and
. constrction time line required for significant transmission investments, as well as the tyical
useful life of these facilities, is well beyond 10 years. A 20-year planning horizon and ability to
reserve transmission capacity to meet forecasted need over that timeframe is more consistent
with the time required to plan for and build large scale transmission projects, and PacifiCorp
supports clear regulatory acknowledgement of this reality and corresponding policy guidance.
PacifiCorp's transmission network is also required to meet increasingly strgent mandatory
federal reliability stadards, which require infrastrctue sufficient to withstad unplanned
outage events. The majority of these mandatory standards are the responsibility of the
transmission owner.
For this IRP, a number of Energy Gateway configurations, rangig from Gateway Central to the
full. Gateway expansion scenario, were investigated in the context of alternate C02 cost, natual
gas price, and renewable portfolio standards. PacifiCorp continues to believe that proceeding
with the full Gateway expansion scenario is the most prudent strategy given expected customer
loads, resource diversity benefits, regulatory uncertinty, and the long lead time for adding new
transmission facilties. While Energy Gateway is timed to coincide with PacifiCorp'sresource
needs, delays in the project due to siting and permitting challenges or other factors may result in
the need to pursue alternative resource scenaros. See Chapter 10 for PacifiCorp's transmission
expansion action plan, which requests regulatory acknowledgment of the Energy Gateway
projects scheduled to be in-service in 2014 or sooner.
In line with state IRP standards and guidelines, PacifiCorp included a wide variety of resource
options in portfolio modeling coverig generation, demand-side management and transmission.
Table ES.2 summarizes the different resource options by category included in portfolio
modeling. The Company developed resource option attbutes and costs reflecting updated
information from project experience, public stakeholder input and consultant studies. Projected
resource costs have generally decreased from the previous IRP due to the economic slow-down
in 2009 and 2010. However, capital cost uncertainty for many of the generation options is high
due to such factors as labor cost, commodity price, and resource demand volatility.
A 2010 resource potential study served as the basis for updated resource characterizations
coverig demand-side management (DSM) and distrbuted generation. Input on photovoltaic
resource modeling assumptions from public stakeholders informed the study effort. Also in 2010,
the Company commissioned a geothermal resource study that identified eight sites in the
Company's service terrtory that potentially meet specific criteria for commercial viability.
5
PACIFiCORP-2011 IR CHAPTER 1 - EXECUTIVE SUMMY
For wind resources, PacifiCorp adopted a modeling approach that more closely aligns with
Western Renewable Energy Zones and faciltates assignent of incremental transmission costs
for the Energy Gateway transmission scenario analysis.
Table ES.2 - 2011 IRP Resource Options
Cogeneration Supercriical
Pulverid
Coal without
CC
Wind, 35% and
29% Capacity
Factors
Advanced Coimined Heat & Residential and Nine measure
Battery Storage Power, Small Co1liai bundles grouped by
Reciprocatig Air Conditioning cost for fie statesEngine plus three measure
bundles for Orgon
provided by the
Fnery Trust of
Orgon
One bundle fur
ColIact Florescent
Ùls for 2011 and
2012.
Residential Tim-of- Fnergy GatewayUse Central
Aeroderivativesee Supercriical GeothemiL
pulverd coal Brownfieldwih CC (Dal Flsh)
Hydro Pumped Coimined Heat & Residential
Storage Powe, Gas Electric Water
Tuibine Heating
Conmrcial Crical Fnery Gateway
Peak Priing Central plus
Windstar-Populus
Intercooled
Aerodervative
scer
Supercritical GeotherL ColIressed Air Microtuibine
pulverid coal Grenfield Fnergy Storage
with retrofit (Binary)
CCS
Integrated Sola, Thin Fil
Gasifcation Photovoltaic
Combined
Cycle with
CCS
Iration Dict
Load Contrl
Fnergy Gateway
Central plus
Winds tar-Populus
plus Aeolus-Mona
ConmiaV Fnergy Gateway
Industril Real Tim Central plus
Prcing Winds tar-Populus
plus Aeolus-Mona
plus Populus-
HengwaylHemi
gway-Boardim-
Cascade Crssing
Internal
Combustion
Engine
ConmrciaV
Industril
Curtaint
(includes
distruted stad-
by genertion)
SCerFraiæ Nuclear
Hydrokietic
. CCS ~ Carbon Captur and Seuestraion, seCT = Simle-ycle Comusion Turine, ccer = Combin-Ccle Combustion Turbine
PacifiCorp's IRP modeling approach seeks to determine the comparative cost, risk, and
reliability attbutes of resource portfolios, and consists of seven phases:
. Define input scenarios for portfolio development
· Price forecast development (natual gas and wholesale electricity by market hub)
· Optimized portfolio development using PacifiCorp's System Optimizer capacity expansion
model
· Stochastic Monte Carlo production cost simulation of each optimized portfolio
· Selection of top-performing portfolios using a two-phase screening process that incorporates
stochastic portfolio cost and risk assessment measures
. Deterministic risk assessment of top-performing portfolios using System Optimizer along
with the input scenaros
· Preliminary prefeITed portfolio selection, followed by resource acquisition risk analysis and
determination of the fmal preferred portfolio
6
PACIFiCORP-2011 IR CHAPTER 1 - EXECUTIVE SUMMY
PacifiCorp defined 67 input scenarios for portfolio development, covering alternative (1) Energy
Gateway transmission configuations, (2) C02 tax levels and regulation tyes, (3) natual gas
prices, (4) regulatory renewable acquisition requirements, (4) load forecasts, (5) renewable
generation cost and acquisition incentives, and (6) demand-side management resource
availability assumptions. The Company also conducted proof-of-concept modeling of coal unit
replacements with combined-cycle combustion tubine (CCCT) alternatives, incorporating
incremental costs for existing coal plants.
For portfolio modeling, PacifiCorp used three underlying natual gas price forecasts (low,
medium, and high) to develop gas price projections that include the impact of C02 costs
beginning in 2015: no C02 tax; "medium" ($19/ton escalatig to $29 by 2030); "high" ($25/ton
escalating to $68 by 2030); and "low-to-very-high" ($ 12/ton escalating to $93 by 2030).
PacifiCorp selected top-performing portfolios on the basis of the combination of lowest average
portfolio cost and worst-case portfolio cost resulting from 100 Monte Carlo simulation rus. The
Monte Carlo rus captue stochastic behavior of electrcity prices, natual gas prices, loads,
thermal unit availability, and hydro availability. Final prefeITed portfolio selection considered
additional criteria such as risk-adjusted portfolio cost, the lO-year customer rate impact, C02
emissions, supply reliability, resource diversity, and futue uncertainty and risk of greenhouse
gas and renewable portfolio standard (RPS) policies.
The portfolios serving as preferred portfolio candidates exhibited modest resource mix
variability in the first 10 years. Every portfolio included a CCCT resource in 2014, a second
CCCT in either 2015 or 2016, and frequently a third CCCT in 2019.
Energy efficiency (Class 2 DSM) represents the largest resource added on an average capacity
basis across the portfolios through 2030. Cumulative capacity additions ranged from about 2,520
MW to 2,850 MW. The amounts are significantly higher relative to the 2008 IRP and 2008 IRP
Update due to larger forecasted potential amounts, updated costs, and a mandated switch to a
"Utility Cost" basis for Utah resources. Portfolios contained an average of 160 MW of load
control resources (Class 1 DSM), with the bulk added by 2015.
Geothermal resources are selected in every portfolio. However, the lack of state legislation and
regulatory pre-approval mechanisms for recovery of dr-hole driling costs prompted PacifiCorp
to exclude geothermal resources from the preferred portfolio. While geothermal resources to date
have not been found to be cost-effective in the Company's competitive all-source requests for
proposals (RFPs), they wil nevertheless continue to be treated as eligible resources in futue
RFPs.
Taking into consideration the costs of variable energy resource integration, wind capacity
additions exhibited the greatest variability across portfolios, ranging from zero to over 2,700
MW. Selection of wind and other renewable resources is highly sensitive to natual gas prices,
C02 costs, and availability of the federal production tax credit.
Certain distrbuted generation resources-biomass combined heat and power (CHP) and solar
hot water heating-were found to be cost-effective for all portfolios. Utility-scale and distrbuted
solar photovoltaic resources were not found to be cost-effective.
7
PACIFICORP - 2011 IRP CHAPTER 1 - EXECUTIVE SUMMARY
All the portfolios exhibited the same acquisition pattern for front offce transactions2 through
2014, increasing to a peak of about 1,420 MW in 2013, and then decreasing to a low of
approximately 750 MW each year after 2020. Varabilty between 2015 and 2020 averaged about
330 MW across the portfolios.
PacifiCorp's preferred portfolio consists of a diverse mix of resources. Table ES.3 lists the
resource tyes and anual megawatt capacity additions for 2011 through 2030, while Figure
ES.4 shows how the preferred portfolio, along with existing resources, meets capacity
requirements through 2020. The portfolio takes advantage of favorable natual gas and electricity
prices in the first 10 years of the planning horizon through a combination of CCCT additions and
firm market purchases. The cost advantages and risk mitigation benefits of DSM are realized
though average annual energy efficiency measure additions equivalent to about 130 MW, along
with 250 MW of load control added though 2015. In recognition of long-ru public policy goals
and regulatory compliance and incentive uncertinty, PacifiCorp also includes 2,100 MW of
wind added in increments of 100 to 300 MW begining in 2018, as well as the Oregon solar
initiative requirements. For the first 10 years, these additions are nearly the same as the amount
added for the 2008 IRP Update.
As part of the acquisition path analysis documented in Chapter 9, the Company anticipates
alterig the renewable acquisition timing and strategy to align with legislative, regulatory,
technology and market developments.
Table ES.3 - 2011 IRP Preferred Portfolio
1222
475 475
des 12 19 6 18 8 2 65
300 300 200 200 200 200 200 100 100 100 100 100 2100
5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 104
6 70 57 20 97 5 255
108 114 110 118 122 124 126 120 122 125 125 134 133 139 140 146 136 135 141 145 2563
4 4 4 3 3 19
4 4 4 4 4 4 4 30
350 1240 1,429 1190 1149 775 822 967 695 995 700 750 750 750 750 750 750 750 750 750 N/A
250 546 975 1150 1265 N/A
2 Front office transactions (FOT) are proxy market purchases, assumed to be firm, that represent procurement
activity made on a forward basis to help the Company cover short positions. PacifiCorp modeled two FOT tyes for
all portfolios: an armual flat product and a third-quaer heavy load hour product.
8
PACIFICORP - 2011 IRP CHAPTER 1 - EXECUTIVE SUMMARY
Figure ES.4 - Addressing PacifiCorp's Peak Capacity Deficit, 2011 through 2020
9,000
15,000
14,000
13,000
12,000
I~
i ~i el 11,000¡ Q,I~
I 10,000
2012 2013 2014 2015 2016 2017 2018 2019
imCCCT2019
i;Genertion Upgrdes
__ Obliga~n + Reser:!?J_
2020
! _New MatketPurcbases -Oter Additions¡ _CCCT2016 IILake Side 2
L",._"_.,__,_,,, _,LongTenn Contrcts!'!'dPPA's ,mm,_ IIP~sicalAs~,~~!,dDSM
Major resource differences relative to the 10-year portfolio reported in the 2008 IRP Update
report include the following:
. Three CCCT resources included in the portfolio by 2019 rather than just two, drven by
an increased planning reserve margin (12 to 13 percent), lowered expectations for
irrigation load control program capacity, and lower gas prices.
. Significantly more energy efficiency and dispatchable load control-312 MW and 79
MW, respectively.
. 60 MW less wind, which is largely driven by a one-year deferral of the Windstar -
Gateway West transmission project from 2017 to 2018.
Figue ES.5 shows the resource capacity mix for representative years 2011 and 2020.
9
PACIFICORP - 2011 IR CHAPTER 1 - EXECUTIVE SUMMAY
Figure ES.5 - Current and Projected PacifCorp Resource Capacity Mix
2011 Resource Capacity Mix with Preferred Portfolio Resources
Front Office TmnsactionsClass i DSM + 5.4%
Intemiptibles
4.7%
Renewable *
2.4%
CHP& Other
0.1%
Gas
18.3%
Existing Purchases
9.3%
Hydroelectnc **
11.%
· Renewable resources include wind, solar andgeothL. Wind capacity is repor as the pea load contbuton.
Renewable capacity reflects categoizon by technology typeand not dispsition of renewable ener attbute for reguato compliance reqirements.
.. Hydroelectrc resooes include ownd, qualifyig facilities and contract puichases.
2020 Resource Capacity Mix with Preferred Portfolio Resources
FrontOffice Tmnsactions
6.5%
Class 2 DSM
8.2%
Class I DSM +
Intemiptibles
5.0%
Coal
40.4%
Renewable *
2.6%
CHP& Other
0.3%
Existing Purchases
3.2%
Hydroelectric **
7.4%
Gas
26.%
· Renewable resouces include wind, solar andgeothnnL. Wind capacity is report as the pea load contbuton.
Renewable capacity reflects categorizaton by tehnology type and not dispsition of renewab Ie energ attibute for reguato compliance reqirements.
** Hydroelectrc resouoes include owned, qualifyi facilties and contract purchases.
10
CHAPTER 1- EXECUTIVE SUMMARYP ACIFICORP - 2011 IR
Figue ES.6 shows PacifiCorp's forecasted RPS compliance position for the California, Oregon,
and Washington3 programs, along with a federal RPS program scenari04, covering the period
2010 through 2020 based on the preferred portfolio. Utah's RPS goal is tied to a 2025
compliance date, so the 2010-2020 position is not shown below. However, PacifiCorp meets the
Utah 2025 state target of 20 percent based on eligible Utah RPS resources, and has significant
levels of baned RECs to sustain continued futue compliance. As an IRP planing assumption,
PacifiCorp anticipates utilizing flexible compliance mechanisms such as baning and/or tradable
RECs where allowed, to meet RPS requirements.
Figure ES.6 - Annual State and Federal RPS Position Forecasts
PacifiCorp
California RPS Compliance Forecast
PacifiCorp
Oregon RPS Compliance Forecast
300 ...-7,00 -~_._._._-_.
6,00
j 200
~ 150
~ 100
~.,4,OOO--
'i
~ 3,000
,!!'"2,000
so '.0
2010 2011 2012 2013 2014 201S 2016 2017 2018 201920202010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
IIPreferred Portfolio iiSJAdditional RECs ..RPS Targei(GWh)IIPreferred Portolio ~Additional RECs .. RPS Target (GWh)
PacifiCorp
Federal RPS Compliance Forecast
PacifiCorp
Washington RPS Compliance Forecast
700 ._- .............................---.--.----------- ......_-~---- ...................................._..10,000 --_..
600 ....._....................._- ..........................................................................................__......
500 _._._.....7,00
~6.02
10 5,000
~
g:4,000
¡¡
3,000
2,000
1,000
~
.ê 400 ..---..-----.--.....
~ 300 .....'"'"
200
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 20202010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
IIRPSEligibie Renewables =AdditionalRECs ..RPSTarget_Preferred Portolio iIAdd~ional RECs ..RPS Target (GWh)
Figue ES.7 shows annual and cumulative additions of renewable resource installed capacity for
2003 through 2030. As indicated, the Company has already exceeded its MidAmerican Energy
Holdings Company and PacifiCorp merger commitment to acquire 1,400 MW of cost-effective
renewable resources by 2015.
3 The Washington RPS requirement is tied to January 1st of the compliance year, begining in 2012.4 The forecasted federal RPS position is a scenario based on the Waxan-Markey legislation with targets of 6
percent begining in 2012, 9.5 percent in 2014, 13 percent in 2016, 16.5 percent in 2018, and 20 percent in 2020.
11
PACIFiCORP-2011 IR CHAPTER 1 - EXECUTIVE SUMMARY
Figure ES.7 - Annual and Cumulative Renewable Capacity Additions, 2003-2030
,~oo
',0.
3,500
',0.
2,500
l......
:E 1.00
'.000
500 .
2003 2004 2005 2006 2007 200 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2018 2029 2030
li Annual Additions ~ Cumulative Additions
Note: the renewable energy capacity reflects categorization by technology tye and not disposition of
renewable energy attbutes for regulatory compliance requirements.
Regarding CO2 emìssìons, near-term reductìons are drven by plant dìspatch changes in response
to assumed C02 prices. In the longer term, cumulative energy effcìency and wind addìtions help
offset emìssìons stemmìng from resource growt needed to meet load oblìgatìons. Fìgue ES.8
ìlustrates these emìssìon trends for the preferred portfolìo under both the medìum and low
natual gas price scenarios. Fìgue ES.9 shows the resource generation mìx for 2011 and 2020
assuming the medìum CO2 tax and natual gas price trajectories. As indicated, gas resources
become more heavìly utÌlìzed ìn response to the CO2 tax, whìch reaches $24/ton in 2020.
Figure ES.8 - Carbon Dioxide Generator Emission Trend, $19/ton CO2 Tax
65
'"=
~60....=.=""'"=55=3
:?~=50='¡;
.f!5fi..45:s~.sQ==40ofOiU
õi=. =35=~
30
...::."............~""~.. '.
..~ '\-
it....... mm._~..m_mm_m_._.__m_._.__......................"'......
.................................
...."'...................
....m-....Ii....oI....,¡
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
_Medium gas price forecast, total emissions ..;¡. Medium gas price forecast, generator only
~Low gas price forecast, total emissions .."'.. Low gas price forecast, generator only
12
PACIFiCORP-2011 IR CHAPTER 1 - EXECUTE SUMARY
Figure ES.9 - Current and Projected PacifiCorp Resource Energy Mix
2011 Resource Energy Mix with Preferred Portolio Resources
Front Offce Tmnsactions
1.%
Hydroelectrc ..
. 8.1%
Renewable'
7.4%
.. Renewable resomcesincludewin,solar andgeotherl. Renewable enei geemtioo reflectscateorÎmtion bytehoolog type andnot disposition of renable energy attbute for reguato compliance reqire.
** Hydroelectrc resouces include own, qualify facilities and contå purchas.
2020 Resource Energy Mix with Preferred Portfolio Resources
$24 CO2 Tax (nominal dollars)
Front Office Transactions
3.2%
Class i DSM +
Intemiptibles
0.1%
Hydroelectnc ..
5.2%
Class 2 DSM
11.2%
Coal
36.3%
Existing Purchases
7.1%
Renewable'
10.7%
Gas
25.5%
.. Renewable resouces include wind, solar andgeothnnL. Renewble ener genemtion reflect cateoriztion by tehnolog ty and
not disposition of renewable energy attbute for reguato compliance requirnt.
** Hydroelectrc resoces inchideowid, qualifyng facilities and contac purchas.
13
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17
PACIFiCORP-2011 IRP CHAPTER 2 - INTRODUCTION
CHAPTER 2 - INTRODUCTION
PacifiCorp files an Integrated Resource Plan (IRP) on a biennial basis with the state utility
commissions of Utah, Oregon, Washington, Wyoming, Idaho, and California. This IRP, the 11th
plan submitted, fulfills the Company's commitment to develop a long-term resource plan that
considers cost, risk, uncertainty, and the long-ru public interest. It was developed though a
collaborative public process with involvement from regulatory staff, advocacy groups, and other
interested parties. As the owner of the IRP and its action plan, all policy judgments and decisions
concerning the IRP are ultimately made by PacifiCorp in light of its obligations to its customers,
regulators, and shareholders.
This IRP also builds on PacifiCorp's prior resource planning efforts and reflects continued
advancements in portfolio modeling and analytical methods. Modeling advancements focused on
improvements and expanded use of the Company's capacity expansion optimization model,
System Optimizer. These advancements include:
. customized enhancements for improved representation of carbon dioxide (C02) and
renewable portfolio standard (RPS) reguatory futues;
. for the first time, use of System Optimizer for evaluating coal plant utilization and
resource replacement scenarios;
. evaluation of multiple Energy Gateway transmission scenaros, along with incorporation
of incremental transmission costs for wind resources, and;
. expansion of the west-side model topology to improve representation of transmission
constraints and to conduct economic assessment of transmission projects associated with
the Energy Gateway strategy.
Significant studies conducted to support the IRP include:
. an update of the 2007 demand-side management (DSM) and dispersed generation
potentials study;
. a geothermal resource study;
. a loss of load study for determining an adequate capacity planning reserve margin for
load and resource balance development;
. a state-of-the-art wind integration study;
. market reliance scenario analysis, and;
. evaluation of price hedging strategies.
Finally, this IRP reflects continued alignment efforts with the Company's annual ten-year
business planing process. The purose of the alignment, initiated in 2008, is to:
. provide corporate benefits in the form of consistent planning assumptions,
. ensure that business planing is informed by the IRP portfolio analysis, and, likewise, that
the IRP accounts for near-term resource affordability concerns that are the province of
capital budgeting, and;
19
P ACIFICORP - 2011 IRP CHAPTER 2 - INTODUCTION
. improve the overall transparency of PacifiCorp's resource planing processes to public
stakeholders.
The planning alignent strategy also follows the 2008 adoption of the IRP portfolio modeling
and analysis approach for requests for proposals (RFP) bid evaluation. This latter initiative was
part of PacifiCorp's effort to unify planing and procurement under the same analytical
framework. The Company used this analytical frmework for bid evaluation in support of the all-
source RFP reactivated in December 2009.
This chapter outlines the components of the 2011 IRP, summarizes the role of the IRP, and
provides an overview of the public process.
The basic components ofPacifiCorp's 2011 IRP, and where they are addressed in this report, are
outlined below.
. the set of IRP principles and objectives that the Company adopted for this IRP effort, as well
as a discussion on customer/investor risk allocation (this chapter).
. an assessment of the planning environment, including PacifiCorp's 2011 business plan-
approved by the MidAerican Energy Holdings Company board of directors in December
201 D-market trends and fudamentals, legislative and regulatory developments, and curent
procurement activities (Chapter 3).
. a description of PacifiCorp's transmission planing efforts and description of IRP modeling
studies conducted to support Energy Gateway transmission financial evaluation (Chapter 4).
. a resource needs assessment covering the Company's load forecast, status of existing
resources, and determination of the load and energy positions for the 10-year resource
acquisition period (Chapter 5).
. a profile of the resource options considered for addressing futue capacity and energy deficits
(Chapter 6).
. a description of the IRP modeling, risk analysis, and portfolio performance assessment
processes (Chapter 7).
. presentation of IR modeling results, and selection of top-performing resource portfolios and
PacifiCorp's preferred portfolio (Chapter 8).
. an IRP action plan linkg the Company's preferred portfolio with specific implementation
actions, including an accompanying resource acquisition path analysis and discussion of
resource risks (Chapter 9).
20
PACIFiCORP-2011 IRP CHATER 2 - INTRODUCTION
. PacifiCorp'stransmission expansion action plan, focusing on the Energy Gateway
Transmission project (Chapter 10).
The IRP appendices, included as a separate volume, comprised of a detailed load forecast report
(Appendix A), fulfillment of IRP regulatory compliance requirements, (Appendix B), . detailed
modeling results for Energy Gateway transmission scenario analysis (Appendix C), detailed IRP
modeling results (Appendices D and E), the public input process (Appendix F), hedging strategy
sensitivity analysis (Appendix G), an assessment of resource adequacy for western power
markets, including a market reliance "stress" scenario analysis (Appendix H), the Company's
2010 wind integration cost study (Appendix I), the Company's loss ofload study (Appendix 1),
an assessment of the applicability and impact of moving from a one-hour to l8-hour sustained
hydro peaking capability standard (Appendix K), and historical plant water consumption data
(Appendix L).
PacifiCorp intends to fie a 2011 IRP supplement report with the state commssions that includes
results of additional studies that could not be completed in time to include in this IRP report.
These studies consist of the following:
. Stochastic analysis of the Energy Gateway transmission scenarios documented in Chapter 4.
. A cost impact analysis of an "Energy Gateway Central onll" scenario that focuses on
transmission constraints associated with out-year resources besides wind.
. An energy efficiency avoided cost study (decrement analysis).
. Response to stakeholder (Interwest Energy Allance) submission of alternate wind capital
cost and capacity information on January 10, 2011.
This IRP supplement report wil be fied upon completion of these studies, expected in the
second quarter of 20 11.
PacifiCorp's IRP mandate is to assure, on a long-term basis, an adequate and reliable electricity
supply at a reasonable cost and in a manner "consistent with the long-ru public interest.,,9 The
main role of the IRP is to serve as a roadmap for determining and implementing the Company's
long-term resource strategy according to this IRP mandate. In doing so, it accounts for state
commission IRP requirements, the curent view of the planning environment, corporate business
goals, risk, and uncertinty. As a business planning tool, it supports informed decision-making
8 Energy Gateway Central consists of the Populus-Terminal, Mona-Oquirrh, and Sigud-Red Butte projects.
9 The Public Utility Commission of Oregon and Public Servce Commission of Utah cite "long ru public interest"
as part of their definition of integrted resource planing. Public interest pertins to adequately quantifying and
captung for resource evaluation any resource costs external to the utility and its ratepayers. For example, the Public
Servce Commission of Uta cites the risk of futue internalization of environmental costs as a public interest issue
that should be factored into the resource portfolio decision-making process.
21
PACIFICORP - 20 11 IRP CHAPTER 2 -INODUCTION
on resource procurement by providing an analytcal framework for assessing resource investment
tradeoffs, including supporting RFP bid evaluation efforts. As an external communications tool,
the IRP engages numerous stakeholders in the planng process and guides them through the key
decision points leading to PacifiCorp's preferred portfolio of generation, demand-side, and
transmission resources.
While PacifiCorp continues to plan on a system-wide .basis, the Company recognizes that new
state resource acquisition mandates and policies add complexity to the planning process and
present challenges to conducting resource planing on this basis.
The IRP standards and guidelines for certin states require PacifiCorp to have a public process
allowing stakeholder involvement in all phases of plan development. The Company held 13
public meetings/conference calls durng 2010 and early 2011 designed to facilitate information
sharing, collaboration, and expectations setting for the IRP. The topics covered all facets of the
IRP process, ranging from specific input assumptions to the portfolio modeling and risk analysis
strategies employed. Table 2.1 lists the public meetings/conferences and major agenda items
covered.
Table 2.1 - 2011 IRP Public Meetings
Workshop 2/16/2010
General Meeting 4/28/2010
State Staeholder Input 6/16/2010
State Staeholder Input 6/29/2010
State Staeholder Input 7/28/2010
General Meetig 8/4/2010
State Stakeholder Input 8/11/2010
General Meeting 10/5/2010
State Stakeholder Input 12/9/2010
General Meetig 12/15/2010
General Conference Call 1/27/2011
General Conference Call 1/1/2011
General Conference Call 2/23/2011
General Conference Call 3/23/2011
Wind integration cost study
2011 IRP kickoff meeting
Oregon / California staeholder comments
Uta stakeholder dialogue session
Idao dialogue session
DSM, supply-side resources, planning reserve margin, proposed portòlio
develo ment
Wyomig staeholder dialogue session
Energy Gateway, load forecast, hedgig strtegy, maket reliance,
preliminar load and resource balance, portfolio development case
defmition
Geothermal resoure modeling and risk assessment
Supply-side resource update, final capacity/energy load and resource
balances, capacity expansion model set-up, stochastic parameter
estimation and research, referred ortfolio selection methodolo
Solar photovoltaic resource modeling
Core case portolio development results
Stochastic production cost modeling results; preferred portolio selection;
coal utilization stud results
Question & anwer session on portfolio modeling results, and discussion
on the IR draft document distrbuted for ublic review and comment.
22
PACIFiCORP-2011 IRP CHAPTER 2 - INTODUCTION
Appendix F provides more details concerning the public meeting process and individual
meetings.
In addition to the public meetings, PacifiCorp used other channels to faciltate resource planning-
related information sharing and consultation throughout the IRP process. The Company
maintains a website (htt://www.pacíficorp.comJeslirp.htmI).an e-mail "mailbox"
(irp(à)pacificorp.com), and a dedicated IR phone line (503-813-5245) to support stakeholder
communications and address inquiries by public participants.
MidAmerican Energy Holdings Company and PacifiCorp committed to continue to produce
IRPs according to the schedule and various state commission. rules and orders at the time the
transaction was in process. Production of the Transaction Commitments Anual Report for 2010
is in progress and due to be fied with each state commission in late May 2011.
23
PACIFICORP - 2011 IRP CHAPTER 3 - THE PLANING ENVIRONMENT
CHAPTER 3 - THE PLANNING ENVIRONMENT
This chapter profies the major external influences that impact PacifiCorp's long-term resource
planning as well as recent procurement activities drven by the Company's past IRPs and state
resource mandates. External influences are comprised of events and trends affectig the
economy and power industr marketplace, along with governent policy and regulatory
intiatives that influence the environment in which PacifiCorp operates.
Specifically addressed in this chapter is PacifiCorp's assessment of the wholesale electricity
market, an overview of federal and state environmental and renewable energy policies, hydro
relicensing activities, and an update on the Company's resource procurement efforts. Detailed
coverage of load growth trends is provided in Appendix A" while transmission expansion
planning is addressed in Chapter 4.
25
P ACIFICORP - 2011 IRP CHAPTER 3 - THE PLANING ENVIRONMENT
PacifiCorp's system does not operate in an isolated market. Operations and costs are tied to a
larger electrc system known as the Western Interconnection which fuctions, on a day-to-day
basis, as a geographically dispersed marketplace. Each month, milions of megawatt-hours of
energy are traded in the wholesale electrcity market. These transactions yield economic
effciency by assurg that resources with the lowest operating costs are serving demand while
providing the reliabilty benefits that arise from a larger portfolio of resources.
PacifiCorp partcipates in the wholesale market in this fashion, making purchases and sales to
keep its supply portfolio in balance with customers' constatly varying needs. This interaction
with the market taes place on time scales ranging from hourly to years in advance. Without the
wholesale market, PacifiCorp or any other load serving entity would need to constrct or own an
unecessarily large margin of supplies that would go unutilized in all but the most unusual
circumstances and would substantially diminish its capabilty to efficiently match delivery
patterns to the profie of customer demand. The market is not without its risks, as the experience
of the 2000-2001 market crisis, followed by the rapid price escalation durng the first half.of
2008 and subsequent demand destrction and rapid price declines in the second half of 2008,
have underscored. Unanticipated paradigm shifts in the market place can also cause significant
changes in market prices as evidenced by advancements in the ability of natual gas producers to
cost-effectively access abundant shale gas supplies over the past several years.
As with all markets, electrcity markets are faced with a wide range of uncertainties. However,
some uncertainties are easier to evaluate than others. Market paricipants are routinely studying
demand uncertainties driven by weather and overall economic conditions. Similarly, there is a
reasonable amount of data available to gauge resource supply developments. For example, the
Western Electrcity Coordinating Council (WECC) publishes an anual assessment of power
supply and any number of data services are available that track the status of new resource
additions. A review of the WECC power supply assessments is provided in Appendix H. The
latest assessment, published in September 2010, indicates that WECC has adequate resources
through 2019, while the Basin sub-region, which includes Utah, wil have suffcient resources
until 2018.
There are other uncertainties that are more diffcult to analyze and that possess heavy influence
on the direction of futue prices. One such uncertinty is the evolution of natual gas prices over
the course of the IRP planning horizon. Given the increased role of natual gas-fired generation,
gas prices have become a critical determinant in establishing western electrcity prices, and this
trend is expected to continue over the term of this plan's decision horizon. Another critical
uncertainty that weighs heavily on this IRP, as in past IRPs, is the prospect of futue greenhouse
gas policies. A broad landscape of federal, regional, and state proposals aiming to curb green
house gas emissions continues to widen the range of plausible futue energy costs, and
consequently, futue electrcity prices. Each of these uncertinties is explored in the cases
developed for this IRP and are discussed in more detail below.
26
PACIFiCORP-2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
Natural Gas Uncertainty
Over the last eight years, Nort American natual gas markets have demonstrated exceptional
price volatility. Figue 3.1 shows historical day-ahead prices at the Henr Hub benchmark from
April 2, 2001 through December 2,2010. Over this period, day-ahead gas prices settled at a low
of$1.n per MMBtu on November 16,2001 and at a high of$18.41 per MMBtu on Februar 25,
2003. Durg the fall and early winter of2005, prices breached $15 per MMBtu after a wave of
huricanes devastated the Gulf region in what tued out to be the most active hurcane season
in recorded history. More recently, prices topped $13 per MMBtu in the sumer of 2008 when
oil prices began their epic climb above $140 per barel in the months preceding the global credit
crisis. More recently, slow economic growth has reduced demand and abundant shale gas
supplies have kept prices below $5 per MMBtu.
Figure 3.1 - Henry Hub Day-ahead Natural Gas Price History
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¡¡Day Ahead Index -Average Annual Price
Source: IntercontinentalExchange (ICE), Over the Counter Day-ahead Index
Beyond the geopolitical, extreme weather, and economic events that spawned some rather
spectacular highs in the recent past, natual gas prices have exhibited an underlying upward trend
from approximately $3 per MMBtu in 2002 to nearly $9 per MMtu by 2008. Over much of this
period, declining volumes from conventional, matue producing regions largely offset growth
from unconventional resources. However, prices in 2009 and 2010 buck the trend largely due to
reduced demand and significant production gains from unconventional domestic supplies such as
coal bed methane and shale. Figue 3.2 shóws a breakdown of U.S. supply alongside natual gas
27
PACIFiCORP-2011 IR CHATER 3 - THE PLANING ENVRONMNT
demand by end-use sector and Figue 3.3 ilustrtes the shale gas discoveries ("plays") in the
lower 48 states.
Figure 3.2 - Historical Natural Gas Production by Type
60
50
40
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CQ
20
10
0
2001 2002 2003 2004 2005 2006 2007 2008 2009
I II Conventional II Shale II Coal Bed Methane
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Source: U.S. Deparment of Energy, Energy Information Admistration
Figure 3.3 - Shale Plays in Lower 48 States
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Upd~: M:a~~a,. 20in
28
PACIFiCORP-2011 IR CHAPTER 3 - THE PLANNING ENVIRONMENT
The supply/demand balance began to shift in 2007 and 2008 thanks to an unprecedented and
unexpected burst of growth from unconventional domestic supplies across the lower 48 states.
With rapid advancements in horizontal drillng and hydraulic fractug technologies, producers
began drlling in geologic formations such as shale. Some of the most prominent contrbutors to
the rapid growth in unconventional natual gas production have been the Barnett Shale located
beneath the city of Forth Worth, Texas, the Woodford Shale located in Oklahoma and the
Marcellus Shale located in Pennsylvania. Strong growt also continued in the Rocky Mountain
region.
Looking forward, many forecasters have historically expected that a gradual restoration of
improved supply/demand balance would be achieved largely with growth in liquefied natual gas
(LNG) imports. Indeed, there has been tremendous growth in global liquefaction facilties
located in major producing regions. This expectation led to significant investments in re-
gasification capacity to accommodate the need for futue LNG imports. However, the evolution
of unconventional supplies and continually growing estimates of shale gas reserves has
significantly lowered the outlook for LNG supplies. Curently, U.S. re-gasification capacity is
approximately 15.9 BCF/d with 2010 imports at approximately 1.0 BCF/d. The supply outlook
as changed dramatically and so quickly that there is now industr chatter suggesting there may
be a need to convert some re-gasification facilities to liquefaction facilties as a means to export
the newly discovered abundance of domestic natual gas supply.
Several factors contribute to a wide range of price uncertinty in the mid- to long-term.
Supporting downside price risk, technological advancements underlying the recent expansion of
unconventional supplies opens the door to tremendous growt potential in both production and
proven reserves from shale formations across North America. A number of shale formations
outside of the Barnett and Woodford have significant upside production potentiaL Supporting
upside price risk, the next generation of unconventional supplies may prove to be more diffcult
or costly to extract with the possibility of drllng restrctions due to environmental concerns
associated with hydraulic fractug, which would raise marginal costs, and consequently, raise
prices. Moreover, a concerted U.S. policy effort to shift the transporttion sector away from oil
toward natual gas has potential to significantly increase demand, and thus natual gas prices.
Western regional natual gas markets are likely to remain well-connected to overall North
American natual gas prices. Rocky Mountain region production has caused prices at the Opal
hubs to transact at a discount to the Henr Hub benchmark in recent years. Major pipeline
expansions to the mid-west and east coupled with fuher pipeline expansion plans to the west
have provided price support for Opal; however, prices remain discounted to Henr Hub. In the
Northwest, where natural gas markets are influenced by production and imports from Canada,
prices at Sumas have traded at a premium relative to other hubs in the region. This has been
driven in large part by declines in Canadian natual gas production and reduced imports into the
U.S. In the near-term, Canadian imports from British Columbia are expected to remain below
- historical levels lending support for basis differentials in the region; however, in the mid- to
long-term, production potential from regional shale formations wil have the opportity to
soften the Sumas basis.
29
P ACIFICORP - 20 11 IRP CHAPTER 3 - THE PLANING ENVIRONMENT
PacifiCorp faces a continuously-changing environment with regard to electrcity plant emission
regulations. Although the exact natue of these changes remains uncertin, they are expected to
impact the cost of futue resource alternatives and the cost of existing resources in PacifiCorp's
generation portfolio.
PacifiCorp's parent company, MidAerican Electrc Holdigs Company, has long been an
active member of the Edison Electrc Institute (EEl) modeling group, particularly with respect to
the analysis of potential U.S. Environmental Protection Agency (EPA) regulatory scenarios.
Understanding the effect that pending EPA regulations will have on the electric industry remains
a critical focus for EEl and its members.
In January 2011, EEl published a report titled "Potential Impacts of Environmental Regulation
on the U.S. Generation Fleet", which reflects a collaborative effort by EEl and its members to
model a variety of prospective EPA rules for air quality, coal combustion residuals, cooling
water intakes, and greenhouse gases. The report summarizes the potential impacts of uncertain
regulatory outcomes on unit retirements, capacity additions, pollution control installations, and
capital expenditures, based on national-level average input assumptions. As the results contained
in the report wil help gude PacifiCorp's own prospective modeling efforts, the Company feels it
is important to share this report with its IRP staeholders. This re~ort, and the associated
transmittl letter to the EPA, is available on PacifiCorp' s IRP Web site.!
A Possible Time Horizon for EPA Regulation
The U.S. EPA has underten a multi-pronged approach to minimize air, land, and water-based
environmental impacts. Many environmental regulations from the EPA are in various parallel
stages of development, as outlined on the timeline below (Figue 3.4).
IOLins to the EPA report trsmittl letter and the final report:
http://www.pacificorp.com/contelit/dam/pacificorp/doc/Energv Sourcesilntegrated Resource Plani2011IRP!Trans
inittltoLísaJacksoiiFínaI28Januaiy20 1 I.pdf
http://www.pacificorp.com/content!dam/pacificorp/doc/Energy Sources/Integrated Resource Plaiii20 I IIRP iEEIM
odeJingReportFinal-28Januarv2011.pdf
30
PACIFiCORP~2011 IRP CHAPTER 3 - THE PLANING ENVRONMENT
Figure 3.4 - EPA Regulatory Timeline for the Utilty Industry
Possible Timeline for Environmental Regulatory
Requirements for the Utility Industry
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Aside from potential greenhouse gas regulations, few of these other regulations are likely to
materially impact the industr in isolation; in aggregate, however, they are expected to have a
significant impact - especially on the coal-fueled generating units that supply approximately 50
percent of the nation's electrcity. As such, each of these regulations wil have a significant
impact on the utility industry and could affect environmental control requirements, limit
operations, change dispatch, and could ultimately determine the economic viability of
PacifiCorp's coal-fueled generation assets.
Federal Climate Change Legislation
PacifiCorp continues to evaluate the potential impact of climate change legislation at the federal
leveL. The impact of a given legislative proposal varies significantly depending on its selection of
key design criteria (i.e., level of emissions cap, rate of decline of the cap, the use of carbon
offsets, allowance allocation methodology, the use of safety valves, and etc.) and macro-
economic assumptions (i.e., electricity load growt, fuel prices - especially natual gas,
commodity prices, new technologies, etc.).
To date, no federal legislative climate change proposal has successfully been passed by both the
U.S. House of Representatives and the U.S. Senate for consideration by the President. The two
31
PACIFiCORP-2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
most prominent legislative proposals introduced for attempted passage though Congress have
been the Waxman-Markey bil in 2009 and the Kerr-Lieberman bil in 2010; neither measure
was able to accumulate enough support to pass.
In the 112th Congress, several bils have been introduced designed to limit, remove, or suspend
EPA's asserted regulatory authority over greenhouse gases. Meanwhile, Congress and the
President are likely to look at alternatives to comprehensive climate change legislation, such as a
clean energy standard, and deferrng the formal proposal of new climate change legislation until
a futue session of Congress.
As noted in the regulatory time line above, the EPA has aggressively pursued the regulation of
greenhouse gas (GHG) emissions. Key recent initiatives include the following:
New Source Review / Prevention of Significant Deterioration (NSR / PSD)
On May 13, 2010, the EPA issued a final rule that addresses GHG emissions from stationary
sources under the Clean Air Act (CAA) permtting programs, known as the "tailorig" rule. This
final rule sets thresholds for GHG emissions that define when permits under the New Source
Review (NSR) / Prevention of Significant Deterioration (PSD) and Title V Operating Permit
programs are required for new and existing industral facilties. This final rule "tailors" the
requirements of these CAA permttg progrms to limit which facilities wil be required to
obtain PSD and Title V permits. The rule also establishes a schedule that wil initially focus
CAA permitting programs on the largest sources with the most CAA permitting experience.
Finally, the rule expands to cover the largest sources of GHGs that may not have been previously
covered by the CAA for other pollutants.
Guidance for Best Available Control Technology (BACT)
On November 10,2010, the EPA published a set of guidance documents for the tailoring rule to
assist state permitting authorities and industr permitting applicants with the Clean Air Act PSD
and Title V permitting for sources of GHGs. Among these publications was a general guidance
document entitled "PSD and Title V Permitting Guidance for Greenhouse Gases," which
included a set of appendices with ilustrative examples of Best Available Control Technology
(BACT) determinations for different tyes of facilities, which are a requirement for PSD
permitting. The EPA also provided white papers with technical information concerning available
and emerging GHG emission. control technologies and practices, without explicitly defining
BACT for a paricular sector. In addition, the EPA has created a "Greenhouse Gas Emission
Strategies Database," which contains information on strategies and control technologies for GHG
mitigation for two industrial sectors: electricity generation and cement production.
The guidance does not identify what constitutes BACT for specific types of facilities, and does
not establish absolute limits on a permitting authority's discretion when issuing a BACT
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PACIFiCORP-2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
determination for GHGs. Instead, the guidance emphasizes that the five-step top-down BACT
process for criteria pollutants under the Clean Air Act generally remains the same for GHGs.
While the guidance does not prescribe BACT in any area, it does state that GHG reduction
options that improve energy efficiency wil be BACT in many or most instances because they
cost less than other environmental controls, may even reduce costs, and other add-on controls for
GHGs are limited in number and are at differig stages of development or commercial
availability. Utilities have remained very concerned about the NSR implications associated with
the tailoring rule (the requirement to conduct BACT analysis for GHG emissions) because of
great uncertinty as to what constitutes a trggering event and what constitutes BACT for GHG
emissions.
New Source Performance Standards (NSPS)
On December 23,2010, in a settlement reached with several states and environmental groups in
New York v. EPA, the EPA agreed to promulgate emissions standards coverig GHGs from both
new and existing electrc generating units under Section 111 of the Clean Air Act by July. 26,
2011 and issue final regulations by May 26, 2012.11 New source performance standards (NSPS)
are established under the Clean Air Act for certain industral sources of emissions determined to
endanger public health and welfare and must be reviewed every eight years. While NSPS were
intended to focus on new and modified sources and effectively establish the floor for determining
what constitutes BACT, the emission guidelines wil apply to existing sources as well.
The emissions guidelines issued by the EPA wil be used by states to develop plans for reducing
emissions and include targets based on demonstrated controls, emission reductions, costs and
expected timeframes for installation and compliance, and may be less strngent than the
requirements imposed on new sources. States must submit their plans to the EPA within nine
months after the guidelines' publication unless the EPA establishes a different schedule. States
have the ability to apply less strngent standards or longer compliance schedules if they
demonstrate that following the federal guidelines is uneasonably cost-prohibitive, physically
impossible, or that there are other factors that reasonably preclude meeting the guidelines. States
may also impose more stringent standards or shorter compliance schedules. Lastly, under Section
111 of the Clean Air Act, the EPA may establish standards that rely upon market mechanisms
rather than technology-specific emissions rates.
The EPA regulatory timeline above identifies several categories of regulations for non-GHG
emissions, some of which are discussed below:
1 i EPA also entered into a similar settlement the same day to address greenhouse gas emissions from refmeries with
proposed regulations by December 15,2011 and fmal reguations by November 15,2012.
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PACIFiCORP~2011 IRP CHAPTER 3 - THE PLANING ENVRONM
Clean Air Act Criteria Pollutants
Curently, PacifiCorp'sgeneration units must comply with the federal Clean Air Act (CAA),
which is implemented by the States subject to EPA approval and oversight. The CAA requires
the EPA to set National Ambient Air Quality Standads (NAAQS) for certain pollutants
considered harful to public health and the envionment. For a given NAAQS,the EPA and/or a
state identifies varous control measures that once implemented are meant to achieve a quality
standard for. a certain pollutant, with each stadad rigorously vetted by the scientific
community, industr, public interest groups, and the general public.
Parculate matter (PM), sulfu dioxide (S02), ozone (03), nitrogen dioxide (N02), carbon
monoxide (CO), and lead are often grouped together because under the Clean Air Act, each of
these categories is linked to one or more National Ambient Air Quality Standards (NAAQS).
These "criteria pollutants", while undesirable, are not toxic in tyical concentrations in the
ambient air. Under the Clean Air Act, they are regulated differently from other tyes of
emissions, such as hazardous air pollutants and greenhouse gases.
The EPA has recently established new standards for pariculate matter, sulfu dioxide, and
nitrogen dioxide. In addition, EPA is expected to fmalize new ozone standards in 2011.
Clean Air Transport Rule
In July 2009, EPA proposed its Clean Air Transport Rule (Transport Rule), which would require
hew reductions in S02 and NOx emissions from large stationary sources, including power plants,
located in 31 states and the Distrct of Columbia begining in 2012. The Transport Rule is
intended to help states attin NAAQS set in 1997 for ozone and fme pariculate 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 cour because it failed to effectively address
pollution from upwind states that is hamperig efforts by downwind states to comply with ozone
and PM NAAQS.
PacifiCorp does not own generating units in states identified by the Transport Rule and thus wil
not be directly impacted; however, the Company intends to monitor amendments to the
Transport Rule closely, paricularly since there is some indication that the 2014 revisions to the
Transport Rule wil extend the geographic scope of impacted states.
Regional Haze
While not depicted within the EPA regulatory timeline, EPA's rule to address Regional Haze
visibility concerns wil drive additional NOx reductions paricularly from facilities operating in
the Western United States, including the states of Utah and Wyomig where PacifiCorp operates
generating units. Hence, although the Transport Rule has no direct impact on PacifiCorp's states
with generation, the impacts of finalized Regional Haze regulatory activity wil.
On June 15, 2005, EPA issued final amendments to its July 1999 Regional Haze rule. These
amendments apply to the provisions of the Regional Haze rule that require emission controls
34
PACIFiCORP-2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
known as Best Available Retrofit Technology (BART), for industral facilities meeting certin
regulatory criteria that with emissions that have the potential to impact visibility. These
pollutants include PM2.5, NOx, S02, certain volatile organic compounds, and ammonia. The
2005 amendments included final guidelines, known as BART guidelines, for states to use in
determining which facilities must install controls and the tye of controls the facilities must use.
States were given until December 2007 to develop their implementation plans, in which states
were responsible for identifying the facilities that would have to reduce emissions under BART
as well as establishing BART emissions limits for those facilties. These facilties are expected to
install additional emissions controls usually within five years after the EPA approves a state's
Regional Haze plan (2014-2017). In early 2011, both Utah and Wyoming amended their state
implementation plans and submitted them to EPA for approvaL.
Mercury.and Hazardous Air Pollutants
In March 2005, the EPA issued the Clean Air Mercur Rule (CAMR) to permanently limit and
reduce mercur emissions from coal-fired power plants under a market-based cap-and-trade
program. However, the CAMR was vacated in February 2008, with the cour findig the mercur
rules inconsistent with the stipulations of Section 112 of the Clean Air Act.
A replacement Clean Air Act rule, expected in 2011, is aimed at sharply reducing utility
emissions of mercur, acid gases and other hazardous air pollutants by establishing a new
maximum achievable control technology (MCT) standard, which would require coal- and oil-
fired power plants to meet a specified emissions rate for mercur and other hazardous air
pollutantsY A cour-approved settlement requires the new MACT rule to take effect in 2012.
Under the Clean Air Act, affected facilities would have three years to comply (2015), with a
possible one-year extension that the EPA can grant on a case-by-case basis.
The EPA's actions on mercur and hazardous air pollutants could potentially require the
installation of additional pollution control equipment on a number of U.S. coal plants, including
those ofPacifiCorp; however, the outcome of this rulemaking remains uncertain.
Coal Combustion Residuals
Coal Combustion Residuals (CCRs), including coal ash, are the bypro ducts from the combustion
of coal in power plants.
CCRs are curently considered exempt wastes under an amendment to the Resource
Conservation and Recovery Act (RCRA); however, EPA proposed in 2010 to regulate CCRs for
the first time. EPA is considerig two possible options for the management of CCRs. Both
options fall under the Resource Conservation and Recovery Act (RCRA). Under the first
proposal, 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 proposal, EPA would regulate coal combustion
12 In addition to mercur, the hazardous air pollutats MACT rue would regulate: 1) acid gases, using hydrogen
chloride (HCl) as a surogate for all the acid gases, 2) non-rnercur metals (such as arsenic, lead, and selenium)
using parculate matter (PM) as a surogate; 3) dioxins and fuans; and 4) semi and volatile organics.
35
PACIFICORP - 2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
residuals as nonhazardous waste under Subtitle D of RCRA and establish minimum nationwide
standards for the disposal of coal combustion residuals. A final rule is expected in 2012.
While national greenhouse gas legislation has yet to be successfully adopted, regional and state
initiatives continue with the active development of climate change regulations that wil impact
PacifiCorp.
Regional Climate Change Initiatives
As shown in the map below depicting the various initiatives, the most prominent regional
program is the Western Climate Initiative, with the Regional Greenhouse Gas Initiative
continuing its development for the Eastern U.S.
Figure 3.5 - Regional Climate Change Initiatives
CP ~G
C)
_ Regional Greenhouse Gas Initiative RC'~1
. RGGI Observer
_ Midwestern Regional GHG Reducton Accord
. MRGHGRA Observer
_ Wesærn aimale Initiative
_ Western Ctrnale Initìatie Observer
_Inddual State Caand.Trade Program
Western Climate Initiative
Launched in February 2007, the Western Climate Initiative is a collaborative effort comprising
seven United States governors and four Canadian Premiers. The Western Climate Initiative was
36
PACIFiCORP-2011 IRP CHAPTER 3 - THE PLANING ENVIRONMENT
created to identify, evaluate, and implement collective and cooperative ways to reduce
greenhouse gases in the region, focusing on a market-based cap-and-trade system.
In September 2008, the Western Climate Initiative Parters released their proposal for a regional
cap-and-trade program. The seven states and four provinces would cover 20 percent of the
United States and 70 percent of the Canadian economies. Covered emitters include electrcity
generators and industrial and commercial stationary sources that emit more than 25,000 metric
tons of carbon dioxide equivalent per year. The fist phase of the cap and trade program is
scheduled to begin in 2012. Begining in 2015, the market would expand to also cover
petroleum-based fuel combustion from residential, commercial, and industral operations, for an
overall goal of reducing emissions to 15 percent below 2005 levels by 2020. The proposed
market has also been designed with futue linkages to other regions, possibly including a federal
market and other regional systems.
In July 2010, the Western Climate Initiative's Parters updated its September 2008
recommendations with the release of the Design for the Western Climate Initiative Regional
Program, which was a comprehensive strategy to meet the objectives of reducing greenhouse gas
emissions, stimulating development of clean-energy technologies, creating green jobs, increasing
energy security, and protecting public health. It is a plan to reduce regional GHG emissions to 15
percent below 2005 levels by 2020, and is the culmination of two years of work by seven U.S.
states and four Canadian provinces.
By the end of 2010, only California, New Mexico, and several Canadian Provinces were
participating in the initial phase of the Western Climate Initiative. California is continuing to
finalize its mandatory GHG reporting and cap-and-trade compliance program rules in 2011 in
anticipation of a 2012 program start.13 New Mexico, while adopting cap-and-trade rules in
December 2010 that are lined to the progression of the Western Climate Initiative, has a new
governor who has expressed concern over implementation of the state rule in 2013.
Washington and Oregon are both Western Climate Initiative Parters and may implement similar
programs in a subsequent phase, but no formal plans have been anounced in either state.
State-Specifc Initiatives
Many states have developed climate action plans and the formation of legislative advisory
groups. PacifiCorp continues to actively monitor and participate in state and regional policy
discussions relevant to all of its retail jursdictions.
California
An executive order signed by California's governor in June 2005 would reduce greenhouse gas
emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990
levels by 2050. In 2006, the California Legislatue passed and Governor Schwarzenegger signed
13 A tentative ruling by a San Francisco County Superior Cour judge in Association of Irritated Residents, et al. v.
California Air Resources Board (CARB), issued Janua 21,2011, halted implementation of California's greenhouse
gas rules because CAR failed to properly consider alternatives to cap-and-trade rule. The final impact of this
tentative ruling on California's cap-and-trade program is not yet known.
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P ACiyiCORP - 2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
Assembly Bil 32, the Global Warming Solutions Act of 2006, which set the 2020 greenhouse
gas emissions reduction goal into law. It directed the California Air Resources Board to begin
developing discrete early actions to reduce greenhouse gases while also preparing a scoping plan
to identify how best to reach the 2020 limit. The reduction measures to meet the 2020 target are
to become effective by 2012.
On December 12, 2008 the California Air Resources Board approved a scoping plan for
Assembly Bil 32. The Assembly Bil 32 scoping plan contains the primar strategies California
wil use to reduce the greenhouse gases that cause climate change. The scoping plan has a range
of greenhouse gases reduction actions which include mandatory reporting requirements, direct
regulations, alternative compliance mechanisms, monetary. and non-monetary incentives,
voluntar actions, market-based mechanisms such as a cap-and-trade system, greenhouse gas
emission performance standards, and an implementation fee regulation to fud the program.
On December 16, 2010, the California Air Resources Board approved resolutions to move
forward with the finalization of two important rulemaking initiatives pursuant to the goals of
Assembly Bil 32: (1) a state-wide cap-and-trade compliance program and (2) significant
amendments to the existing mandatory reporting regulation. Under these two programs , utilities
that report greenhouse gas emissions related to serving California retail customers are required to
meet compliance obligations using cap-and-trade allowances that are either administratively
allocated to emitting entities or purchased via auction. Both regulations wil be finalized durng
2011 and take effect starting in Janua 2012.
Oregon and Washington
The Washington and Oregon governors signed executive orders in May 2007 and August 2007,
respectively, establishing economy-wide goals for the reduction of greenhouse gas emissions in
their respective states. Washington's goals seek to (i) by 2020, reduce emissions to 1990 levels;
(ii) by 2035, reduce emissions to 25 percent below 1990 levels; and (iii) by 2050, reduce
emissions to 50 percent below 1990 levels, or 70 percent below Washington's forecasted
emissions in 2050. Oregon's goals seek to (i) by 2010, cease the growth of Oregon greenhouse
gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10 percent below 1990 levels; and
(iii) by 2050, reduce greenhouse gas levels to at least 75 percent below 1990 levels. Each state's
legislation also calls for state governent developed policy recommendations in the futue to
assist in the monitoring and achievement of these goals. In addition, Washington adopted
legislation that imposes a greenhouse gas emission performance stadard to all electricity
generated within the state or delivered from outside the state that is no higher than the
greenhouse gas emission levels of a state-of-the-ar combined-cycle natual gas generation
facility.
Durng the 2009 legislative sessions for Washington and Oregon, cap-and-trade legislation was
introduced in both states. The legislation would give the states statutory authority to participate
in the Western Climate Initiative. However, both legislatures adjoured without reaching
consensus on climate change legislation. New proposals for carbon-related legislation is
expected for the 2011 legislative sessions in both Washington and Oregon, as is the submission
to the Oregon state legislatue of the Oregon Global Waring Commission'sfinal report, which
wil contain a recommended roadmap for Oregon to addressing greenhouse gas emissions.
38
PACIFiCORP-2011 IRP CHAPTER 3 - THE PLANING ENVIRONMENT
A renewable portfolio stadard (RPS) is a policy that obligates each retail seller of electrcity to
include in its resource portfolio (the resources procured by the retail seller to supply its retail
customers) a certain amount of electrcity from renewable energy resources, such as wind and
solar energy. The retailer can satisfy this obligation by either (1) owning a renewable energy
facility and producing its own power, or (2) purchasing renewable electrcity from someone
else's facility.
Some RPS statutes or rules allow retailers to trade their obligation as a way of easing compliance
with the RPS. Under this trading approach, the retailer, rather than maintaining renewable energy
in its own energy portfolio, instead purchases tradable credits that demonstrate that another
electricity provider has generated the required amount of renewable energy.
RPS policies are curently implemented at the state level (although interest in a federal RPS is
expanding), and var considerably in their requirements with respect to time frame, resource
eligibility, treatment of existing plants, arangements for enforcement and penalties, and whether
they allow trading of renewable energy credits. By 2008, twenty-five states had adopted
mandatory renewable portfolio standards, five states had adopted voluntary renewable portfolio
standard, and fourteen states had adopted no form of renewable portfolio standard.
Within PacifiCorp's service terrtory, California, Oregon, and Washington have mandatory
renewable portfolio standards, with Utah having adopted a voluntary renewable portfolio
standard. Each of these states is sumarized in Table 3.1, with additional discussion below.
Table 3.1- Summary of state renewable goals (as applicable to PacifiCorp)
Utah
Obtain 20 percent of electrcity from renewable resources by 2010.
Renewable procurement compliance obligation is increased to 33
ercent b 2020.
Obtain at least 25 percent of electrcity sold by the utility to retail
electricity consumers from qualifying electricity, as defied, by
2025 in the following increments:
. 5 percent: 2011 - 2014
. 15 percent: 2015 - 2019
. 20 percent: 2020 - 2024
. 25 percent: 2025 and beyond
To the extent it is cost effective, by 2025, obtain 20 percent of
annual adjusted retail sales from cost effective renewable
resources, as determined by the Public Service Commission or
renewable energy certificates.
California
Oregon
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PACIFiCORP-2011 IRP CHAPTER 3 - THE PLANNG ENVRONMENT
Serve at least 15 percent ofload from renewable resources and/or
renewable energy credits by 2020 in the following increments:
Washington . 3 percent by Januar 1,2012 though December 31,2015
. 9 percent by Januar 1,2016 though December 31,2019
. 15 percent by Januar 1,2020 and each year thereafter
California
California law requires electrc utilities to increase their procurement of renewable resources by
at least one percent of their annual retail electrcity sales per year so that 20 percent of their
annual electricity sales are procured from renewable resources by no later than December 31,
2010. In March 2010, the California Public Utilities Commssion issued a decision to allow the
use of tradable renewable energy credits (TRECs) with certin limitation to satisfy a retail
seller's California RPS obligation. Several petitions to modify the decision were filed. However,
in Januar 2011, the California Public Utilities Commission issued a decision resolving the
petitions for modification and authorized the use of TRECs for the California RPS program. At
the time of the publication of this IRP, several applications for rehearig and petitions for
modification were fied with the California Public Utilties Commission on the TREC decisions.
In September 2010, the California Air Resources Board unanimously adopted a "Renewable
Electrcity Standard" ("RES") pursuant to Executive Order S-21-09 issued in September 2009
under California's Global Warming Solutions Act to expand existing RPS tagets to a 33% by
2020 for most retail sellers of electrcity in California, including PacifiCorp. Additional changes
to the RES are anticipated, in part due to potential impacts of Senate Bil 23 that was introduced
in the California Legislatue in Janua 2011. Senate Bil 23 may impose more restrctive
compliance obligations than those set fort in the RES. PacifiCorp cannot predict the final
outcome of the California legislation or how the RES or Senate Bil 23 may interact with the
requirements of the California RPS.
Oregon
In June 2007, the Oregon Renewable Energy Act was adopted, providing a comprehensive
renewable energy policy for Oregon. Subject to certin exemptions and cost limitations
established in the Oregon Renewable Energy Act, PacifiCorp and other qualifying electric
utilities must meet minimum qualifying electrcity requirements for electrcity sold to retail
customers of at least five percent in 2011 through 2014, 15 percent in 2015 through 2019, 20
percent in 2020 through 2024, and 25 percent in 2025 and subsequent years. Qualifying
renewable energy sources can be located anywhere in the United States portion of the Western
Electrcity Coordinating Council area, and a limited amount of unbundled renewable energy
credits can be used. The Oregon Public Utilities Commission and the Oregon Departent of
Energy have adopted rules to implement the initiative.
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P ACIFICORP - 2011 IR CHAPTER 3 - THE PLANING ENVIRONMNT
Utah
In March 2008, Utah's governor signed Utah Senate Bil 202, "Energy Resource and Carbon
Emission Reduction Initiative;" legislation supported by PacifiCorp. Among other things, this
provides that, begining in the year 2025, 20 percent of adjusted retail electrc sales of all Utah
utilties be supplied by renewable energy, if it is cost effective. Retail electric sales wil be
adjusted by deducting the amount of generation from sources that produce zero or reduced
carbon emissions, and for sales avoided as a result of energy efficiency and demand-side
management programs. Qualifying renewable energy sources can be located anywhere in the
Western Electrcity Coordinating Council areas, and unbundled renewable energy credits can be
used for up to 20 percent of the annual qualifying electricity target.
Washington
In November 2006, Washigton voters approved a ballot initiative establishing a RPS
requirement for qualifying electric utilities, including PacifiCorp. The requirements are three
percent of retail sales by January 1,2012 through 2015, nine percent of retail sales by Januar 1,
2016 through 2019 and 15 percent of retail sales by Januar 1, 2020. Qualifying renewable
energy sources must be located within the Pacific Northwest. The Washington Utilities and
Transportation Commission adopted final rules to implement the initiative.
Federal.Renewable Portfolio Standard
In his January 25, 2011, State of the Union address, President Obama proposed a national clean
energy strategy, with goals of boosting investment in renewable energy technology, having one
milion pure battery and plug-in hybrid electrc vehicles on the road by 2015, and ensurg that
80% of American electrcity comes from clean energy sources by 2035. The President has
significantly broadened his previous interpretation of "clean energy" to include nuclear, clean
coal with carbon captue and sequestration technology, and natual gas in the definition, in
addition to more broadly acknowledged energy sources like wind, geothermal, and solar.
Curently, the details of an electricity sector national clean energy standad and a corresponding
80% goal by 2035 remain unclear. Critical aspects of such a program would include the
economic incentives or research and development fuding to expedite the commercial
availabilty of carbon captue and sequestration and small modular (nuclear) reactors, in addition
to an extension of federal production tax credits for renewables.
While the Senate is likely to work on legislation calling for a national clean energy stadard,
prospects in the House of Representatives are less uncertain. Proponents of a national clean
energy standard argue that it would ease the move toward a mandatory cap on greenhouse gas
emissions by requirg utilities to invest in low-carbon energy sources. Enactment of such a
procurement standard would be a significant shift in the way electrc utilties are regulated, as it
would dramatically increase the authority of the federal governent to dictate the makeup of a
utility's energy portfolio-a power curently exercised by state governents.
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P ACIFICORP - 2011 IR CHAPTER 3 - TH PLANING ENVIRONMENT
Renewable Energy Certificates and Renewable Generation Reporting
Absent either a RPS compliance obligation or an opportity to bank unbundled renewable
energy certficate (RECs) for futuè year RPS compliance, PacifiCorp has historically relied on
an assumption that a renewable project may generate $5 per megawatt'-hour for five years from
the sale of unbundled RECs. Unbundled REC sales have helped mitigate the near-term cost
differential between new renewable resources and traditional generating resources.
However, once greenhouse gas emissions are regulated, surlus unbundled REC sales would
cease. PacifiCorp assumes if an unbundled REC is sold, then the underlying power (aka "null"
power) would likely have a carbon emissions rate imputed upon it by regulatory authorities, thus
obligating PacifiCorp to purchase either allowances or carbon offsets suffcient to cover the
imputed carbon emissions. By selling an unbundled REC, PacifiCorp may generate revenue, but
risks incurng a new carbon liability. Once greenhouse gases are regulated-and until the
unbundled REC and carbon markets are reconciled-PacifiCorp plans to cease sellng unbundled
RECs. As an assumption for portfolio modeling, renewable resource costs do not reflect a
revenue credit for unbundled REC sales.
Unless otherwise noted, renewable energy generation reported in the IRP reflects categorization
by technology tye and not disposition of renewable energy attbutes for regulatory compliance
requirements. Reported generation reflects facilties for which PacifiCorp may (1) use the
renewable energy attbutes to comply with state renewable portfolio standards or other
regulatory requirements, (2) sell the renewable attbutes to third parties in the form of renewable
energy credits or other environmental commodities, or (3) not have title to the ownership of the
renewable energy attbutes.
The issues involved in relicensing hydroelectrc facilities are multifaceted. They involve
numerous federal and state environmental laws and regulations, and participation of numerous
stakeholders including agencies, Indian tribes, non-governental organizations, and local
communities and governents.
The value to relicensing hydroelectrc facilities is contiued availabilty of hydroelectrc
generation. Hydroelectrc projects can often provide unique operational flexibility as they can be
called upon to meet peak customer demands almost instantaeously and provide back-up for
intermittent renewable resources such as wind. In addition to operational flexibility,
hydroelectrc generation does not have the emissions concerns of thermal generation. With the
exception of two hydroelectrc projects, all of PacifiCorp's applicable generating facilities now
operate under contemporar Orders from the Federal Energy Regulatory Commssion (FERC).
The Klamath River hydroelectric project continues to work with parties to reach a settlement
agreement on futue project conditions, and the Condit project is seekig a Surender Order to
decommission the project.
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PACIFiCORP-2011 IR CHAPTER 3 - THE PLANING ENVIRONMENT
FERC hydroelectrc relicensing is administered within a very complex regulatory framework and
is an extremely political and often controversial public process. The process itself requires that
the project's impacts on the surounding environment and natual resources, such as fish and
wildlife, be scientifically evaluated, followed by development of proposals and alternatives to
mitigate for those impacts. Stakeholder consultation is conducted throughout the process. If
resolution of issues cannotbe reached in this process, litigation often ensues which can be costly
and time-consuming. There is only one alternative to relicensing, that being decommissioning.
Both choices, however, can involve significant costs.
The FERC has sole jurisdiction under the Federal Power Act to issue new operating licenses for
non-federal hydroelectric projects on navigable waterways, federal lands, and under other certin
criteria. The FERC must find that the project is in the broad public interest. This requires
weighing, with "equal consideration," the impacts of the project on fish and wildlife, cultual
activities, recreation, land-use, and aesthetics against the project's energy production benefits.
However, because some of the responsible state and federal agencies have the ability to place
mandatory conditions in the license, the FERC is not always in a position to balance the energy
and environmental equation. For example, the National Oceanic and Atmospheric
Administration Fisheries agency and the U.S. Fish and Wildlife Service have the authority withn
the relicensing to require installation of fish passage facilities (fish ladders and screens) at
projects. This is often the largest single capital investment that wil be made in a project and can
render some projects uneconomic. Also, because a myrad of other state and federal laws come
into play in relicensing, most notably the Endangered Species Act and the Clean Water Act,
agencies' interests may compete or conflict with each other leading to potentially contrar, or
additive, licensing requirements. PacifiCorp has generally taken a proactive approach towards
achieving the best possible relicensing outcome for its customers by engaging in settlement
negotiations with stakeholders, the results of which are submitted to the FERC for incorporation
into a new license. The FERC welcomes settlement agreements into the relicensing process, and
with associated recent license orders, has generally accepted agreement terms.
Potential Impact
Relicensing hydroelectrc facilities involves significant process costs. TheFERC relicensing
process takes a minimum of five years and generally taes nearly ten or more years to complete,
depending on the characteristics of the project, the number of stakeholders, and issues that arise
durng the process. As of December 31, 2008, PacifiCorp had incured $56.6 millon in costs for
ongoing hydroelectrc relicensing, which are included in Constrction work-in-progress on
PacifiCorp's Consolidated Balance Sheet. As relicensing and/or decommissioning efforts
continue for the Klamath River and Condit hydroelectric projects, additional process costs are
being incured that wil need to be recovered from customers. Also, new requirements contained
in FERC licenses or decommissioning Orders could amount to over $1.2 bilion over the next 30
to 50 years. Such costs include capital and operations and maintenance investments made in fish
passage facilities, recreational facilities, wildlife protection, cultual and flood management
measures as well as project operational changes such as increased in-stream flow requirements to
protect fish resulting in lost generation. Over 95 percent of these relicensing costs relate to
PacifiCorp's three largest hydroelectrc projects: Lewis River, Klamath River and Nort
Umpqua.
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PACIFICORP - 20 11 IRP CHAPTER 3 - THE PLANING ENVIRONMENT
Treatment in the IRP
The known or expected operational impacts mandated in the new licenses are incorporated in the
projection of existing hydroelectrc resources discussed in Chapter 5.
PacifiCorp's Approach to Hydroelectric Relicensing
PacifiCorp continues to manage this process by pursuing a negotiated settlement as part of the
Klamath River relicensing process. PacifiCorp believes this proactive approach, which involves
meeting agency and others' interests through creative solutions is the best way to achieve
environmental improvement while managing costs. PacifiCorp also has reached agreements with
licensing stakeholders to decommission projects where that has been the most cost-effective
outcome for customers.
All-Source Request for Proposals
PacifiCorp reactivated its All-Source Request for Proposal on December 2, 2009. This RFP
sought 1,500 MW of cost-effective resource consisting of base load, intermediate load and
summer peak resources for 2014 to 2016.14 Bid responses were due March 1, 2010, and
thoughout the remainder of 2010 the Company conducted its bid and Company benchmark
evaluation under the oversight of Independent Evaluators for both the Oregon and Utah
commissions. PacifiCorp received acknowledgment of its final short list of bidders on December
27, 2010 from the Public Utilty Commission of Oregon. The Company fied an application for
"Approval of a significant Energy Resource" with the Public Service Commission of Utah in
December 2010, indicating its intent to acquire a 637 MW gas-fired combined-cycle combustion
tubine, to be built adjacent to the Lake Side site in Utah by CH2M Hil E&C, Inc. with an on-
line date of June 1,2014.
Demand-side Resources
The comprehensive demand-side management RFP (2008 DSM RFP) released in November
2008 produced several proposals that are being considered. Additional analysis, contracting and
regulatory approvals are required before new programs can be introduced. Contracting for new
products accepted under the 2008 DSM RFP are forecast to be complete by the end of 2011 with
regulatory approvals and implementation commencing after contracting is complete.
Other procurement work anticipated in the 2011 and early 2012 time frame include finalizing
new contracts generated by competitively re-procuring program delivery services for existing
programs and delivery channels; issuing RFPs for program evaluations of existing programs for
14 PacifiCorp's All-Source RFP website: htto:i!wvl'w.pacificorp.comisup/rfsi2009asr.html
44
PACIFiCORP-2011 IR CHAPTER 3 - THE PLANNING ENVIRONMENT
the 2009 - 2010 period and the re-procurement of ongoing irgation load management services
in Utah and Idaho as well as the possible extension of these programs into Oregon, Washington
and California.
Oregon Solar Request for Proposal
PacifiCorp issued a request for proposals on November 30, 2010 for solar resources serving
Oregon retailload.I5 The system sized must be larger than 500 kW (alternating curent)and less
than 2 MW (alternating curent) and be classified as solar photovoltaic energy systems. This
request is in response to a recent Oregon Statute ORS 757.370 pertaining to the solar
photovoltaic generating capacity standard, which requires Oregon utilties to acquire at least 20
MW (alternating curent). PacifiCorp's share of the total is 8.7 MW. The RFP calls for resources
to be on line by December 31, 2011. Responses were due Januar 7, 2011, and bids are curently
undergoing evaluation.
15 PacifiCorp website for the Solar RFP: htt://v,'v\fw.pacificorp.com/sup/rfps/rsoJar201O.html
45
PACIFiCORP-2011 IRP CHAPTER 4 - TRASMISSION PLANING
CHAPTER 4 - TRANSMISSION PLANNING
47
PACIFiCORP-2011 IR CHAPR 4 - TRSMISSION PLANING
This chapter describes the transmission planing approach durg the development of the 2011
Integrated Resource Plan, which spanned from Janua 2010 to March 2011.
PacifiCorp owns one of the largest privately held trmission systems in the United States. The
Company's transmission system spans over 15,800 miles across 10 states, interconnecting with
more than 80 generating plants and 13 adjacent control areas at 152 interconnection points. This
infrastrctue is critical to the Company's ability to serve its 1.7 milion retail electrc customers
in Utah, Oregon, Wyoming, Washington, Idaho, and nortern California.
As is discussed throughout the 2011 Integrted Resource Plan, PacifiCorp plans extensively to
ensure that an optimal combination of resources is utilized to cost-effectively meet its customers'
growing demand for electricity. The Company considers a multitude of generation, demand-side
management and transmission options. These options are weighed against federal regulations as
well as policy goals and requirements that vary from state to state. Due to the lengthy planning,
permitting and constrction processes required for new transmission, the Company must also
anticipate potential new federal regulations, paricularly those related to greenhouse gas
emissions and renewable energy resources.
In identifying its optimal transmission investment plan, and as detailed in the Transmission
Scenario Analysis section, the Company evaluated multiple transmission scenarios within two
different energy futues - one in which federal and state policies continue to support increasing
integration of renewable and low-carbon generation options, and one that assumes carbon
legislation and federal/state renewable energy requirements wil subside, with the majority of
new energy being generated by existing fuel resources.
The uncertinties surounding federal reguation of C02 emissions and potential new renewable
energy requirements do not defer PacifiCorp's obligation to plan for and meet its customers'
futue electrcity needs. The Company's planed transmission additions reflect its belief that
state and federal energy policies wil contiue to push toward renewable and low-carbon
resources. However, regardless of futue policy direction, these projects are well aligned with
rich and diverse resource areas throughout the Company's service territory, and represent
PacifiCorp's best estimation. of the resources that wil be needed to cost-effectively and reliably
meet its customers' needs over the long term.
What is also important to note is that the cost range for the different transmission scenarios
considered is relatively close, which suggests economics do not drve a clear selection. The key
question is - what is the best investment based on an assumed futue state? PacifiCorp looks to
its stakeholders to acknowledge and/or comment on the Company's assumption of a renewable
and low-carbon futue which underlies the transmission footprit assumed in the prefeITed
portfolio.
48
PACIFiCORP-2011 IRP CHAPTER 4 - TRSMISSION PLANING
PacifiCorp's bulk transmission network is designed to reliably transport electrc energy from
generation resources (owned generation or market purchases) to various load centers. There are
several related benefits associated with a robust transmission network:
1. Reliable delivery of power. to continuously changig customer demands under a wide
variety of system operating conditions.
2. Ability to supply aggregate electrcal demand and energy requirements of customers at all
times, taking into account scheduled and reasonably unscheduled outages.
3. Economic exchange of electrc power among all systems and industr participants.
4. Development of economically feasible generation resources in areas where it is best
suited.
5. Protection against extreme market conditions where limited transmission constrains
energy supply.
6. Abilty to meet obligations and requirements of PacifiCorp's Open Access Transmission
Tariff.
7. Increased capability and capacity to access Western energy supply markets.
PacifiCorp's transmission network is a critical component of the IRP process and is highly
integrated with other transmission providers in the western United States. It has a long history of
reliable service in meeting the bulk transmission needs of the region. Its purose wil become
more critical in the futue as energy resources become more dynamic and customer expectations
become more demanding.
Transmission constraints and the abilty to address capacity or congestion issues in a timely
maner represent important planning considerations for ensuring that peak load and energy
obligations are met on a reliable basis. The cycle time to add significant transmission
infrastrctue is often much longer than adding generation resources or securing contractual
resources. Transmission additions must be integrated into regional plans and then permits must
be obtained to site and constrct the physical assets. Inadequate transmission capacity limits the
utility's ability to access what would otherwise be cost effective generating resources.
Consistent with the requirements of its Open Access Transmission Tarff ("OATT"), approved
by the Federal Energy Regulatory Commission ("FERC"), PacifiCorp plans and builds its
transmission system based on its network customers' 10-year load and resource forecasts. Per
FERC guidelines, the Company is able to reserve transmission network capacity based on this
lO-year forecast data. PacifiCorp's experience, however, is that the lengthy planning, permitting
and constrction time line required for signifcant transmission investments, as well as the tyical
useful life of these facilities, is well beyond the 10-year time frame of load and resource
49
PACIFiCORP-2011 IR CHAPTER 4 - TRNSMISSION PLANING
forecasts.16 A 20-year planing horizon and abilty to reserve transmission capacity to meet
forecasted need over that time frame is more consistent with the time required to plan for and
build large scale transmission projects, and PacifiCorp supports clear regulatory
acknowledgement of this reality and cOITesponding policy guidance.
As discussed in the following sections, PacifiCorp is engaged in a significant transmission
expansion effort called Energy Gateway that requires cooperative transmission planning with
regional and sub-regional planing groups across the Western Interconnection. Transmission
infrastrctue wil continue to play an importt role in futue resource plans as segments of
Energy Gateway are added over time along with other system reinforcement projects.
Various regional planning processes have developed over the last several years in the Western
Interconnection. I? It is expected that, in the futue, these processes wil be the primary forus
where major transmission projects are identified, evaluated, developed and coordinated. In the
Western Interconnection, regional planning has evolved into a three-tiered approach where an
interconnection-wide entity, the Western Electrcity Coordinating Council (WCC) conducts
regional planning at a very high level; several sub-regional planning groups focus with greater
depth on their specific jursdictions; and transmission providers perform local planning studies
within their sub-regions. This coordinated plang helps to ensure that customers in the region
are served reliably and at the least cost.
Regional Planning
WECC is responsible for coordinating and promoting bulk electrc system reliability in the
Western Interconnection, assurng open and non-discriminatory transmission access and
providing a foru for coordinating the operating and planning activities of its members. In 2006,
in accordance with the transmission planing principles outlined in the Federal Energy
Regulatory Commission's Order 890, WECC took on a larger planning role through the
establishment of the Transmission Expansion Planning Policy Committee (TEPPC). In 2009,
WECC was awarded nearly $15 milion in American Recovery and Reinvestment Act (ARR)
funds to conduct interconnection-wide transmission planing studies. This funding provided for
a significant expansion of WECC's transmission planning and stakeholder involvement
activities, which are managed by TEPPC.
TEPPC is tasked with engaging stakeholders to evaluate long-term regional transmission needs
based on curent and projected electrc demand, generation resources, energy policies,
technology costs, impacts on transmission reliabilty, and emissions considerations. TEPPC's
efforts complement those of WECC members and staeholders, and the resulting plans wil
16 The application to begin the Environmental Impact Statement processwas fied with the Bureau of Land
Management in late 2007 for Energy Gateway West. For this paricular project, permttg wil require five years or
more before constrction can begin.17 The Western Interconnection stretches from Western Canad south to Baja California in Mexico, reachig
eastward over the Rockies to the Great Plains.
50
PACIFiCORP-2011 IR CHAPTER 4 - TRASMISSION PLANING
provide transmission providers and decision makers with thorough, credible information to help
guide infrastrctue investment decisions throughout the West.
TEPPC organizes and steers WECC's regional economic transmission planning activities,
including:
. Steering decisions on key assumptions and the process by which economic transmission
expansion planing data are collected, coordinated and validated;
. Approving transmission study plans, including study scope, objectives, priorities, overall
approach, deliverables, and schedules;
. Steering decisions on analytical methods and on selecting and implementing production
cost and other models found necessary;
. Ensurg the economic transmission expansion planing process is impartial, transparent,
properly executed and well communicated;
. Ensurng that regional experts and stakeholders participate, including state and provincial
energy offices, regulators, resource and transmission developers, load serving entities,
and environmental and consumer advocate stakeholders through a staeholder advisory
group;
. Advising the WECC Board on policy issues affecting economic transmission expansion
planning; and
. Approving recommendations to improve the economic transmission expansion planning
process.
TEPPC's analyses and studies focus on plans with west-wide implications and include high-level
assessments of congestion and congestion costs. The analyses and studies also evaluate the
economics of resource and transmission expansion alternatives on a regional, screening study
basis. Resource and transmission alternatives may be targeted at relieving congestion,
minimizing and stabilizing regional production costs, diversifying fuels, achieving renewable
resource and clean energy goals, or other puroses. Alternatives often draw from state energy
plans, integrated resource plans, large regional expansion proposals, sub-regional plans and
studies, and other sources if relevant in a regional context.
Members and stakeholders of TEPPC include transmission providers, policy makers,
governmental representatives, and others with expertise in planning, building new economic
transmission, evaluating the economics of transmission or resource plans, or managing public
planing processes.
Similar to the TEPPC activities and process at WECC, a similar process exists under the
oversight of WECC's Planning Coordination Committee, which provides for the reliability
aspects of transmission system planning.
Sub-Regional Planning Groups
Recognizing that planing the entire Western Interconnection in one forum is impractical due to
the overwhelming scope of work, a number of smaller sub-regional groups have been formed to
address specific challenges in various areas of the Western Interconnection. Generally, all of
51
PACIFiCORP-2011 IR CHAPTER 4 - TRSMISSION PLANING
these forums provide similar regional planing fuctions, including the development and
coordination of major transmission plans within their respective areas. It is these sub-regional
forums where the majority of transmission projects are expected to be developed. These forus
coordinate with each other directly through liaisons and though TEPPC. A . list of sub-regional
groups is provided below:
. NTTG - Northern Tier Trasmission Group
· CCPG - Colorado Coordinated Planing Group
. CG - Columbia Grid
· SIERR - Sierra Subregional Planning Group
· SWAT - Southwest Area Transmission
· CAISO - California Independent System Operator
· CTPG - California Transmission Planning Group
· WestConnect - A southwest sub-regional planng group that includes paricipants from
CCPG, SWAT and other utilities
· AESO - Alberta Electrc System Operator
. BC - BC Hydro
PacifiCorp is one of the founding members of Northern Tier Transmission Group (NTTG).
Originally formed in early 2007, NTTG has an overall goal of improving the operation and
expansion of the high-voltage transmission system that delivers power to consumers in seven
western states. NTTG members serve more than four milion customers with nearly 30,000 miles
of transmission lines within Oregon, Washington, California, Idaho, Montana, Wyoming, and
Utah. In addition to PacifiCorp, other members include Deseret Power Electric Cooperative,
NorthWestern Energy, Idaho Power, Portland General Electrc, and the Utah Associated
Municipal Power Systems.
Per the NTTG Steering Committee Charter,I8 PacifiCorp and other members are committed to
"(the) furtherance of ancillary services markets, regional transmission tarif, common and/or
joint Open Access Transmission Tarif, energy and/or regulation markets, and other
transmission products or tarif structures if both economically justifed and initiated by
unanimity of the Steering Committee. " See the Regional Initiatives section below for examples
of programs PacifiCorp and NTTG are engaged in developing.
The geographical areas covered by these sub-regional planning groups are approximately shown
in Figue 4.1 below:
18 NTTG Steering Committee Charter:
http://nttg. biz/site/index. php? optíon=com docrnan&task=doc dO\\111oad&gid= 1 085&Itemid=31
52
PACIFiCORP-2011 IR CHAPTER 4 - TRNSMISSION PLANING
Figure 4.1 - Sub-regional Transmission Planning Groups in the WECC
Sub-regional Coordination Group (SCG)
The SCG is a sub group of TEPPC, and is comprised of a member from each of the TEPPC-
recognized sub-regional planning groups (including NTTG). The SCG was formed to faciltate
WECC's efforts, though TEPPC, to create interconnection-wide transmission plans for the
West. Its primary task is the creation of a list of "foundational transmission projects," which
represents projects that have a very high probability of being in service in the 2010-2020
timeframe. This list wil be used by TEPPC for studies used to develop its 10-year Regional
Transmission Plan.
In Augut 2010, the SCG issued its report to TEPPC; the Foundational Transmission Project
List "reflects the minimum transmission system additions that have a sufficient level of
53
PACIFiCORP-2011 IR CHATER 4 - TRASMISSION PLANING
commitment or defined need to provide WECC with a starting point for the development of their
interconnection-wide transmission plans.,,19 A map representing all projects on the foundational
projects list, including PacifiCorp's Energy Gateway Transmission Expansion projects, is
provided below as Figue 4.2.
Figure 4.2 - Sub-regional Coordination Group (SCG) Foundational Projects by 2020
"CI\¡SDQ~: Sunrise
N"lG
.~,JTG01 Gateway Sout Phase 1
.NTTG02 Gateway Gentral Phase 1
-NTTG03Gateway Wese Phase 1
'NTG05Hemlngway - Boardman
.NTTGG6 Cascde Crossing
CG
-GG011.5 Corridor
PROJECTS BY 20~
..(;41$003 8iythe~r:svers
..Cf;.JSCG4 T ~~h?Ghep¡ UpgmC0
SSPG
'SSPG02 SWIP SoUth
'SSPG05 TCP Harr Allen. Northwest
.SSPG06 TOP Northwest -Amargosa -GG02 West McNary
oCG03Big Edd - Knight
-GG04 Little Goose Area Reinforcement.!
'BCH01 Nlcoie - Meridian
",BCH038C;.!JS intertie
Albert AESO
.AESOO3 1202L. Conversion
'AESOO4Heartiand
.AESOO5West HVDC
'AESOO5 East HVDC
'AESOO7 Fort McMurray. East Line
.AESOQ8 Fort McMurray. West Line
(1) Map.d6notrefied230 or Z40.kV linasttiatar indudad.in.lte Foi.datioriallrarlmission Projed.List(2llntemat reinlbementsprcls not shown for dariy
(3) UrieSshow arloilusraive puoses only and may-not renect final line routing
The SCG report also includes a list of "potential transmission projects," which represents
projects that have been identified in the sub-regional planning groups' lO-year plans but do notmeet the criteria (including permitting status, financIal commitment, reliabilty impacts and
interconnection-wide significance) to be included on the foundational transmission projects list.
These projects were provided for TEPPC to use when selecting additional transmission facilities
needed to develop the WECC interconnection-wide transmission plan. A map representing all
projects on the potential projects list is provided below as Figure 4.3.
19 August 2010 SCG Foundational Transmission Projects List:
htt:!¡wINw. wecc.biz!committees¡BOD/TEPPC!SCG¡Shared%20Documents¡SCG%20Foundational%20Transmissio
n%20Project%20List%20Repoit.pdf
54
PACIFiCORP-2011 IRP CHAPTER 4 - TRANSMISSION PLANING
Figure 4.3 - Sub-regional Coordination Group (SCG) Potential Projects by 2020
PROJECTS BY 2020
NTTG
.NTTG01 Gateway South Phase 2
.NTTG02 Gateway Central Phase 2
?i~\i'TTGQ3Gateway.Vvest Phase.::
CAISO
SSPG
.SSPG1 SWIP Nort
~8SFC03.8NiP 'NTTG04 Hemingway-Captain Jack
.SSPG04 Harry Allen - EldfMead
.SSPG07 BlaCkhawk - Amargosa
SWAT
'NTTG08 Chmook
'NTTG09Zephyr
.NTTG10 Ovenand
'NTG11 Transwest Express
.NTG13 Coistrip Upgrade
£!
.SWAT04Sur!Zli:
":::lvV f;;.TD9 Santa
.SVVAT10 T res .CG06 Juan De Fuca Cable #2
'SW AT11 Southline Project
CCPG
"CGOTV'4estCoast Cable
!£
vvc "8CHD2
Albert ESO
.CCPGG5La-mar Front Range -AESCJU2 Nurtr;Jérn Ll.ghts
.CCPG07 Pawnee - Daniels Park
~CCPG08 Pawnee- Story
Final- Ver. 7.1,(1). Map does flt reflect 23kV or 240kV lines that are indlièd-il'l the Foudaonal TransmisSiOn' PrjectL.ist
(2)lntmaireintocemerpro.; notshnwfordaiity(3) Lines 'sho :arErfor'ilustvepUiioses'oll and may notrefled: tim line IóWg
Regional Initiatives
Joint Initiative (JI)
Since 2008, representatives from Northern Tier Transmission Group, Co1umbiaGrid and
WestConnect have worked together to develop concepts that would achieve mutual benefits
though a broader reach of expertise and geography. Through "strike teams" established by the
n, PacifiCorp and other interested parties have supported technical exploration and helped
develop programs aimed at achieving transmission system efficiencies and accommodating
increasing levels of variable energy resources. Three key tools developed though the n are:
. Dynamic System Scheduling - Developed in order to simplify, enhance and reduce the
cost of dynamically scheduling resources between balancing authority areas across the
Western Interconnection, providing for the setup and exchange of dynamic schedules on
a much more frequent and efficient basis than dynamic schedules curently in place.
55
PACIFiCORP-2011 IR CHAPTER 4 - TRASMISSION PLANING
· Intra-hour Transmission Scheduling Business Practices - Developed to standardize
transmission scheduling business practices across multiple transmission service providers
to allow for intra-hour changes within a given operating hour; giving transmission
customers options for expandig opportities across paricipating transmission providers
and balancing authorities more frequently than once an hour.
· Intra-hour Transaction Accelerator Platform - The I-TAP concept was developed to
enable intra-hour bilateral energy and capacity transactions via an internet-accessible
"hub" that links the various existing processes used to complete a transaction (such as
OASIS, e-Tag author and submission, deal-captue, trading platforms, etc.) to enable
high-speed, real-time transactions though a single port of entr.
PacifiCorp is participating in the development, testing and early stages of implementation of
each of these programs. For more information on these concepts, please visit the Joint Initiative's
website at "\"\vw.columbiagrid.org/ji-nttg-wc-overview.cfin.
Effcient Dispatch Toolkit (EDT)
WECC and its member organizations and stakeholders are working cooperatively to develop a
comprehensive cost benefit study to validate the EDT concept with the goal of optimizing
generation and transmission efficiency and maintaining a reliable bulk electric system in the
Western Interconnection. The EDT is composed of two separate but related tools-the Energy
Im:balance Market and the Enhanced Curilment Calculator.
· Energy Imbalance Market (ElM - The proposed ElM would supplement the curent
bilateral market with real-time balancing via a sub-hourly, real-time energy market that
provides centralized, automated, interconnection-wide generation dispatch. This
automation is expected to increase system effciency by providing access to balancing
resources located throughout the region and optimizing the overall dispatch through
incorporating real-time generation capabilties, transmission availabilty and constraints,
and pricing. While this concept proposes an independent market operator, it does not
propose a single consolidated regional taff or to implement an Independent System
Operator (ISO) or Regional Transmission Organization (RTO) in the Western
Interconnection. As proposed, paricipation in the EIM would be voluntar.
· Enhanced Curilment Calculator (ECC) - The ECC is a proposed tool for calculating
curailment responsibilities, and would calculate curailments on many more paths-rated
and unated-than the curent tool, webSAS, is capable of captung. The proposed ECC
would allow real-time updates of transmission system data to include actual outages,
which are curently updated only twice annually, and a more detailed model of the
physical system. While the ECC could be developed and implemented independently of
the ElM, the ECC plays an integral role in the effectiveness of the proposed EIM.
In 2010, the WECC Board of Directors approved a proposal for detailed analyses of the potential
costs and benefits of the EDT. These analyses, which are curently underway, wil provide
importnt data to inform the Board and WECC members and help determine next steps of EDT
56
PACIFiCORP-2011 IR CHAPTER 4 - TRASMISSION PLANING
development. PacifiCorp wil continue to participate directly in the development of the EDT and,
should the concept corne to fruition, wil base its ultimate decision on whether to participate on
the costs and benefits to customers and the impact on transmission system reliability. For more
information on the Effcient Dispatch Toolkit, please visit WECC's website at
\v,"vw. wecc. biz! committees! edt/Pages! default.aspx.
Energy Gateway Origins
Since the last major transmission infrastrctue constrction in the 1970s and early 1980s, load
growt and increased use of the western transmission system has steadily eroded any surlus
capacity of the network: In the early 1990s, when limited transmission capacity in high growt
regions became more severe, low natual gas prices generally made adding gas fired generation
close to load centers less expensive than remote generation coupled with transmission
infrastrctue additions. As natual gas prices started moving up in the year 2000, transmission
constrction became more attactive, but long transmission lead times and rate recovery.
uncertinty suppressed new transmission investment.
Numerous regional and sub-regional studies have shown critical need to alleviate. transmission
congestion and move transmission constrained energy resources to regional load centers. These
studies include the September 2004 Rocky Mountain Area Transmission StudiO, the May. 2006
Western Governors' Association Transmission Task Force Repoil1, the Nortern Tier
Transmission Group Fast Track Project Process in 200722, the TEPPC 2008 Annual Repoil3, the
2009 TEPPC Western Interconnection Transmission Path Utilization Studl4, and subsequent
PacifiCorp planning studies.
The recommended bulk electric transmission additions for PacifiCorp took on a consistent
footprint, which is now known as Energy Gateway, establishing a triangle over Idaho, Uta and
Wyoming with paths extending into Oregon and Washington.
Prior to 2007, PacifiCorp transmission activity was primarily focused on maintaining existing
transmission reliabilty, executing queue studies, addressing compliance issues, and paricipating
in shaping regional policy issues. Investments in main grd assets for load service, regional
expansion or economic expansion to meet specific customer requests for servce were addressed
as transmission customers requested service.
New Transmission Requirements
Historically, transmission planning took place at the utility level and was focused on connecting
specific utility generation resources to designated load centers. Under Order 888/889 Federal
20 http://pse.state''''.usíhtdoes/subregionaLiReports.htm
21 http://\v\'Vw . westgov .org/index.php? option=eorn j oomdoc&task=doe download&gid=97 <emid
22 http://nttg.biz/site/index.php?option=com doeman&task=doe download&gid= 121&Itemid=3 i
23http://vv''w.weec.biz/committees/BOD/TEPPC/Shared%20Documents/TEPPC%20Annual%20Reports/2008/Cove
rLetter Exec SummarY Final .pdf24http://www.weec.biz/eominittees/BOD/TEPPCiShared%20Documents/TEPPC%20Annual%20Reports/2009/2009
%20Westem%20Interconiieetion%20Trasnsmission%20Path%20Utilization%20Study.pdf
57
PACIFiCORP-2011 IR CHAPTER 4 - TRASMISSION PLANING
Energy Regulatory Commission rules, customer requests for transmission service were sporadic
and uncoordinated with high levels of uncertinty in many markets which inibited transmission
investments.
Due to PacifiCorp's transmission system being a major component of the Western
Interconnection, the Company has the responsibility to provide network customers adequate
transmission capability that optimizes generation resources and provides reliable service both
today and into the futue. Based on curent projections, loads and the dynamic blend of energy
resources are expected to become more complex over the next twenty years, which. wil
challenge the existing capabilities of the transmission network.
In addition to ensurng suffcient capacity is available to meet the needs of its network
customers, the Federal Energy Regulatory Commission in Order 890 encourages transmission
providers such as PacifiCorp to plan and implement regional solutions for transmission reliability
and expansion.
Based on PacifiCorp customers' aggregate needs, a blueprit for transmission expansion was
developed. The expansion plan is a culmination of prior studies and PacifiCorp customers' needs
over a long term horizon for new resource development. The expansion plan, now referred to as
Energy Gateway, wil support multiple load centers, resource locations and resource types, and
calls for the constrction of numerous transmission segments - totaling approximately 2,000
miles.
The Energy Gateway blueprit uses a "hub and spoke" concept to most efficiently integrate
transmission lines and collection points with resources and load centers aimed at serving
PacifiCorp customers while keeping in sight regional and sub-regional needs.
In addition to regulatory requirements for regional planning, futue siting and permitting of new
transmission lines wil require significant paricipation and input from many stakeholders in the
west. As part of new transmission line permitting, PacifiCorp wil have to demonstrate that
several key requirements have been met, including 1). the Company has satisfied an ongoing
requirement for transmission to serve customers, 2) the Company is planning and building for
the futue and is obtaining corrdors and mitigating environmental impacts prudently, and 3) that
any projects being proposed economically meet the reliability and infrastrcture needs of the
region overall. This regional process and the Western Electrcity Coordinating Council's
planning process are considered critical to gaining wide support and acceptance for PacifiCorp's
transmission expansion plan.
Customer Loads and Resources
PacifiCorp's Open Access Transmission Tariff ("OATT"), approved by the Federal Energy
Regulatory Commission ("FERC"), details the Company's requirements and obligations to
provide transmission service. Section 28.2 defines PacifiCorp's responsibilities, which include
the requirement to "plan, constrct, operate and maintain the system in accordance with good
utilty practice." Section 31.6 defines the requirement for network customers to supply annual
load and resource updates ("L&Rs") for inclusion in planning studies.
58
PACIFiCORP-2011 IR CHAPTER 4 - TRASMISSION PLANING
The Company solicits each of its network customers for L&R data annually in order to determine
futue load and resource requirements for all transmission network customers. These customers
include PacifiCorp Energy (which serves PacifiCorp's retail customers and comprises the bulk of
the Company's transmission network customer needs), Utah Associated Municipal Power
Systems, Utah Municipal Power Agency, Deseret Power Electrc Cooperative, Bonnevile Power
Administration, Basin Electrc Power Cooperative, and Moon Lake Electric Association.
The Company uses its customers' L&Rs and best available information to determine project
need and investment timing. In the event that customer L&R forecasts change significantly,
PacifiCorp may consider alternative deployment scenarios for its project investment as
appropriate.
Reliabilty
PacifiCorp's transmission network is required to meet increasingly strgent mandatory Federal
Energy Regulatory Commission (FERC) and Nòrth American Electric Reliability Corporation
(NRC) reliabilty standards, which require infrastrctue suffcient to withstand unplaned
outage events. Compliance with NERC planning standards is required of the NERC Regional
Councils and their members, as well as all other electrc industr participants if the reliability of
the interconnected bulk electrc systems is to be maintained in the competitive electrcity
environment. The majority of these mandatory standards are the responsibility of the
transmission owner.
NERC planning standards define reliability of the interconnected bulk electrc system in terms of
adequacy and securty. Adequacy is the electrc system's ability to meet aggregate electrcal
demand for customers at all ties. Security is the electric system's ability to withstand sudden
distubances or unanticipated loss of system elements. Increasing transmission capacity often
requires redundant facilities in order to meet NERC reliability criteria.
Transmission system designs require the abilty to recover from system distubances that impact
main grid transmission. Designs often require accommodating multiple contingency scenarios,
which Energy Gateway helps facilitate along with other system reinforcement projects. A
number of main grd transmission outages occured in the latter part of 2007, resulting in
curtilment of schedules, curilments of interrptible loads and generation curilments. These
outages occured on main grid paths and the lack of transmission capacity severely limited
available mitigation measures for system recovery.
Resource Locations
PacifiCorp's primary energy resources are located in Utah, Wyoming, desert southwest and the
west. Energy Gateway leverages PacifiCorp's diverse mix of energy resources at key locations
throughout its service territory. As an extension of Energy Gateway's 'hub and spoke' strategy,
PacifiCorp must consider logical resource locations for the long-term based on environmental
constraints, economical generation resources, and federal and state energy policies. Energy
59
PACIFiCORP-2011 IRP CHAPTER 4 - TRSMISSION PLANING
Gateway's design and extensive footprit support the development of a diverse range of cost-
effective resources required for meeting customer energy needs.
Figue 4.4 below shows PacifiCorp's servce terrtories and owned generation with an overlay of
the Energy Gateway Transmission Expansion Plan. Also noted are the planed generation
additions per the 2011 IRP preferred portfolio. New trsmission capacity is required to deliver
these energy resources to customers. The Transmission Scenario Analysis section provides an in-
depth comparison of different energy futues and how varying Energy Gateway segment
combinations impact PacifiCorp's 20 year present value revenue requirement.
60
PACIFICORP - 2011 IRP CHAPTER 4 - TRANSMISSION PLANING
Figure 4.4 - PacifiCorp service territory, owned generation and Energy Gateway overlay25
~- 230 kV mínímum ~~
. &císdii iu\)i.tion
This map is for general reference only and reflects current plans. It may not reflect the final routes,
construction sequence, exact line configuration or facility locations.
25 Visit PacifiCorp's Energy Gateway website for maps of renewable energy potential in the Western U.S. as
provided by the National Renewable Energy Laboratory (NL), including Energy Gateway overlays:
. Wind: http://www.pacificon).com/content/dam/pacificom/docrTmnsmission/Tmnsmission Projects!WindPowerPotential. 1 O.pdf
. Solar: http:!¡wv.".v.pacitìcoi:,com!content!daipacificoi:! d.oc!T ransmissi on/Transmission Projects!SolarPoteiitiaL 10. pdf
. Geothermal: http:i¡",'ww,pacitìcorp,comi eontentídamipacifieoi:!doc/T ransmissiowT ransmi ssion Pro jeets!GeothermlPotential.l O,pdf
. Biomass: http://www .pacificom.eonii content! damipacificoi:idoc:Transmission/Transmission Proj ects/BioinassPotentia1.i O.pdf
61
PACIFiCORP-2011 IR CHAPTER 4 - TRNSMISSION PLANING
Major segments of the Energy Gateway project originate in Wyoming and Uta and migrate west
to Oregon and Idaho. The Energy Gateway project taes into account the existing 2006
MidAerican Energy Holdigs Company transaction commitments relating to transmission
system improvements between southeast Idao and nortern Utah (Populus to Terminal), within
Utah's Wasatch Front (Mona to Oquirh), and the Nortwest's Mid-C area (Walla Walla to
McNary).
PacifiCorp is actively puruing the Energy Gateway transmission project under the following
overarching key objectives:
· Customer driven - Energy Gateway is drven by PacifiCorp's retail, wholesale and
network customers' needs. Including Energy Gateway as a base allows PacifiCorp to
move forward with the knowledge that over the coming years, transmission lines wil be
utilized to their fullest potentiaL.
· Support multiple resource scenarios - The transmission expansion project wil
accommodate a variety of futue resource scenaros, including meeting renewable and
low-carbon generation requirements, supportg natual gas fueled combustion tubines
and market purchases, and recognizing that clean coal-based generation may emerge as a
viable resource.
· Consistent with past and current regional plans - The proposed projects are consistent
with numerous regional planing efforts. The need to expand transmission capacity has
been known for years and is increasing due to substatial variable resource additions to
the system.
· Get it built - Transitioning from planing to implementation is key to achieving "steel in
the ground" and meeting customer needs. Proactive engagement with staeholders and
policymakers in the planning process wil help minimize barers to implementation.
· Secure the support of state and federal utity commissions for rate recovery -
PacifiCorp wil continue to seek the input of state and federal regulators thoughout the
planning process to ensure concerns are communicated and addressed early.
· Protect the investment to the benefit of customers - An appropriate balance must be
strck to ensure that network customers do not subsidize third part use and to ensure
that PacifiCorp's long-term network allocation requirements are retained.
"Rightsizing" Energy Gateway
PacifiCorp's priority in building Energy Gateway is to meet the needs of its customers. The
Company requires new transmission capacity to adequately serve its customers' load and growth
needs across the next 20 year horizon and beyond. Recognizing the potential regional benefits of
"up sizing" the project (such as maximized use of energy corrdors, reduced environmental
impacts and improved economies of scale), the Company included in its original Energy
Gateway plan the potential for doubling the project's capacity to encourage third-par
commitments and equity parterships necessary to support such an investment. In the years since
the May 2007 announcement of Energy Gateway, the Company has pursued such partnerships
62
PACIFiCORP-2011 IRP CHAPTER 4 - TRANSMISSION PLANING
but due to the significant costs inerent in transmission investments - and the Company's
obligation to shelter its customers from costs and risks associated with "upsizing" the project for
third~paries' benefit - these commitments have not materialized. PacifiCorp is committed to
building Energy Gateway to meet the needs of its customers and is moving ahead with the
appropriate investments to do so.
The core transmission expansion plan includes lines and stations required to deliver additional
transmission capacity required to meet PacifiCorp's long-term reguatory requirement to serve
loads. Each segment wil be justified individually within the overall program. A combination of
benefits, including net power cost savings derived from the IRP, reliability, capital offsets for
renewable resource development in low yield geographic regions and system loss reductions wil
be used to assess the viabilty of each segment. See the Transmission Scenario Analysis section
below.
Each Energy Gateway segment wil be re-evaluated during the Company's annual business plan
and IRP cycles to ensure optimal benefits and timing before movig forward with permitting and
constrction. Depending on conditions or alternatives, certain segments could be deferred or not
constrcted if evaluations prove the need or timing has shifted. PacifiCorp also evaluates joint
development opportities with other utilities and transmission developers where appropriate to
minimize cost and impacts while providing necessary benefits to customers. See Chapter 10 -
Transmission Expansion Action Plan, for more information on Energy Gateway and joint
development opportities.
WECC Ratings Process
The Western Electrcity Coordinating Council ("WECC") provides a formal process for project
sponsors to achieve a WECC Accepted Rating and demonstrate how their project wil meet the
related NERC and WECC Planning Standards. This process requires close coordination between
the project sponsor(s) and representatives of other transmission systems that may be impacted by
the proposed project. Figue 4.5 below shows the stages of the WECC rating process, and a high-
level summary of the 3-phase process is provided here:
. Phase 1: The project sponsor conducts studies to demonstrate the proposed rating of the
project and prepares a Comprehensive Progress Report documenting study results and
project details. Once the progress report is accepted by WECC, the project is granted a
"Planned Ratting" and Phase 1 is considered complete.
. Phase 2: A review group comprised of interested WECC members conducts a thorough
review of the project, validating its planned rating and fuer assessing its simultaneous
transfer capability and impacts on neighboring transmission systems. All studies and
findings in this phase are documented in a Phase 2 Rating Report. Once this report is
accepted by WECC, the project is granted an "Accepted Rating" and Phase 2 is
considered complete.
63
PACIFiCORP-2011 IR CHAR 4 - TRSMISSION PLANING
· Phase 3: Major changes in project assumptions and system conditions are evaluated to
ensure the Accepted Rating is maintained. Phase 3 is completed when the project is
placed into service.
Figure 4.5 - Stages of the WECC Ratigs Process
Regonal PlanD and Project Rating Process Sequence
Project PhaSES
Regional Planning
Process Assessmt. Prjec Reiew
Rating R~iew Process Ph 1
pose Rati
Ph 2
P1aed
Progress Reports Progre.ss Reps Ar Required Thoughout the Entie Planing Process
Notes:
1. "Propos Rati'" -used at the intiation an thoughout Phse I of the Projec Ratig Review Press
2. "Pled Rati'" - is th fil ratig at the conclusion of Phase I of th Prec Rati Review Process and us thoughout Phse
2 of the Prject Ratig Review Process
3. "Acceped Ratig'" - is th fil ratig at th coluon of Phse 2 of th Projec Ratig Review Press an is also the ratig tht
is u!l when th Project is placed in-sece
Source: WECC Overview of Policies and Procedures for Regional Planing Project Review, Project Rating Review. and Progress Reports
(Revised by RPPTF 01119/2005) httpj/www.wecc.biz!Documents/2005!PCC%20Meetings/Policies Procedures OI-19-05 version clean vI.pdt
Since the initial May 2007 announcement of Energy Gateway, PacifiCorp has made significant
progress through the extensive WECC ratings process. PacifiCorp initiated the process for
Energy Gateway West and Energy Gateway South in June 2007. Phase 1 Comprehensive
Progress Reports were issued in November 2008 and, following a 60-day review period, both
projects were granted Phase 2 status in Febru 2009.
The following is a list of Energy Gateway transmission paths that have completed the Phase 2
process and have been granted Phase 3 Status:
. Energy Gateway West
o TOT 4A - December 2010
o Aeolus West - January 2011
o Bridger/Anticline West - Janua 2011
o Path C - Januar 2011
. Energy Gateway South
o Aeolus South - December 2010
Additional paths for each project are nearing completion of Phase 2, including Borah West and
Midpoint West (Gateway West), and TOT 2B/C (Gateway South). Upon WECC's granting of
64
PACIFiCORP-2011 IR CHAPTER 4 - TRNSMISSION PLANING
Phase 3 status, WECC recognizes the capacity ratings of these transmission paths to a similar
extent as a completed project.26
Regulatory Acknowledgement and Support
Beyond the extensive list of planning efforts discussed in this section-the joint initiatives, rating
studies, federal and state policy directives, system reliability requirements, and all the other
considerations that are factored into transmission planning-regulatory support is critically
important to these investments materializing. Also, timely permitting by agencies is importnt
for these investments to be available to meet PacifiCorp's need to serve load.
PacifiCorp provides electric service across six western states through an expansive integrated
system of generation and transmission facilities necessary to serving its customers. System
maintenance, reinforcements and additions are fudamental to the Company's ability to provide
reliable service. Likewise, cost recovery for prudent investments is fudamental to the
Company's ability to contiue making these necessary investments on behalf of its customers.
PacifiCorp wil seek fair valuation and cost recovery for all of its Energy Gateway investments
to ensure customers pay for an appropriately balanced share of these facilities.
By June 1, 2011, PacifiCorp wil fie a transmission rate case with the Federal Energy
Regulatory Commission ("FERC") to update the service rates in its FERC-approved Open
Access Transmission Tariff ("OA TT"). The Company wil seek updated rates that appropriately
reflect the transmission investments made since its last FERC rate case in the 1990s. The OATT
rates set by FERC apply to wholesale and third-part customer transmission transactions. Since it
is PacifiCorp's retail customers who wil pay for the Energy Gateway investments, the revenues
from wholesale and third-part transmission sales are a dollar-for-dollar offset to retail
customers' rates.
PacifiCorp has already begu seeking state regulatory approval and cost recovery for its Energy
Gateway investments, which to date consist primarily of the Populus to Terminal project
completed in November 2010. A fair valuation of these investments by each state commission
means PacifiCorp's retail customers in each of the states it serves wil pay an appropriate
allocation of these costs and no more. However, regulatory challenges and disallowances in one
state upsets this balance, resulting in customers in one state paying more than customers in
another state, or in PacifiCorp under-recoverig for the prudent investments it has made-r
both.
PacifiCorp wil continue to work with its state and federal regulators to demonstrate the prudence
of the Company's investments and to ensure an equitable cost-balance among all of its
customers.
26 For complete details on all WECC rated transmission paths, see the WECC 2011 Path Rating Catalog available at
W\¥w.wecc.biz (click "Quick Links" and choose "Path Ratig Catalog)
65
P ACIFICORP - 2011 IRP CHAPTER 4 - TRSMISSION PLANING
Additional Transmission Scenarios
The 2008 IRP included background information on Energy Gateway resulting from varous
regional planning studies and the Company's responsibilty for interconnection-wide
transmission planning under the Federal Energy Regulatory Commission's Order 890.
Specifically, several planing studies dating back to September 2004 identified the critical need
to alleviate transmission congestion and move transmission constrained energy resources to
Company load centers. The 2008 Energy Gateway strategy outlined the overarching key
objectives and action plan to constrct the proposed transmission segments between 2010 and
2019. The Populus to Terminal segment identified for 2010 completion has been placed in-
service and is providing additional transmission capacity as planned.
Feedback on the 2008 IRP from varous staeholders requested additional transmission analysis
to be undertaken that would examine different deployment scenaros based on a varety of input
assumptions. In 2010, the Company undertook a transmission sensitivity analysis that involved
variations of the Energy Gateway transmission footprint, timing of in-service dates, megawatt
capacity, futue loads, energy resources and drvers that influence energy resources as well as the
need for transmission. Previous analysis focused on an all-inclusive Energy Gateway scenario
compared to a "no-Gateway" scenario where variable production cost savings and least-cost
constrction estimates were the basis of the recommendation to move forward. The 2010 Energy
Gateway analysis undertook a broader approach to the Energy Gateway strategy by determining
if constrcting all or parts of the transmission segments is in the best interest of customers.
Two underlying strategies emerged regardig renewable resources and the need for additional
transmission.
Green Resource Future
This outlook assumes that federal and state governents continue a 'green' resource strategy that
optimizes renewable resources as a significant energy source and reduces carbon emissions. The
outlook also assumes the United States takes an aggressive role in accelerating renewable
resources through incentives, CO2 taxes or renewable tagets. Demand for energy experiences a
significant increase through renewed economic growth and the higher penetration of electric
applications such as electric vehicles. Alternate resource technologies continue to be developed
but the mainstay of renewable energy resources for the next twenty years is wind located in areas
that offer economic and political acceptance.
Incumbent Resource Future
This scenario assumes carbon legislation and federal/state renewable energy requirements wil
subside, thereby lessening the demand for renewable resources and where they are placed. This
scenario ignores natual gas price volatility and assumes stable natual gas prices which diminish
the need for large wind resource additions and transmission projects originating in Wyoming
66
PACIFICORP - 201 1 IRP CHAPTER 4 - TRNSMISSION PLANING
over the next twenty years. Lower gas prices translate to serving loads with gas tubines located
closer to Company load centers such as Utah. Alternate energy technologies such as electrcity
storage, battery and smart grd technologies wil be developed, but the majority of new energy is
generated from existing fuel resources.
2011 IRP Transmission Analysis
Seven Energy Gateway scenarios were initially selected and modeled using the Company's
System Optimizer capacity expansion tool. These scenarios ranged from a "base case" scenario
with minimal planned transmission (including the Populus to Terminal, Mona to Oquirrh and
Sigud to Red Butte27 projects) to the full "incremental" Energy Gateway strategy (including
Energy Gateway West, Aeolus to Mona and west-side projects). With a combination of
alternative renewable portfolio standard and C02/gas price assumptions these scenarios reflect
the key elements of the Green Resource and Incumbent Resource futues, although specific
assumptions such as increased electrc vehicle applications were not modeled for the 2011 IRP.
The scenarios represent the most logical combination of transmission segments to move energy
from resource centers to regional Company load centers including timing of in-service dates and
subsequent incremental transmission capacity.
Incremental transmission capacity became very dynamic in some scenarios due to certain
transmission segments providing redundant/contingency back-up and therefore resulting in
higher incremental capacity ratings compared to transmission segments without redundancy.
Less than full incremental transmission path ratings were assumed for some segments when
modeling incremental capacity without redundancy, which translated to almost half the designed
capacity rating.
The System Optimizer can solve simultaneously for resources and transmission expansion;
however a limitation of the model occurs when one transmission option is dependent on another,
such as for ratings support. Such "contingent" optimization required 'fixed' transmission
configurations utilizing multiple transmission scenarios rather than have the model optimize
transmission expansion options independently.
Figues 4.6 to 4.12 show maps of the seven System Optimizer scenarios for Energy Gateway
Transmission. (Refer to Chapter 10 - Transmission Expansion Action Plan, for detailed
descriptions of each of the planned Energy Gateway segments.) The 'base case' scenaro
(Scenario 1) is a minimum-build transmission plan that is also par of the Energy Gateway
strategy; however, it needs to be constrcted regardless of other Energy Gateway options due to
specific load and reliability requirements. PacifiCorp is also committed to pursuing the
27 The Utah Public Service Commission (Docket No. 09-2035-01, April 1,2010) directed the Company to "OITt
from its core cases any resource for which it does not already have a signed final procurement contract or certficate
of public convenience and necessity." Each of the Energy Gateway segments in the Company's base case (Scenario
1) has received a CPCN with the exception of the Sigurd to Red Butte project. Sigud to Red Butte, like the other
base-case projects, is part of the Company's minimum-build transmission plan based on need for these specific
projects among studied alternatives. The CPCN filing for this project is imminent and its scheduled in-service date
is consistent with the in-service date range of other base case projects (2012-2014) for which the Company requests
acknowledgement in this IRP.
67
PACIFiCORP-2011 IR CHAPTER 4 - TRSMISSION PLANING
incremental additions of Energy Gateway and is permitting each segment based on what the
Company believes is needed for customers. PacifiCorp and its stakeholders wil continue to have
opportity to evaluate that need as some of the policy uncertainties are addressed in the coming
years and before reaching "steel-in-the-ground" on these incremental additions.
Figure 4.6 - System Optimizer Energy Gateway Scenario 1
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario I
m.
îi PadfiCorp service are
Planed trasmissin lines
- 50 kV minimum voltae
- 345 kV minimum volta
-. 230 kV minimum votage
€) Transmission hub
. Substatin
ii Generatin plant/station
68
PACIFiCORP-2011 IR CHAPTER 4 - TRANSMISSION PLANING
Figure 4.7 - System Optimizer Energy Gateway Scenario 2
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario 2
. PacifiCorp serice area
Plmned trsmisioi lìn
- 500 kV minimum voltage
.. 345 k\ minimum voltae
W'~Æ 230 kV minimum voltae
il Transmissloo hub
. S~bstatín
I~ Generatin plntJstation
69
P ACIFICORP - 2011 IR CHATER 4 - TRSMISSION PLANING
Figure 4.8 - System Optimizer Energy Gateway Scenario 3
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario 3
. PacìfCorp seice area
- 500 kV minimum voltge
- 345 kV minmum volt
- 230 leV mìnimum vòltge
o Transmisson hub
. Substtion
ii Genon plrJsi:ti
70
P ACIFICORP - 2011 IR CHAPTER 4 - TRASMISSION PLANING
Figure 4.9 - System Optimizer Energy Gateway Scenario 4
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario 4
. Paciforp ~ervke area
Planned trasmission lines
- 50 kV minimum voe
- 345 kV minimum volta
- 230 kV minimum voltae
ø TransmssiOl hub
. Sutation
fi GeneratiÐf phntlmitín
71
PACIFiCORP-2011 IR CHAPTER 4 - TRSMISSION PLANING
Figure 4.10 - System Optimizer Energy Gateway Scenario 5
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario 5
(N PacifCop servçf¡ area
- 500 kV l'l'imum vok:
- 3'lS kV minimum VQltage
- 230 kV minimum volta
ø Trasmiss hub
. Subtation
il Generation pbtlstation
72
P ACIFICORP - 2011 IR CHAPTER 4 - TRASMISSION PLANING
Figure 4.11 - System Optimizer Energy Gateway Scenario 6
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario'
. PadlìCorp ...,..,.. ....ea
Plannd trnsmission lins
.. SOO kV minimum voltae
.. 34S kV minimum volt
-- 230 kV minimum voltae
l2 T ransmí.sio hub
. Substa1:on
ii Ge,,,ratJufl pJamhtatiori
73
P ACIFICORP - 2011 IR CHAPR 4 - TRANSMISSION PLANING
Figure 4.12 - System Optimizer Energy Gateway Scenario 7
Energy Gateway Transmission Expansion Plan
System Optimizer Scenario 7
mi G...,..ti plantston
.PaciCcrp service area
- 50 IN minimum voltae
~ 345 kV mírúmum VOltaE
.-- 230 kV minimum voltae
ø Trasmission hub
. Substaon
System Optimizer Assumptions
The placement of wind, if selected as a resource, was facilitated by incremental transmission
capacity. The System Optimizer placed wind resources in the most cost-effective locations
considering available transmission. Without available transmission, the model placed wind
resources, if economic, in alternative wind generation bubbles outside of the Energy Gateway
scenarios. See Chapter 6 for treatment of wind resources and supporting transmission costs, and
Chapter 7 for a detailed description of the Energy Gateway scenario specification and the System
Optimizer modeling methodology.
74
PACIFiCORP-2011 IRP CHAPTER 4 - TRANSMISSION PLANING
The System Optimizer uses the capacity contrbution of resources at the time of system peak to
determine the capacity expansion plan that meets the planing reserve margin constraint. In the
case of intermittent resources with relatively variable capacity contrbutions, the nominal
capacity added by the model can exceed available transmission capacity for certin hours where
the intermittent resource is operating near maximum capacity.
A set of four C02 tax and natual gas price combinations were assumed in the modeling: medium
C02 tax!medium gas price, medium CO2 tax/igh gas price, high C02 tax! medium gas price and
high C02 taxlhigh gas price for transmission scenarios. The range of C02 taxes and natual gas
cost values are described in Chapter 7.
While the System Optimizer selects resources based on certin assumptions using deterministic
loads and resources, it does not model stochastic risk which is done through the Planing and
Risk (PaR) model as described in Chapter 7.
The System Optimizer does not take into account all transmission operating requirements or
limitations such as Remedial Action Schemes (RAS), which manage automatic protection
systems designed to detect abnormal or predetermined system conditions and tae corrective
actions in order to maintain system reliabilty. Placement of additional resources cannot expose
the network to abnormal RAS risks. In one scenario, wind had to be moved to a different
location due to lack of transmission capacity.
A 20 year present value revenue requirement (PVRR) was calculated for each Energy Gateway
scenario by including fixed and variable costs for the resource portfolios. The Energy Gateway
scenaros with the lowest PVR represent the least cost solution as calculated by the System
Optimizer. A full financial analysis requires the System Optimizer resource selection to be ru
through the PaR model for stochastic calculations. of probabilistic outcomes to measure risk
(loads, market prices, gas prices, hydro availabilty, and forced outages).
Output from initial transmission scenario uploads in the System Optimizer eliminated three
scenaros for various reasons. Scenario 6, which added Boardman - Cascade Crossing to the
base-case, was eliminated from fuher analysis at this time because the System Optimizer
topology in the West was not detailed enough to calculate credible results. Scenaro 5, which
added Populus - Boardman - Cascade Crossing to the base-case, was eliminated from fuer
analysis given the difference between scenario 7 and scenario 3 would isolate the value of
Scenario 5. Scenario 4, which added Windstar - Populus - Boardman - Cascade Crossing to the
base-case, was eliminated because the placement of wind resources was identical to Scenaro 2
and it did not make sense to consider additional transmission costs from Populus - Boardman -
Cascade Crossing.
Green Resource Future Results
The Green Resource Future included a set of System Optimizer rus to reflect planning
assumptions favorable to more wind development along with the four combinations of C02 and
natual gas prices.
75
PACIFiCORP-2011 IR CHAPTER 4 - TRSMISSION PLANING
Federal renewable energy requirements were assumed át the Waxman-Markey level (20 percent
by 2020). The Company limited geothermal resource selection to the Blundell site in Utah at 80
MW s due to uncertinty regarding the prospects for geothermal development and cost recovery
in PacifiCorp's other state jursdictions.28 This resulted in wind selection more in line with the
wind amounts in the prefeITed portfolios for the 2008 IR and 2008 IRP Update.
PacifiCorp also adjusted import capacities for the Goshen and Yakima topology bubbles. The
adjustments eliminated capacity deficits in these bubbles caused by transmission constraints.
These transmission constraints are a fuction of model behavior and not indicative of any real
transmission constraints for these areas of the system. Relieving these "artificial" transmission
constraints improved the economics of Scenaro 1 relative to the other segment scenarios. The
other scenarios were not affected by the topology changes because the incremental transmission
segments they reflected, such as Windstar-Populus, relieved the constraints as well.
The System Optimizer selection of wind resources under the Green Resource Futue are
sumarized in Table 4.1. Note that the scenario identification numbers 1, 2, 3, and 7, were
renumbered to base, 1, 2, and 3 for presentation in public IRP documents. This modified labeling
convention is used for the rest of the IR document.
In all cases, wind was a significant resource pick priarly based on the renewable resource
requirement. Variations between resource locations and megawatt totals were based on
economics and available transmission. In transmission Scenario 1 for instance, the System
Optimizer assigned a significant amount of wind resources in Washington since there was no
transmission path between east and west. Given that the incremental megawatts for. wind
exceeded curent transmission capacity, additional transmission facilities had to be incorporated
into the present value revenue requirement for Scenario 1.
Similar logic was applied to Scenario 2 where the System Optimizer assigned significant wind
resources in Wyoming, but lack of transmission capacity and RAS risks required the wind to be
moved, with additional transmission facilities.
The wind resources picked under this set of sensitivities are similar to the resources shown in the
2008 IRP Update.
The System Optimizer 20-year PVR results from the Green Resource Futue analysis are
summarized in Table 4.2. Definitions for the System Optimizer cost categories are as follows:
· Station Costs: Represents the PVRR cost for fuel, variable operation and maintenance, fixed
costs, emissions, decommissioning, and investment capital recovery for existing and new
power stations. Stations are generally defined as resources that are not contracted
· Transmission Costs: Represents the PVRR cost for the specified Energy Gateway scenaro
plus the capital recovery for any transmission additions required to support location
dependent resources. Wheeling costs are also included.
28 While Utah geothermal resources were allowed for this scenao analysis, the Company anticipates legislative and
regulatory actions to address cost recovery and resource pre-approval concerns before geothermal acquisition is
pursued as a resource strategy. This issue is discussed in Chapters 8 and 9.
76
PACIFiCORP-2011 IRP CHAPTER 4 - TRASMISSION PLANG
. DSM CostS: Represents the PVR cost for existing and new demand-side management
programs and measures. Costs include energy, capacity, and the recovery of capital
investment.
. Contract Costs: Represents the PVRR cost for existing Company power supply contracts.
Costs include energy and capacity portion of contracts. These costs remain static between
portfolios.
. Spot Market Net Purchases/Sales: Represents the net PVR cost of spot market transactions
(purchases and sales) at the market hubs. The cost is a fuction of the megawatt volume sold
or purchased and the forward prices assigned to the market hubs.
. Unserved Energy: Represents the penalty cost of not meeting the planning reserve margin
(unserved capacity) as well as the penalty cost of any energy not able to be served. The unit
penalty costs are set to $9 milion per MW-month for unet capacity, and $5,000 per MW
for unserved energy. These values are set sufficiently high to prevent System Optimizer from
generating unet energy and capacity as a means to lower PVRR.
Table 4.1- Green Resource Future, Selected Wind Resources (Megawatts)29
Wind-il 200 146
Wind-UT 529 72 500 84
Wind-WY 2 1,184 1,246 1,246 2 1,172 1,620 1,960
Wind-WA 871 200 200 200 1,021 200 200 200
Wind-OR
29 See Appendix C for detailed resource portfolio tables.
30 Scenario 2 calls for up to 1,184 MW of incremental Wyoming wind, however present value revenue requirements
reflect added transmission to accommodate a portion of wind resource moved to Utah. Scenario 2 wil not support
1,184 MW of additional wind in Wyoming due to transmission constraints and operational requiements.
77
PACIFiCORP-2011 IR CHAPTER 4 - TRASMISSION PLANG
Table 4.2 - Green Resource Future, Present Value Revenue Requirement ($ milions)
Station Costs 37,934 37,395 37,394 37,393 40,171 39,511 39,509 39,509
Transmission
Costs3l 3,103 2,499 2,524 2,564 3,103 2,499 2,524 2,563
DSM Costs 2,528 2,549 2,549 2,549 2,660 2,669 2,669 2,669
Contrat Costs 3,294 3,294 3,294 3,294 3,303 3,303 3,303 3,303
Spot Market,
Net Purchase I
Sales (6,544)(6,186)(6,185)
Unserved
Ener
Station Costs 42,794 42,082 42,078 42,075 45,601 44,736 44,611 44,630
Transmission
Costs 3,103 2,499 2,524 2,563 3,104 2,500 2,525 2,564
DSM Costs 2,598 2,705 2,705 2,705 2,693 2,752 2,753 2,752
Contrat Costs 3,299 3,299 3,299 3,299 3,302 3,302 3,302 3,302
Spot Market,
Net Purchase I
Sales
Unserved
Ener
31 Represents the present value revenue requiement (PVR) for the specified Energy Gateway scenaro plus any
capital recovery of transmission additions required to support location dependent resources. Scenaro 7 represents
the full Energy Gateway expansion plan, which is an approximately $6 bilion investment plan. This investment is
amortized over a 58-year period, but for consistency with the IR's 20-year scope, only 20 year of the total
amortzed cost is provided here. See Appendix C for a detailed Transmission PVR cost table.
78
PACIFiCORP-2011 IRP CHAPTER 4 - TRANSMISSION PLANING
The System Optimizer PVRR results are a 20-year determnistic view of resources and portfolio
costs. In order to assess the stochastic PVRR results, the resource selection must be ru through
the Planing and Risk model for a complete cost assessment. However, a 'base-case' Scenaro i
development plan is clearly more expensive when compared to the alternatives. Stochastic
production cost evaluation of these Energy Gateway scenaros, or new ones as dictated by the
planning environment, is expected to be performed before the final 2011 IRP update is issued.
Incumbent Resource Future Results
A series of System Optimizer runs were initiated assuming the same range of C02 taxes and
natual gas costs used in the Green Resource Futue. The Energy Gateway scenarios were also
repeated along with the assumption for production tax credits. Renewable requirements were
established to meet curent state requirements on a system basis, which also satisfies Senator
Bingaman's proposed federal targets of 9 percent by 2021 and 15 percent by 2025r for all
scenarios.
The Incumbent Resource Futue results for wind resources produced much lower MW s
compared to the Green Resource Futue due to the lower renewable requirements, lack of a
production tax credit after 2014, and displacement by geothermal resources.32 Unlike the Green
Resource Futue, the Company assumed no limitations in terms of geothermal resource selection
on a regional basis. Also, the model topology does not reflect transmission capacity adjustments
for the Yakima and Goshen topology bubbles discussed above. Wind became the selected
resource in high C02 taxi high gas price scenaros due to economics, but was not selected in
other pricing scenarios. For scenarios with high natual gas costs, the System Optimizer selected
several hundred megawatts of geothermal in the west.
Wind resources for the Incumbent Resource Futue analysis are sumarized in Table 4.3.
Complete resource portfolio tables are provided in Appendix C.
In all cases, except when C02 taxes and natual gas prices were high, the System Optimizer did
not pick wind resources. Only with the combination of high C02 and natual gas prices did the
System Optimizer select wind in Wyoming. A high C02 tax and a renewable standard could be
contradictory in actual practice.
The System Optimizer 20-year PVR results from the Incumbent Resource Futue analysis are
summarized in Table 4.4.
32 The December 2010 model rus incorporated updated geothermal resource potentials and cost information frorn a
consultat study. As noted in Chapter 9, uncertainty regarding whether geothermal development costs for specific
resources can be recovered is curently the most significant resource risk.
79
PACIFiCORP-2011 IR CHAPTER 4 - TRSMISSION PLANING
Table 4.3 - Incumbent Resource Future, Selected Wind Resources (Megawatts)
Wind-il
Wind-UT
Wind-WY 2 52 52 76
Wind-WA 56 100 100 100 100
Wind-OR
Total Wind 58 52 52 76 100 100 100 100
Wind-il
Wind-UT
Wind-WY
Wind-WA
Wind-OR
4
2
2
47 47 72 1,157
200
1,157
200
1,563
200
1,948
200
80
PACIFiCORP-2011 IRP CHAPTER 4 - TRSMISSION PLANING
Table 4.4 - Incumbent Resource Future, Present Value Revenue Requirement ($ milons)
Station Costs
Trans Costs
DSM Costs
Contract
Costs
Spot Market,
Net Purchase
I Sales
Unserved
Ener
3,294 3,294 3,294 3,294 3,303 3,303 3,303 3,303
Station Costs 41,408 41,293 41,287 41,353 44,355 44,427 43,591 44,485
Transmission
Costs 1,457 1,916 2,419 2,518 1,601 2,500 2,525 2,564
DSM Costs 3,550 3,553 3,553 2,695 3,800 3,768 3,958 2,845
Contract
Costs 3,299 3,299 3,299 3,299 3,302 3,302 3,302 3,302
Spot Market,
Net Purchase
I Sales
Unserved
Ener
The System Optimizer 20-year PVRRs for Scenaros 2 and 3 were higher than the base-case
Scenario 1. The full Energy Gateway strategy, Scenario 7, was less costly than base-case
Scenario 1. However, if the import capabilties for Goshen and Yakima topology bubbles were
. adjusted for Scenario 1 similar to the Green Resource Futue Scenario 1, the total PVRR costs
would be less. (As noted above, the Goshen and Yakima topology adjustments relieve artificial
transmission constraints that inflate portfolio costs in the absence of the Energy Gateway
transmission additions.) Unless significant wind resources are added to Wyoming as in the high
81
P ACIFICORP - 2011 IRP CHAPR 4 - TRSMISSION PLANING
C02 and high natual gas cost scenarios, the utilization percentage of Gateway West and
Gateway South would be fairly miimaL. This would be a prime factor for the Company to
decide not to pursue building these incremental transmission segments.
Energy Gateway Treatment in the Integrated Resource Plan
The System Optimizer analysis and previous. stochastic production cost modeling demonstrated
the logical connection between several trsmission scenaros and incremental resource
requirements. The modeling analysis indicates that the full Energy Gateway strategy is cost-
effective assumig incremental wid additions are in line with the Company's curent wind
acquisition plans. However, without the mandate for additional renewable resources and
regulatory support for associated transmission investments, fuer evaluation of proposed
incremental transmission originating in Wyoming (most economic location for wind) would be
required to determine need for Company load service. One thing is clear; the Energy Gateway
strategy provides the necessary capacity for the Company to be aligned with a green resource
futue.
What is also important to note is that the cost range for the scenarios considered is relatively
close, which suggests economics do not drve a clear selection. The key decision is what is the
best investment based on an assumed futue state.
Assuming a futue scenario with reduced renewable energy requirements or other energy sources
such as geothermal resources located in the west or implementation of new technologies presents
a significant risk if the assumptions tu out wrong and transmission expansion was halted.
The Company curently believes that strong support for renewables development wil continue
(notwithstanding regulatory hurdles and governent budgetary pressures that may erode
financial support programs), and therefore concludes that proceeding with the full Gateway
expansion scenario is the most prudent strategy given regulatory uncertainty, benefits from
resource diversity, and the long lead time for adding new transmission facilities. Consequently,
the Company decided to reflect the full Energy Gateway in portfolios used to develop its 2011
IRP preferred portfolio. Furher, the Company seeks acknowledgment of Energy Gateway plans
as outlined in the transmission expansion action plan (Chapter 10).
82
P ACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
This chapter presents Pacifi Corp's assessment of resource need, focusing on the first ten years of
the IRP's 20-year study period, 2011 through 2020. The Company's long-term load forecasts
(both energy and coincident peak load) for each state and the system as a whole are addressed in
detail in Appendix A. The sumar level coincident peak is presented first, followed by a profile
of PacifiCorp's existing resources. Finally, load and resource balances for capacity and energy
83
PACIFICORP - 2011 IR CHATER 5 - RESOURCE NEEDS ASSESSMENT
are presented. These balances are comprised of a year-by-year comparson of projected loads
against the resource base without new additions. This comparson indicates when PacifiCorp is
expected to be either deficit or surlus on both a capacity and energy basis for each year of the
planning horizon.
The 2011 IRP used the Company's October 2010 forecast, which also supported development of
the ten year business plan. Table 5.1 shows the anual coincident peak megawatts for the East
and West-side of the system as reported in the capacity load and resource balance, prior to any
load reductions from energy efficiency (Class 2 DSM). The system peak load grows at a
compounded average anual growt rate (CAAGR) of2.l percent for 2011 though 2020.
Table 5.1 - Forecasted Coincidental Peak Load in Megawatts, Prior to Energy Effciency
Reductions
PacifiCorp's eastern system peak is expected to contiue growing faster than the western system
peak, with average annual growth rates of 2.4 percent and 1.4 percent, respectively, over the
forecast horizon. The main drvers for the higher coincident peak load growt for the eastern
states include the following:
· Customer growt in residential and commercial classes.
· New large commercial customers such as data centers.
· Increased usage by Industral class due to addition of new large industrial customers or
expansion by existing customers.
For the forecasted 2011 summer peak, PacifiCorp owns, or has interest in, resources with an
expected system peak capacity of 12,459 MW. Table 5.2 provides anticipated system peak
capacity ratings by resource category as reflected in the IRP load and resource balance for 2011.
Note that capacity ratings in the following tables are rounded to the nearest megawatt.
Table 5.2 - Capacity Ratings of Existing Resources
Pulverized Coal
Gas-CCCT
Gas-SCCT
Hydroelectric
Class 1 DSM 3/
Renewables
6,188
2,025
358
1,236
324
297
49.7
16.3
2.9
9.9
2.6
2.4
84
PACIFiCORP-2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Purchase 4/ 1,510 12.1
Qualifying Facilities 239 1.9Interrptible 281 2.3Total 12,459 100
Sales and Non-Owned Reserves are not included.2/ Represents the capacity available at the time of system peak used for preparation of the capacity load and
resource balance. For specific defmitions by resource tye see the section entitled, "Load and Resource
Balance Components", later in this chapter.3/ Class i DSM is PacifiCorp's dispatchable load control.
4/ Puchases constitute contracts that do not fall into other categories such as hydroelectrc, renewables, and
natural gas.
Thermal Plants
Table 5.3 lists existing PacifiCorp's coal fired thermal plants and Table 5.4 lists existing natual
gas fired plants. As a modeling assumption, no coal or gas plants are shut down during the IRP
20-year planning period. Plant operating decisions wil be based on an assessment of plant
economics that considers the cost for replacement power given environmental compliance
requirements, market conditions, and other factors.
Table 5.3 - Coal Fired Plants
Carbon 1 100 Uta 67
Carbon 2 100 Utah 105
Cholla4 100 Arizona 387
Colstrp 3 10 Montana 74
Colstrip 4 10 Montana 74
Craig 1 19 Colorado 84
Craig 2 19 Colorado 83
Dave Johnston 1 100 Wyoming 105
Dave Johnston 2 100 Wyoming 105
Dave Johnston 3 100 Wyoming 220
Dave Johnston 4 100 Wyoming 330
Hayden 1 24 Colorado 45
Hayden 2 13 Colorado 33
Hunter 1 94 Uta 419
Hunter 2 60 Uta 269
Hunter 3 100 Utah 460
Huntigton 1 100 Utah 463
Huntington 2 100 Utah 450
Jim Bridger 1 67 Wyoming 357
Jim Bridger 2 67 Wyoming 351
85
PACIFiCORP-2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Jim Bridger 3 67 Wyomig 353
Jim Bridger 4 67 Wyomig 353
Naughton 1 100 Wyoming 160
Naughton 2 100 Wyomig 210
Naughton 3 100 Wyomig 330
Wyoda 80 Wyomig 271
TOTAL-Coal 6,173
Table 5.4 - Natural Gas Plants
Chehalis 100 Washington 509Curant Creek 100 Uta 506Gadsby 1 100 Uta 57Gadsby 2 100 Uta 69Gadsby 3 100 Utah 100Gadsby 4 100 Uta 41Gadsby 5 100 Utah 39Gadsby 6 100 Utah 39Hermston 1 . 50 Oregon 233Hermston 2 . 50 Oregon 233Lake Side 100 Uta 545Little Mountain 100 Utah 12
Jarnes River Cogen (CHP) 100 Washington 14
TOTAL - Gas and Combined Heat & Power 2,397
* Remainder of Hermston plant is purchased under contract by the Company for a plant total of932 MW.
Renewables
PacifiCorp's renewable resources, presented by resource tye, are described below.
Wind
PacifiCorp acquires wind power from owned plants and various purchase agreements. Since the
2008 IRP Update, PacifiCorp has acquired several large wind resources including McFadden
Ridge I at 28.5 MW and Dunlap I at 111 MW. These projects came on line in 2009 and 2010,
respectively. The Company also entered into 20-year power purchase agreements for the total
output of several projects that include Top of the World at 200.2 MW, and four other projects
due online in 2011 and 2012 that include Power County Wind Park North and South for a total of
43.6 MW, and Pioneer Wind I and II at a total of99 MW.
86
PACIFiCORP-20ll IRP CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Table 5.5 shows existing wind facilities owned by PacifiCorp, while Table 5.6 shows existing
wind power purchase agreements.
Table 5.5 - PacifCorp-owned Wind Resources
Foote Creek 1* 33Leanin Juni er 101Goodnoe Hils East Wind 94Maren 0 140Glenrock Wind I 99Glenrock Wind II 39Maren 0 II 70Rollin Hils Wind 99Seven Mile Hil Wind 99
Seven Mile Hil Wind II 20Hi h Plains 99
McFadden Rid e 1 ** 29Dunla 1 ** ILL
TOTAL - Owned Wind 1,032
*Net total capacity for Foote Creek I is 41 MW.
**New since the 2008 IR Update.
6
37
23
6
11
2
4
5
12
o
9
2
6
124
Table 5.6 - Wind Power Purchase Agreements and Exchanges
2005
2006
2007
2007
2008
2008
2008
2008
2008
2008
2009
2009
2010
WY
OR
WA
WA
WY
WY
WA
WY
WY
WY
WY
WY
WY
Foote Creek II
Foote Creek II
Foote Creek IV
Combine Hills
Stateline Wind
Wolverine Creek
Rock River I
Mountain Wind Power I
Mountain Wind Power II
S anish Fork
Three Buttes Wind Power Duke
Thee Mile Can on Wind
Ore on Wind Farm I
Ore on Wind Far II
Cas erWind
To of the World *
Pioneer Wind I **
Pioneer Wind II **
Power Coun Wind Park North **
Power Coun Wind Park South **
TOTAL - Purchased Wind
*New since the 2008 IR Update.
**New plants under constrction with newly signed power purchase agreements.
2
25
17
41
210
65
50
60
80
19
99
10
45
20
17
200
50
50
22
22
1,101
o
3
2
1
6
11
7
26
31
6
o
o
13
1
1
5
9
9
8
7
167
2005
2005
2005
2003
2002
2005
2006
2008
2008
2008
2009
2009
2009
2010
2010
2010
2011
2012
2011
2011
WY
WY
WY
OR
OR/WAil
WY
WY
WY
UT
WY
OR
OR
OR
WY
WY
WY
WYilil
87
PACIFiCORP-20ll IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
PacifiCorp also has wind integration, storage and retu agreements with Bonnevile Power
Administration (BPA), Eugene Water and Electrc Board, Public Service Company of Colorado,
and Seattle City Light.
Geothermal
PacifiCorp owns and operates the Blundell Geothermal Plant in Utah, which uses natually
created steam to generate electrcity. The plant has a net generation capacity of 34 MW.
Blundell is a fully renewable, zero-discharge facility. The bottoming cycle, which increased the
output by 11 MW, was completed at the end of 2007. The Oregon Institute of Technology added
a new small qualifying facility (QF) using geothermal technologies to produce renewable power
for the campus and is rated at 0.28 MW.
Biomass / Biogas
Since the 2008 IRP Update, PacifiCorp has added less than 1 MW of resources. These tyes of
resources are primarily QF.
Renewables Net Metering
As of year-end 2010, PacifiCorp had 2,419 net metering customers throughout its six-state
territory, generating more than 10,000 kWusing solar, hydro, wind, and fuel cell technologies.
About 92 percent of customer generators are solar-based, followed by wind-based generation at 7
percent of total generation.
Net metering has grown by more than 50 percent from last year. The Company averaged 68 new
net metered customers a month in 2010, compared to 39 new customers per month in 2009.
Hydroelectric Generation
PacifiCorp owns 1,236 MW of hydroelectric generation capacity and purchases the output from
346 MW of other hydroelectrc resources. These resources account for approximately 10.percent
of PacifiCorp's total generating capability, in addition to providing operational benefits such as
flexible generation, spining reserves and voltage control. PacifiCorp-owned hydroelectrc plants
are located in California, Idao, Montana, Oregon, Washington, Wyoming, and Utah.
The amount of electricity PacifiCorp is able to generate or purchase from hydroelectrc plants is
dependent upon a number of factors, including the water content of snow pack accumulations in
the mountains upstream of its hydroelectrc facilities and the amount of precipitation that falls in
its watershed. When these conditions result in above average ruoff, PacifiCorp is able to
generate a higher than average amount of electrcity using its hydroelectrc plants. However,
when these factors are unfavorable, PacifiCorp must rely to a greater degree on its more
expensive thermal plants and the purchase of electricity to meet the demands of its customers.
Hydroelectrc purchases are categorized into three groups as shown in Table 5.7, which reports
2011 capacity included in the load and resource balance.
88
PACIFiCORP-20ll IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Table 5.7 - Hydroelectric Contracts
Table 5.8 provides an operational profie for each of PacifiCorp's owned hydroelectrc
generation facilities. The dates listed refer to a calendar year.
Table 5.8 - PacifiCorp Owned Hydroelectric Generation Facilties - Load and Resource
Balance Capacities
Bi Fork
Clearwater 1
Clearwater 2
Co co 1 and 2
Fish Creek
Iron Gate
JC Bo Ie
Lemolo 1
Lemolo 2
Merwin
Ro e
Small West H dro
Soda S rin s
Swift 1
Swift 2
Toketee and Slide
East-Side / West-Side
Yale
3
12
21
55
12
19
82
31
30
26
34
3
12
255
64
60
3
150
1 Includes Bend, Condit, Fall Creek, and Wallowa Falls
2/ Cowlitz County PUD owns Swift No.2, and is operated in coordination with the other projects by PacifiCorp.
3/ Includes Ashton, Paris, Pioneer, Weber, Stairs, Granite, Snake Creek, Olmstead, Fountain Green, Veyo, Sand
Cove, Viva Naughton, and Gunlock.
Hydroelectric Relicensing Impacts on Generation
Table 5.9 lists the estimated impacts to average annual hydro generation from FERC license
renewals. PacifiCorp assumed that all hydroelectric facilities curently involved in the
89
PACIFiCORP-2011 IR CHATER 5 - RESOURCE NEEDS ASSESSMENT
relicensing process wil receive new operating licenses, but that additional operatig restrctions
imposed in new licenses, such as higher bypass flow requirements, will reduce generation
available from these facilities.
Table 5.9 - Estimated Impact of FERC License Renewals on Hydroelectric Generation
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
167,112
201,228
201,228
201,228
201,228
201,228
201,228
201,228
201,228
918,048
918,048
918,048
918,048
918,048
918,048
918,048
918,048
918,048
918,048
918,048
Demand-side Management
DSM resources/products vary in their dispatchabilty, reliability of results, term of load reduction
benefit and persistence over time. Each has its value and place in effectively managing utility
investments, resource costs and system operations. Those that have greater persistence and
firmess can be reasonably relied upon as a base resource for planning puroses; those that do
not are more suited as system reliability resource options. Reliability tools are used to avoid
outages or high resource costs as a result of weather conditions, plant outages, market prices, and
unanticipated system failures. DSM resources/products can be divided into four general classes
based on their relative characteristics, the classes are:
. Class 1 DSM: Resources from fully dispatchable or scheduled firm capacity product
offerings/programs - Class 1 DSM programs are those for which capacity savings occur as
a result of active Company control or advanced scheduling. Once customers agree to
participate in Class 1 DSM program, the timing and persistence of the load reduction is
involuntary on their part within the agreed limits and parameters of the program. In most
cases, loads are shifted rather than avoided. Examples include residential and commercial
central air conditioner load control programs ("Cool Keeper") that are dispatchable innature
90
PACIFiCORP-201l IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
and irgation load management and interrptible or curtilment programs (which may be
dispatchable or scheduled firm, depending on the particular program).
. Class 2 DSM: Resources from non-dispatch able, firm energy and capacity product
offerings/programs - Class 2 DSM programs are those for which sustainable energy and
related capacity savings are achieved through facilitation of technological advancements in
equipment, appliances, lighting and structues. Class 2 DSM programs generally provide
financial and/or service incentives to customers to replace equipment and appliances in
existing customer owned facilities (or to upgrade in new construction) to more effcient
lighting, motors, air conditioners, insulation levels, windows, etc. The savings endure over
the life of the improvement (are considered firm). Program examples include air conditioning
effciency programs ("Cool Cash"), comprehensive commercial and industral new and
retrofit energy effciency programs ("Energy FinAnswer" and "FinAswer Express"),
refrgerator recycling programs ("See ya later, refrgeratoríI") and comprehensive home
improvement retrofit programs ("Home Energy Saving").
. Class 3 DSM: Resources from price responsive energy and capacity product
offerings/programs - Class 3 DSM programs seek to achieve short-duration (hour by hour)
energy and capacity savings from actions taken by customers voluntarly, based on a
fmancial incentive or signaL. Savings are measured at a customer-by-customer level (via
metering and/or metering data analysis against baselines), and customers are compensated or
charged in accordance with a program's pricing parameters. As a result of their volunta
natue, savings are less predictable, making them less suitable to incorporate into resource
planing exercises, at least until such time that their size and customer behavior profie
provide suffcient information for a reliable diversity result for modeling and planning
puroses. Savings tyically only endure for the duration of the incentive offerig and loads
tend to be shifted rather than avoided. Program examples include large customer energy bid
programs ("Energy Exchange"), time-of-use pricing plans, critical peak pricing plans, and
inverted tariff designs.
. Class 4 DSM: Resources from energy effciency education and non-incentive based
voluntary curtailment programs/communications/pleas - Class 4 DSM programs
resources may be in the form of energy and/or capacity reductions. The reductions are
tyically achieved from voluntary actions taken by customers, behavior changes, to save
energy and/or reduce costs, benefit the environment or in response to public or Company
pleas to conserve or shift their usage to off peak hours. Program savings are diffcult to
measure and in many cases tend to var over time. While not specifically relied upon in
resource planning, Class 4 DSM savings appear in historical load data therefore into resource
planning through the plan load forecasts. The value of Class 4 DSM is long-term in natue.
Class 4 DSM programs help foster an understanding and appreciation as to why utilities seek
customer paricipation in Classes 1, 2 and 3 DSM programs, as well provide a foundational
understading of how to use energy wisely. Program examples include Utah's PowerForward
program, Company brochures with energy savings tips, customer newsletters focusing on
energy efficiency, case studies of customer energy efficiency projects, and public education
and awareness programs such as "Let's turn the answers on" and "wattsmart" campaigns.
Studies have shown potential savings from behavior changes, especially when coupled with
91
P ACIFICORP - 2011 IRP CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
complimenta DSM programs to assist customers with a portion of the actions taken.33
Although these behavior savings are often diffcult and costly to trck and measure, enough
studies have measured their effects to expect at least a degree of savings (equal to or greater
than those expected to be acquired though DSM programs; e.g. i plus percent) to be realized
and reflected in customer usage and futue load forecasts.
PacifiCorp has been operating successful DSM progrs since the late 1970s. While the
Company's DSM focus has remained strong over this tie, since the 2001 western energy crisis,
the Company's DSM pursuits have been expanded in terms of investment level, state presence,
breadth of DSM resources purued (Classes 1 though 4) and resource planning considerations.
Company investments continue to increase year on year with 2010 investments exceeding $112
milion (all states). Work continues on the expansion of program portfolios in all states. In 2010
Wyoming's results more than doubled those of 2009, the first year programs were widely
available across all customer sectors. In Oregon the Company continues to work closely with the
ETO on helping to identify additional resource opportities, improve delivery and
communication coordination, and ensure adequate fuding and Company support in pursuit of
DSM resource targets. The Company is also actively pursuing Class 1 DSM load management
opportities in response to the growing need for capacity resources in the west.
The following represents a brief sumary of the existig resources by class.
Class 1 Demand-side Management
Curently there are four Class 1 DSM programs ruing across PacifiCorp's six state service
area; Utah's "Cool Keeper" residential and small commercial air conditioner load control
program; Idaho's and Utah's scheduled finn irrgation load management programs; and Idaho's
and Utah's dispatchable irigation load management programs. In 2010 these programs
accounted for over 519 MW of participating Class 1 DSM program resources under management
helping the Company better manage peak load requirement periods.
Class 2 Demand-side Management
The Company curently manages ten distinct Class 2 DSM products, many of the products are
offered in multiple states. In all, the combination of Class 2 DSM programs across the five states
where the Company is directly responsible for delivery totals thirt. The cumulative historical
energy and capacity savings (1992-2010) associated with Class 2 DSM program activity has
accounted for nearly 4.4 millon MW and approximately 800 MW of capacity reductions.
Class 3 Demand-side Management
The Company has numerous Class 3 DSM programs curently available. They include metered
time-of-day and time-of-use pricing plans (in all states, availabilty vares by customer class),
residential seasonal inverted rates (Uta and Wyomig), residential year-around inverted rates
(California, Oregon, and Washington) and Energy Exchange programs (Oregon, Utah, Idaho,
Wyoming and Washington). Savings associated with these programs are captued within the
Company's load forecast, with the exception of the more immediate call-to-action programs like
33 John Green and Lisa A. Skuatz, "Evaluatig the Impacts of Education/Outreach Programs: Lessons on Impacts,
Methods and Optimal Education, "paper presented at the American Council for an Energy Effcient Economy
sumer Study on Energy Effciency in Buildings (2000).
92
PACIFiCORP-201l IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Energy Exchange and Utah's PowerForwardprograms. The impacts of these programs are thus
captued in the integrated resource planning framework. Energy Exchange and Utah's
PowerForward are examples of Class 3 DSM programs relied upon as reliabilty resources as
opposed to base resources. System-wide paricipation in metered time-of-day and time-of-use
programs as of December 31, 2010 was approximately 19,700 customers. All of the Company's
residential customer base on default non-time of use rates are curently subject to inverted rate
plans either seasonally or year-around.
PacifiCorp continues to evaluate Class 3 DSM programs for applicabilty to long-term resource
planning. As discussed in Chapter 6, five Class 3 DSM programs were provided as resource
options in preliminary IRP modeling scenarios.
Class 4 Demand-side Management
Educating customers regardig energy efficiency and load management opportities is an
important component of the Company's long-term resource acquisition plan. A variety of
channels are used to educate customers including television, radio, newspapers, bil inserts, bil
messages, newsletters, school education programs, and personal contact. Specific firm load
reductions due to Class 4 DSM activity wil show up in Class 2 DSM program results and non-
program/documented reductions in the load forecast over time.
Table 5.10 summarizes the existing DSM programs. Note that since Class 2 DSM is determined
as an outcome of resource portfolio modeling, and is included in the preferred portfolio, existing
Class 2 DSM is reported as having zero MW.
Table 5.10 - Existing DSM Summary, 2011-2020
93
P ACIFICORP- 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Inverted rate pricing
MWa/ unavailable
1.47 million residential
customers
No. Historical behavior is captued
in load forecast.
PowerForward 0-80 MW sumer peak
No. Program is leveraged as
economic and reliability resource
dependent on market prices/system
loads.
No. Program is captued in load
forecast over time and other
Classes 1 and 2 DSM program
results.
4
Energy Education MWa/ unavailable
Power Purchase Contracts
PacifiCorp obtains the remainder of its energy requirements, including any changes from
expectations, through long-term firm contracts, short-term firm contracts, and spot market
purchases.
Figue 5.1 presents the contract capacity in place for 2011 through 2020 as of November 2010.
As shown, major capacity reductions in purchases and hydro contracts occur. (For planing
puroses, PacifiCorp assumes that curent qualifying facility and interrptible load contracts are
extended through the end of the IRP study period.) Note that renewable wind contracts are
shown at their capacity contrbution levels.
94
P ACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Figure 5.1 - Contract Capacity in the 2011 Load and Resource Balance
2,400 _____,rl.........
2,200
2,000
1,800
1,600
1,400
'"=1,200=i
~=i~1,000~~
800
600
400
200
o
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
I~ Purchase Interptible ~ Qualifying Facilities Renewable II Hydroelectric
Listed below are the major contract expirations expirg between the summer 2011 and sumer
2012:
. BPA Peakg- 575 MW
. Morgan Stanley - 100 MW
. Morgan Stanley - 100 MW
. Colocku Capacity Exchange - 108MW
. Rocky Reach - 65 MW
. Grant Displacement - 63 MW
Figue 5.2 shows the year-to-year changes in contract capacity. Early year fluctutions are due to
changes in short-term balancing contracts of one year or less, and expiration of the contracts
cited above.
.
95
PACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Figure 5.2 - Changes in Power Contract Capacity in the Load and Resource Balance
100.0
0.0
(100,0)
(200.0)
(300.0)
il
(400.0)os~oslO..~(500.0)
(6tXW)
(i00.0)
(800.0)
2012
Purchase
..
2013 2014 2015 2016 2017 2018 2019 2020
~ Interrptible Qualifying Facilties II Renewable i~ Hydroelectric
Capacity and Energy Balance Overview
The purose of the load and resource balance is to compare the annual obligations for the first
ten years of the study period with the anual capability ofPacifiCorp's existing resources, absent
new resource additions. This is done with respect to two views of the system, the capacity
balance and energy balance.
The capacity balance compares generating capability to expected peak load at time of system
peak load hours. It is a key par of the load and resource balance because it provides guidance as
to the timing and severity of futue resource deficits. It was developed by first determining the
system coincident peak load hour for each of the first ten years (2011-2020) of the planning
horizon. The peak load and the finn sales were added together for each of the annual system
peak hours to compute the anual peak-hour obligation. Then the anual fir-capacity
availability of the existing resources was determined for each of these annual system peak hours.
The annual resource deficit (surlus) was then computed by multiplying the obligation by the
planning reserve margin (PRM), and then subtracting the result from the existing resources.
96
P ACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
The energy balance shows the average monthly on-peak and off-peak surplus (deficit) of energy
over the first ten years of the plannng horizon (2011-2020). The average obligation (load plus
sales) was computed and subtracted from the average existing resource availability for each
month and time-of-day period. This was done for each side of the PacifiCorp system as well as at
the system leveL. The energy balance complements the capacity balance in that it also indicates
when resource deficits occur, but it also provides insight into what tye of resource wil best fill
the need. The usefulness of the energy balance is limited as it does not address the cost of the
available energy. The economics of adding resources to the system to meet both capacity and
energy needs are addressed with the portfolio studies described in Chapter 8.
Load and Resource Balance Components
The capacity and energy balances make use of the same load and resource components in their
calculation. The main component categories consist of the following: existing resources,
obligation, reserves, position, and reserve margin. This section provides a description of these
various components.
Existing Resources
A description of each of the resource categories follows:
. ThermaL. This category includes all thermal plants that are wholly-owned or partially-owned
by PacifiCorp. The capacity balance counts them at maximum dependable capability at tie
of system peak. The energy balance also counts them at maximum dependable capability, but
de-rates them for forced outages and maintenance. This includes the existing fleet of 11 coal-
fired plants, six natual gas-fired plants, and one cogeneration unit. These thermal resources
account for roughly two-thirds of the firm capacity available in the PacifiCorp system.
. Hydro. This category includes all hydroelectrc generation resources operated in the
PacifiCorp system as well as a number of contracts providing capacity and energy from
various counterparties. The capacity balance counts these resources by the maximum
capabilty that is sustainable for one hour at the time of system peak, an approach consistent
with curent WECC capacity reporting practices. The energy associated with critical level
stream flow is estimated and shaped by the hydroelectrc dispatch from the Vista Decision
Support System modeL. The energy impacts of hydro relicensing requirements, such as higher
bypass flows that reduce generation, are also accounted for. Over 90 percent of the
hydroelectric capacity is situated on the west side of the PacifiCorp system.
The Public Service Commission of Utah, in its 2008 IRP acknowledgment order, directed the
Company to continue investigating the hydro capacity accounting methodology curently
under consideration for regional resource adequacy reporting puroses in the Pacific
Northwest. This accounting methodology extends the one-hour sustained peaking period to
an 18-hour sustained peaking period: the six highest load hours over three consecutive days
of highest demand. Appendix K provides PacifiCorp's assessment of the applicabilty and
impact of moving to the 18-hour standard.
97
P ACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
· Dispatchable Load Control (Class 1 DSM). In 2011, there are projected to be
approximately 324 MW of Class 1 DSM programs included as existing resources. These are
projected to increase to 329 MW by 2012. Both the capacity balance and the energy balance
count DSM programs by program capacity available for system dispatch. Dispatchable load
control resources directly curil load and thus planing reserves are not held for them.
34
. Renewable. This category contains one geothermal project, 21 existing wind projects and
two planned wind projects. The capacity balance counts the geothermal plant by the
maximum dependable capability while the energy balance counts the maximum dependable
capability after forced outages. Project-specific capacity credits for the wind resources were
statistically determined using a peak load caring capability (PLCC) methodology.35 Wind
energy is counted according to hourly generation data used to model the projects.
· Purchase. This includes all of the major contracts for purchases of firm capacity and energy
in the PacifiCorp system. The capacity balance counts these by the maximum contract
availability at time of system peak. The energy balance counts the optimum model dispatch.
Purchases are considered firm and thus planning reserves are not held for them.
· Qualifying Facilties (QF). All QF that provide capacity and energy are included in this
category. Like other power purchases, the capacity balance counts them at maximum system
peak availabilty and the energy balance counts them by optimum model dispatch. It is
assumed that all QF agreements wil stay in place for the entire duration of the 20-year
planning period. It should be noted that thee of the QF resources (Kennecott, Tesoro, and
US Magnesium) are considered non-fu and thus do not contrbute to capacity planning.
· Interruptible. There are thee east-side load curilment contracts in this category. These
agreements with Monsanto, MagCorp and Nucor provide 281 MW of load interrption
capabilty at time of system peak. Both the capacity balance and energy balance count these
resources at the level of full load interrption on the executed hours. Interrptible resources
directly curail load and thus planing reserves are not held for them.
Obligation
The obligation is the total electrcity demand that PacifiCorp must serve, consisting of forecasted
retail load and firm contracted sales of energy and capacity. The following are descriptions of
each of these components:
· Load. The largest component of the obligation is the retail load. The capacity balance counts
the peak load (MW at the hour of system coincident peak load. The system coincident peak
hour is determined by suming the loads for all locations (topology bubbles with loads).
Loads reported by East and West control areas thus reflect loads at the time of PacifiCorp's
34 Energy effciency measures-Class 2 DSM programs-are treated as futue resources that reduce forecasted loads
(see Appendix A). Consequently, they are not included as existing resources in the capacity load and resource
balance.35 See, Dragoon, K., Dvortsov, V, "Z-method for power system resource adequacy applications" IEEE Transactions
on Power Systems (Volume 21, Issue 2, May 2006), pp. 982 - 988.
98
PACIFiCORP-201l IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
coincident system peak. The energy balance counts the load as an average of monthly as well
as annual time-of-day energy (MWa).
. Sales. This includes all contracts for the sale of firm capacity and energy. The capacity
balance counts these contracts by the maximum obligation at time of system peak and the
energy balance counts them by optimum model dispatch. All sales contracts are firm and thus
planning reserves are held for them in the capacity view.
Reserves
The reserves are the total megawatts of planing and non-owned reserves that must be held for
this load and resource balance. A description of the two tyes of reserves follows:
. Planning reserves. This is the total reserves that must be held to provide the planning
reserve margin (PRM). The planning reserve margin accounts for WECC operating
reserves36, load forecast errors, and other long-term resource adequacy planng
uncertinties. The following equation expresses the planning reserve requirement.
Planning reserves = (Obligation - Firm Purchases - Class 1 DSM - Interruptible) x PRM
. Non..owned reserves. There are a number of counterpartes that operate in the PacifiCorp
control areas that purchase operating reserves. This amounts to an annual reserve obligation
of about 7 MW and 70 MW on the west and east-sides, respectively. As the balancing
authority, PacifiCorp is required to hold reserves for these counterparties but is not required
to serve any associated loads.
Position
The position is the resource surlus (deficit) after subtractmg obligation plus requied reserves
from the resource total. While similar, the position calculation is slightly different for the
capacity and energy views of the load and resource balance. Thus, the position calculation for
each of the views wil be presented in their respective sections.
Reserve Margin
The reserve margin is the difference between system capability and anticipated peak demand,
measured either in rnegawatts or as a percentage of the peak load. A positive reserve margin
indicates that system capabilities exceed system obligations. Conversely, a negative reserve
margin indicates that system capabilities do not meet obligations. If system capabilties equal
obligations, then the reserve margin is zero. It should be pointed out that the position can be
negative when the corresponding reserve margin is non-negative. This is because the reserve
margin is measured relative only to obligation, while the position is measured relative to
obligation plus reserves. PacifiCorp adopted a 13 percent target planning reserve margin for the
2011 IRP. Note that a resource can only serve load in another topology location if there is
adequate transfer capacity. PacifiCorp captures transfer capacities as part of its capacity
expansion planning procèss. The supporting loss of load probability study is included as
Appendix J.
36 As par of the WECC, PacifiCorp is curently required to maintain at least 5 percent and 7 percent operating
reserve margins on hydro and thermal load-serving resources, respectively.
99
P ACIFICORP - 201 I IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Capacity Balance Determination
Methodology
The capacity balance is developed by first determining the system coincident peak load hour for
each of the first ten years of the planing horizon. Then the anual firm-capacity availability of
the existing resources is determined for each of these anual system peak hours and summed as
follows:
Existing Resources = Thermal + Hydro + Class 1 DSM + Renewable + Firm Purchases + QF
+ Interruptible
The peak load and firm sales are then added together for each of the annual system peak hours to
compute the annual peak-hour obligation:
Obligation = Load + Sales
The amount of reserves to be added to the obligation is then calculated. This is accomplished by
first removing the firm purchase and load curailment components of the existing resources from
the obligation. This resulting amount is then multiplied by the planning reserve margin. The non-
owned reserves are then added to this result to yield the megawatts of required reserves. The
formula for this calculation is the following:
Reserves = (Obligation - Firm Purchases - Class 1 DSM - Interrptible) x PRM + Non-owned
reserves
Finally, the annual capacity position is derived by adding the computed reserves to the
obligation, and then subtracting this amount from existing resources as shown in the following
formula:
Capacity Position = Existing Resources - Obligation - Reserves
Fir capacity transfers from PacifiCorp's west to east control areas are reported for the east
capacity balance, while capacity transfers from the east to west control areas are reported for the
west capacity balance. Capacity transfers represent the optimized control area interchange at the
time of the system coincident peak load as determined by the System Optimizer mode1.37
Load and Resource Balance Assumptions
The assumptions underlying the curent load and resource balance are generally the same as
those from the 2008 IRP update with a few exceptions. The following is a summary of these
assumption changes:
. Wind Commitment. In October 2010, the Company's commitment to acquire 1,400 MW of
renewable resources was met with recent wind projects:
37 West-to-east and east-to-west transfers should be identicaL. However, decimal precision of a trnsmission loss
parameter internal to the System Optimizer model results in a slight discrepancy (less than 2 MW) between reported
values.
100
PACIFiCORP-2011 IRP CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
o Dunlap i ~ 111 MW
o Top of the World purchase ~ 200.2 MW
Additionally, the Company acquired other renewable projects since the last IR, which
include
o McFadden Ridge 1 - 28.5 MW
o Three Buttes Wind - 99 MW
o Casper Wind - 16.5 MW
o Four Mile Canyon Wind - 10 MW
o Four Corners Wind - 10 MW
New Qualifying Facility Wind Plants under constrction
o Power County Wind Park North - 21.8 MW
o Power County Wind South - 21.8 MW
o Pioneer Wind I - 49.5 MW
o Pioneer Wind II - 49.5 MW
. Coal plant turbine upgrades. The curent load and resource balance assumes 65 MW of
coal plant tubine upgrades, which is down from the 134 MW assumed in the 2008 IRP
Update Report. The reduction is due to capital reprioritization and issues with Sub-
Synchronous Resonance (SSR) at the Jim Bridger plants.
Capacity Balance Results
Table 5.11 shows the anual capacity balances and component line items using a taget planning
reserve margi of 13 percent to calculate the planning reserve amount. Balances for the system
as well as PacifiCorp's east and west control areas are shown. (It should be emphasized that
while west and east balances are broken out separately, the PacifiCorp system is planned for and
dispatched on a system basis.) Also note that the new QF wind projects listed above are reported
under the Qualifying Facilities line item rather than the Renewables line item.
Figues 5.3 through 5.5 display the anual capacity positions (resource surlus or deficits) for the
system, west control area, and east control area, respectively. The large decrease in 2012 is
primarily due to the expiration of the BP A peaking contract in August 2011.
101
PACIFiCORP-20ll IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Table 5.11 - System Capacity Loads and Resources Without Resource Additions
Caldar Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Thmi1 6,019 6,026 6,028 6,028 6,028 6,046 6,046 6,046 6,046 6,046Hydeletr133133133133133129129129129129
Class 1 DSM 324 329 329 329 329 329 329 329 329 329Renable179179179178176176176176176176
Purhae 655 705 604 304 304 283 283 283 283 283
Quali Facils 152 187 206 206 207 206 207 207 206 206Inrrtile281281281281281281281281281281Trafè810451414456311499547299361328
East Existig Resoures 8,553 8,290 8,174 7,916 7,768 7,949 7,997 7,749 7,811 7,778
Load 7,184 7,344 7,566 7,805 8,009 8,201 8,377 8,544 8,712 8,896
Sale 758 997 1,045 745 745 745 659 659 659 659
East Obligation 7,942 8,341 8,611 8,550 8,754 8,946 9,036 9,203 9,371 9,555
Pia reseres 869 913 962 993 1,019 1,047 1,059 1,080 1,102 1,126
Non-ownd reserves 70 70 70 70 70 70 70 70 70 70
East Reserves 939 984 1,032 1,063 1,090 1,117 1,129 1,151 1,173 1,196
East Obliation + Reserves 8,881 9,324 9,643 9,613 9,844 10,063 10,165 10,354 10,544 10,752
East Position (3281 (1.0341 (1.469)(1,698)(2,076)(2,114)(2,168)(2,605)(2,7321 (2.9741
East Reserve Margin 9%1%(4%)(7%1 (11%)(11%)(11%)(15%)(16%)
Thmi1 2,552 2,552 2,556 2,556 2,556 2,556 2,541 2,550 2,550 2,550
Hydrelectr 1,103 958 958 957 958 959 958 958 902 745
Class 1 DSM
Reneable 77 71 71 71 71 71 71 71 71 71
Purhae 856 247 331 226 221 225 255 269 285 242
Qua Facils 136 136 136 136 136 136 136 136 136 136Trafè(809)(452)(416)(457)(311)(499)(547)(300)(360)(330)
West Existi Resoures 3,915 3,512 3,636 3,489 3,631 3,447 3,415 3,684 3,584 3,414
Load 3,266 3,374 3,395 3,448 3,491 3,541 3,584 3,650 3,666 3,713
Sale 290 258 258 258 158 108 108 108 108 108
West Obligation 3,556 3,632 3,653 3,706 3,649 3,649 3,692 3,758 3,774 3,821
PIa reservs 351 440 432 452 446 445 447 454 454 465
. Non-ownd reserves 7 7 7 7 7 7 7 7 7 7
West Reserves 357 447 438 459 452 452 453 460 460 472
West Obliation + Reserves 3,913 4,079 4,092 4,165 4,101 4,100 4,145 4,218 4,234 4,293
West Position 2 (567)(456)(676)(470)(653)(7301 (5341 (650)(879)
West Reserve Marg 13%(3%)1%(5%)0%(5%)(7~~)(1%)(4%)(10%)
Total Resoures 12,468 11,802 11,810 11,404 11,399 11,397 11,412 11,433 11,395 11,192
System Obliation 11,497 11,973 12,264 12,256 12,403 12,595 12,728 12,961 13,145 13,376
Reserves 1,297 1,430 1,470 1,522 1,542 1,569 1,582 1,611 1,633 1,668
Obliation + 13% Plani Reserves 12,794 13,403 13,735 13,778 13,945 14,164 14,310 14,572 14,777 15,044
System Position (326)(l,601)(1,925)(2,3731 (2.546)(2.767)(2,898)(3,139)(3,383)(3,852)
Reserve Marg 10%(0%)(3%)(6%)(8%)(9%)(10%)(11%)(13%)(16%)
102
PACIFiCORP-20ll IR CHAPTER5 - RESOURCE NEEDS ASSESSMENT
Figure 5.3 - System Capacity Position Trend
12,000
10,000
~
~8,000Ol"::
6,000
4,000
2,000
16,000
14,000
r piannin; Res \ _,.~"'''P''/P_H/,w,_p
"""""___""_,"~_""'U"M___.-~~"~-',"_"',"~,"M'U"-~"'''',"''_u,,~
2011 2016 2018 2019 202020122015201720132014
Figure 5.4 - West Capacity Position Trend
14,000
12,000
10,000
i
~8,000Ol"::
6,000
4,000
2,000
16,000
2011 2017 2018 2019 202020122013201420152016
103
P ACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Figure 5.5 - East Capacity Position Trend
16,000
14,000
12,000
10,000
'"
i 8,000Cl'"::
6,000
4,000
2,000
r-PI.mlng Rt'''""_m,,_~
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Energy Balance Determination
Methodology
The energy balance shows the average monthly on-peak and off-peak surlus (deficit) of energy.
The on-peak hours are weekdays and Satudays from hour-endig 7:00 am to 10:00 pm; off-peak
hours are all other hours. Peaking resources such as the Gadsby units are counted only for the on-
peak hours. This is calculated using the formulas that follow. Please refer to the section on load
and resource balance components for details on how energy for each component is counted.
Existing Resources = Thermal + Hydro + Class 1 DSM + Renewable + Firm Purchases + QF
+ Interruptible
The average obligation is computed using the followig formula:
Obligation = Load + Sales
The energy position by month and daily time block is then computed as follows:
Energy Position = Existing Resources - Obligation - Reserve Requirements (13 percent PRM)
104
PACIFiCORP-201l IRP CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Energy Balance Results
Figues 5.6 through 5.8 show the energy balances for the system, west control area, and east
control area, respectively. They indicate the energy balance on a monthly and annual average
basis across heavy load hours and light load hours.38 The monthly cross-over point, where the
system starts to become energy deficient during the summer is 2011.
Figure 5.6 - System Average Monthly and Annual Energy Positions
3,000
1,000
\. .-t-U "II "U '.I. S., ~
I I
.
"
Ii
"
2,500
2,000
1,500
i!; 500
..Cl
~.. 0Cl........-0 (500)
(1,000)
(1,500) ..., "Syste- Light Load Hours (LLH)
I
I .. Annua Balance-Light Load Hour (LLH)
(2,000) t - - -Syste- Heavy Lo Hours (HLH)
I ..AnnuaBalanceHeavy Load Hour
(HLH)
(2,500)
7~ ~~~~ ~~ ~ ~ ~ ~ ~~ ~~ ~ ~ ~ ~ ~~ ~ ~ ~~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~~ ~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Q ~ ~ ~ ~ ~ 4 ~ ~ ~ ~ ~ ~. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~ ~ ~a ~
38 Heavy load hours constitute the daily time block of 16 hours, Hour-Ending 7 am - 10 pm, for Monday through
Satuday, excluding NERC-observed holidays.
105
PACIFiCORP-20ll IR CHATER 5 - RESOURCE NEEDS ASSESSMENT
Figure 5.7 - West Average Monthly and Annual Energy Positions
3,00
2,500
2,000
~
~=I~..
~
~
o
~ -- "'PACEatOff-Pea
.. AnuaBaleeLight Load Hour (LLH)
- _. PAC Eat On.Pea
.. Anua Balce-Heavy Load Hour (HLH)
I '
I ~i l
I~
L
1,500
1,000
500
(500)
(1,000)
(1.500)
(2,000)~~ ~~~~~~~~ ~ ~ ~~ ~~~~ ~ ~ ~~ c c~~~~~~~~~~ ~~ Q~QQ¡ Z 4 Z ¡ i 4 Z ¡ i ~ z ¡ ~ ~ z ¡ z ~ z ¡ i ~ z¡ z ~? ¡ ~ ~ z ¡ z ~ z ~ ~ ~~~ ~aa~ ~aa~ ~aa~ ~aaa ~aaa ~aaa ~aaa ~aaa ~a a a ~a a
Figure 5.8 - East Average Monthly and Annual Energy Positions
3,000
2,500
2,000
1,500
1,000
~500=~=..
~~..
~
~
(500)
(1.000)
(1,500)
_.. *PACWest- Light Lo Hour(LL)
.. Annua BaleeLight Load Hours (LLH)
- - . PAC West- Heavy Load Hour (HLH)
-AnnuaBaleeHea Load Hour (HLH)
(2.000) ,~~~~~~~~~~ ~ ~ ~~~ ~~~ ~ ~ ~~~ ~ ~~ t t ~~~~ ~ ~ ~ ~ ~~~ar: ,, ~ ~ ~ f! :: .. q ~ :: t i: f!:: .. i: ~ :t. t Q ,, :: .. & f! ., .. Q ,: :: t i: ~ ': .. Q ~ ': ..a ~~ a a ~~ a ~ ~~ 0 ~ ~~ a a ~~ 0 a ~~ a a ~~ a a ~~ 0 ~ ~~ a a ~~ a
106
PACIFICORP - 2011 IR CHAPTER 5 - RESOURCE NEEDS ASSESSMENT
Load and Resource Balance Conclusions
Without additional resources the Company projects a summer peak system resource deficit of
326 MW begining in 2011. The near-term deficit wil be filled by additional DSM programs,
renewables, and market purchases. The Company wil consider other options durg this time
frame if they are cost-effective and provide other system benefits. Then, begining 2014, base
load and/or intermediate load resource additions wil be necessar to cover the widening capacity
deficit.
107
PACIFiCORP-20ll IRP CHAPTER 6 - RESOURCE OPTIONS
CHAPTER 6 - RESOURCE OPTIONS
109
P ACIFICORP - 201 1 IR CHAPR 6 - RESOURCE OPTIONS
This chapter provides background information on the various resources considered in the IRP for
meeting futue capacity and energy needs. Organized by major category, these resources consist
of supply-side generation (utility-scaled and distrbuted resources), DSM programs, transmission
expansion projects, and market purchases. For each resource category, the chapter discusses the
criteria for resource selection, presents the options and associated attbutes, and describes the
technologies. In addition, for supply-side resources, the chapter describes how PacifiCorp
addressed long-term cost trends and uncertinty in deriving cost figues.
Resource Selection Criteria
The list of supply-side resource options has been modified in relation to previous IRP resource
lists to reflect the realities evidenced through permitting, public meeting comments, and studies
undertaken to better understand the details of available generation resources. Capital costs, in
general have decreased due to the slow-down of the economy in 2009 and 20 i O. Based on
information, from outside sources, including proprieta data from Cambridge Energy Research
Associates (CERA) and Gas Turbine World, as well as internal studies, the prices of single and
combined-cycle gas tubine plants have declined in recent years but, are recovering slowly.
Alternative energy resources continue to receive a greater emphasis. Specifically additional solar
generation options and geothermal options have been included in the analysis compared to the
previous IRP. Additional solar resources include utility-size photovoltaic systems (PV) as well as
solar thermal with and without thermal storage. Energy storage systems continue to be of interest
with options included for advanced large batteries (1 MW as well as traditional pumped hydro
and compressed air energy storage.
Derivation of Resource Attributes
The supply-side resource options were developed from a combination of resources. The process
began with the list of major generatig resources from the 2007 IRP. This resource list was
reviewed and modified to reflect public input and permtting realities. Once the basic list of
resources was determined, the cost and performance attbutes for each resource were estimated.
A number of information sources were used to identify parameters needed to model these
resources. Supporting utility-scale resources were a number of engineering studies conducted by
PacifiCorp to understand the cost of coal and gas resources in recent years. Additionally,
experience with the constrction of the 2x 1 combined cycle plants at Curant Creek and Lake
Side as well as other recent simple-cycle projects at Gadsby provided PacifiCorp with a detailed
understanding of the cost of new power generatig facilities. Preparation of benchmark
submittals for PacifiCorp's recent generation RFPs were also used to update actual project
experience, while governent studies were relied upon for characterizing futue carbon captue
costs.
Extensive new studies on the cost of the coal-fired options were not prepared in keeping with the
reduced emphasis on these resources for new near-term generation.
110
PACIFiCORP-201l IRP CHAPTER 6 - RESOURCE OPTIONS
The results of these estimating efforts were compared with other cost databases, such as the one
supporting the Integrated Planning Model (IPM(I) market model developed by ICF International,
which the Company now uses for national emissions policy impact analysis among other uses.
The IPM(I cost estimates were used when cost agreement was close.
The Company made use of The WorleyParsons Group's renewable generation study completed
in 2008 for solar, biomass and geothermal resources. As described below, a geothermal resource
study was conducted for the Company by Black & Veatch/Geothermx in 2010 to supplement
geothermal information for the third expansion at Blundell and other potential resources.
Wind costs are based on actual project experience in both the Pacific Northwest and Wyoming,
as well as current projections. Nuclear costs are reflective of recent cost estimates associated
with preliminary development activities as well as published estimates of new projects.
Hydrokinetic, or wave power, has been added based on proposed projects in the Pacific
Northwest. Other generation options, such as energy storage and fuel cells, were adopted from
PacifiCorp's previous IRP. In some cases costs from the previous IRP were updated using cost
increases for other studied resources.
Resource options also include a variety of small-scale generation resources, consisting of
combined heat and power (CHP) and onsite solar supply-side resource options. Together these
small resources are referred to as distrbuted generation. The Cadmus Group, Inc. (previously
named Quantec LLC) provided the distrbuted generation costs and attbutes as par of the DSM
potential study update conducted for PacifiCorp in 2010. The DSM potential report identified the
economic potential for distributed generation resources by state.
Handling of Technology Improvement Trends and Cost Uncertainties
The capital cost uncertinty for many of the proposed generation options is high. Various factors
contrbute to this uncertainty. Previously experienced shortages of skiled labor are not a problem
in the curent business climate but volatile commodity prices are stil a large part of the
uncertainty in being able to predict project costs for lump-sum contracting. For example, Figue
6.1 shows the trend in North American carbon steel sheet prices. The volatility trend is expected
tö continue, although prices have trended upward in the last year.
111
PACIFICORP - 201 1 IR CHAPTER 6 - RESOURCE OPTIONS
Figure 6.1- World Carbon Steel Price Trends
World Carbon Steel Transaction Pricing
(steelonthenetcom)
..Hot Rolled Steel Plate ..Medium Steel Sections ..Steel Wire Rod ~Hot Rolled Steel Coil
$O.4S
$0.30
$0.40
$O.3S
..::..II::
$0.2S
$0.20
'"'"'"'"'"'"'"'"'"'"'"'"0 0 0 0 0 0 0 0 099~9 î 9 9 'l 9 0 ~9 ....¿";....";....
"..Ì5 "~c..,u i:..Ì5 ,;i:~On Q.
!!QJ '"'"-='"QJ u 0 QJ !!QJ '"'"-='"QJ..:2 co :2 co II 0 Z C ..:2 co :2 co Vl
Some technologies that have seen a decrease in demand, such as wind tubines and coal, have
seen significant cost decreases since the 2008 IRP. As such, subsequent to completion of its
2008 IRP portfolio analysis in late 2008 and early 2009, the Company has witnessed price
declines for wind tubines and certin other power plant equipment. Other technologies stil in
demand, such as gas tubines, have seen more stable prices. Thus, long-term resource pricing
remains challenging to forecast.
Technologies, such as the integrated gasification combined cycle (lGCC) and certin renewables,
like solar, have greater price and operational uncertinty because only a few units have been built
and operated. As these technologies matue and more plants are built and operated the costs of
such new technologies may decrease relative to more matue options such as pulverized coal and
conventional natual gas-fired plants.
The supply-side resource options tables below do not consider the potential for such savings
since the benefits are not expected to be realized until the next generation of new plants are built
and operated for a period of time. Any such benefits for IGCC facilities are not expected to be
available until after 2025 with commercial operation in 2030. As such, future IRPs wil be better
able to incorporate the potential benefits of futue cost reductions. Given the curent emphasis on
renewable generation, the Company anticipates the cost benefits for these technologies to be
available sooner. The estimated capital costs are displayed in the supply-side resource tables
along with expected availability of each technology for commercial utilzation.
112
PACIFiCORP-201l IRP CHAPTER 6 - RESOURCE OPTIONS
Resource Options and Attributes
Tables 6.2 and 6.3 present cost and performance attbutes for supply-side resource options
designated for PacifiCorp's east and west control areas, respectively. Tables 6.4 though 6.7
present the total resource cost attbutes for supply-side resource options, and are based on
estimates of the first-year reallevelized cost per megawatt-hour of resources, stated in June 2010
dollars. The resource costs are presented for the modeled C02 tax levels in recognition of the
uncertinty in characterizing these emission costs.
As mentioned previously, the attibutes were mainly derived from PacifiCorp's recent cost
studies and project experience. Cost and performance values reflect analysis concluded by June
2010. Additional explanatory notes for the tables are as follows:
. Capital costs are intended to be all-inclusive, and account for Allowance for Funds Used
Durg Constrction (AFUDC), land, EPC (Engineering, Procurement, and Constrction)
cost premiums, owner's costs, etc. Capital costs in Tables 6.3 and 6.4 reflect mid-2010
dollars, and do not include escalation from mid year to the year of commercial operation.
. Wind sites are modeled with location-specific peak load carring capabilty levels and
capacity factors.
. Certain resource names are listed as acronyms. These include:
PC - pulverized coal
IGCC - integrated gasification combined cycle
SCCT - simple cycle combustion tubine
CCCT - combined cycle combustion tubine
CHP - combined heat and power (cogeneration)
CCS - carbon captue and sequestration
. PacifiCorp's September 2010 forward price cures were used to calculate the 1evelized
fuel costs reported in Tables 6.4 through 6.7.
. Utility-scale solar resources include federal production tax credits. Hybrid solar with
natual gas backup is also treated this way.
. PacifiCorp assumes that wind, hydrokinetic, biomass, and geothermal resources are
qualified for Production Tax Credits (PTC), depending on the installation date. The cost
of these credits is included in the supply-side table.
. Gas backup for solar with a heat rate of 11,750 BtuWh is less efficient than for astandalone SCCT. .
. Capital costs include transmission interconnection costs (switchyard and other upgrades
needed to interconnect the resource to PacifiCorp's transmission network).
. For the nuclear resource, capital costs include the cost of storing spent fuel on-site durng
the life of the facility. Costs for ultimate off-site disposal of spent fuel is not included
since there are no details regarding where, when or how that wil be done. While the
reported capital cost does not reflect the cost of transmission, PacifiCorp adjusted the
modeled capital cost to include transmission assuming a plant location near Payette,
Idaho. The transmission cost adder is $ 842/kW, and factors in transmission lines and
termination points for connections to the Hemingway and Limber substations.
113
P ACIFICORP - 2011 IR CHAPTER 6 - RESOURCE OPTIONS
. The capacity degradation of retrofitting an existing 500 MW pulverized coal unit with a
carbon captue and sequestration (CCS) system represents the net change to capacity. The
heat rate is the total net heat rate after retrofitting an existing 10,000 BtuWh unit with a
CCS system.
. The wind resources are representative generic resources included in the IRP models for
planning puroses. Cost and performance attbutes of specific resources are identified as
part of the acquisition process. An estimate for wid integration costs, $9. 701MWh, has
been added in Tables 6.3 through 6.6.
. State specific ta benefits are excluded from the IR supply side table but would be
considered in the evaluation of a specific project.
c'
114
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PACIFICORP - 20 11 IRP CHAPTER 6 - RESOURCE OPTIONS
Distributed Generation
Tables 6.7 and 6.8 present the total resource cost attibutes for these resource options, and are
based on estimates of the first-year real levelized cost per megawatt-hour of resources, stated in
June 2010 dollars. The resource costs are presented for both the $0 and $19 CO2 tax levels in
recognition of the uncertainty in characterizing emission costs. Additional explanatory notes for
the tables are as follows:
. A 14-percent administrative cost (for fixed operation and maintenance) is included in the
overall cost of the resources. This cost level is in line with the administration costs of the
Utah State Energy Program's Renewable Energy Rebate Program, which was 14 percent of
total program costs39 as well as PacifiCorp's program administrative cost experience.
. Federal tax benefits are included for the following resources based on a percent of capital
cost.
o Reciprocating Engine 10 percento Microtubine 10 percent
o Fuel Cell 30 percento Gas Turbine 10 percent
o Industrial Biomass 10 percent
o Anaerobic Digesters 10 percent
. The resource cost for Industrial Biomass is based on The Cadmus Group data. The fuel is
assumed to be provided by the project owner at no cost, a conservative assumption. In reality,
the cost to the Company would be each state's filed avoided cost rate; and
. Installation costs for on-site ("micro") solar generation technologies are treated on a total
resource cost basis; that is, customer installation costs are included. However, capital costs
are adjusted downward to reflect federal benefits of 30 percent of installed system costs. The
state tax incentives are not included as the Total Resource Cost test sees the incentive as a
benefit to customers who install the systems, but is a cost to the state's tax payers, making
the net effect zero.
39 See the Uta Geological Surey's comments on Rocky Mountain Power's solar incentive program, Docket No.
07-035-T14. The comments can be downloaded at:
http://Vv'Ww.psc.state. ut. us! utilities! electric/OJ docs!0703 5T 14/66677Comments%20from%20State%20ofO/o20Utah%
20DNR.pdf
121
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4
PACIFiCORP-2011 IRP CHAPTER 6 - RESOURCE OPTIONS
Supercritical technology was chosen over subcritical technology for pulverized coal for a number
of reasons. Increasing coal costs are makig the added efficiency of the supercritical technology
cost-effective for long-term operation. Additionally, there is a greater competitive marketplace
for large supercritical boilers than for large sub critical boilers. Increasingly, large boiler
manufactuers only offer supercritical boilers in the 500-plus MW sizes. Due to the increased
effciency of supercritical boilers, overall emission quantities are smaller than for a similarly
sized subcritical unit. Compared to sub critical boilers, supercritical boilers can follow loads
better, ramp to full load faster, use less water, and require less steel for constrction. The smaller
steel requirements have also leveled the constrction cost estimates for the two coal
technologies. The costs for a supercritical PC facility reflect the cost of adding a new unit at an
existing site. PacifiCorp does not expect a significant difference in cost for a multiple unit at a
new site versus the cost of a single unit addition at an existing site.
CO2 captue and sequestration technology represents a potential cost for new and existing coal
plants if futue regulations require it. Research projects are underway to develop more cost-
effective methods of captung carbon dioxide from the flue gas of conventional boilers. The
costs included in the supply side resource tables utilize amine based solvent systems for carbon
captue. Sequestration would store the CO2 underground for long-term storage and monitoring.
PacifiCorp and MidAerican Energy Holdings Company are monitorig C02 captue
technologies for possible retrofit opportities at its existing coal-fired fleet, as well as
applicability for future coal plants that could serve as cost-effective alternatives to IGCC plants if
CO2 removal becomes necessar in the future. An option to captue CO2 at an existing coal-fired
unit has been included in the supply side resource tables. Curently there are only a couple of
large-scale sequestration projects in operation around the world and a number of these are in
conjunction with enhanced oil recovery. CCS is not considered a viable option before 2025 due
to risk issues associated with technological matuty and underground sequestration li~bi1ty.
An alternative to supercritical pulverized-coal technology for coal-based generation would be the
use of IGCC technology. A significant advantage for IGeC when compared to conventional
pulverized coal with amine-based carbon capture is the reduced cost of captuing C02 from the
process. Gasification plants have been built and demonstrated around the world, primarily as a
means of producing chemicals from coaL. Only a limited number of IGCC plants have been
125
PACIFiCORP-2011 IR CHAPTER 6 - RESOURCE OPTIONS
constrcted specifically for power generation. In the U.S., these facilities have been
demonstration projects and cost significantly more than conventional coal plants in both capital
and operating costs. These projects have been constrcted with significant fuding from the
federal governent. A number of IGCC technology suppliers have teamed up with large
constrctor to form consortia who are now offerig to build IGCC plants. A few years ago, these
consortia were willng to provide IGCC plants on a lump-sum, tu-key basis. However, in
today's market, the wilingness of these consortia to design and constrct IGCC plants on lump-
sum tuey basis is in question. The costs presented in the supply-side resource options tables
reflect recent studies of IGCC costs associated with efforts to parer PacifiCorp with the
Wyoming Infrastrctue Authority (WI) to investigate the acquisition of federal grant money to
demonstrate western IGCC projects.
PacifiCorp was selected by the WI to participate in joint project development activities for an
IGCC facility in Wyoming. The ultimate goal was to develop a Section 413 project under the
2005 Energy Policy Act. PacifiCorp commissioned and managed feasibility studies with one or
more technology suppliers/consortia for an IGCC facility at its Jim Bridger plant with some level
of carbon captue. Based on the results of initial feasibility studies, PacifiCorp declined to submit
a proposal to the federal agencies involved in the Section 413 solicitation.
PacifiCorp is a member of the Gasification User's Association. In addition, PacifiCorp
communicates regularly with the primar gasification technology suppliers, constrctors, and
other utilities. The results of all these contats were used to help develop the coal-based
generation projects in the supply side resource tables. Over the last two years PacifiCorp has help
a series of public meetings as a par of an IGCC Working Group to help provide a broader level
of understanding for this technology.
Coal Plant Effciency Improvements
Fuel effciency gains for existing coal plants (which are manifested in lower plant heat rates) are
realized by (1) emphasizing continuous improvement in operations, and (2) upgrading
components if economically justified. Such fuel efficiency improvements can result in a smaller
emission footprit for a given level of plant capacity, or the same footprit when plant capacity
is increased.
The efficiency of generating units degrades gradually as components wear out over time. Durng
operation, controllable process parameters are adjusted to optimize unit output and efficiency.
Typical overhaul work that contrbutes to improved effciency includes (1) stearn tubine
overhauls, (2) cleaning and repairing condensers, feed water heaters, and cooling towers and (3)
cleaning boiler heat transfer surfaces. .
When economically justified, effciency improvements are obtained through major component
upgrades. Examples include tubine upgrades using new blade and sealing technology, improved
seals and heat exchange elements for boiler air heaters, cooling tower fill upgrades, and the
addition of cooling tower cells. Such upgrade opportities are analyzed on a case-by-case basis,
and are tied to a unit's major overhaul cycle. PacifiCorp is taking advantage of improved
upgrade technology through its "dense pack" coal plant tubine upgrade initiative where justified.
126
PACIFiCORP-2011 IR CHAPTER 6 - RESOURCE OPTIONS
Natural Gas
Natual gas generation options are numerous and a limited number of representative technologies
are included in the supply-side resource options table. SCCT and CCCT are included. As with
other generation technologies, the cost of natual gas generation has increased substantially from
previous IRPs. Costs for gas generation have not decreased since the 2008 IRP, depending on
the option, due not only to general utility cost issues mentioned earlier, but also due to the
decrease in coal-based projects thereby putting an increased demand on natual gas options that
can be more easily permitted.
Combustion turbine options include both simple cycle and combined cycle configuations. The
simple cycle options include traditional frame machines as well as aero-derivative combustion
tubines. Two aero-derivative machine options were chosen. The General Electrc LM6000
machines are flexible, high effciency machines and can be installed with high temperatue SCR
systems, which allow them to be located in areas with air emissions concerns. These tyes of gas
tubines are identical to those installed at Gadsby. LM6000 gas tubines have quick-start
capability (less than ten minutes to full load) and higher heating value heat rates near i 0,000
BtuWh. Also selected for the supply-side resource options table is General Electric's new
LMS-IOO gas tubine. This machine was recently installed for the first time in a commercial
ventue. It is a cross between a simple-cycle aero-derivative gas tubine and a frame machine
with significant amount of compressor intercooling to improve efficiency. The machines have
higher heating value heat rates of less than 9,500 BtuWh and similar starting capabilities as the
LM6000 with significant load following capability (up to 50 MW per minute).
Frame simple cycle machines are represented by the "F" class technology. These machines are
about 150MW at western elevations, and can deliver good simple cycle effciencies.
Other natual gas-fired generation options include internal combustion engines and fuel cells.
Internal combustion engines are represented by a large power plant consisting of 14 machines at
10.9 MW. These machines are spark-ignited and have the advantages of a relatively attactive
heat rate, a low emissions profile, and a high level of availabilty and reliabilty due to the
number of machines. At present, fuel cells hold less promise due to high capital cost, partly
attbutable to the lack of production capability and continued development. Fuel cells are not
ready for large scale deployment and are not considered available as a supply-side option until
after 2013.
Combined cycle power plants options have been limited to lxl and 2xl applications of "F" class
combustion tubines and a "G" lxl facility. The "F" class machine options would allow an
expansion of the Lake Side facility. Both the lxl and 2xl configuations are included to give
some flexibility to the portfolio planning. Similarly, the "G" machine has been added to take
advantage of the improved heat rate available from these more advanced gas tubines. The "G"
machine is only presented as a lxl option to keep the size of the facility reasonable for selection
as a portfolio option. These natual gas technologies are considered matue and installation lead
times and capital costs are well known.
127
PACIFiCORP-20ll IRP CHATER 6 - RESOURCE OPTIONS
Wind
Resource Supply, Location, and Incremental Transmission Costs
PacifiCorp revised its approach for locating wind resources to more closely align with Western
Renewable Energy Zones (WZ), facilitate assignent of incremental transmission costs for
the Energy Gateway transmission scenaro analysis, and allow the System Optimizer model to
more easily select wid resources outside of transmission-constrained areas in Wyoming.
Resources are now grouped into a number of wid-generation-only bubbles as well as certain
conventional topology bubbles. Wind generation bubbles are intended to enable assignment of
incremental transmission costs. Table 6.9 shows the relationship between the topology bubbles
and cOITesponding WREZ.
Table 6.9 - Representation of Wind in the Model Topology
Wyoming Lined to Aeolus
Utah Wind Generation Onl Linked to Utah South
Oregon/ ashington Wind Generation Only Lined to BP A
Brad, Idao
Walla Walla, W A
Yakia, WA
Conventional N/A
Conventional N/ A
Conventional N/ A
Incremental transmission costs are expressed as dollars-per-kW values that are applied to costs
of wind resources added in wind-generation-only bubbles.4o The only exception is for the
Oregonlashigton bubble. PacifiCorp's transmission investment analysis indicated that
supporting incremental wind additions of over 500 MW in the PacifiCorp west control area
would require on the order of $1.5 bilion in new transmission facilities (several new 500/230 kV
segments would be needed). Since the model cannot automatically apply the transmission cost
based on a given megawatt threshold, the incremental transmission cost was removed from this
bubble for the base Energy Gateway scenaro (which excludes the Wyoming transmission
segment) and added as a manual fixed cost adjustment to the portfolio's reported cost if the west
side wind additions exceed the 500 MW threshold. It is important to note that the west-side
transmission cost adjustment is only applicable to the Energy Gateway scenario analysis, and
not core case portfolio development, which is based on the full Energy Gateway footprint. Only
if a core case portfolio included at least 500 MW of west-side wind would PacifCorp apply an
out-of-model transmission cost adjustment. None of the core case portfolios reached this wind
capacity threshold.
40 Incremental transmission costs also could have been added directly to the wind capital costs. However, assigning
a cost to a wind generation bubble avoids the need to individually adjust costs for many wind resources.
128
P ACIFICORP - 2011 IRP CHAPTER 6 - RESOURCE OPTIONS
In the case of east-side wind resources, the only resource location-dependent transmission cost
was $71/kW assigned to Wyoming resources based on an estimated incremental expansion of at
least 1,500 MW.
As noted above, the model can also locate wind resources in conventional bubbles. No
incremental transmission costs are associated with conventional bubbles, other than wheeling
charges where applicable. Transmission interconnection costs-direct and network upgrade costs
for connecting a wind facility to PacifiCorp's transmission system (230 kV step-up)-are
included in the wind capital costs. It should be noted that primary drvers of wind resource
selection are the requirements of renewable portfolio standards and the availability of production
tax credits.
Capital Costs
PacifiCorp stared with a base set of wind capital costs. The source of these costs is the.database
of the IPM~, a proprietary modeling system licensed to PacifiCorp by ICF InternationaL. These
wind capital costs are divided into levels that differentiate costs by site development conditions.
PacifiCorp then applied adjustments to the base capital costs to account for federal tax credits,
wind integration costs, fixed O&M costs, and wheeling costs as appropriate. (The cost
adjustments .are converted into discounted values and added to the base capital cost.) These
adjusted capital cost values are used only in the System Optimizer modeL. Table 6.10 shows cost
values, WRZ resource potentials, and resource unit limits.
To specify the number of discrete wind resources for a topology bubble, PacifiCorp divided the
WREZ resource limit (or depth) by the number of cost levels, rounding to the nearest multiple of
100, and then divided by a 100 MW unit size. (Table 6.10) This formula does not apply to the
200 MW of Washington South and Oregon Northeast wind resources that are available without
incremental transmission in the Yakima and Walla Walla bubbles. All wind resources are
specified in 100 MW blocks, but the model can choose a fractional amount of a block.
Wind Resource Capacity Factors and Energy Shapes
All resource options in a topology bubble are assigned a single capacity factor. Wyoming
resource options are assigned a capacity factor value of 35 percent, while wind resources in other
states are assigned a value of 29 percent. Capacity factor is a separate modeled parameter from
the capital cost, and is used to scale wind energy shapes used by both the System Optimizer and
Planing and Risk (PaR) models. The hourly generation shape reflects average hourly wind
variability. The hourly generation shape is repeated for each year of the simulation.
Wind Integration Costs
To captue the costs of integrating wind into the system, PacifiCorp applied a value of
$9.701M (in 2010 dollars) for portfolio modeling. The source of this value was the
Company's 2010 wind integration study, which is included as Appendix H. Integration costs
were incorporated into wind capital costs based on a 25-year project life expectancy and
generation performance.
Annual Wind Selection Limits
To reflect realistic system resource addition limits tied to such factors as transmission
availability, operational integration, rate impact, resource market availabilty, and procurement
129
P ACIFICORP - 2011 IR CHAPTER 6 - RESOURCE OPTIONS
constraints, System Optimizer was constrained to select wid up to certin anual limits. The
limit is 200 MW per year with the exception of the hard C02 emission cap cases, where the
annual limit was specified as 500 MW. These limits apply on a system basis. Note that the effect
of the annual limits is to spread wind additions across multiple years rather than cap the
cumulative total wind added to a portfolio.
Table 6.10 - Wind Resource Characteristics by Topology Bubble
Utah South wid-only bubble
BPAwid-only bubble
Oregon Norast
(Wall Wall)2016 29"10
Oregon West 2016 29"10
Wyoming wid resourees in Aeolus wid-only bubble
Idaho (Goshen) wid resoures in Brady bubble
OregonIasbigton wid resourees that do not reqni new inreinnta trmision *
Washion Sout
(Yaki
Oregon Norast
(Wall Wall
* This section includes only the 200 MW of Oregon and Washington wind resources that do not require
incremental trsmission. Wind resources in these areas that require additional trnsmission are modeled
with the pareters shown in the "EPA wind only bubble" section above.
2013 29"10 nla
130
PACIFiCORP-2011 IR CHAPTER 6 - RESOURCE OPTIONS
Other Renewable Resources
Other renewable generation resources included in the supply-side resource options table include
geothermal, biomass, landfill gas, waste heat and solar. The fmancial attrbutes of these
renewable options are based on EPRI's TAG!I database and have been adjusted based on
PacifiCorp's recent constrction and study experience.41
Geothermal
In response to the 2008 IRP Update, comments from the Utah stakeholders requested a
geothermal resources study to review the geothermal resources in PacifiCorp's service terrtory.
A geothermal resources study was commissioned by PacifiCorp in 2010 and pedormed by Black
& Veatch in conjunction with Geothermx. The study established criteria for the commercial
viability for a geothermal resource as a resource with at least 25 percent of the geothermal
resource capacity drlled and operated in the past. While over 80 potential projects were
identified within 100 miles of an interconnection to the PacifiCorp grd only eight resources met
the commercial criteria. Figue 6.2 and Table 6.11, which come from the report, identify the
eight resources and compares their capacity and cost attbutes, including the levelized cost of
energy (LCOE).42 All resources, except Roosevelt hot springs (Blundell) because of moderate
fluid temperatures, would use binary technology and are inerently more costly and less effcient
than the flash design suitable for the higher temperatue brie at Blundell. For the supply side
table, two tyes of geothermal resources are defmed. East side geothermal refers to the Roosevelt
Hot Sprigs resource (Blundell) and utilizes a cost estimate equivalent to the study conclusion
and the current expectation for the cost of a third unit at the Blundell plant. Other geothennal
resources are designated Greenfield geothermal and utilize a cost equal to the average of the
binary geothermal costs from the geothermal study. These additional geothermal resources are
considered western resources for modeling puroses.
PacifiCorp has committed to conduct additional geothermal studies in 2011 to fuher define and
quantify the geothermal opportities uncovered in the 2010 geothermal study. The 2011 study
wil also look and the other identified geothermal options and determine which, if any, merits
additional development work. The 2011 study wil identify new geothermal opportities
sufficient to allow a request for approval of development fuds for recovery from the various
state commissions.
41 Technical Assessment Guide, Electrc Power Research Institute, Palo Alto, CA.
42 The levelized cost of energy is the constant dollar cost of the energy generated over the life of the project, and
includes operation and maintenance costs, investment costs, and taes/tax benefits.
131
PACIFiCORP-20ll IR CHAPTER 6 - RESOURCE OPTIONS
Figure 6.2 - Commercially Viable Geothermal Resources Near PacifCorp's Service
Territory
orp Serlçe Terry
, Pote erml Prjets'(MW
. 8-10,.,
.. 10 -100
. 100-500
.. 500+
Major Subsons (:0=345 kV)
, Transmission line-OCUne
,~~,- 50kV
345kV
..............230-287kV
100161 kV
Under 100kV
Commercially Viable Geothrmal
Resources in and Near PacifCorp's
Service Territory
This ma sh th 8 co depotil geo pro id byfO in anSÎ ín tl st,
Laic;i;itý)
(~urprisevalley)Ciys
Roose~
Arizona
1."",,,..,,,,,,,,,,,,,,,,,,,,,,,,,,
,~~~ ii...I20 100
;,,~;;_"'''uuu m",,,mu/'.~
, Mn BLACK & VETCH'JI. ¡¡Jó.wiiùØ_wM'
u......,.."'..uu..u,:;,..~,,_
132
PACIFiCORP-20ll IRP CHAPTER 6 - RESOURCE OPTIONS
Table 6.11 - 2010.Geothermal Study Results
Table 1-1. Sites Selected for In-Depth Review.
Additional Additional Additional AnticipatedCapacity LCOE LCOE
Field Name State Capacity Capacity Available to Plant Type (Low,(High,Available Available PacifiCorp for Additonal
$/MWh)b,C $/MWh)b,C(GrossMW)(Net MW)(Net MW)8
Capacity
Lake City CA 30 24 24 Binary $83 $90
Medicine Lake CA 480 384 384 Binary $91 $98
Raft Ri\Ar 10 90 72 43 Binary $93 $100
Neal Hot OR 30 24 0 Binary $80 $87Springs
CO\A Fort UT 100 80 60 to 63 Binary $68 $75
Crystal-UT 30 24 0 Binary $93 $100Madsen
Roose\Alt Hot UT 90 81d 81d Flash/Binary $46 $51SpringsHybrid
Thermo Hot UT 118 94 0 Binary $91 $98Springs
Totals 968 783 592 to 595
Source: BVG analysis for PacifiCorp.
Note:
8 Calculated by subtracting the amount of resource under contract to or in contract negotiations
with other parties frm the estimated net capacity available.
b Net basis
C These screening le\A1 cost estimates are based on available public information. More detailed
estimates based on proprietary information and calculated on a consistent basis might yield
diffrent comparisons.
d While 81 MW net are estimated to be available, the resource should be de\Aloped in smaller
increments to \Arify resource sustainabilty
Biomass
The biomass project option would involve the combustion of whole trees grown in a plantation
setting, presumably in the Pacific Northwest.
Solar
Three solar resources were defined. A concentrating PV system represents a utility scale PV
resource. Optimistic performance and cost figues were used equivalent to the best reported PV
efficiencies. Solar thermal projects are represented by both a solar concentrating design trough
system with natual gas backup and a solar concentrating design thermal tower aITangement with
six hours of thermal storage. The system parameters for these systems were suggested by the
WorleyParsons Group study and reflect curent proposed projects in the desert southwest. Efforts
are being undertaken in 2011 to verify this data. A two-megawatt solar project wil be built in
Oregon as a par of the Oregon solar initiative. Development of PV resources in Uta wil be
studied with Sandia National Laboratories.
133
PACIFiCORP-20ll IR CHAPTER 6 - RESOURCE OPTIONS
Combined Heat and Power and Other Distributed Generation Alternatives
Combined heat and power (CHP) plants are small (ten megawatts or less) gas compressor heat
recovery systems using a binary cycle. PacifiCorp evaluated both larger systems that would be
contracted at the customer site (labeled as utility cogeneration in Tables 6.1, 6.3, and 6.5) and
smaller distrbuted generation systems.
A large CHP (40 to 120 megawatts) combustion tubine with signficant steam based heat
recovery from the flue gas has not been included in PacifiCorp's supply-side table for the eastern
service terrtory due to a lack of large potential industral applications. These CHP opportities
are site-specific, and the generic options presented in the supply-side resource options table are
not intended to represent any paricular project or opportity.
Small distrbuted generation resources are unique in that they reside at the customer load. The
generation can either be used to reduce the customer load, such as net metering, or sold to the
utìlty. Small CHP resources generate electrcity and utilize waste heat for space and water
heating requirements. Fuel is either natual gas or renewable biogas. On-site solar resources, also
refeITed to as "micro solar", include electrc generation and energy-effciency measures that use
solar energy. The DG resources are up to 4.8 MW in size.
Table 6.12 shows modeling attbutes for the distrbuted generation resources reflected in The
Cadmus Group's 2010 potentials study. Rather than using the year-by-year resource potentials
for 2011-2030 from The Cadmus Group, PacifiCorp calculated the average annual values based
on the 2030 cumulative resource totals.43 PacifiCorp also applied a three-megawatt threshold for
the average annual capacity values to designate resources to include in the IRP models.
Table 6.12 - Distributed Generation Resource Attributes
Rec' oca' En' e 56.94 20MicTnrbine 54.02 15Fuel CeD 35.04 10Gas Tnrin 56,94 20
Indutrl Bioss 3.20 0.36 0.63 1.22 3.78 1.48 31.54 15Anaerobic D' sters 52.97 20PV 1.7 0.08 0.09 0.05 1.0 0.11 23.83 30
Sola Water Heaters 0.52 0.32 0.97 0.27 2.37 OA7 11.8 20Solar Allic Fans 0.35 0.00 10 14%
11 Technologies wi no capacities lite indicate that the average annual capacity for 2011-2030 is less than the 3 MW threshold for inclusion in the IR imdels.
Introduction of many new distrbuted generation technologies designed to fill the needs of niche
markets has helped spur reductions in capital and operatig costs.
More details on the distrbuted generation resources can be found in the Cadmus potentials study
report available for download on PacifiCorp's demand-side management Web page,
htt://Vv'ww.pacìficorp.coml es! dsm.html.
43 Many of the anual capacity potentials are a small frction of a megawatt. This resource set-up approach enabled
one resource with multiple units to be defined for each technology as opposed to an individual resource having to be
defined for each year. The number of resource options is one of the key factors that establish rnodel run-time.
134
PACIFiCORP-20ll IRP CHAPTER 6 - RESOURCE OPTIONS
As in past IRPs, a number of energy storage technologies are included, such as compressed
energy storage (CAES), pumped hydroelectrc, and advanced batteries. There are a number of
potential CAES sites-specifically solution-mined sites associated with gas storage in southwest
Wyoming-that could be developed in areas of existing gas trnsmission. CAES may be an
attactive alternative for high elevation sites since the gas compression could compensate for the
higher elevation. Thermal energy storage is also included as a load control (Class 1 DSM)
resource. Although not included in this IRP, flywheel energy storage systems show promise for
such applications as frequency regulation, and wil be investigated for the next IRP as PacifiCorp
gathers data from other utility test projects and assesses resource potential for its own system.
Nuclear
An emissions-free nuclear plant has been inCluded in the supply-side resource options table. This
option is based recent internal studies, press reports and information from a paper prepared by
the Uranium Information Centre Ltd., "The Economics of Nuclear Power,"May 2008. A 1,600
MW plant is characterized utilizing advanced nuclear plant designs with an assumed location in
Idaho. Modeled capital costs include incremental transmission costs to deliver energy into
PacifiCorp's system. Nuclear power is not considered a viable option in the PacifiCorp serviceterrtory before 2030. '
Resource Options and Attributes
Source of Demand-side Management Resource Data
DSM resource opportity estimates used in the development of the 2011 IRP were derived from
an update to the "Assessment of Long-Term, System-Wide Potèntial for Demand-Side and Other
Supplemental Resources"study completed in June 2007 (DSM potential study). The 2010 DSM
potential study, conducted by The Cadmus Group, provided a broad estimate of the size, tye,
location and cost of demand-side resources.44 The demand-side resource information was
converted into supply-cures by tye of DSM; e.g. capacity-based Classes 1 and 3 DSM and
energy-based Class 2 DSM for modeling against competing supply-side alternatives.
Demand-side Management Supply Curves
Resource supply cures are a compilation of point estimates showing the relationship between
the cumulative quantity and costs of resources. Supply cures incorporate a linear relationship
between quantities and costs (at least up to the maximum quantity available) to help identify at
any particular cost how much of a particular resource can be acquired. Resource modeling
utilizing supply cures allows utilities to sort out and select the least-cost resources (products and
quantities) based on each resource's cost versus quantity in comparison to the supply cures of
alternative and competing resource tyes. .
44 The Cadmus DSM potentials report is available on PacifiCorp's demand-side management Web page.
http:iíV\i\,,'\v.pacificoæ.conyes!dsm.html.
135
PACIFiCORP-20ll IR CHAPTER 6 - RESOURCE OPTIONS
As with supply-side resources, the development of demand-side resource supply cures requires
specification of quantity, availability, and cost attbutes. Attbutes specific to demand-side
supply cures include:
. resource quantities available in year one-either megawatts or megawatt-hours-
recognizing that some resources may come from stock additions not yet built, and that
elective resources c~nnot all be acquired in the first year
. resource quantities available over time; for example, Class 2 DSM energy-based resource
measure lives
. seasonal availabilty and hours available (Classes 1 and 3 DSM capacity resources)
. the shape or hourly contrbution of the resource (load shape of the Class 2 DSM energy
resource); and
. levelized resource costs (dollars per megawatt per year for Classes 1 and 3 DSM capacity
resources, or dollars per megawatt-hour for Class 2 DSM energy resources).
Once developed, DSM supply cures are treated like any other discrete supply-side resource in
the IRP modeling environment. A complicating factor for modeling is that the DSM supply
curves must be configued to meet the input specifications for two models: the System Optimizer
capacity expansion optimization model, and the Planing and Risk production cost simulation
modeL.
Class 1 DSM Capacity Supply Curves
Supply cures were created for five discrete Class 1 DSM products:
1) residential air conditionig
2) residential electrc water heating
3) irgation load curailment
4) commercial/industral curtailment; and
5) commerciai/industral thermal energy storage
The potentials and costs for each product were provided at the state level resulting in five
products across six states, or thir supply cures before accountig for system load areas (some
states cover more than one load area). After accounting for load areas, a total of fift Class 1
DSM supply cures were used in the 2011 IR modeling process.
Class 1 DSM resource price differences between west and east control areas for similar resources
were driven by resource differences in each market, such as irgation pump size and hours of
operation as well as product performance differences. For instance, residential air conditioning
load control in the west is more expensive on a unitized or dollar per kilowatt-year basis due to
climatic differences that result in less contrbution or load available per installed switch.
The combination residential air conditioning and electric water heating dispatchable load control
product was not provided to the System Optimizer model as a resource option for either control
area. In the west, electrc water heatig control wasn't included as it adds little additional load
for the cost, and electrc water heating market share continues to decline each year as a result of
136
PACIFiCORP-2011 IRP CHAPTER 6 - RESOURCE OPTIONS
conversions to gas. In the east, electric water heating control wasn't included because (1) the
market potential is very small. (It is predominantly a gas water heating market), (2) an
established program already exists that doesn't include a water heater control component, and (3)
the potential identified is assumed to be located in areas where gas is not available; such as more
rual and mountainous areas where direct load control paging signals are less reliable.
The assessment of potential for distrbuted standby generation was combined with an assessment
of commercial/industral energy management system controls in the development of the resource
opportity and costs of the commerciaVindustral curailment product. The costs for this
product are constant across all jursdictions under the pay-for-performance delivery model
assumed.
Tables 6.13 and 6.14 show the sumary level Class 1 DSM program information, by control
area, used in the development of the Class 1 resources supply curves. As previously noted, the
products were fuher broken down by quantity available by state and load area in order to
provide the model with location-specific details.
Table 6.13 - Class 1 DSM Program Attributes West Control Area
50 hours,
Residential and Small Yes, with not to
Commercial Air residential time-exceed 6 Sumer 14 $116.159 2013
Conditioning of-use hours per
da
Residential Electrc Yes, with
Water Heatig residential time-50 hours Sumer 5 $88 2013
of-use
50 hours,
Irrgation Direct Load Yes, with not to
irrgation time-exceed 6 Sumer 27 $74 2013Controlof-use hours per
da
Yes, with
Thermal Energy
80 hours,Commerciallndustral Storage, demand
not to SumerCurailment (includes buyback, and exceed 6 and 40 $82 2013
distrbuted stand-by commercial hours per Wintergeneration)Class 3 time
related price day
products
Yes, with
Commerciai/industral commercial
Thermal Energy Class 3 time 480 hours Sumer $253 2013
Storage related price
roducts
137
P ACIFICORP - 2011 IR CHATER 6 - RESOURCE OPTIONS
Table 6.14 - Class 1 DSM Program Attributes East Control Area
50 hours,
Residential and Small Yes, with not to
Commercial Air residential tie-exceed 6 Sumer 89 $116 2012
Conditioning of-use hour per
da
Residential Electric Yes, with
Water Heating residential time-50 hours Sumer 5 $88 2013
of-use
50 hours,
Irrgation Direct Load Yes, with not to
irgation time-exceed 6 Sumer 28 $50-$74 2012Controlof-use hour per
day
Yes, with
Thermal Energy 80 hour,Commercial/Industral Storage, demad
not to SumerCurailment (includes buyback, and
exceed 6 and 95 $82 2012distrbuted stad-by commercial hours per Wintergeneration)Class 3 time
related price day
roducts
Yes, with
Commerciai/industral commercial
Thermal Energy Class 3 time 480 hours Sumer 6 $253 2013
Storage related price
roducts
To configue the supply cures for use in the System Optimizer model, there are a number of
data conversions and resource attbutes that are required by the System Optimizer modeL. All
programs are defined to operate within a 5x8 hourly window and are priced in $/kW -month. The
following are the primary model attbutes required by the model:
. The Capacity Planning Factor (CPF): This is the percentage of the program size (capacity)
that is expected to be available at the time of system peak. For Classes i and 3 DSM
programs, this parameter is set to i (100 percent)
. Additional reserves: This parameter indicates whether additional reserves are required for
the resource. Fir resources, such as dispatchable load control, do not require additional
reserves.
. Daily and annual energy limits: These parameters, expressed in Gigawatt-hours, are used to
implement hourly limits on the programs. They are obtained by multiplying the hours
available by the program size.
. Nameplate capacity (MW) and servce lie (years)
138
PACIFICORP - 2011 IRP CHAPTER 6 - RESOURCE OPTIONS
. Maximum Annual Units: This parameter, specified as a pointer to a vector of values,
indicates the maximum number of resource units available in the year for which the resource
is designated.
. First year and month available / last year available
. Fractional Units First Year: For resources that are specified such that the model can select
fractions of megawatts, this parameter tells the model the first year in which a fractional
quantity of the resource can be selected. Year 2011 is entered in order to make these DSM
resource options available in all years.
After the model has selected DSM resources, a program converts the resource attibutes and
quantities into a data format suitable for direct import into the Planning and Risk modeL.
Class 3 DSM Capacity Supply Curves
Supply cures were created for five discrete Class 3 DSM products, which are capacity-based
resources like Class 1 DSM products:
1) residential time-of.,use rates;
2) commercial critical peak pricing;
3) commercial and industrial demand buyback;
4) commercial and industral real-time pricing; and
5) mandatory Irrgation time-of-use45
The potentials and costs for each product were provided at the state level resultig in five
products across six states, or thir supply cures before accounting for system load areas (some
states cover more than one load area). After accounting for load areas, a total of fift Class 3
DSM supply cures were used in the 2011 IRP modeling process.
In providing the data for the constrction of Class 3 DSM supply cures, the Company did not
net out one product's resource potential against a competing product. As Class 3 DSM resource
selections are not included as base resources for planning puroses, not taking product
interactions into consideration poised no risk of over-reliance (or double counting the potential)
of these resources in the final resource plan. For instance, in the development of the supply
curves for residential time-of-use the program's market potential was not adjusted by the market
potential or quantity available of a lesser-cost alternative, residential critical peak pricing.
Market potentials and costs for each of the five Class 3 DSM programs modeled were taken from
the estimates provided in the Updated DSM potential study and evaluated independently as if it
were the only resource available targeting a particular customer segment.
Modest product price differences between west and east control areas were drven by resource
opportity differences. The DSM potential study assumed the same fied costs in each state in
4S This rate design is an alternative product to the voluntary Class 1 irgation load management product and
assumes regulators and interested partes would support mandatory paricipation with sufficiently high rates to
enable realization of peak energy reduction potential.
139
PACIFiCORP-20ll IRP CHAPTER 6 - RESOURCE OPTIONS
which it is offered regardless of quantify available. Therefore, states with lower resource
availability for a paricular product have a higher cost per kilowatt-year for that product.
Tables 6.15 and 6.16 show the sumary level Class 3 DSM program information, by control
area, used in the development of the Class 3 DSM resources supply cures. As previously noted,
the products were fuher broken down by quantity available by state and load bubble in order to
provide the model with location specific information.
Table 6.15 - Class 3 DSM Program Attributes West Control area
Residential Time-of-Yes, with Res 480/600 Sumer
Use A/C and water hours and Winter 7 $13 2013
heaterDLC
Yes, with C&I
curailment,
Commercial Critical demand buyback 40 hour Summer 17 $13 2013Peak Pricing and other Class 3
time related price
roducts
Yes, with C&I
Commercial/Industral curilment and Sumer
Demand Buyback Class 3 time 87 hours and Winter 6 $18 2011
related price
roducts
Yes, with C&I
curilment,
Commercial/Industral demand buyback 87 hours Sumer 2 $8 2013Real Time Pricing and other Class 3 and Winter
tie related price
roducts
Mandatory Irgation Yes, with 480 hours Sumer 125 $9 2013Time-of-Use ir ation DLC
Table 6.16 - Class 3 DSM Program Attributes East Control area
Residential Time-of-Yes, with Res 480/600 Sumer
Use A/C and Water hours and Winter 12 $13 2013
HeaterDLC
Yes, with C&I
curilment,
Commercial Critical demand buyback 40 hour Sumer 100 $13 2013Peak Pricing and other Class 3
time related price
roducts
Yes, with C&I
curilment and
Commercial!ndustral Class 3 time 87 hours Sumer 40 $18 2013Demand Buyback related price and Winter
products
140
PACIFiCORP-20ll IRP CHAPTER 6 - RESOURCE OPTIONS
Yes, with C&I
curilment,
Commercial/Industral demand buyback 87 hours Sumer 23 $6 2013Real Time Pricing and other Class 3 and Winter
time related price
roducts
Mandatory Irgation Yes, with 480 hour Sumer 182 $4-9 2013Time-of-Use ir ation DLC
System Optimizer data formats and parameters for Class 3 DSM programs are similar to those
defined for the Class 1 DSM programs. The data export program converts the Class 3 DSM
programs selected by the model into a data format for import into the Planning and Risk modeL.
Class 2 DSM, Capacity Supply Curves
The 2011 IRP represents the second time the Company has utilized the supply cure
methodology in the evaluation and selection of Class 2 DSM energy products. The Updated
DSM potential study provided the information to fully assess the contribution of Class 2 DSM
resources over the IRP planning horizon and adjusted resource potentials and costs taking into
consideration changes in codes and standards, emerging technologies, resource cost changes, and
state specific modeling conventions and resource evaluation considerations (Washington and
Uta). Class 2 DSM resource data was provided by state down to the individual measure and
facility levels; e.g., specific appliances, motors, air compressors for residential buildings, small
offces, etc. When compared to the 2007 DSM potential study, the number of measures in the
Updated DSM potential study increased, primarily due to utilizing the relevant measure level
data developed in support of the Northwest Power and Conservation Council's 6th Power Plan. In
all, the Updated DSM potential study provided Class 2 DSM resource information at the
following granularity level:
. State: Washington, California, Idaho, Uta, Wyomig
. Measure:
126 residential measures
133 commercial measures
- 67 industral measures
Three irrigation measures
12 street lighting measures
. Facilty type46:
Six residential facility tyes
24 commercial facility tyes
14 industrial facility tyes
One irrigation facilty tye
- One street lighting tye
46 Facility tye includes such attbutes as existing or new constrction, single or multi-family, etc. Facility types are
more fully described in the Updated DSM potential study.
141
P ACIFICORP - 2011 IR CHAPTER 6 - RESOURCE OPTIONS
The DSM potential study also provided total resource costs, which included both measure cost
and a 15 percent adder for administrative costs levelized over measure life at PacifiCorp's cost of
capital, consistent with the treatment of supply-side resource costs. Utah resource costs were
levelized using utility costs instead of total costs and an adder for admistration.
The technical potential for all Class 2 DSM resources across five states over the twenty-year
DSM potential study horizon totaled 12.3 millon MW. The technical potential represents the
total universe of possible savings before adjustments for what is likely to be realized
(achievable). When the achievable assumptions described below are considered the technical
potential is reduced to a technical achievable potential for modeling consideration of 10.1 milion
MW.
Despite the granularity of Class 2 DSM resource information available, it was impractical to use
this much information in the development of Class 2 DSM resource supply cures. The
combination of measures by facility tye and state generated over 18,000 separate.permutations
or distinct measures that could be modeled using the supply cure methodology.4 This many
supply cures is impossible to handle with PacifiCorp's IRP models. To reduce the resource
options for consideration, while not losing the overall resource quantity available, the decision
was made to consolidate like measures into bundles using levelized costs to reduce the number
of combinations to a more manageable number. The result was the creation of nine cost bundles;
thee more cost bundles than were developed for the 2008 IRP.
The bundles were developed based on the Class 2 DSM Update potential study's technical
potentials. To account for the practical limits associated with acquiring all available resources in
any given year, the technical potential by measure tye was adjusted to reflect the achievable
acquisitions over the 20 year planing horizon. Consistent with regional planning assumptions in
the Northwest, 85 percent of the technical potential for discretionar (retrofit) resources was
assumed to be achievable over the twenty year planning period. For lost-opportity (new
constrction or equipment failure) the achievable potential is 65 percent of the technical over the
twenty year planning period. This assumption is also consistent with planning assumptions in the
Pacific Nortwest. Durng the planning period, the aggregate (both discretionary and lost
opportity) achievable potential is 82 percent of the technical potentiaL.
The application of ramp rates in the curent Class 2 DSM is a change from the 2007 DSM
Potential Study in which the technical achievable potential was assumed to be equally available
in increments that were l/20th of the total. In the updated DSM Potential Study, the technical
achievable potential for each measure by state is assigned a ramp rate that reflects the relative
state of technology and state programs. New technologies and states with newer programs were
47 Not all energy effciency measures analyzed are applicable to all market segments. The two most common
reasons for this are (1) differences in existing and new constrction and (2) some end-uses do not exist in all
building tyes. For example, a measure may look at the savings associated with increasing an existing home's
insulation up to curent code levels. However, this level of insulation would already be required in new constrction,
and thus, would not be analyzed for the new constrction segment. Similarly, certin measures, such as those
affecting commercial refrigeration would not be applicable to all commercial building tyes, depending on the
building's priary business fuction; for example, offce buildigs would not tyically have commercial
refrgeration.
142
PACIFiCORP-2011 IR CHAPTER 6 - RESOURCE OPTIONS
assumed to take more time to ramp up than states and technologies with more extensive track
records. Use of ramp rate assumptions is also consistent with regional planning assumptions in
the Nortwest.
Nine cost bundles across five states (excluding Oregon), and over twenty years, equates to 900
supply cures before allocating across the Company load areas shown in Table 6.17. In addition,
there are compact florescent lamp (CFL) bundles for 2011 and 2012, which are discussed later in
this section.
Table 6.17 - Load Area Energy Distribution by State
CA 100%
OR 4%96%il 42%58%
UT 100%
WA 25%75%
WY 18%82%
After the load areas are accounted for (with some states served in more than one load area as
noted in table 6.17), the number of supply cures grew to 1,440, excluding Oregon.
Figues 6.3 through 6.9 show the changes in Class 2 DSM resource potential (adjusted for
achievable acquisitions) by state relative to the last update conducted in 2009.
143
P ACIFICORP - 2011 IR CHAPTER 6 - RESOURCE OPTIONS
Figure 6.3 - PacifiCorp Class 2 DSM Potential, Aug-2009 vs. Aug-2010 Curves
I
:!'i~
~i;
~
300.0
250.0
200.0
150.0
50.0
0.0
~.... ~~ ~~~ ~ ~ ~~ ~ ~ ~l' ~~ ~~,-'"~~~~~,s~~~ ~~~'\.. ~~ ~-C rJ~
II Aug-Q9 . Aug.10
Figure 6.4 - California Class 2 DSM Potential, Aug-2009 vs. Aug-2010 Curves
I ~.il'i ..CU" 3.0~ ~.. .."i =~ c
6.0
5.0
4,0
2.0
1.0
0.0
~.. .y iß~ ~ ~~ ~ ~~ ~ ~~ ~ ~~ ~ ~~~ ~~ ~",,,~~,s~~~ ~~~'\.. ~~ ~-C rJ~
II Aug-09 II Aug-10
144
PACIFiCORP-2011 IR CHAPTER 6 - RESOURCE OPTIONS
Figure 6.5 - Oregon Class 2 DSM Potential, Aug-2009 vs. Aug-20l0 Curves
70.0
60.0
50.0
i'40.0:; ~
¡,'Jiq¡l1 u.. =30.0- ""~
20.0
10.0
0.0 ~""~~~~~(c~~-&~",Ç)~~-&!C-S~-S ~ ~~ ~0,'"-S~ ~~ ~rS-S ~",,, ~tV ~~ ~~ ~~
mi Aug-09 . Aug-10
Figure 6.6 - Washington Class 2 DSM Potential, Aug-2009 vs. Aug-20l0 Curves
20.0
i~
:!~15.0~
~
-¡
~
10,0
30.0
25.0
5.0
0.0 ~~~~~~~~~~~~~~~~~~~*~~~~~~~~~~~~~~~~~~~~
II Aug-09 II Aug-10
145
P ACIFICORP - 2011 IR CHAPTER 6 - RESOURCE OPTIONS
Figure 6.7 - Utah Class 2 DSM Potential, Aug-2009 vs. Aug-2010 Curves
i ~
~ ~ 100.0i; c
i i
i §
"i = 80.0~ c
180.0
160.0
140.0
120.0
60.0
40.0
20.0
0.0 i-"~~~~~~-S -S -S -S -S -S -S ~ ~-S -S -S~ -S~,,'"-S~ ~ ~-S -S -S ~ ~-S -S-S..., -S'' -S~
I~ Aug-09 . Aug-10
Figure 6.8 - Idaho Class 2 DSM Potential, Aug-2009vs. Aug-2010 Curves
i ~ 8.0
~:6.~ ~
~ §
'i;æ 6.0
~
14.0
12.0
10.0
4.0
2,0
0.0 ~~~~~~~~~~~~~~~~~-S -S -S -S -S -S -S -S -S -S -S -S -S -S -S -S -S -S'''' -S~ -S''''
II Aug-09 II Aug-10
146
PACIFICORP - 2011 IR CHAPTER 6 ~ RESOURCE OPTIONS
Figure 6.9 - Wyoming Class 2 DSM Potential, Aug-2009 vs. Aug-2010 Curves
45.0
40.0 .......----...------...-..-.--..- ...........-......----. .........-....--.......------..
35.0
30.0
5.0
I
:i~
~..
o¡
;2
25.0
20.0
15.0
10.0
0.0 "...~S'~~~~~~~~~~~~.: ~~ ~~ ~",.. é" l' ~~ l' ~~ ~~ 4~ ~~ ~.,,,
!I Aug-D9 . Aug-10
Figue 6.10 shows the Class 2 DSM cost bundles, designated by $/kWh cost breakpoints (e.g.,
$O.OO/kWh to $0.07/kWh) and the associated bundle price after applying cost credits. These cost
credits include the following:
. A transmission and distribution investment deferral credit of $ 54/kW-year
. Stochastic risk reduction credit of$14.981M48
. Northwest Power Act lO-percent credit (Washington resources only)49
The bundle price can be interpreted as the average levelized cost for the group of measures in the
cost range. In specifying the bundle cost breakpoints, narrower cost ranges were defined for the
lower-cost resources to improve the cost accuracy for the bundles expected to be selected by the
System Optimizer model most frequently. In contrast, the highest-cost bundles were specified
with the widest cost breakpoints.
48 PacifiCorp developed this credit by assessing the upper-tail cost of 2008IR portolios that included large
amounts of clean resources (wind and DSM) relative to the upper-tail cost of the 2008 IRP preferred portolio.49 The formula for calculatig the $/Mh credit is: (Bundle price - ((First year MW savings x market value x 10%)
+ (First year MWh savings x T&D deferral x 1O%))/First year MW savings. The levelized forward electrcity price
for the Mid-Columbia market is used as the proxy market value.
147
P ACIFICORP - 2011 IR CHAPTER 6 - RESOURCE OPTIONS
Figure 6.10 - Class 2 DSM Cost Bundles and Bundle Prices
$1.000
$950
$900
$850
$800
$750
$700
$650
I $600
I ~ $550
I:E $500
I:; $450!
$400
$350
$300
$250
$200
$150
$100
$50
$0
CD~~
Sl ~
Idaho Utah Wyoming Oregon California Washington
East West
~ 84-99 Cost Bundle - 27-83 Cost Bundle ~ 19-26 Cost Bundle _ 16-18 Cost Bundle ~. 14-15 Cost Bundle
1M 12-13 Cost Bundle 1M 10-11 Cost Bundle ~ 08-09 Cost Bundle 1M 00-07 Cost Bundle 1M Compact Florescent
As shown in Figue 6.10 the potential associated with standard or spiral "twster" CFLs for 2011
and 2012 were provided as separate bundles for two years. Each of the bundles utilized a
$0.02/kWh levelized cost and represents the technical and achievable potentials available from
this technology prior to the impact of the pending federal lighting stadards. Energy savings
potentials from these measures are not included in any other years durig the planing horizon.
However, potential from specialty CFLs and light emitting diode ("LED") measures not directly
impacted by the pending lighting stadard change are included in lighting resource potentials in
all years.
Class 2 DSM resources in Oregon are acquired on behalf of the Company through ETO
programs. The ETO provided the Company three cost bundles, weighted and shaped by the end-
use measure potential for each year over a twenty-year horion. Allocating these resources over
two load areas in Oregon for consistency with other modeling efforts generated an additional 120
Class 2 DSM supply cures (thee cost bundles multiplied by two load areas multiplied by
twenty years).
In addition to the program attbutes described for the Classes 1 and 3 DSM resources, the Class
2 DSM supply cures also have load shapes describing the available energy savings on an hourly
basis. For System Optimizer, each supply cure is associated with an annual hourly ("8760")
148
PACIFiCORP-2011 IRP CHAPTER 6 - RESOURCE OPTIONS
load shape configued to the 2008 calendar year. These load shapès are used by the model for
. each sìmulatìon year. In contrast, the Planìng and Rìsk model requîres for each supply cure a
load shape that covers all 20 years of the sìmulatìon.
The load shape ìs composed of fractìonal values that represent each hour's demand dìvìded by
the maxìmum demand ìn any hour for that shape. For example, the hour wìth maxìmum demand
would have a value of 1.00 (100 percent), whìle an hoUr wìth half the maxìmum demand would
have a value of 0.50 (50 percent). Sumìng the fractìonal values for all of the hours, and then
multìplyìng thìs result by peak-hour demand, produces the anual energy savìngs represented by
the supply cure.
Distribution Energy Effciency
The two resource optìons, consistìng of megawatt capacity potentials (based on six feeders for
Walla Walla and 13 feeders for Yakima/Sunyside), levelized dollars/M costs, and daily load
shapes, were based on prelimìnar data provided by the consultant performìng the Washington
distribution efficiency study. The resource potential ìs small, totalìng only 0.191 MW for Walla
Walla and 0.403 MW for Yakima/Sunyside. The associated levelized resource costs were
$63/M and $64/M, respectively. The load shapes use a representatìve day pattern for
weekdays and weekends. Figue 6.11 shows a sample load shape for the week of July 20, 2008.
These load shapes are repeated for each year of the 20-year sìmulation. The resources are
assumed to be available begìnnìng ìn 2013, and the model can select a fractional amount of the
total potentiaL
Figure 6.11 - Sample Distribution Energy Effciency Load Shape
j--"----'- -
0.9
0.8
0.7
i:0.6..0..
E::0.5E'x..::
'õ 0.4i:0
:a
l!0.3"-
0.2
0.1
0
._----..-----'''-"
Distribution Energy Efficiency Load Shape, Week of July 20, 200
~---
--
..__.........-
j.....
-
I-
I
-"
~
-~-r i ,,¡,- ,¡,,--
8
~WeekEnd
..WeekDay
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour
149
PACIFICORP - 2011 IR .CHAPTER 6 - RESOURCE OPTIONS
For this IRP, PacifiCorp investigated seven Energy Gateway scenarios, consisting of various
combinations of transmission segments. Prelimiar evaluation of the seven scenarios using the
System Optimizer model resulted in the selection of four scenarios for portfolio modeling.
Detailed information on the scenaros and associated modeling approach and findings are
provided in Chapter 4.
PacifiCorp and other utilities engage in purchases and sales of electrcity on an ongoing basis to
balance the system and maximize the economic effciency of power system operations. In
addition to reflecting spot market purchase activity and existing long-term purchase contracts in
the IRP portfolio analysis, PacifiCorp modeled front offce transactions (FOT). Front office
transactions are proxy resources, assumed to be finn, that represent procurement activity made
on an anual forward basis to help the Company cover short positions.
As proxy resources, front office transactions represent a range of purchase transaction tyes.
They are usually standard products, such as heavy load hour (HLH), light load hour (LLH),
and/or daily HLH call options (the right to buy or "call" energy at a "strke" price) and tyically
rely on standard enabling agreements as a contracting vehicle. Front offce transaètion prices are
determed at the time of the transaction, usually via a third part broker and based on the view
of each respective part regarding the then-curent forward market price for power. An optimal
mix of these purchases would include a range in terms for these transactions.
Solicitations for front offce transactions can be made years, quarers or months in advance.
Anual transactions can be available up to as much as three or more years in advance. Seasonal
transactions are tyically delivered durg quarters and can be available from one to three years
or more in advance. The terms, points of delivery, and products wil all vary by individual
market point.
Two front office transaction tyes were included for portfolio analysis: an annual flat product,
and a HLH third quarter product. An anual flat product reflects energy provided to PacifiCorp
at a constant delivery rate over all the hours of a year. Third-quarer HLH transactions represent
purchases received 16 hours per day, six days per week from July through September. Because
these are firm products the counterparies back the full purchase. For example, a 100 MW front
offce purchase requires the seller to deliver 100 MW to PacifiCorp regardless of circumstance.50
Thus, to insure delivery, the seller must hold whatever level of reserves as waranted by its
system to insure firmess. For this reason, PacifiCorp does not need to hold additional reserves
on its 100 MW firm front office purchase. Table 6.18 shows the front office transaction
resources included in the IRP models, identifying the market hub, product tye, annual megawatt
capacity limit, and availability.
50 Typically, the only exception would be under force majeure. Otherwise, the seller is required to deliver the full
amount even if the seller has to acquire it at an exorbitant price.
150
PACIFiCORP-2011 IRP CHAPTER 6 - RESOURCE OPTIONS
Table 6.18 - Maximum Available Front Offce Transaction Quantity by Market Hub
400 MW + 375 MW with 10%
price premium, 2011 -2030
400 MW, 2011-2030
Mona
3 rd Quarer, Heavy Load Hour (6xI6)
Utah North
3 rd Quarer, Heavy Load Hour (6xI6)
50 MW, 2011-2030
190 MW, 2011-2012
264 MW, 2013-2014
100 MW, 2015-2016
o MW, 2017+
200 MW, 2011-2012
300 MW, 2013+
250 MW, 2011-2030
Mead
3 rd Quarer, Heavy Load Hour (6xI6)
To arrive at these maximum quantities, PacifiCorp considered the following:
. Historical operational data and institutional experience with transactions at the market
hubs.
. The Company's forward market view, including an assessment of expected physical
delivery constraints and market liquidity and depth.
. Financial and risk management consequences associated with acquiring purchases at
higher levels, such as additional credit and liquidity costs.
Prices for front office transaction purchases are associated with specific market hubs and are set
to the relevant forward market prices, time period, and location, plus appropriate wheeling
charges.
For this IRP, the Public Utility Commission of Oregon directed PacifiCorp to evaluate
intermediate-term market purchases as resource options and assess associated costs and risks.51
In formulating market purchase options for the IRP models, the Company lacked cost and
quantity information with which to discriminate such purchases from the proxy FOT resources
already modeled in this IRP. Lacking such information, the Company anticipated using bid
information from the All-Source RFP reactivated in December 2009, if applicable, to inform the
development of intermediate-term market purchase resources for modeling puroses. The
Company received no intermediate-term market purchase bids; therefore, such resources were
not modeled for this IRP.
51 Public Utility Commission of Oregon, In the Matter ofPacifiCoip. dba Pacific Power 2007 Integrated Resource
Plan, Docket No. LC 42, Order No. 08-232, April 4, 2008, p. 36.
151
PACiFIC()RP~20ll IR CHATER 6 - RESOURCE OPTIONS
152
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
CHAPTER 7 - MODELING AND PORTFOLIO
EVALUATION ApPROACH
153
P ACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
The IRP modeling approach seeks to determine the compartive cost, risk, and reliability
attbutes of resource portfolios. These portolio attbutes form the basis of an overall
quantitative portfolio performance evaluation. Ths chapter describes the modeling and risk
analysis process that supported that portfolio performance evaluation. The information drawn
from this process, sumarized in Chapter 8, was used to help determine PacifiCorp's preferred
portfolio and support the analysis of resource acquisition risks.
The 2011 IRP modeling approach consists of seven phases: (l) define input scenarios-referred
to as cases-eharacterized by alternative carbon dioxide costs, commodity gas prices, wholesale
electrcity prices, load growth trends, and other cost drvers, (2) case-specific price forecast
development, (3) optimized portfolio development for each case using PacifiCorp's System
Optimizer capacity expansion model, (4) Monte Carlo production cost simulation of each
optimized portfolio to support stochastic risk analysis, (5) selection of top-performing portfolios
using a two-phase screening process that . incorporates stochastic portfolio cost and risk
assessment measures, (6) deterministic risk analysis using System Optimizer, and (7) preliminar
preferred portfolio selection, followed by acquisition risk analysis of prefeITed portfolio
resources and determination of the final preferred portfolio. Figue 7.1 presents the seven phases
in flow chart form, showing the main process steps, data flows, and models involved for each
phase. General modeling assumptions and price mputs are covered first in this chapter, followed
by a profile of each modeling phase.
154
PACIFICORP - 20 11 IRP CHAPTER 7 - MODELING APPROACH
Phase 1: Case Derinition
Figure 7.1- Modeling and Risk Analysis Process
Phase 3: Optied Portolio
Development
I............................................................................
.:=:::::.~.:::::~::.~=:I:::=::::::=:::=:::.:
Phase 2: Price Forecast Development
,.............................................................
Phase 5: Top-performig
Portolio Selection
.:::::::::::::::::::::::::::::i:::::::::::::::::::::::::::.Phase 6: Determiisc RikAssessment
r::::~::::::i
~:::::::.'.'.':::::.'.'.'.'.':::.'.':.'.'I.'.'.':.':::..:....:....::.......................
Phase 4: Monte Carlo
Production Cost Simulation
Study Period and Date Conventions
PacifiCorp executes its IRP models for a 20-year period beginning Januar 1,2011 and ending
December 31, 2030. Futue IRP resources reflected in model simulations are given an in-service
date of Januar 1st of a given year. The System Optimizer model requires in-service dates
designated as the first day of a given month, while the Planning and Risk production cost
simulation model allows any date.
Escalation Rates and Other Financial Parameters
Inflation Rates
The IRP model simulations and price forecasts reflect PacifiCorp's corporate inflation rate
schedule unless otherwise noted. For the System Optimizer model, a single escalation rate value
155
PACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
is used. This value, 1.8 percent, is estimated as the average of the annual corporate inflation rates
for the period 2011 to 2030, using PacifiCorp's Septembèr 2010 inflation cure. PacifiCorp's
inflation curve is a straight average of the Gross Domestic Product (GDP) inflator and Consumer
Price Index (CPI).
Discount Factor
The rate used for discounting in fmancial calculations is PacifiCorp's after-tax weighted average
cost of capital (W ACC). The value used for the 2011 IR is 7.17 percent. The use of the after-tax
WACC complies with the Public Utility Commission of Oregon's IRP guideline la, which
requires that the after-tax WACC be used to discount all futue resource costS.52
For the 2011 IRP Update, to be prepared and filed with state commissions in 2012, PacifiCorp
plans to conduct a sensitivity analysis of the impact of a lower discount rate on resource selection
using the System Optimizer capacity expansion modeL. This sensitivity analysis was
recommended by Commission Staff in the Idaho Public Utility Commission's PacifiCorp 2008
IRP "acceptance of filing" document. PacifiCorp wil use the U.S. Treasur Departent's
published long-term composite fix-coupon bond rates to specify an alternative discount rate
value. For 2010, the average of daily rates is about 4 percent.
Federal and State Renewable Resource Tax Incentives
In Februar 2009, Congress granted another extension of the renewable PTC though December
31, 2012. The curent tax credit of $21.5/M, which applies to the first ten years of
commercial operation for wind, geothermal, and biomass resources, is converted to a levelized
net present value after grossing up for income taxes and added to the resource capital cost for
entr into the System Optimizer modeL. The renewable PTC, or an equivalent federal financial
incentive, is assumed to be available though December 31, 2014, as a base assumption for
resource portfolio modeling.
Utah renewable resources (wind, geothermal, and solar facilities) also incorporate the CUITent
Renewable Energy Tax Credit of $3.5/MWh over four years. Oregon's Business Energy Tax
Credit has been removed from consideration given that the credit has been scaled back and does
not apply to projects completed after July 1,2012.
The Emergency Economic Stabilization Act of 2008 (P.L. 110-343) allows utilties to claim the
30-percent investment tax credit for solar facilities placed in service by January 1,2017. This tax
credit is factored into the capital cost for solar resource options in the System Optimizer modeL.
Asset Lives
Table 7.1 lists the generation resource asset book lives assumed for levelized fixed charge
calculations.
52 Public Utility Commission of Oregon, Order No. 07-002, Docket No. UM 1056, Januar 8, 2007.
156
PACIFiCORP-20ll IR
Table 7.1- Resource Book Lives
CHAPTER 7 - MODELING APPROACH
Frame
CHP
Generators
40
20
40
50
35
40
25
30
30
35
30
30
25
25
25
30
30
20
40
20
20
15
10
15
15
30
15
10
20
15
Transmission System Representation
PacifiCorpuses a transmission topology consisting of 19 bubbles (geographical areas) in its
eastern control area and 15 bubbles in its western control area designed to best describe major
load and generation centers, regional transmission congestion impacts, importexport availability,
and external market dynamics. Fir transmission paths lin the bubbles. The transfer capabilities
for these lins represent PacifiCorp Merchant fuction's curent firm rights on the transmission
lines. This topology is defined for both the System Optimizer and Planning and Risk models, and
was also used for IRP modeling support for PacifiCorp's 2011 business plan.
157
PACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
Figue 7.2 shows the IRP transmission system model topology. Segments of the planned Energy
Gateway Transmission Project are indicated with red dashed lines.
Figure 7.2 - Transmission System Model Topology
..
ij Loa
.y Generation
PurchasSale Markts
_ Conra/Exchanges
.. Modeled Tramission .. , "
+-.. Planned Enery Gatway Trasmission '-
The most significant change to the model topology from the one used for the 2008 IRP Update is
the disaggregation of the previously named "West Main" bubble into four new bubbles:
PortlandIorth Coast, Wilamette Valley/Central Coast, South-Central OregonIorthern
California and the Bethel Substation. This disaggregation supports a more refined view of
Oregon load areas and transmission constraints, mainly to captue benefits of the Hemingway -
Boardman - Bethel ("Cascade Crossing") transmission project option described in Chapter 6.
Links from the Chehalis generation bubble to these new bubbles were added to better represent
generation exports.
Finally, PacifiCorp added special wind generation bubbles to Oregon, Uta, and Wyoming to
enable assignment of applicable incremental transmission investment costs to wind selected by
the model for Energy Gateway transmission scenario studies.
158
PACIFiCORP-201l IRP CHAPTER 7 - MODELING APPROACH
Carbon Dioxide Tax Scenarios
Table 7.2 shows the four C02 tax scenarios developed for the IRP. The Medium and High
scenaros reflect CO2 price trajectories contained in recent federal greenhouse gas emission
policy proposals, and assume a 2015 start date. The Medium scenaro assumes a starting cost of
$19 per short ton (2015 dollars) begining in 2015, with 3 percent annual real escalation plus
anual inflation. The High scenario assumes a starting cost of $25 per short ton (2015 dollars)
begining in 2015, with 5 percent annual real escalation plus annual inflation. The Low to Very
High scenario assumes a staring cost of$12 per short ton (2015 dollars) begining in 2015, with
3 percent annual real escalation plus annual inflation through 2020; beginning in 2021, the cost
escalates at an 18% annual escalation rate plus inflation. Figue 7.3 is a comparson of the thee
C02 tax trajectories.
Table 7.2 - CO2 Tax Scenarios
2015 0.00 19.00 25.00 12.00
2016 0.00 19.93 26.73 12.59
2017 0.00 20.93 28.60 13.22
2018 0.00 21.97 30.60 13.88
2019 0.00 23.05 32.71 14.56
2020 0.00 24.18 34.97 15.27
2021 0.00 25.34 37.34 18.30
2022 0.00 26.53 39.85 21.90
2023 0.00 27.81 42.55 26.24
2024 0.00 29.14 45.45 31.43
2025 0.00 30.54 48.54 37.65
2026 0.00 32.00 51.84 45.11
2027 0.00 33.57 55.42 54.09
2028 0.00 35.22 59.24 64.85
2029 0.00 36.94 63.33 77.75
2030 0.00 38.75 67.70 93.23
159
P ACIFICORP ~ 2011 IR CHAPTER 7 - MODELING APPROACH
Figure 7.3 - Carbon Dioxide Price Scenario Comparison
100
30
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ii 50'i:0.
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40 . ...,...........-_.-.......-..._-.-,.-
20
10
o
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
_Medium __High_Low- Very High
Emission Hard Cap Scenarios
PacifiCorp also modeled two CO2 system emission hard caps scenarios as alternate compliance
mechanisms.
53 Two emission cap scenarios were developed:
· Base: 15 percent below 2005 levels by 2020, and 80% by 2050
· Oregon: 10 percent below 1990 levels by 202û-the Oregon taget in H.B. 3543-and 80
percent below by 2050
The hard caps go into effect in 2015. Table 7.3 shows the hard cap emission limits for each
scenario.
Table 7.3 - Hard Cap Emission Limits (Short Tons)
2015
2016
2017
2018
2019
56,968
55,934
54,900
53,866
52,832
51,075
49,838
48,601
47,364
46,127
53 The Public Utility Coinission of Oregon's 2008 IRP acknowledgment order (Order No. 10-066 under Docket
No. LC 47) included a requirement to provide analysis of potential hard cap regulations.
160
PACIFiCORP-20ll IRP CHAPTER 7 - MODELING APPROACH
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2050
51,798
50,477
49,157
47,837
46,516
45,196
43,876
42,555
41,235
39,915
38,594
12,188
44,890
43,726
42,562
41,398
40,235
39,071
37,907
36,743
35,579
34,416
33,252
9,976
For representing C02 emissions associated with firm market purchases and system balancing
spot market transactions, PacifiCorp's reporting protocols for calculating its greenhouse gas
inventory requires using the EPA's e-Grid sub-region output emission factors for unspecified
market transactions. Consequently, the C02 emission rate of 902 Ibs/MWh is applied for the
Mid-Columbia, COB, Mona, and Mead markets, and 1,300 Ibs/M is applied for the Palo
Verde and Four Corners markets.
When modeling a hard cap in System Optimizer, the model generates shadow emission prices in
order to meet the hard cap. For example, if the hard cap is not met then the shadow price is
increased to decrease the output of the emission-producing stations. These shadow prices are
imported into the PaR model to simulate emission-constrained dispatch. Table 7.4 shows the
shadow prices generated for the four hard cap cases. The medium CO2 tax is also used for hard
cap cases to reflect assumed regional or federal emission prices that impact wholesale electrcity
and gas commodity prices used for portfolio modeling. Note that for PaR portfolio cost
reporting, PacifiCorp applied the C02 tax values to emission quantities rather than the System
Optimizer shadow costs to maintain cost comparability among the portfolios.
Table 7.4 - CO2 Emission Shadow Costs Generated by System Optimizer for Emission
Hard Cap Scenarios
2015 0 0 0 37
2016 10 8 1 39
2017 11 24 16 35
2018 14 30 34 37
2019 15 34 39 40
2020 17 36 50 43
2021 21 40 64 47
2022 24 43 71 55
2023 28 50 78 70
161
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
2024 34 57 85 75
2025 38 60 91 75
2026 47 64 94 77
2027 47 62 95 73
2028 51 71 108 83
2029 63 75 114 101
2030 47 61 78 78
Oregon Environmental Cost Guideline Compliance
The Public Utility Commission of Oregon, in their IRP guidelines, directs utilities to constrct a
base-case scenario that reflects what it considers to be the most likely regulatory compliance
futue for C02, as well as alternative scenarios "ranging from the present C02 regulatory level to
the upper reaches of credible proposals by governing. entities." Modeling portfolios with no CO2
cost represents the curent regulatory leveL. The Medium scenario was considered the most likely
regulatory compliance scenario at the time that IRP C02 scenarios were being prepared and
vetted by public stakeholders (early fall of 2010). Given the late-20 1 0 collapse of comprehensive
federal energy legislation and loss of momentu for implementing federal carbon pricing
schemes, there is no "likely" regulatory compliance futue at the present time (notwithstanding
the U.S. EPA's GHG initiative to revise New Source Performance Standards for electrc
generating units.) PacifiCorp believes that its C02 tax and hard cap scenaros reflect a reasonable
range of compliance futues for meeting the Public Utilty Commission of Oregon scenario
development guideline given continued uncertainty. In paricular, it should be noted that the hard
cap shadow prices for Case 15 exhibit a more moderate trajectory than the Medium scenaro,
effectively providing a "low" CO2 tax case for portfolio evaluation.
The first phase of the IRP modeling process was to define the cases (input scenarios) that the
System Optimizer model uses to derive optimal resource expansion plans. The cases consist of
variations in inputs representing the predominant sources of portfolio cost variability and
uncertainty. PacifiCorp generally specified low, medium, and high values to ensure that a
reasonably wide range in potential outcomes is captued. For the 2011 IRP, PacifiCorp
developed a total of 49 cases.
PacifiCorp defined three tyes of cases: Energy Gateway scenaro evaluation cases, core cases,
and sensitivity cases. Energy Gateway scenario evaluation cases were designed to help
PacifiCorp's transmission planning departent evaluate four Energy Gateway expansion options
based on System Optimizer portfolio modeling results. These 16 cases supplement other Energy
Gateway economic analysis conducted with the IR models, profiled in Appendix C.
162
PACIFiCORP-2011IRP CHAPTER 7 ~ MODELING APPROACH
Core cases focus on broad comparability of portfolio performance results for four key variables.
These variables include (1) the level of a per-ton CO2 tax, (2) the tye of CO2 regulation-tax or
hard emission cap, (3) natual gas and wholesale electrcity prices based on PacifiCorp's forward
price cures and adjusted as necessary to reflect CO2 tax impacts, and (4) extension date for the
federal renewables production tax credit. The Company developed 19 core cases based on a
combination of input variable levels. The core case group includes a 2011 business plan
"reference" portfolio. This portfolio consists of fixed wind and gas resources for 2011 through
2020, reflecting the major generation projects in the business plan. Also included are four hard
cap cases. Because these cases simulate physical emission constraints as opposed to generator
emission costs, they do not have emissions profies comparable to the other portfolios.
In contrast, sensitivity cases focus on changes to resource-specific assumptions and alternative
load growt forecasts. The resulting portfolios from the sensitivity cases are tyically compared .
to one of the core case portfolios. PacifiCorp developed 14 sensitivity cases reflecting evaluation
of existing coal plant operation, alternative load forecasts, alternative renewable generation cost
and acquisition incentives, and demand-side management resource availability assumptions.
In developing these cases, PacifiCorp kept to a target range in terms of the total number (low
50s) in light of the data processing and model ru-time requirements involved. To keep the
number of cases within this range, PacifiCorp excluded some core cases with improbable
combinations of certain input levels, such as a high C02 tax and high load growth. (With a high
CO2 tax, a significant amount of demand reduction is expected to occur in the form of energy
effciency improvements, and utility load control programs.)
PacifiCorp also relied heavily on feedback from public stakeholders. The Company assembled
an initial set of cases in July 2010, and introduced them to stakeholders at the August 8, 2010,
public input meeting. Subsequent updates based on staeholder comments and Company
refinements were reviewed at public input meetings held October 5 and December 15, 2010.
One of the key messages from staeholders was to ensure that the range of cases generate a
diverse set of resource tyes.
54
Case Specifications
Table 7.5 profiles the portfolio development cases specifications. Reference numbers in the table
headings and certain rows correspond to notes providing descriptions of the case variables and
explanatory remarks for specific cases that follow the table.
54 PacifiCorp's IRP public process IRP Web page includes lins to documentation on portolio case development
and how staeholder comments were addressed.
163
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5
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
Case Definition Notes
1. The carbon dioxide tax is a varable cost adder for each short ton of C02 emitted by
PacifiCorp's thermal plants. The C02 tax for market purchases is incorporated in the
electricity price forecast scenarios as simulated by MIDAS, a regional production simulation
model that is described later in this chapter. These marginal wholesale electrcity price
forecasts, by market hub, are then fed into System Optimizer. The hard cap is a physical CO2
emissions limit placed on system generation and purchases.
2. The high, medium, and low natual gas price forecasts are based on a review of multiple
forecasting service company projections, and incorporate the C02 tax assumptions associated
with the case definitions. Details on the price forecasts and supporting methodology are
provided later in this chapter.
3. The main purose of the alternative load forecast cases is to determine the resource tye and
timing impacts resulting from a strctual change in the economy. The focus of the load
growth scenarios is from 2014 onward. The Company assumes that economic changes begin
to significantly impact loads begining in 2014, the cUITently planned acquisition date for the
next CCCT resource. For the low economic growth scenaro (Case 25), another economic
recession hits in 2014. For the high economic growt scenaro (Case 26), the economy is
assumed to fully recover from the curent recession by 2014 and significantly expand
beginning at that point. Low and high load forecasts are one-percent decreases and increases,
respectively, for economic drvers, relative to the Medium forecast. PacifiCorp developed the
"high peak demand" forecast by assumg one-in-ten (10 percent probability of exceedence)
high temperatue loads. Figue 7.4 shows the low, high, and high-peak load forecasts relative
to the medium case. Note that the capacities reflect loads before any adjustments for demand-
side management programs are applied. See Appendix A for a detailed description of the
forecast scenarios.
Figure 7.4 - Load Forecast Scenario Comparison
16,000
11,000
15,000
14,000
~
~13,000=..
~
12,000
10,000
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
..Medium ..Low =gr- High -Peak
166
PACIFICORP - 2011 IRP CHAPTER 7 - MODELING APPROACH
4. The "PTC extension to 2015" assumption is consistent with PacifiCorp's 2011 business plan.
The "PTC extension to 2020" assumption was recommended by a public staeholder.
A wind integration cost of$5.38/M (versus $9.70/M as reported in PacifiCorp's wind
integration study dated September 1,2010) was used for the alternative wind integration cost
case as recommended by Renewable Northwest Project based on their independent analysis.
The PTC is assumed to expire by 20 i 5 for the alternate wind integration cost case.
5. The curent RPS assumption is a system-wide requirement based on meeting existing state
RPS targets under the Multi-State Protocol Revised Protocol. States with applicable resource
standards include California, Oregon, Washington, and Uta. The table below shows the
incremental system renewable energy requirement after accounting for state eligible
resources acquired through 2010. Based on RPS compliance analysis using the compliance
targets proposed by Senator Jeff Bingaman, along with PacifiCorp's eligible renewable
resources though 2010, PacifiCorp would comply with this federal RPS proposal until 2030.
The federal RPS scenaro assumes the higher Waxman-Markey (H.R. 2454) targets that
passed the U.S. House of Representatives in June 2009. This RPS scenario was used for
Energy Gateway and 2011 IRP preferred portfolio scenario analysis. Table 7.6 below
compares the Bingaman and Waxman-Markey combined renewables/electricity savings
compliance targets and the renewable-only targets estimated by PacifiCorp.
Table 7.6 - Comparison of Renewable Portfolio Standard Target Scenarios
2015 0.0% 3.0% 2.3% 9.5% 7.1%2016 0.0% 3.0% 2.3% 13.0% 9.8%2017 0.0% 3.0% 2.3% 13.0% 9.8%2018 0.0% 6.0% 4.5% 16.5% 12.4%2019 0.0% 6.0% 4.5% 16.5% 12.4%2020 0.1% 6.0% 4.5% 20.0% 15.0%2021 2.0% 9.0% 6.8% 20.0% 15.0%2022 2.2% 9.0% 6.8% 20.0% 15.0%2023 2.2% 12.0% 9.0% 20.0% 15.0%2024 2.3% 12.0% 9.0% 20.0% 15.0%2025 3.2% 15.0% 11.% 20.0% 15.0%2026 3.2% 15.0% 11.% 20.0% 15.0%2027 3.2% 15.0% 11.% 20.0% 15.0%2028 3.2% 15.0% 11.% 20.0% 15.0%2029 3.1% 15.0% 11.% 20.0% 15.0%2030 3.2% 15.0% 11.% 20.0% 15.0%
11 Reflects additional renewable energy requirement after accounting for eligible resources acquired though 2010.
2/ Reflects the forecasted renewable portion of a combined renewable/electricity savings requirement.
6. A high achievable percentage assumption of 85 percent for DSM programs applies to all
portfolios. The Cadmus Group's base achievable assumption for the 2007 DSM potential
study, prior to Company adjustment, was 55 percent.
167
PACIFiCORP-2011 IR CHAPTER 7 - MODELING APPROACH
7. For sensitivity Case 31, System Optimizer is allowed to select price-responsive DSM
programs. These programs, outlined in Chapter 6, include residential time-of-use,
commercial/industrial real-time pricing, commerciai/industral demand buyback,
commerciai/industrial load curilment, commercial critical peak pricing, and mandatory
irgation time-of-use rates.
8. This assumption is intended to meet the Public Service Commission of Utah's DSM
evaluation requirements. DSM is modeled based on technical potentiaL.
9. PacifiCorp modeled a Washington-only conservation voltage reduction (CVR) resource
based on estimated energy savings and costs for 19 distrbution feeders analyzed as part of a
consultant study.55 The sensitivity analysis serves as a proof-of-concept test for futue
resource modeling. The levelized cost and resource capacity by Washigton topology bubble
is shown in the following table:
Walla Walla
Yakima
1/ Costs exclude credits applied to meet Initiative 937 methodology
requirements documented in Chapter 6.
10. This case is intended to meet the Public Service Commission of Utah's distrbuted solar
evaluation requirements. For Case 30, Utah roof-top PV resources were modeled with a
program incentive cost (capital cost) of $1,744/kW, which includes a 14 percent
administrative and marketing cost gross-up. For Case 30a, the resources were modeled with
a program cost of 2,326/kW, including the 14 percent administrative and marketing cost
gross-up. Resource potential in Utah is 1.2 MW per year, reaching 24 MW by 2030.56
11. The five coal plant utilization sensitivity cases are designed to investigate, as a modeling
proof-of-concept, the impacts of C02 cost and gas price scenarios on the existing coal fleet
after accounting for: incremental environmental compliance, fueling, decommissioning, and
coal contract liquidated damages, as well as recovery of remaining plant depreciation.
System Optimizer is allowed to select the optimal coal plant shut down dates. This study is
limited to CCCT replacement resources with an earliest in-service date of 2016. The
simulation period covers 2011 though 2030. More details on specification of the coal plant
utilization model set-up are provided later in this chapter.
55 The study was conducted by a consulting team led by Commonwealth Associates, Inc. The modeled resource
reflects preliminar findings of the study. The consultig team applied the Distrbution Effciency Initiative (DEI)
average Pacific Northwest conservation load shape to the 19 distrbution feeder effciency measures to derive hourly
energy savings for use by System Optimizer. DEI was a three-year study initiated in 2005 by the Nortwest Energy
Efficiency Alliance to investigate the cost-effectiveness of distrbution effciency and voltage optimization
measures.56 Resources are modeled by topology bubble. The Uta solar PV resource was located in the Utah North bubble,
which includes a porton of Idaho and southwestern Wyoming. The total solar PV capacity potential per year for
Uta Nort is 1.3 MW, consisting of 1.2 MW for Utah, 0.18 MW for Wyoming, and 0.07 MW for Idaho.
168
PACIFiCORP-2011 IR CHAPTER 7 - MODELING APPROACH
12. Energy Gateway transmission scenarios are defined by including certain transmission
expansion segments. Table 7.7 shows the segments assigned to the Energy Gateway
scenarios. Capital costs for each scenaro included in System Optimizer are also shown.
PacifiCorp ultimately developed 32 portfolios reflecting the base RPS assumption and the
higher Waxman-Markey targets (Cases designated with a "-WM" extension). Modeling
assumptions, transmission maps, and results are provided in Chapter 4.
For the Base scenario, both the Populus - Terminal and Mona - Oquirh projects have a
Certificate of Public Convenience and Necessity (CPCN). The Sigud - Red Butte and Harr
Allen projects are not considered transmission resource options because they are
reliabilty/grid reinforcement investments necessar for serving southwestern Uta loads, and
not justified based on supply-side resource expansion elsewhere on the system. The
"Hemingway - Boardman - Cascade Crossing" transmission project.is treated as a resource
option in Scenario 3 due to the dependency on the Populus - Hemingway segment.
Table 7.7 - Energy Gateway Transmission Scenarios
Gateway Central
(Populus- Teral and
Mona-Oquih)
Sigurd - Red Butte
Gateway Central Gateway Central Gateway Central
Sigurd - Red Butte Sigurd - Red Butte Sigurd - Red Butte
Hany Allen Upgrade Hany Allen Upgrade Hany Allen Upgrade Hany Allen Upgrade
Winds ta - Populus Windstar - Populus
Aeolus - Mona Aeolus - Mona
POpWus - Henung~y
Henung~y-Boardm-
Cascade Crossing
13. Two portfolios were developed for Case 9. The portfolio for Case 9 is a conventional20-year
System Optimizer ru. Portfolio 9a represents the outcome of two System Optimizer rus;
the first ru was a 12-year ru, while the second ru was a 20-year run with the resources
fixed for the first ten years based on the 12-year ru. (The 12-year ru mitigates the
optimization period end effects that would be present on a ten year ru.) These portfolios are
intended to support analysis required in the Public Utility Commission of Oregon's 2008 IRP
acknowledgment order (Order No. LC 47). They also support the Oregon Commission's
"Trigger Point Analysis" IRP standard (Order No. 08-339).
169
PACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
On a central tendency basis, commodity markets tend to respond to the evolution of supply and
demand fudamentals over time. Due to a complex web of cross-commodity interactions, price
movements in response to supply and demand fudamentals for one commodity can have
implications for the supply and demand dynamics and price of other commodities. This
interaction routinely occurs in markets common to the electrc sector as evidenced by a strong
positive cOITelation between natual gas prices and electrcity prices.
Some relationships among commodity prices have a long historical record that have been studied
extensively, and consequently, are often forecasted to persist with reasonable confidence.
However, robust forecasting techniques are required to captue the effects of secondary or even
tertiary conditions that have historically supported such cross-commodity relationships. For
example, the strong correlation between natual gas prices and electrcity prices is intrsically
tied to the increased use of natual gas-fired capacity to produce electrcity. If for some reason in
the future natural gas-fired capacity diminishes in favor of an alternative technology, the linage
between gas prices and electricity prices would almost certainly weaken.
PacifiCorp deploys a variety of forecasting tools and methods to captue cross-commodity
interactions when projecting prices for those markets most critical to this IRP - natual gas
prices, electrcity prices, and emission prices. Figue 7.5 depicts a simplified representation of
the framework used by PacifiCorp to develop the price forecasts for these different commodities.
At the highest level, the commodity price forecast approach begins at a global scale with an
assessment of natual gas market fudamentals. This global assessment of the natual gas market
yields a price forecast that feeds into a national model where the influence of emission and
renewable energy policies is captued. Finally, outcomes from the national model feed into a
regional model where the up-stream gas prices and emission prices drve a forecast of wholesale
electrcity prices. In this fashion, the Company is able to produce an internally consistent set of
price forecasts across a range of potential futue outcomes at the pricing points that interface
with PacifiCorp' s system.
170
PACIFiCORP-20ll IRP CHAPTER 7 - MODELING APPROACH
Figure 7.5 - Modeling Framework for Commodity Price Forecasts
The process begins with an assessment of global gas market fudamentals and an associated
forecast of North American natual gas prices. In this step, PacifiCorp relies upon a number of
third-par proprietary data and forecasting services to establish a range of gas price scenarios.
Each price scenario reflects a specific view of how the North American natual gas market wil
balance supply and demand.
Once a natual gas price forecast is established, the IPMCI is used to simulate the entire North
American power system. IPMCI, a linear program, determines the least cost means of meeting
electrc energy and capacity requirements over time, and in its quest to lower costs, ensures that
all assumed emission policies and RPS policies are met. Concurrently, IPMCI can be confgued
with a dynamic natual gas price supply curve that allows natual gas prices to respond to
changes in demand trggered by environmental compliance. Additional outputs from IPMCI
include a forecast of resource additions consistent with all specified RPS targets, electric energy
and capacity prices, coal prices57, electric sector fuel consumption, and emission prices for
policies administered in a cap-and-trade framework.
57 IPMtI contains over 70 coal supply cures, with reserve estimates, by rank and quality. Coal supply cures are
matched to coal demand areas, including transportation costs, and optimized. As such, IPMtI is able to captue coal
171
P ACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
Once emission prices and the associated gas price response are forecasted with IPM(Ê, results are
used in a regional model named Midas to produce an accompanying wholesale electrcity price
forecast. Midas is an hourly chronological dispatch model configued to simulate the Western
Interconnection and offers a more refined representation of western wholesale electrcity markets
than is possible with IPM(Ê. Consequently, PacifiCorp produces a more granular price projection
that covers all of the markets required for the system models used in the IRP. The natual gas
and wholesale electrcity price forecasts developed under this framework and used in the cases
for this IRP are summarized in the sections that follow.
Gas and Electricity Price Forecasts
Price forecasts for this IRP are significantly lower than those produced for the Company's 2008
IR and the subsequent 2008 IRP Update filed with state commissions in March 2010. Figues
7.6 and 7.7 compare natual gas (Henr Hub) and electrcity price forecasts, respectively, forthe
2011 IRP, 2008 IRP Update, and 2008 IRP.
Figure 7.6 - Comparison of Henry Hub Gas Price Forecasts used for Recent IRPs
$16.00
Henry Hub Natural Gas Prices
$14.00
$12.0
$10.00 ..---.-..------.--,.-.--,-------.
!l:
:?
:?$8.00-'"
-;i:
13 $6.00~Z
$4.00$2.00 ,-------,-.,.
$0.00 ---...--r
2010 20ll 2012 2013 2014 2015 2016 2017 201S 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~2008 IRP (October 2008) ----w-2008 IRPUpdate (September 2009) ..2011 IRP (September 2010)
price response from incremental (decrernental) demand, which ultimately affects the natual gas and emission prices
that feed into System Optimizer and PaR.
172
PACIFiCORP-20ll IR CHATER 7 - MODELING APPROACH
Figure 7.7 - Comparison of Electricity Price Forecasts used for Recent IRPs- " -
180.00 -r-
10 Verde Electricity Prices, 3rd Quarter Heavy Load Hour
80.00
160.00
140.00
I
i ~
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100.00
i .,
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......_r-.._.m!_.___?'.m_-.--_._..m,m._-rm.....~-m....m...-r....._..- ¡
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
..2008 IRP(October 2008) '#"~M2008 IRPUpdate (September 2009) ..2011 IRP (September 2010)
A total of thee underlying natual gas price. forecasts are used to develop the 15 unique gas price
projections for the cases analyzed in this IRP. A range of fudamental assumptions affecting
how the North American market wil balance supply and demand defines the three underlying
price forecasts. Table 7.8 shows representative prices at the Henr Hub benchmark for the thee
underlying natual gas price forecasts. The three forecasts serve as a point of reference and are
adjusted to account for changes in natual gas demand drven by a range of environmental policy
and technology assumptions specific to each IRP case. Figue 7.6 compares the Henr Hub price
forecasts used for the 2008 IRP, 2008 IRP Update, and 2011 IRP, indicating the large drop in
forecasted prices.
Table 7.8 - Henry Hub Natural Gas Price Forecast Summary (nominal $/MMBtu)
Price Projections Tied to the High Forecast
The underlying high gas price forecast is defined by higher global oil prices and lower LNG and
Canadian gas imports, and delayed unconventional gas development. Despite higher gas prices,
increases in gas demand for transportation have the effect of offsetting demand decreases in the
173
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
power generation and industral sectors; Figue 7.8 sumarizes prices at the Henr Hub
benchmark and Figue 7.9 sumarzes the accompanying electrcity prices for the forecasts
developed around the high gas price projection.
Figure 7.8 - Henry Hub Natural Gas Prices from the High Underlying Forecast
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
WØÆ' High - Sept 2010 Range ..ca13 4-case14 _cases 12 & EG 13-16
Figure 7.9 - Western Electricity Prices from the High Underlying Gas Price Forecast
$200 ~--_.....------ ...--,-,-,------,------..--....---.--..-.-.--...--.----..-----
$175
$150
::¡_. $100
$75
$25
$0
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~i High - Sept 2010 Range _case 13 4-ca14 _cases 12 & EG 13-16
Note: Western electrcity prices are presented as the average of flat prices at Mid-Columbia and Palo Verde.
174
PACIFICORP - 2011 IRP CHAPTER 7 - MODELING APPROACH
Price Projections Tied to the Medium Forecast
The underlying September 2010 medium gas price forecast relies upon market forwards for the
first six years and a fudamentals-based projection thereafter. For the market portion of the
forecast, prices are based upon forwards as of market close on September 30, 2010. The
fudamentals-based part of the forecast depicts a futue in which declining LNG imports
coincide with a strong demand from the electrc sector drven by resistance to new coal-fired and
nuclear capacity and ineffcient coal plant retirements. Unconventional production, especially
shale gas, is assumed to largely be able to keep pace with growing demand. Quantities of shale
gas are forecasted to be higher than previously thought. Figure 7.10 shows Henr Hub
benchmark prices and Figue 7.11 includes the accompanying electrcity prices for the forecasts
developed around the medium gas price projection.
Figure 7.10 - Henry Hub Natural Gas Prices from the Medium Underlying Forecast
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Wff4i Medium -Sept 2010 Range ..Cases8, 22& EG 9-12 ..Case9 ~Case 10 ..case 30 ~Case31 ..Case2 -'Case 1
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PACIFiCORP-2011 IR CHAPTER 7 - MODELING APPROACH
Figure 7.11- Western Electricity Prices from the Medium Underlying Gas Price Forecast
$200
$175
$150
$125
..$100
:;::;;
$75
$50
$25
$0
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~ Medium-Sept 2010 Range -tCases 8, 22& EG 9.12 _Case9 ..caselO -+Cas30 ~Case31 ..case 1 ~Case2
Note: Western electrcity prices are presented as the average of flat prices at Mid-Columbia and Palo Verde.
Price Projections Tied to the Low Forecast
The underlying low gas price forecast is defined by contiued growth of low-cost non-
conventional gas supplies and an increase in LNG imports as weaker global economic growth
drves down demand in Europe, China and elsewhere. This increase in supply, coupled with
weaker demand growth, primarly in industral and power generation sectors, results in lower gas
prices that continue to support coal switching. Figue 7.12 shows Henr Hub benchmark prices
and Figue 7.13 includes the accompanying electrcity prices for the forecasts developed around
the low gas price projection.
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PACIFiCORP-20ll IRP CHAPTER 7 - MODELING APPROACH
Figure 7.12 - Henry Hub Natural Gas Prices from the Low Underlying Forecast
$20
$18 '.
$16
$14
$12
~t;$10:;:;~
$8
$6
$4
$2
$0
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~ Low. Sept 2010 Range ..CaseS _Ca5e6 _Ca5054 & 23
Figure 7.13 - Western Electricity Prices from the Low Underlying Gas Price Forecast
$175 '
$150 '
$125
-";::õ..$100'"
$75
$50
$25
$0 ........1..-..--M~~....._.---....._...r
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
W.. Low. Sept 2010 Range ..CaseS ~Case6 _Ca5e54&23
¡Western electricity prices are presented as the average of flat prices at Mid-Columbia and Palo Verde.
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P ACIFICORP - 2011 IR CHATER 7 - MODELING APPROACH
For Phase 3, System Optimizer is executed for each set of case assumptions, generating an
optimized investment plan and associated real levelized present value of revenue requirements
(PVRR) for 2011 through 2030. System Optimizer operates by minimizing for each year the
operating costs for existing resources subject to system load balance, reliability and other
constraints. Over the 20-year study period, it also optimizes resource additions subject to
resource investment and capacity constraints (monthly peak loads plus a planing reserve margin
for each load area represented in the model).
To accomplish these optimization objectives, the model performs atime-of-day least-cost
dispatch for existing and potential planed generation, contract, DSM, and transmission
resources. The dispatch is based on a representative-week method. Time-of-day hourly blocks
are simulated accordig to a user-specified day-tye pattern representing an entire week. Each
month is represented by one week, with results scaled to the number of days in the month and
then the number of months in the year. The dispatch also determines optimal electrcity flows
between zones and includes spot market transactions for system balancing. The model minimizes
the overall PVRR, consisting of the net present value of contract and spot market purchase costs,
generation costs (fuel, fixed and variable operation and maintenance, unserved energy, and
unmet capacity), and amortized capital costs for planned resources.
For capital cost derivation, System Optimizer uses anual capital recovery factors to address
end-effects issues associated with capital-intensive investments of different durations and in-
service dates. PacifiCorp used the real-Ievelized capital costs produced by System Optimizer for
portfolio cost reporting by the PaR modeL.
System Optimizer Customizations
PacifiCorp had its model vendor Venty add custom fuctionality to the model to improve the
representation of C02 and renewable portfolio stadards modeling. The new fuctionality
consists of a topology overlay for defining and lining sources and sin for tracking carbon
emissions and renewable energy production. The sources represent individual generators while
sinks are defined as user-specified areas tyically demarcated as states or multi-state regions.
The key benefit of this new fuctionality is the ability to assign a C02 emission rate to system
balancing (spot market) transactions and account for such transaction activity in hard emission
cap regulatory scenaros. This fuctionality also enables definition of C02 emission constraints
for a specific thermal generator as it relates to one or multiple sinks. An application of this
capability is to apply a state-specific emission performance standard to a coal plant, thereby
limiting or preventing energy to be exported to that state. Finally, this functionality allows the
model to allocate system renewable energy to individual states to meet RPS requirements.58
58 This fuctionality does not enable the model to optimize renewable energy capacity expansion based on
individual state RPS requirements. Rather, it ensures that suffcient renewable energy can be generated within a state
and irnported from other pars of the system to meet a state-specific RPS taget. This fuctionality also does not
account for banking rules.
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PACIFiCORP-2011 IRP CHAPTER 7 ~ MODELING APPROACH
For the 2011 IRP, the Company used the new fuctionality to model system balancing
transaction emissions for the various emission hard cap scenarios described above. Initial System
Optimizer modeling for the IRP yielded no new coal plants in any portfolio, so implementation
of state-specific emission performance standards was deemed unecessary.
Representation and Modeling of Renewable Portfolio Standards
PacifiCorp incorporates annual system-wide renewable generation constraints in the System
Optimizer model to ensure that each optimized portfolio meets CUITent state RPS requirements
and applicable federal RPS scenaros. As noted above, for the base case RPS requirement,
curent Oregon, Utah, Washington, and California rules are followed. Two of the core cases
assume no RPS is in place as a baseline for measurng renewable resource costs. A key
assumption backing the system-wide RPS representation is that all of PacifiCorp's State
jurisdictions wil adopt renewable energy credit (REC) trading rules through the Multi;.state
Process, thus enabling sales and purchase of surplus banked RECs. System Optimizer is not
designed to track or optimize REC sales, purchases, or baning balances.
Modeling Front Office Transactions and Growth Resources
Front offce transactions, described in Chapter 6, are assumed to be transacted on a one-year
basis, and are represented as available in each year of the study. For capacity optimization
modeling, System Optimizer engages in market purchase acquisition-both front office
transactions, and for hourly energy balancing, spot market purchases-to the extent it is
economic given other available resources. The model can select virtally any quantity of FOT
generation up to limits imposed for each case, in any study year, independently of choices in
other years. However, once a front offce transaction resource is selected, it is treated as a must-
ru resource for the duration of the transaction period. For this IRP, front office transactions are
available for all years in the study period.
The front office transactions modeled in the Planing and Risk Module. generally have the same
characteristics as those modeled in the System Optimizer, except that transaction prices reflect
wholesale forward electric market prices that are "shocked" according to a stochastic modeling
process prior to simulation execution.
Another resource tye included in the IRP models is the growth resource. This resource is
intended for capacity balancing in each load area to ensure that capacity reserve margins are met
in the out years of each simulation (after 2020). The System Optimizer model can select an
anual flat or third-quarter HLH energy pattern priced at forward market prices appropriate for
each load area. Growth resources are similar to front office transactions, except that they are not
transacted at market hubs. For each market hub, they are capped at 1,000 MW on a cumulative
basis for 2021-2030.
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PACIFiCORP-20ll IR CHATER 7 - MODELING APPROACH
Modeling Wind Resources
As discussed in Chapter 6, PacifiCorp revised its approach for locatig wind resources to match
up with WRZs and facilitate assignent of incremental transmission costs for the Energy
Gateway transmission scenario analysis. Wind resources are modeled as must-ru units in both
the System Optimizer and Planing and Risk models using hourly fixed energy shapes. Because
System Optimizer is not a detailed chronological unit commitment and dispatch model, the cost
impacts of wind tied to unit commitment are not captued. Also, system costs and reliability
effects associated with intra-hour wid varability are not captued.
Stochastic Production Cost Adjustment for Combined-cycle Combustion Turbines
Historically, System Optimizer has undervalued CCeT resources relative to peakig gas
resources. To help ensure that System Optimer resource selection accounts for the value of
flexible dispatchable resources given stochastic uncertainty, the Company estimated a capital
cost credit for CCCTs using deterministic and stochastic production cost simulations.59 The cost
credit reflects the levelized net operating revenue difference between gas resources in a portfolio
simulated stochastically and the same portfolio simulated deterministically. PacifiCorp selected
an intercooled aeroderivative simple-cycle combustion tubine (IC aero SCCT) as the proxy
peaking resource for derivation of the cost credit.
The cost credit is $179/kW in 2010 dollar, and is applied to the capital cost of all CCCT
resource options in the modeL. Since this cost credit is only used to affect the outcome of
resource selection, the credit is removed from the System Optimizer's reported PVR as a post-
modeling cost adjustment.
Modeling Fossil Fuel Efficiency Improvements
For all IR modeling, PacifiCorp used forward-looking heat rates for existing fossil fuel plants,
which account for plant efficiency improvement plans. Previously the Company used four-year
historical average heat rates. This change ensures that such planned improvements are factored in
the optimized portfolios and stochastic production cost simulations, in line with the goals of the
PURPA fossil fuel generation efficiency stadard that is part of the 2005 Energy Policy Act.
Modeling Coal Plant Utilzation
The five coal plant utilization sensitivity cases are designed to investigate, as a modeling proof-
of-concept, the impacts of C02 cost and gas price scenaros on the existing coal fleet after
accounting for coal plant incremental costs. They are intended to pave the way for futue
refinement of the modeling approach for investigating coal plant operations. These proof-of-
concept studies are not intended to draw conclusions on the disposition of individual generating
units or desirability of specific strategies to respond to futue regulatory developments. As noted
59 More information on the stochastic cost adjustment approach can be found in the report for the April 28, 2010,
public input meeting, available on PacifiCorp's IRP Web site.
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PACIFICORP - 2011 IRP CHAPTER 7 - MODELING APPROACH
in the Company's IRP public meetings, the lack of certainty around key cost and regulatory
drvers serves as a major caveat for this study.
Table 7.9 below outlines the costs assigned to the existing coal unit and the gas plant betterment
option by cost category. Note that certain costs have not been incorporated into the analysis;
however, capital expenditues for planed and/or ongoing pollution control equipment
investments included in the Company's business plan are incorporated whether curently
committed via contract or not. In addition to best available retrofit technology (BART)
requirements under the EPA's regional haze rules, increasingly more strgent National Ambient
Air Quality Standards (NAAQS) have been, and are continuing to be, adopted for criteria
pollutants, including S02,N02, ozone, and PM. The pollution control project costs included in
the coal utilization study assist in meeting these more stringent stadards, avoiding the negative
consequences of an area being declared to be a nonattainment area. . The Company does,
however, anticipate that additional state and federal environmental laws and regulations wil
necessitate fuer investment in pollution control and environmental compliance projects, as
well as fuer evaluation of unit specific operational/dispatch impacts, especially with respect to
pending greenhouse gas regulations and hazardous air pollutants maximum achievable control
technology (HAPs MACT) requirements.
Table 7.9 - Resource Costs, Existing and Associated Plant Betterment Cost Categories
· Fixed Operations & Maintenance (O&M)
. Coal fuel cost
. Incremental fixed O&M - on-going capital
recovery
· Incremental fixed O&M - Planned
comprehensive air initiative investments
. Incremental comprehensive air initiative
capital recovery
· Incremental mining capital recovery
. Constrction, $/kW
. Varable and fixed O&M
. Liquidated damages for not complying with
minimum-take provisions of existing coal
supply contracts
. Existig un-depreciated coal plant
. Fixed cost - natual gas pipeline expansion
and transportation
. Natul gas commodity cost
. Decommissioning existing plant/site
preparation (one time fixed O&M charge)
Costs associated with Mercur MACT compliance have been incorporated. Costs that have not
been incorporated include potential plant regulatory compliance costs associated with the EPA's
proposed rules for coal combustion residuals (CCR) and cooling water intae strctues, as well
as any transmission upgrade costs associated with replacement resource options. Such costs and
operational impacts are speculative, and in the case of pending environmental rules and
regulations, depend on the outcome of the respective rulemaking processes.
As a simplifying assumption, coal contract liquidated damages reflect estimated costs from 2016
to 2020 and are converted to a reallevelized payment over the 20-year model simulation period.
Similarly, the remaining plant balance for 2011 is converted to a real levelized payment that
reflects capital recovery and depreciation over the 20-year simulation period.
181
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P ACIFICORP - 201 1 IR CHAPTER 7 - MODELING APPROACH
Coal units are not specified with a shut-down date; in other words, the units are assumed to
operate past 2030 unless the model chooses a replacement. System Optimizer is allowed to select
the gas plant betterment option for any year after 2016. The existing coal unit is dispatched up to
the point when the replacement resource is added.
Modeling Energy Storage Technologies
Energy storage resources in both System Optier and Planing and Risk (PaR) are
distinguished from other resources by the following thee attbutes:
. energy "take" - generation or extrction of energy from a reservoir;
. energy "retu" - energy used to fill (or charge) a reservoir; and
. storage cycle efficiency - an indicator of the energy loss involved in storing and extracting
energy over the course of the take-retu cycle.
The models require specification of a reservoir size. For System Optimizer, reservoir size is
defined as a megawatt capacity value, whereas in PaR it is defmed in gigawatt-hours. System
Optimizer dispatches a storage resource to optimize energy used by the resource subj ect to
constraints such as storage cycle efficiency, the daily balance of tae and retu energy, and fuel
costs (for example, the cost of natual gas for expandig air with gas tubine expanders). To
determine the least-cost resource expansion plan, the model accounts for conventional generation
system performance and cost characteristics of the storage resource, including investment cost,
capacity factor, heat rate (if fuel is used), O&M cost, minimum capacity, and maximum capacity.
In PaR, simulations are conducted on a week-ahead basis. The model operates the storage plant
to balance generation and charging, accounting for cycle efficiency losses, in order to end the
week in the same net energy position as it began. The model chooses periods to generate and
retu energy to minimize system cost. It does this by calculating an hourly value of energy for
charging. This value of energy, a form of margial cost, is used as the cost of generation for
dispatch puroses, and is derived from calculations of system cost and unit commitment effects.
For compressed air energy storage (CAES) plants, a heat rate is included as a parameter to
captue fuel conversion efficiency. The heat rates entered in both models represent the use of
PacifiCorp's off-peak coal-fired plants.
Phase 4 entails simulation of each optiized portolio from Phase 3 using the Planing and Risk
model in stochastics mode. The PaR simulation produces a dispatch solution that accounts for
chronological commitment and dispatch constraints. Thee stochastic simulations were executed
for the three CO2 tax levels: none, medium - starting at $19/ton, and low to high - staring at
$12/ton and escalating to $93/ton by 2030. All the simulations used the September 2010 forward
price cures as the expected gas and electrcity price forecast values. This maintains
comparability with the price forecast assumptions used for the 2011 business plan. All the core
cases, coal plant utilization cases, and the high/low economic growt cases, are simulated with
the PaR modeL.
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PACIFiCORP-2011 IR CHAPTER 7 - MODELING APPROACH
The PaR simulation incorporates stochastic risk in its production cost estimates by using a
stochastic model and Monte Carlo random sampling of five stochastic variables: loads,
commodity natural gas prices, wholesale power prices, hydro energy availability, and thermal
unit availability for new resources. (For existing thermal units, planned maintenance schedules
were used.
60) Representation of wid output as a stochastic variable in PaR was ruled out
because of the incremental model ru-time impacts and impracticality of representing the
significant intra-hour fluctuations not captued in hourly data. Although wind resource
generation was not vared in the same way as the other stochastic variables, the hour-to-hour
generation does vary throughout the year, but the pattern is repeated identically for all study
years and Monte Carlo iterations. Note that intra-hour varabilty and associated incremental
reserve requirements and costs are addressed in PacifiCorp's wind integration study, included as
Appendix I in Volume 2.
For stochastic analysis, only the core cases (1-19), coal utilization cases (21_2461), and
alternative load growth sensitivity cases (25-27) were modeled using the Planing and Risk
production cost modeL. In the case of the two Utah solar buy-down sensitivity cases, 30 and 30a,
it is important to note that the Uta distrbuted solar PV resource costs reflect assumed deep
discounts to motivate significant customer program participation. Consequently, these Utah solar
resources are not comparable to other resources on a cost evaluation basis. Similarly, comparison
of stochastic PVRR cost measures for portfolios that include cost buy-down solar resources
relative to those that do not is not meaningful and fails to meet the state IRP Standards and
Guidelines provision to evaluate resources "on a consistent and comparable basis".
The Stochastic Model
The stochastic model used in PaR is a two-factor (short-ru and long-ru) short-ru mean
reverting modeL. Variable processes assume normality or log-normality as appropriate. Since
prices and loads are bounded on the low side by zero they tend to take on a lognormal shape.
Thus, prices, especially, are described as having a lognormal distrbution (i.e. having a positively
skewed distrbution while their loge has more of a normal distribution). Load growth is inerently
more bounded on the upside than prices, and can therefore be modeled as having a normal or
lognormal distrbution. As such, prices and loads were treated as having a lognormal and normal
distribution, respectively. Stochastic parameters may only be modeled as having a normal or
lognormal distrbution using PaR's integrated stochastic modeL.
Separate volatility and correlation parameters are used for modeling the short-ru and long-ru
factors. The short-ru process defines seasonal effects on forward variables, while the long-run
factor defines random structual effects on electrcity and natual gas markets and retail load
regions. The short-ru process is designed to captue the seasonal patterns inerent in electrcity
and natual gas markets and seasonal pressures on electrcity demand.
60 Stochastic simulation of existing thermal unit availability is undesirable because it introduces cost variability
unassociated with the evaluation of new resources, which confounds cornparative portfolio analysis.61 The Case 20 coal utilization portfolio (medium CO2 tax and gas prices) did not result in any coal plant
replacements, so the Company did not consider it worthwhile to conduct a stochastic production cost simulation
with this portfolio.
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PACIFiCORP-201l IR CHAPTER 7 - MODELING APPROACH
Mean reversion represents the speed at which a distubed varable will retu to its seasonal
expectation. With respect to market prices, the long-ru factor should be understood as an
expected equilibrium, with the Monte Carlo draws defming a possible forward equilibrium state.
In the case of regional electrcity loads, the Monte Carlo draws defme possible forward paths for
electrcity demand.
Stochastic Model Parameter Estimation
Stochastic model parameters are developed with econometrc modeling techniques. The short-
ru seasonal stochastic parameters are developed using a single period auto-regressive regression
equation (commonly called an AR(l) process). The standard error of the seasonal regression
defmes the short ru volatilty, while the regression coefficient for the AR(l) variable defines the
mean reversion parameter. Loads and commodity prices are mean-reverting in the short term.
For instance, natual gas prices are expected to "hover" around a moving average within a given
month and loads are expected to hover near seasonal norms. These built-in responses are the
essence of mean reversion. The mean reversion rate tells how fast a forecast wil revert to its
expected mean following a shock. The short-ru regression eITors are correlated seasonally to
captue inter-variable effects from informational exchanges between markets, inter-regional
impacts from shocks to electrcity demand and deviations from expected hydroelectrc
generation performance.
The long ru does not display mean reversion since long-ru volatility is a growth rate (trend)
that progresses steadily over time. Mean reversion is responsible for ultimately dampening
short-ru volatility into long-ru volatility. The long-ru parameters are derived from a "random-
walk with drift" regression. The short- and long-ru parameter estimations are compatible
because both come from the same data but short-ru volatilities are influenced by mean reversion
whereas the long-ru are not. The standard error of the random-walk regression defmes the long-
ru volatility for the regional electricity load variables. However, for this IRP, the long-ru load
volatility parameters were tued off. The justification for this decision is described is the next
section. Use of this parameter drves increasingly higher load excursions and severity of unmet
energy situations (reserve deficiencies and unserved demand) as the Monte Carlo simulation
progresses, and thus becomes one of the most significant portfolio cost drivers. Much of the
focus for out-year portfolio modeling is to appropriately captue the end effects of near-term
resource decisions reflected in the IRP action plan. Consequently, PacifiCorp believes that
dropping the long-ru load volatility parameters results in a more realistic comparison between
portfolios.
Long-term price volatility (i.e., natual gas and electrcity) is estimated using the standard error
of a random walk regression of historic price data, by market. The resulting parameters are then
used in PaR to develop alternative price scenarios around the Company's official forward price
cures, by market, over the twenty-year IRP study period. The long-ru regression errors are
correlated to captue inter-variable effects from changes to expected market equilibrium for
natual gas and electrcity markets, as well as the impacts from changes in expected regional
electrcity loads.
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PACIFiCORP-20ll IRP CHAPTER 7 - MODELING APPROACH
PacifiCorp's econometrc analysis is performed for the following stochastic variables:
. Fuel prices (natual gas prices for the Company's western and eastern control areas)
. Electrcity market prices for Mid-Columbia (Mid C), California ~ Oregon Border (COB)
. Four Corners, and Palo Verde (PV)
. Electrc transmission area loads (California, Idaho, Oregon, Utah, Washington and Wyoming
regions)
. Hydroelectric generation
For this IRP, PacifiCorp only updated its seasonal short-term stochastic load parameters
(volatilities, mean reversions, and cOITelations); its long-term load volatilities were set to zero.
Usually, long4erm load volatility can be thought of as year-on-year growth. For example, in this
IRP, average annual system load growth is forecast at approximately 1.9 percent. Thus, by
setting the long-term load volatilities to zero, only the expected system load growth (~1.9%) is
simulated over the 20-year horizon. The decision to tu off long-term load volatilities is
discussed further in the next section. Typically, for long-term planning puroses, parameter
updating is only needed on an infrequent basis. However, due to changes in the model topology
representation of load, coupled with the recent availability of a well-scrubbed hourly load
dataset62, the Company decided the timing was right to update load parameters.
As seen in Table 7.10 the 2011 short-term load parameters are similar in magnitude to those of
the 2008 IRP. Differences are attbuted to both the vintage and definition of load data used to
estimate parameters. PacifiCorp estimated the 2008 parameters with 48 months of load data
ending September 2005, whereas the 2011 load parameters were calculated using 36 months of
calendar-year data for 2007-2009. PacifiCorp believes that three years of hourly load data is
suffcient for short term stochastic volatilty parameter estimation, and, as noted above, it was
prudent to use the already scrubbed dataset developed for the wind integration study. Moreover,
PacifiCorp estimated the 2008 parameters using jursdictional state load data. In contrast, the
20 11 parameters were estimated using hourly load data as defined by the model topology.
Natual gas and electrcity price correlations by delivery point, as shown in Table 7.11, are the
same as those developed for the 2007 IRP.
Table 7.10 - Short Term Stochastic Parameter Comparison, 2008 IRP vs. 2011 IR
Winter 2011 IRP 0.045 0.028 0.044 0.043 0.021
S ri 2011 IR 0.038 0.037 0.043 0.044 0.017
Sumer 2011 IRP 0.040 0.040 0.051 0.041 0.017
Fall 2011 IR 0.040 0.036 0.046 0.042 0.019
Winter 2008 IRP 0.041 0.026 0.051 0.041 0.025
S rin 2008 IR 0.051 0.028 0.038 0.032 0.022
Sumer 2008 IRP 0.054 0.045 0.053 0.038 0.019
Fall 2008 IR 0.046 0.036 0.040 0.043 0.019
62 As prepared for PacifiCorp's 2010 wind integration study and based on actual load data for 2007 - 2009.
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PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
Winter 2011 IR 0.19 0.10 0.18 0.16 0.07
S rin 2011 IRP 0.02 0.16 0.24 0.21 0.10
Sumer 2011 IRP 0.02 0.10 0.24 0.20 0.07
Fall 2011 IRP 0.03 0.08 0.11 0.1 1 0.05
Winter 2008 IR 0.27 0.23 0.24 0.26 0.13
S ri 2008 IR 0.05 0.09 0.19 0.16 0.10
Sumer 2008 IR 0.08 0.14 0.23 0.28 0.08
Fall 2008 IR 0.23 0.1 7 0.20 0.18 0.10
Table 7.11- Price Correlations
Nat Gas -Four Mid Nat Gas -
East Comers COB Columbia Palo Verde West
Nat Gas - East 1.000 0.304 0.386 0.277 0.371 0.835
Four Comers 0.304 1.000 0.592 0.784 0.817 0.299
COB 0.386 0.592 1.000 0.634 0.564 0.492
Mid Columbia 0.277 0.784 0.634 1.000 0.811 0.312
Palo Verde 0.371 0.817 0.564 0.811 1.000 0.364
Nat Gas - West 0.835 0.299 0.492 0.312 0.364 1.000
Four
Comers COB
Nat Gas - East 0.085 0.034
Four Comers 1.000 0.559
COB 0.559 1.000
Mid Columbia 0.459 0.770
Palo Verde 0.787 0.468
Nat Gas - West 0.025 0.067
Nat Gas-Four Mid Nat Gas-
East Comers COB Columbia Palo Verde West
Nat Gas - East 1.000 0.115 0.074 0.002 0.101 0.908
Four Comers 0.115 1.000 0.705 0.699 0.917 0.132
COB 0.074 0.705 1.000 0.809 0.734 0.1 17
Mid Columbia 0.002 0.699 0.809 1.000 0.696 0.013
Palo Verde 0.101 0.917 0.734 0.696 1.000 0.126
Nat Gas - West 0.908 0.132 0.1 17 0.013 0.126 1.000
Nat Gas-Four Mid Nat Gas-
East Comers COB Columbia Palo Verde West
Nat Gas - East 1.000 0.156 0.233 0.142 0.182 0.795
Four Comers 0.156 1.000 0.458 0.719 0.921 0.244
COB 0.233 0.458 1.000 0.446 0.467 0.299
Mid Columbia 0.142 0.719 0.446 1.000 0.740 0.160
Palo Verde 0.182 0.921 0.467 0.740 1.000 0.281
Nat Gas - West 0.795 0.244 0.299 0.160 0.281 1.000
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P ACIFICORP - 20 11 IRP CHAPTER 7 - MODELING APPROACH
For outage modeling, PacifiCorp relies on the PaR model's Convergent Monte Carlo simulation
method to create a distributed outage pattern for new resources. PacifiCorp does not estimate
stochastic parameters for plant outages. Due to the tre randomness of forced outages the
Convergent Monte Carlo is the prefeITed mode of operation for obtaining results of multi-
iteration Monte Carlo quality. While average historical and/or technology-specific outage rates
are specified by the user the timing and duration of outages is random. The Convergent Monte
Carlo produces fully converged results by rejecting highly unlikely outage combinations in peak
and off-peak hours. As such, it takes fewer iterations and less time to produce robust results.
In its 2008 IRP acknowledgment order, the Public Service Commission of Utah requested that
the Company address the "number of years relied upon for stochastic parameter estimation. ,,63
PacifiCorp performed a literatue search on stochastic electrcity price forecasting models to
glean information on time series sampling periods used for parameter estimation. The tie
periods selected varied from one year to six years depending on the pricing process, time
resolution, and electricity markets studied. A key factor driving the sampling period was a long
enough time series to captue seasonal and mean reversion patterns. For forecasting models
based on hourly to daily time scales, the most common sampling periods were two to four years.
These sampling periods are in line with PacifiCorp's parameter estimation methodology.
Monte Carlo Simulation
Durng model execution, PaR makes time-path-dependent Monte Carlo draws for each stochastic
variable based on the input parameters. The Monte Carlo draws are of percentage deviations
from the expected forward value of the varables, and are the same for each Monte Carlo
simulation. In the case of natual gas prices, electricity prices, and regional loads, PaR applies
Monte Carlo draws on a daily basis. In the case of hydroelectric generation, Monte Carlo draws
are applied on a weekly basis.
The PaR model is configured to conduct 100 Monte Carlo simulation rus for the 20-year study
period, . so that each of the 100 simulations has its own set of stochastic parameters and shocked
forecast values. The end result of the Monte Carlo simulation is 100 production cost rus
(iterations) reflecting a wide range of portfolio cost outcomes.
Unlike the 2008 IRP, the long-term load volatility parameters for the 2011 IRP are set to zero.
PacifiCorp believes this is an improvement to its past stochastic treatment of loads. Key drvers
tend to fall into temporal classifications of short-, medium-, and long-term. Respective
classifications are not confined to convenient time periods but generally can be thought of as
spanning days, months, and years. Table 7.12 summarizes the key drvers with respect to their
temporal classifications.
63 Public Se.rice Commission of
Utah, Report and Order, PacifiCorp 2008 Integrated Resource Plan, Docket No.
09-2035-01, p. 38-39.
187
PACIFiCORP-20ll IR CHATER 7 - MODELING APPROACH
Table 7.12 - Load Drivers by Time Period
Weather
Time of Day
Load Management
Day of Week
Seasonal
Commodity Prices
Economic Growt
New TechnologiesÆnd Uses
Demographics
Fuel Switching
Demand Side Management
Economic Growth
As previously discussed, PaR generates 100 Monte Carlo simulations on natual gas prices,
electrcity prices, regional loads, and hydroelectrc generation. PaR optimizes electricity prices
subject to operating and physical constraints, one of which is a fixed capacity expansion plan.
That is, PaR solves for the most efficient solution subject to a given capacity plan. For short- and
medium-term shocks this is not problematic since capacity is assumed to be fixed anyway and
PaR simply responds to shocks by re-dispatching.
The underlying causes of long-term load changes are fudamental shifts in: technology (e.g.,
electrc cars); demographics (e.g., population); fuel switching (e.g., switching from gasoline
engines to electrc motors); DSM (e.g., energy efficiency, appliance standards); and economic
growth. These long-term shifts require a solution that allows capacity change. But, PaR cannot
re-optimize its capacity additions, which creates a problem when dispatching to meet the more
extreme load excursions often seen in long-term stochastic modeling. Since capacity is not fixed
in the long term, this constraint yields an inefficient static solution. Additionally, several public
stakeholders have raised concerns regarding out-year resource impacts on near-term resource
selection and investment for capacity expansion modeling using System Optimizer. Large load
excursions in the out years, driven by the long-term load volatility parameter, represent a parallel
example of out-year resource influence on portfolio cost. These observations, coupled with the
fact that loads are, by natue, somewhat bounded in the upper tail, led PacifiCorp, in consultation
with its model vendor, Venty, to refine the stochastic modeling process by setting long-term
load volatilities to zero. Note: only long-term load volatilities were affected; long-term price
volatilities were not set to zero.
Figues 7.14 though 7.17 show the 100-iteration frequencies for market prices resulting from the
Monte Carlo draws for two representative years, 2012 and 2020. Note that Monte Carlo draws
are the same for all core case portfolios simulated with the PaR model, since only the medium
electrcity and gas price forecasts are used. Figues 7.18 though 7.23 show annual loads (by
system and load area) for the fist, tenth, twenty-fift, fiftieth, seventy-fift, ninetieth, and
ninety-ninth percentiles. For ilustrtive puroses, system load frequencies were also generated
incorporating the long-term load volatilties from PacifiCorp's 2008 IRP. The results are shown
in FigueFigue 7.25 shows the 25th, 50th, and 75th percentiles for hydroelectrc generation.
188
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
Figure 7.14 - Frequency of Western (Mid-Columbia) Electricity Market Prices for 2012
and 2020
90
~ 80
:8 70
~ 60:i
Õ 50
~ 40
ã: 30::0" 20
l!u. 10
o
2012,,78," "
24 47 71 94 118 141 165 188 212 235 235+
($/MWh)
II
g 50:¡
~ 40:i
Õ 30
~
ã: 20::0"
l! 10u.
60 2020
:::::::"".::2Z:":.:~~::
o
24 47 71 94 118 141 165 188 212 235 235+
($/MWh)
Figure 7.15 ~ Frequency of Eastern (palo Verde) Electricity Market Prices, 2012 and 2020
II 100
i: 90
:8 80
~ 70;:60
~ 50
g 40
~ 30
go 20
it 10
o
2012
26 51 77 103 128 154 179 205 231 256 256+
($/MWh)
189
P ACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
Ul 60c
~ 50
I!
:i 40
õ 30
~
li 20::tr
l! 10u.
2020
o
26 51 77 103 128 154 179 205 231 256 256+
($/MWh)
Figure 7.16 - Frequency of Western Natural Gas Market Prices, 2012 and 2020
2012Ul 80
g 70
~ 60
:i 50
õ 40;:
g 30
GI
5- 20
l! 10u.
o
3 6 10 13 16 20 23 26 30 33
($/MMBtu)
Ul 60co 50
~
:i 40
õ 30
~
li 20::
e 10u.
2020
, ..."3G
o
3 6 10 13 16 20 23 26 30 33
($/MMBtu)
190
PACIFICORP - 2011 IRP CHAPTER 7 - MODELING APPROACH
Figure 7.17 - Frequency of Eastern Natural Gas Market Prices, 2012 and 2020
ti 80
~ 70
l! 60
:: 50
Õ 40~
g 30
Ql
5- 20
l! 10LL
o
2012
3 5 8 11 14 17 20 22 25 28
($/MMBtu)
60 2020tii:0 50;;l!
~.40..
~ 30ui:20Ql:i
~ 10 m1LL
0
3 5 8 11 14 17 20 22 25 28
($/MMBtu)
191
P ACIFICORP - 20 llIR CHAPTER 7 - MODELING APPROACH
Figure 7.18 - Frequencies for Idaho (Goshen) Loads
7,000
6,500
6,00
5,00
~5,00Cl
4,500
4,000
3,500
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~99th '''--l''' 90th -t 75th -I mean---& 25th -B 10th -I1 st
Figure 7.19 - Frequencies for Utah Loads
43,000
40,000
~37,000Cl
34,000
31,000
49,000
46,000
28,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~99th "'''t¡-.90th -t75th -!mean -t25th -B10th _1st I
192
PACIFiCORP-2011 IR CHAPTER 7 - MODELING ApPROACH
Figure 7.20 - Frequencies for Washington Loads
6,300
5,900
5,700
5,00
~5,300
(!
5,00
4,900
4,700
4,500
6,100
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~99th -~90Ui -b75Ui _mean ""25th -B10th -1st I
21,000
Figure 7.21- Frequencies for California and Oregon Loads
20,000
19,000
18,000
~(!
17,000
16,000
15,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~99Ui ~90Ui --75th ..mean ""25Ui -810Ui _1st I
193
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
14,000
Figure 7.22 - Frequencies for Wyoming Loads
12,000
11,000
~(!
10,000
9,000
8,000
13,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
I --99th ~90th -å75th -lmean -å25th -a10th -1st I
100,000
Figure 7.23 - Frequencies for System Loads
95,000
90,000
85,000
80,000
~75,000
70,000
65,000
60,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
I _99th ",mEl""", 90th -i75th _mean -i' 25th -a 10th _1st I
194
PACIFiCORP-2011 IRP CHAPTER 7 - MODELING APPROACH
Figure 7.24 - Frequencies for System Loads (with long-term volatilty)
160,000
140,000
120,000
100,000
80,000
~0 60,000
40,000
20,000
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
I ..99th mm¡gmm90th ~75th -lmean -t-25th --10th -1st I
Figure 7.25 - Hydroelectric Generation Frequency, 2011 and 2020
195
PacifiCorp derives expected values for the Monte Carlo simulation by averaging ru results
across all 100 iterations. The Company also looks at subsets of the 100 iterations that signify
paricularly adverse cost conditions, and derives associated cost measures as indicators of high-
end portfolio risk. These cost measures, and others used to assess portfolio performance, are
described in the next section.
Stochastic Portfolio Performance Measures
Stochastic simulation results for. the optimized portfolios are sumarized and compared to
determine which portfolios perform best according to a set of performance measures. These
measures, grouped by category, include the following:
Cost
. Mean PVR (Present Value of Revenue Requirements)
. Risk-adjusted mean PVR
. lO-year customer rate impact
Risk
. Uttper-tail Mean PVRR
. 5 and 95th Percentile PVR
. Production cost standard deviation
Supply Reliability
. Average annual Energy Not Served (ENS)
. Upper-tail ENS
. Loss of Load Probability (LOLP)
196
P ACIFICORP - 2011 IRP CHAPTER 7 ~ MODELING APPROACH
In addition to these stochastic measures, PacifiCorp reports fuel source diversity statistics and the
emission footprint of each portfolio.
The following sections describe in detail each of these performance measures as well as the fuel
source diversity statistics.
MeanPVRR
The stochastic mean PVRR for each portfolio is the average of the portfolio's net variable
operating costs for 100 iterations of the PaR model in stochastic. mode, combined with the real
levelized capital costs for new resources determined by the System Optimizer modeL. The PVRR
is reported in 2010 dollars.
The net variable cost from the PaR simulations, expressed as a net present value, includes system
costs for fuel, variable plant O&M, unit start-up, market contracts, spot market purchases and
sales, and costs associated with making up for generation deficiencies (Energy Not Served and
reserve deficiency costs; see the section on ENS below for background on ENS.) The variable
costs included are not only for new resources but existing system operations as well. The capital
additions for new resources (both generation and transmission) are calculated on an escalated
"real-Ievelized" basis to appropriately handle investment end effects. Other components in the
stochastic mean PVRR include renewable production tax credits and emission externality costs,
such as a C02 tax.
The PVRR measure captues the total resource cost for each portfolio, including externality costs
in the form of C02 cost adders. Total resource cost includes all the costs to the utility and
customer for the variable portion of total system operations and the capital requirements for new
supply and Class 1 demand-side resources as evaluated in this IRP.
A refinement to stochastic PVR reporting for this IRP is to identify the portion of the PVRR
contributed by stochastic unmet energy costs. This term refers to the sum of reserve deficiency
costs and Energy Not Served (ENS) costs. Reserve deficiencies are priced at $500/MWh, a high
penalty value that incents the model to minimize dipping below operating reserve requirements
specified in the modeL. (The model accounts for WECC operating reserves, regulation reserves,
and operating reserves held for wind integration.) Energy Not Served, described in more detail
below, is a condition where there is insufficient generation available to meet load. A price is also
assigned to unserved load, reflecting the marginal cost of avoiding it.
Risk-adjusted Mean PVRR
Unlike a simple mean PVRR the risk-adjusted PVR also incorporates the expected-value cost
oflow-probability, expensive outcomes.64 This measure-risk-adjusted PVR for short-is
calculated as the stochastic mean PVRR plus the expected value, EV, of the 95th percentile
production cost PVRR, where EV = PVR95 x 5%. This metric expresses a low-probabilty
portfolio cost outcome as a risk premium applied to the expected (or mean) PVRR based on the
100 Monte Carlo simulations conducted for each production cost ru. For past IRPs,
64 Prices are assumed to take on a lognormal distrbution for stochastic Monte Carlo sampling, since they are
bounded on the low side by zero and are theoretically unbounded on the up side, exhibiting a skewed distrbution.
197
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
PacifiCorp's public stakeholders have indicated that avoiding expensive outcomes (upper-tail
risk) should be the key risk metrc for portfolio cost evaluation.
The rationale behind the risk-adjusted PVR is to have a consolidated stochastic cost indicator
for portfolio ranking, combining expected cost and high-end cost risk concepts without eliciting
and applying subjective weights that express the utility of tradig one cost attbute for another.
Ten-year Customer Rate Impact
For this IRP, the Company has adopted a "full revenue requirements" approach for reporting
year by year and cumulative incremental portolio rate impacts for 2011 through 2020.
To derive the rate impact measures, the Company computes the percentage revenue requirement
increase (annual and cumulative 10-year basis) attbutable to the resource portfolio relative to a
baseline full revenue requirements forecast. These revenue requirement figues are then divided
by the retail sales forecast assumed for the 2011 business plan to derive the dollars-per-MWh
rate impacts. The source for the full revenue requirements is the latest baseline forecast prepared
for the Multistate Process (MSP).
The IRP portfolio revenue requirement is based on the stochastic production cost results and
capital costs reported for the portfolio by the System Optimizer modeL. Costs include variable
costs, DSM program costs, existig station fixed costs, and new resource fixed and capital
recovery costS.65 The focus of the rate impact review wil be on the stability of year-to-year
percentage full revenue requirement impacts, as well as the cumulative 10-year total impact.
While this approach provides a reasonable representation of projected total system revenue
requirements for IRP portfolio comparison puroses, it is not intended as an accurate depiction
of such revenue requirements for rate-makig puroses. For example, the IRP revenue impacts
assume immediate ratemaking treatment and make no distinction between curent or proposed
multi-jurisdictional allocation methodologies.
Upper-Tail Mean PVRR
The upper-tail mean PVRR is a measure of high-end stochastic cost risk. This measure is derived
by identifying the Monte Carlo iterations with the five highest production costs on a net present
value basis. The portfolio's reallevelized fixed costs are added to these five production costs,
and the arithmetic average of the resultig PVR is computed.
95t/i and 5t/i Percentile PVRR
The fifth and ninety-fifth percentile stochastic PVRRs are also reported. These PVRR values
correspond to the iteration out of the 100 that represents the fifth and ninety-fifth percentiles on
the basis of production costs (net present value basis), respectively. These measures captue the
extent of upper-tail (high cost) and lower-tail (low cost) stochastic outcomes. As described
65 New IR resource capital costs are represented in 2010 dollars and grow with inflation, and start in the year the
resource is added. This method is used so resources having different lives can be evaluated on a comparble basis.
The customer rate impacts wil be lower in the early years and higher in the later years when compared to customer
rate impacts computed under a rate-making formula.
198
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
above, the 95th percentile PVRR is used to derive the high-end cost risk premium for the risk-
adjusted PVRR measure. The 5th percentile PVR is included for informational purposes.
Production Cost Standard Deviation
To captue production cost volatility risk, PacifiCorp uses the stadard deviation of the stochastic
production cost for the 100 Monte Carlo simulation iterations. The production cost is expressed
as a net present value for the anual costs for 2011 through 2030. This measure is included
because Oregon IRP guidelines require a stochastic measure that addresses the varabilty of
costs in addition to one that measures the severity of bad outcomes.
Average and Upper-Tail Energy Not Served
Certin iterations of a PaR stochastic simulation wil have "energy not served" or ENS.66 Energy
Not Served is a condition where there is insuffcient generation available to meet load because of
physical constraints or market conditions. This occurs when the iteration has one or more
stochastic variables with large random shocks that prevent the model from fully balancing the
system for the simulated hour. Typically large load shocks and simultaneous unplanned plant
outages are implicated in ENS events. (Deterministic PaR simulations do not experience ENS
because there is no random behavior of model parameters; for example, loads increase in a
smooth fashion over time.) Consequently, ENS, when averaged across all 100 iterations, serves
as a measure of the stochastic reliability risk for a portfolio's resources.
For reporting of the ENS statistics, PacifiCorp calculates an average annual value for 2011
through 2030 in Gigawatt-hours, as well as the upper-tail ENS (average of the five iterations
with the highest ENS). Results using the $ 1 9/ton CO2 tax scenaro are reported, as the tax level
does not have a material influence on ENS amounts.
For valuing ENS, PacifiCorp recognizes that, in practice, the planning response to significant
ENS is different for short-ru versus long-ru ENS expectations. In the short-ru, the Company
would have recourse to few remedial options, and would expect to pay a large premium for
emergency power. On the other hand, the Company has more planning options with which to
respond to long-term forecasted ENS growt, including acquisition of peaking resources.
Consequently, a tiered pricing scheme has been applied to ENS quantities generated by the
Planning and Risk modeL. The ENS cost is set to $400/M (real dollars) for the first 50
GWhyr of ENS, $2001M for the next 100 GWhyr, and $1001M for all quantities above
150 GWhyr. For large forecasted ENS quantities that occur in the out years of the study period,
the acquisition of peaking generation would become cost-effective, with the $ 100/MWh
reflecting the long-ru all-in cost for such generation.
Loss of Load Probabilty
Loss of Load Probability is a term used to describe the probability that the combinations of
online and available energy resources cannot supply suffcient generation to serve the load peak
durng a given interval of time.
For reporting LOLP, PacifiCorp calculates the probability of ENS events, where the magnitude
of the ENS exceeds given threshold levels. PacifiCorp is strongly interconnected with the
66 Also referred to as Expected Unserved Energy, or EUE.
199
PACIFiCORP-20ll IR CHAPTER 7 - MODELING APPROACH
regional network; therefore, only events that occur at the time of the regional peak are the ones
likely to have significant consequences. Of those events, small shortfalls are likely to be resolved
with a quick (though expensive) purchase. In Chapter 8, the proporton of iterations with ENS
events in July exceeding selected threshold levels are reported for each optimized portfolio
simulated with the PaR modeL. The LOLP is reported as a study average as well as year-by-year
results for an example theshold level of 25,000 MW. This theshold methodology follows the
lead of the Pacific Northwest Resource Adequacy Foru, which reports the probabilty of a
"significant event" occurng the winter season.
Fuel Source Diversity
For assessing fuel source diversity on a sumar basis for each portfolio, PacifiCorp calculated
the new resource generation shares for thee resource categories as reflected in the System
Optimizer expansion plan:
. Thermal
. Renewables
. Demand-side management
The shares were calculated from the generation for 2020 by resource category. Since the
resource mix beyond 2020 is heavily influenced by the addition of generic growth resources,
generation shares for these years are not paricularly usefuL.
Initial Screening
As noted earlier, PacifiCorp conducted stochastic simulations of all the core cases, along with the
coal plant utilization cases and the high/low economic growth cases (a total of26 portfolios). For
prefeITed portfolio selection, the Company focused on stochastic performance of the 19 core
cases. For initial screening, PacifiCorp applied the following decision rule for identifying
portfolios with the best combination oflowest mean PVR and lowest upper-tail mean PVRR.
For each C02 tax scenaro:
. select the portfolio with the lowest mean PVRR as well as portfolios within $500 milion
of the least-cost portfolio;
. select the portfolio with the lowest upper-tail PVRR as well as portfolios within $500
millon of the least-cost portfolio, and then;
. select portfolios within both least-cost groups as the top performers for the CO2 tax
scenario.
All portfolios identified as top performers for the four cost comparisons pass the initial
screening.
200
PACIFiCORP-2011 IR CHAPTER 7 - MODELING APPROACH
In addition to the three CO2 tax scenarios, the screening decision rule is applied to the cost
averages for the three CO2 cost scenarios.
The mean and upper-tail portfolio cost comparisons, as well as the top-performing portfolios, are
shown graphically with the use of scatter-plot graphs. Figue 7.26 ilustrates the application of
the decision rule for the zero C02 tax scenaro results.
Figure 7.26 - Ilustrative Stochastic Mean vs. Upper-tail Mean PVR Scatter-plot
ZeroCOi Tax
33.5
33.0
ase 15
-;c
.!2 32.5=
:õe
~
c 32.0.-
~
==.-¡-..
~ 31.
::
31.0
Case 13
11+
Case 14
~
Case 10
30.5
26.0 26.5 27.0 27.5 28.0 28.5 29.0 29.5
Stochastic Mean PVR ($ bilions)
Final Screening
The optimal portfolios for the three CO2 cost scenaros plus the cost averaging view are
evaluated based on the following primary criteria and measures:
· Risk-adjusted PVRR
· Frequency of inclusion in the optimal portfolio group across CO2 cost scenaros
. lO-year customer rate impact
· Carbon dioxide emissions (generator plus net market transaction contrbution)
· Supply reliability - average annual Energy Not Served and upper-tail mean (ENS)
201
P ACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
Secondary measures include the following:
. 5th Percentile PVRR
. Production cost stadad deviation
. Resource Diversity
The top two portfolios on the basis of the fial screen are subjected to a deterministic risk
assessment (Phase 6) as the final step before preferred portfolio selection.
The purose of Phase 6 is to determine the rage of deterministic costs that could result given a
fixed set of resources under varg gas/electrcity price and C02 cost assumptions, the two main
sources of portfolio risk. It is used to help validate the selection of the prefeITed portfolio
resulting from the final screening step.
PacifiCorp used the System Optimizer to determine PVRs for the top-performing portfolios for
10 combinations of C02 and natual gas/electricity price scenarios. These price scenario
combinations are shown in Table 7.13.
Table 7.13 - Deterministic Risk Assessment Scenarios
Medium
Low
Low
Low
Medium
Medium
Medium
Hi
Hi
Hi
Based on phases 5 and 6, a provisional prefeITed portfolio is selected. For phase 7, the Company
looks at fine-tuing the provisional preferred portfolio based on analysis of key resource
acquisition and regulatory compliance risks. These risks, and the approach for factoring them
into prefeITed portfolio resource selection, are described below.
Gas Plant Timing
The major resource timing issue for this IRP pertins to a second Uta CCCT targeted for a 2016
acquisition in the Company's 2011 business plan. The IRP portfolios have not been designed to
202
P ACIFICORP - 2011 IR CHAPTER 7 - MODELING APPROACH
isolate acquisition timing implications for an individual major resource and then determine
economic benefits of resource defeITal or advancement using stochastic production cost
simulation. The purose of ths acquisition risk analysis is to determine if a 2016 in-service date
continues to be cost-effective considering stochastic risks, and, adjust if warranted, CCCT timing
for the preferred portfolio.
Geothermal Development Risk
As expected, portfolio modeling found geothermal to be cost-effective based on the resource
potentials and costs cited in a Black & Veatch/Geothermix report for PacifiCorp (See Chapter 6).
In IRP public meetings PacifiCorp cited uncertinty concerning development cost recovery
among its state jursdictions (with the possible exception of Utah) as a significant baITier to
exploitation of this resource. The Company addresses geothermal development risk as a non-
modeling consideration for selecting preferred portfolio resources.
Regulatory Compliance Risk and Public Policy Goals
The last risk assessment area is uncertainty regarding public policy and specific regulations
pertining to renewable energy acquisition and greenhouse gas reductions. For this final analysis,
PacifiCorp determines whether the preliminary preferred portfolio is positioned for addressing
regulatory compliance risks and aligns with expected long-term public energy policy goals. To
accomplish this, the Company evaluated the renewable energy mix of the core case portfolios
that performed the best at minimizing high-cost outcomes (that had the lowest stochastic upper-
tail mean PVR). These portfolios served as benchmarks for developing a single out-year
renewable resource schedule that is then integrated into the preliminar preferred portfolio. This
renewable resource schedule is also compared with one needed to comply with the Waxman-
Markey renewable targets-one of the scenarios investigated as part of the acquisition path
analysis described in Chapter 9. This approach aligns with the methodology the Company used
to develop a risk reduction cost credit for energy effciency, described in Chapter 6. The
approach also recognizes the importnce of strategic positioning in the out-years given the lin to
transmission planning and the public policy goal of transitioning to a clean energy futue.
203
PACIFICORP - 2011 IR CHAPTER 8 - MODELING RESULTS
CHAPTER 8 -MODELING AND PORTFOLIO
SELECTION RESULTS
d on combinatio
ios) exhibited m
2 DSM) represents the largest resour
ross the portfolios through 2030. Cum
18
300 200 200 200
5 5 5 5 5 5 5
57 20 97
1I0 liS 122 124 126 120 122 125 125 134 13 141
4 3 3
4 4 4 4 4 4
1.429 1190 1149 775 822 967 695 995 71)0 750 750 750 751)
li 95 201 975 1150
205
PACIFiCORP-20ll IRP CHATER 8 - MODELING RESULTS
This chapter reports modeling and performance evaluation results for the portfolios developed
with alternate input assumptions using the System Optizer model and simulated with the
Planning and Risk modeL. The preferred portolio is presented along with a discussion of the
relative advantages and risks associated with the top-performg portfolios.
Discussion of the portfolio evaluation results falls into the following two main sections.
. Preferred Portfolio Selection - This section covers: (1) development of the core case
portfolios, (2) stochastic production cost modeling results for these portfolios, (3) portfolio
screening results (initial and final screens), (4) evaluation of the top-performing portfolios,
includig the deterministic risk assessment, and (5) preferred portfolio selection.
. Portfolio Sensitivity Analysis - This section covers development and analysis of sensitivity
portfolios relative to a base portfolio, as well as the coal plant utilzation study and Energy
Not Served price sensitivity study.
Core Case Portfolio Development Results
Table 8.1 shows the cumulative capacity additions by resource tye for each of the core cases for
years 2011-2030. Megawatt amounts for front office transactions and growth resources represent
anual averages: 20 years for FOT, and 10 years for growth resources. (The detailed portfolio
resource tables are included in Appendix A, along with PVRR results.)
Resource Selection
Resource selection patterns across portfolios include the following:
Gas Resources
. Every portfolio has a CCCT (Nort Utah, wet-cooled 2xl F class) selected in 2014. Also
noteworty is that under the low economic growth scenaro, a CCCT was selected for 2014.
. A second CCCT is selected predominately for 2015, although a number of portfolios include
a CCCT in 2016 or 2018. The timing is on the "knife edge", and is driven primarly by
natual gas prices. All the high gas price cases have the CCCT added in 2016 or 2018. Under
the low economic growt scenaro (Case 25), the second CCCT was deferred to 2018.
. A third CCCT is generally selected in 2019 (H class, located in Utah) under low and medium
natual gas price scenarios. Under high gas price cases, the model replaces the third CCCT
with west-side geothermal and additional DSM resources in both the east and west.
206
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PACIFiCORP-20ll IR CHAPTER 8 - MODELING RESULTS
Demand-side Management
. Energy efficiency (Class 2 DSM) represents the largest resource through 2030 on an average
capacity basis across the portfolios, followed by CCCTs.
. Energy efficiency additions occur steadily thoughout the simulation period; varability across
portfolios is not large, and is within a range of about 330 MW.
. Greater reliance on energy efficiency relative to the 2008 IRP is due to larger forecasted
potential amounts and the application of new or updated cost credits, along with a switch to a
"Utility Cost" basis for Utah resources (See Chapter 6).
. The model selected an average of 160 MW of dispatchable load control (Class 1 DSM) across
the core case portfolios though 2030, with the bulk added in 2012 in the east and 2013 in the
west.
Geothermal
. Geothermal is heavily exploited, particularly in the near term, due to favorable baseload
economics, availability of the federal production tax credit which is assumed to end by 2015,
state renewable energy targets, and lack of competition from Wyoming wind until 2018 when
Gateway West is assumed to be in service.
. The Utah Blundell geothermal resource-proposed unit 3 and additional expansion at
Roosevelt Hot Springs for a total of 80 MW-is selected in every portfolio; unit 3 is selected in
the earliest year available, 2015, while the remaining resource is acquired by 2020.
. Geothermal resources at new sites in the east (greenfield development) totaling 35 MW, and
west-side greenfield geothermal (ranging from 70 to 560 MW, are selected in all but two
portfolios. Either CO2 costs or state RPS requirements are needed to prompt selection of west-
side geothermal selection in 2015.
. Higher CO2 cost scenarios-"High" and "Low to Very High"-dives the model to rely on
west-side geothermal by 2020.
Wind
. Consistent with wind selection patterns for the 2008 IRP portfolios, this resource exhibited the
most variability, ranging from none selected in Case 2 (no RPS requirement) to 2,730 MW in
Case 17 (C02 emission hard cap with high gas prices).
. Reliance on wind is diminished overall across the portfolios relative to the 2008 IRP core case
portfolios due to changes in the assumed duration of federal renewable PTC (extension to 2015
or 2020 for the 2011 IRP, versus extension to the end of the 20-year simulation period for the
2008 IRP), as well as lower staring points for CO2 tax values.
Front Office Transactions
. All the portfolios exhibit the same anual acquisition pattern for front office transactions
through 2014, increasing to a peak of about 1,420 MW in 2013, and then decreasing to a low of
about 750 MW post-2020. Variability between 2015 and 2020 averages about 330 MW across
the portfolios. Figue 8.1 shows annuallO-year trends for FOT by portfolio. The lO-year trend
for the 2008 IRP preferred portfolio is shown with the red dashed line, indicating that reliance
on FOT is significantly reduced beyond 2017 for the 2011 IRP core portfolios.
208
PACIFiCORP-201l IRP CHATER 8 - MODELING RESULTS
Figure 8.1- Front Offce Transaction Addition Trends by Portolio, 2011-2020
1,800
1,600
1,400
1,200
oni
~1,000....::,;
"g 800
D-IIU
600
400
200
;¡~,pm"" .;i"i"~
-+Case1
_Case2
~Case3
-*Case4
~Case5
~Case6
""Case7
II
-Case 8
WWøwøø=, Case 9
..Case10
_Case 11
~Case13
~Case14
~Case15
W"Ø~'W'$ Case 16
""Case17
WW$W$W= Case 18
~Case19
~ 2008 Preferred Portfolio
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Distrbuted Generation
. The model selected solar hot water heating resources in all portfolios, with additions of about
4.5 MW per year through the mid-2020s. For the east-side and west-side, the model was
allowed to select up to 3.1 MWand 1.8 MW per year, respectively. The tyical annual values
selected were 2.6 MW for the east-side and the full 1.8 MW amount for the west-side.
. The model consistently added 104 MW of biomass-based combined heat & power (CHP) for
the portfolios by 2030; a small amount of reciprocating engine-based CHP was also added,
averaging a cumulative 4 MW by 2030 across the portfolios.
Nuclear, Coal Plant Carbon Captue & Sequestration, and Energy Storage
. Nuclear and coal plant carbon captue & sequestration (CCS) resources were allowed to be
selected only in 2030. Nuclear was selected in three portfolios, requiring high gas cost
assumptions and aggressive carbon regulation in the form of the "Low to Very High" CO2 tax
levels or a C02 emission hard cap.
· The model selected no energy storage resources in any of the portfolios.
Carbon Dioxide Emissions
Figues 8.2 through 8.6 show annual portfolio emission reductions by C02 tax and policy tye.
Figue 8.2, which shows the medium C02 tax portfolios, also includes the 2011 IRP preferred
portfolio described later in this chapter. The 2005 system emission baseline amount of 61 milion
short tons is also shown for reference puroses. The System Optimizer emission quantities account
for generation as well as market purchases (front offce transactions, spot market transactions for
system energy balancing, and growth resources). Note that the significant drop in emissions in
209
PACIFiCORP-20ll IR CHAPTER 8 - MODELING RESULTS
2015 is due to the sta of the assumed CO2 tax. Large emission reductions in 2030 are due to the
addition of clean baseload resources (nuclear and coal plant CCS retrofits), which are only
available in that year. While this represents an optimation end effects issue, is does highlight the
impact of such resources on the C02 emissions footprit.
Figure 8.2 - Annual C02 Emissions: Medium C02 Tax Scenario
65.0
62.5
60.0
i57.5
55.0ÕU52.5,Ulc~50.0....0 47.5.iIIÕ 45.0UlC
~42.5
~40.0
37.5
35.0
32.5
30.0 ~~#~#~~#~~#~#~#~~~~~
~Preferred
C02 Cases - Medium
~Case-03 u#Æ--Case-07 -Case-ll ...~w-Case-19
210
PACIFiCORP-20ll IR CHATER 8 - MODELING RESULTS
Figure 8.3 - Annual C02 Emissions: High C02 Tax Scenario
65.0
62.5
60,0
57.5
N 55.00U52.5,UICti....0.con..0 45.0UIC
~42.5
~40.0
37.5
35.0
32.5
30,0
~'"..i:..i:"''' ..i:~1'..'" ..i:.... ..i:~~..i:~"..i:~'"..i:~..i:ri'"..i::C..i:~'òl'rii:..i:~l'~l'ri'ò..i:~..i:r!i:l'~.,..i:
C02 Cases - High
-'Case-04 --Case-OS -0~~Case-12
Figure 8.4 - Annual C02 Emissions: Low to Very High C02 Tax Scenario
65.0
62.
60.0
57.5
Õ55.0
U 52.5,UIc~50.0
t:0 47.5.con..0 45.0UIC
~42.5
~40.0
37.5
35.0
32.5
30.0
..i:"''' ..i:.y 1'~~..i:ri'"l'~..i:~'"..i:~..i::C..i:ri"..i:ri'"..i:ri'ò..i:~..i:r!i:l'~'ò..i:~.,..i:rii:..i:..i:.... ..i:~~..i:
C02 Cases - Low to Very High
--Case-OS --Case-06 -Case-09 -Case-10 -Case-13 --Case-14
211
PACIFiCORP-20ll IR CHAPTER 8 - MODELING RESULTS
Figure 8.5 - Annual CO2 Emissions: Hard Cap Scenarios
65.0
62.5 .
60.0
57.5
Õ55.0
1.52.5.IIi:ti 50.0....0 47.5.:II
'So 45.0IIi:
~42.5
~40.0
37.5
35.0
32.5
30,0 ~~~~#~~~~~#~~~~#~~~~
C02 Cases - Hard Cap
~Ca5e-15 -Case-16 wo.ww.Case-17
Figure 8.6 - Annual CO2 Emissions: No CO2 Tax
._......................._~._""_....'...,.,......_...
65.0
62,5 ................_--_...............-........_----_..........._--_............-......._..__._--~._..-.....~.-------------------------------------------------60.0~.......-_...._.............................................
57.5
55.0 _......-....Õ1.52.5 -,..._-'."...__._..-_................._...__....__........................_...-_..................._...._-_....__....._...........-.........................~..IIi:
ti 50.0 _....,._............._-_...............~._.._~.._..............__.._.................
t:0 47.5 ..~-_.._-~..-..-.:II..0 45,0IIi:
~42.5 --_..----~
~40.0 --
37.5
35.0 ........_~-~
32.5
30.0 ~~-~----"~,'!-~~--l-~~'
~"~'\S'S"~~'"y ~'b ~ri'"ri":V ~~~ri'":C ri'b ri'":!'"
'\'"'\'"'\'"'\'"'\'"'\'"'\'"'\'"'\'"'\'"'\'"'\'"-s '\'"~'\'"'\'"'\'"'\'"~
C02 Cases - None
-Case-Ol -Case-02
212
PACIFiCORP-2011 IRP CHATER 8 - MODELING RESULTS
Initial Screening Results
Figue 8.7 shows the upper-tail cost versus mean cost scatter-plot chart for the zero CO2 tax
scenario.67 The red line demarcates the group of four portfolios-eases i, 2, 3, and 7--esignated
as superior with respect to the combination of upper-tail and mean cost using the $500 milion
threshold for both mean PVRR and upper-tail mean PVR.. For example, case 6 was excluded
because its mean PVRR difference relative to the top-performing portfolio (case 2) was $584
milion, exceeding the $500 milion threshold. (As a reminder, all stochastic production cost rus
are based on the medium natual gas price forecast.) Note that PacifiCorp excluded some of the
hard cap portfolios from the charts-for example, Cases 17 and 18-due to outlying PVRs that
impacted legibility. Appendix E includes scatter-plot graphs showing all core case portfolios.
Portfolios in the top-performing group were more reliant on gas, distrbuted generation, and front
offce transactions (in the out-years) relative to the others, and less reliant on energy effciency,
wind, and geothermal resources.
Figure 8.7 - Stochastic Cost versus Upper-tail Risk, $0 C02 Tax Scenario
Zero CO2 Tax
33.5
31.0
+
Case 15
Case !9 Case 13
.~,"._.H_'''_''"Case 12
!"'\
Case 8
Case4 Cai 11.
Case5 ~~OI Case9
Case 14
"......-.,,"_...__H.......~/
Case 2. Case I
3.IK ..
Ca Case 10
:ase7/ Case 6
33.0
'V0:~ 32.5
:Ee
~
~= 32.0
....::
:;
E-..
~ 31.5
~
30.5
26.0 26.5 27.0 27.5 28.0 28.5 29.0 29.5
Stochastic Mean PVR ($ bilions)
67 PacifiCorp recently updated the Case 13 and 14 portfolios to correct for a natual gas price input error. The
stochastic results have not been updated, but the PVR for Case 14 would be expected to increase due to the revised
resource mi.
213
PACIFiCORP-2011 IR CHATER 8 - MODELING RESULTS
Outler portfolios, Cases 12 and 13, include large quatities of clean generating capacity; almost
2,600 MW of wind in the Case 12 portfolio, and 3,200 MW of nuclear capacity and 1,700 MW of
wind in Case 13.
Figue 8.8 shows the mean cost versus upper-tail cost scatter-plot chart for the medium ($19/ton)
C02 tax scenario. Two of the C02 hard cap portolios (Cases 17 and 18) were excluded from the
char because they resulted in extreme outlyig PVR. The red line demarcates the nine
portfolios-I, 2,3,4,5,6, 7, 9, and l5--esignated as superior with respect to the combination of
upper-tail and mean cost.
Portfolios in the top-performing group were more reliant on gas and front office transactions, and
less reliant on wind and geothermal resources.
Figure 8.8 - Stochastic Cost versus Upper-tail Risk, Medium CO2 Tax Scenario
$19C02Tax
42.0
'V 41.i=o
~e.:'"=..
1: 41.0
iS
~
¡t
~. = 40.5....:i
~..
~
;; 40.0
Case 16
Case 19
Case 13.II
I Case 12
Case 10 Case 14
39.5
34.5 35.0 35.5 36.0 36.5 37.0
Stochastic Mean PVRR($ bilions)
214
PACIFiCORP-20ll IR CHATER 8 - MODELING RESULTS
Figue 8.9 shows the mean cost versus upper-tail cost scatter-plot chart for the Low to Very High
C02 tax scenario ($12/ton escalating to $93/ton by 2030). Two of the CO2 hard cap portfolios were
again excluded from the chart because they resulted in extreme outlyig PVR results. Cases 1,3,
5,6, 7, 9, and 15 have the lowest combination of upper-tail and mean COSt.
Portfolios in the top-performing group were more reliant on gas, but less reliant on wind,
geothermal, and energy effciency than the others.
Figure 8.9 - Stochastic Cost versus Upper-tail Risk, Low to Very High C02 Tax Scenario
$12 CO2 Tax (low to very high)
44.0
.
Case 16
,.."~~,,...._.....
....,.."'..._--_._..
"" Case 19
Case8
Case 2_.. Case4 +Casell
-roo . ,-,,~A .
Case3 ..~:. .. case;\\.CaseS.0.7
\,. Case 12
base IS
C:~iCase6Case 10~
43.5
'Vi=~ 43.0
:õe
~
5:= 42.5
Ol
~
:;....
~ 42.0
;:
41.5
41.0
35.0 35.5 36.0 36.5 37.0 37.5
Stochastic Mean PVRR($ bilions)
Figue 8.10 shows the mean cost versus upper-tail cost scatter-plot chart for the averaged PVRR
results across the CO2 tax scenarios. Averaging cost results for the thee CO2 cost scenarios yields
a tighter clustering of portfolios. Cases selected as the top-performers include 1,2,3,4,5,6, 7, and
9.
215
P ACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
Figure 8.10 - Stochastic Cost versus Upper-tail Risk, Average of CO2 Tax Scenarios
Average of CO2 Tax Levels
40.5
37.5
Case 16~-
.
"--..................
Case 15
~
r~....~.: CaseR
Case 19
Case 10 Case,.~, .0
Case2 Caseis;;'';:)\."..,,":~:Case ii
W
Case 12
Case 3 .""_"_"''':'ON_.~m.._.",_,,~,
Case 7 \\
40.0
~ 39.5
i:
2
:Beg¡ 39.0
~"..
~38.5.;
..
~
-- 38.0
37.0
32.0 32.5 33.0 33.5 34.0 34.5
Stochastic Mean PVRR ($ bilions)
Based on the mean versus upper-tail cost comparisons, PacifiCorp selected eight of the 19 core
case portfolios for the final screening-I, 3, 4, 5, 6, 7, 9, and 15. The Case 2 portfolio does not
comply with state renewable portfolio stadards, and was therefore rejected as a preferred portfolio
contender. (Note that stochastic cost and risk measures are reported for this portfolio in Appendix
E.) Table 8.2 summarizes the selection results for each of the CO2 tax scenarios and the averaged
results across CO2 tax scenarios.
Table 8.2 - Initial Screening Results, Stochastic Cost versus Upper-tail Risk
216
P ACIFICORP - 2011 IRP CHATER 8 - MODELING RESULTS
Final Screening Results
Risk-adjusted PVRR
Table 8.3 reports the risk-adjusted PVR results for the eight case portfolios by CO2 tax scenario
selected for final screening. In addition to rankgs, the table shows the cost spread between a case
portfolio and the lowest-cost case portfolio for each C02 tax scenaro group. Cases i and 3 have
the lowest risk-adjusted PVR under the $0 and Medium C02 tax scenaros, whereas Cases 3 and
6 have the lowest values under the Low to Very High scenario. On an average cost basis (two
colums far right), Cases 3 and 7 perform the best.
Table 8.3 - Portfolio Comparison, Risk-adjusted PVR
I 27,819
3 27,808
4 28,207
5 28,194
6 28,182
7 27,842
9 28,323
15 28,882
10-year Customer Rate Impact
Table 8.4 reports the lO-year customer rate impacts for the eight case portfolios by CO2 tax
scenario. Rate impacts are expressed as thelO-year cumulative percentage increase relative to the
2010 forecasted system full revenue requirements.
Table 8.4 -Portfolio Comparison, to-year Customer Rate Impact
i 22.62%
3 22.57%
4 22.88%
5 22.68%33.59%
6 23.26%34.01%
7 22.66%33.56%
9 22.89%33.79"10
15 24.06%33.75%0.27%
217
PACIFiCORP-20ll IR CHATER 8 - MODELING RESULTS
The Case 3 portfolio performs the best across all C02 tax scenarios, followed by the Case 1 and
Case 7 portfolios.
Cumulative Carbon Dioxide Emissions
Table 8.5 reports the PaR model's cumulative 20-year generator CO2 emissions (average of the
100 Monte Carlo iterations) for each of the eight portolios. The Case 5 and 6 portfolios have the
lowest emissions among the non-hard cap portolios. As discussed above, the hard cap cases are
modeled with shadow emission prices from System Optimier rather than the C02 tax values used
for the other cases (See Table 7.4). While the Company adjusted portfolio costs for the hard cap
cases to reflect the C02 tax scenaro values, the emissions are drven by the shadow costs.
Table 8.5 -Portfolio Comparison, Cumulative Generator C02 Emissions for 2011-2030
1 941,203
3 937,901
4 930,958
5 929,942
6 924,985
7 938,503
9 930,726
15 814,681
Supply Reliability
Table 8.6 reports two measures of stochastic supply reliability: average annual Energy Not Served
(ENS) and ùpper-tail mean Energy Not Served. The portfolios for Case 5 and 6 perform the best
on these two measures. These results are for the $l9/ton C02 tax scenaro. Differences are not
material between CO2 tax scenaros.
Table 8.6 - Portfolio Comparison, Energy Not Served
I
3
4
5
6
7
9
15
218
PACIFiCORP-201l IRP CHAPTER 8 - MODELING RESULTS
Resource Diversity
Table 8.7 reports the generation shares for each portfolio by resource category for 2020. The
resource categories include thermal, renewable, and DSM. The Case 6 portfolio has the highest
renewable generation share due to more wind resources, but has the lowest share of DSM.
Portfolios for Case 1 and 9 have high renewable shares reflecting the addition of a 50 MW utility-
scale biomass resource. The Case 1 and 7 portfolios have the highest shares of renewables and
DSM combined, at a respective 40.4 percent and 40.2 percent.
Table 8.7 - Generation Shares by Resource Type, 2020
1 51.8%10.9%29.5%40.4%
3 61.%8.6%24.2%32.8%
4 61.1%8.5%24.3%32.8%
5 60.7%8.7%24.5%33.1%
6 58.3%12.8%22.9%35.7%
7 52.3%10.4%29.7%40.2%
9 52.9%10.3%29.4%39.7%
15 61.1%8.6%24.2%32.8%
Final Screening and Preliminary Preferred Portfolio Selection
Selection of the Top Three Portfolios
PacifiCorp narowed down the eight portfolios to three top candidates for preliminary preferred
portfolio selection. Table 8.8 summarizes the performance of the thee portfolios selected--ases
1, 3, and 7-based on the various primary and secondary portfolio performance measures
described in Chapter 7:
Table 8.8 - Top-three Portfolio Comparison, Final Screening Performance Measures
Least -cost/least-risk
group (initial screening)
One of only thee portolios
selected in all four least-
cost/least risk groups (See
Table 8.2
Ranked first under the $0,
Medium, and averaged CO2
tax scenaros; ranked second
under the Low to Very High
CO2 tax scenaro
Risk~adjusted cost
219
PACIFiCORP-20ll IR CHATER 8 - MODELING RESULTS
10-year customer rate Raed second under the Raed first under all CO2 ta Ranked second under the
impact $0 and averaged CO2 ta scenanos Medium and Low to Very
scenaros; raed third High CO2 tax scenarios;
under Low to Very High ranked third under the $0
CO2 ta scenaro and averaged CO2 tax
scenanos
CO2 Emissions Not among the top three Not among the top three Not among the top thee
portfolios; highest portolios; lowest emissions portfolios; second after
emissions among Case 1,among Case 1,3, and 7 Case 3 on emissions
3, and 7 ortfolios ortolios
Supply Reliability Not among the top thee Not among the top thee Not arnong the top thee
(Energy Not Served)portfolios; highest mean portolios; lowest mean and portolios; second after
and upper-tail mean ENS upper-tail mean ENS among Case 3 on mean and
among Case 1, 3, and 7 Case 1,3, and 7 portolios upper-tail mean ENS
ortolios
Resource Diversity Highest combined Not among the top thee Second highest combined
renewable/DSM portolios renewable/DSM
eration share for 2020 eneration share for
Ranked second under the Ranked first under the Ranked third under the
$0, Medium and averaged Medium and averaged CO2 tax Medium and averaged
CO2 tax scenaros; ranked scenaros; raned second CO2 ta scenaros; ranked
four under the Lòw to under the Low to Very High four under the $0 tax
Very High CO2 ta CO2 ta scenaro, and third scenario and fifth under
scenaro under the $0 CO2 tax scenaro the Low to Very High
(Rnked four to seventh (Ranked four or fifth among CO2 tax scenaro (Raned
among all 14 core case all 19 core case portolios)sixth to eighth among all
ortolios 19 core case ortfolios
Production Cost Not among the top three Not among the top thee Raned fist under the $0
Standad Deviation portfolios portolios CO2 ta scenaro; ranked
second under the
averaged $0 CO2 tax
scenaro; ranked third
under the Medium and
Low to Very High CO2
tax scenarios
Deterministic Risk Assessment
PacifiCorp selected the Case 1 and Case 3 portfolios for deterministic risk assessment. Table 8.9
reports the deterministic PVR results of ruing each portfolio through the System Optimizer
model with the 10 combinations of C02 ta and natual gas price assumptions.
The reason that the Case 7 portfolio was excluded was because resource differences between this
portfolio and the Case 3 portfolio were relatively small, primarily limited to the amount of DSM-
35 MW more DSM in Case 7-and the timing and location of out-year growth resources (see
Table 8. lOa). In contrast, the Case 1 and Case 3 portfolios exhibit more significant resource
differences; specifically a one-year shift in the timig of the first CCCT, 100 MW more DSM in
Case 3, and a 50 MW biomass plant in Case 1 that was not included in Case 3 (Table 8. lOb ).
220
PACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
As shown in Table 8.9, the PVR for the Case 3 portfolio is lower than that for the Case i
portfolio under all but the Case 1 defmition.
Table 8.9 - Deterministic PVRR Comparison for Case 1 and Case 3 Portfolios
1 None ($0)
3 Medium ($19) Low $39,752
4 High ($25)Low $4,717 $4,651
5 Low to very high ($12)Low $4,443 $4,398
7 Medium ($19) Medium $41,099 $41,074
8 High ($25)Medium $4,284 $4,221
9 Low to very high ($12)Medium $41,869 $41,815
11 Medium ($19) High $42,398 $42,337
12 High ($25)High $47,548 $47,456
13 Low to very high ($12)High $43,226 $43,142
Minirm $30,936 $30,978
Maxim $47,548 $47,456
Mean $41,827 $41,765
Average of medium CO2 cases $41,083 $40,997
Average of high CO2 cases $4,183 $46;IIO
Average oflow to very high C02 cases $41,846 $41,785
221
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2
PACIFCORP-20ll IR CHAPTER 8 - MODELING RESULTS
Preliminary Preferred Portfolio Selection
Based on the PVR cost/risk, CO2 emissions, supply reliability measures, and deterministic risk
assessment, the Case 3 specification resulted in the best cost/risk portfolio.
Acquisition Risk Assessment
Combined-cycle Combustion Turbine Resource Timing
PacifiCorp evaluated the deferral value of moving the dr-cooled CCCT proxy resource (assumed
to be located at the Currant Creek site) from 2015 to 2016. As noted in the methodology chapter,
the portfolios developed for stochastic production cost simulation do not isolate the impact of
CCCT acquisition timing. Also, while all portfolios included a CCCT in 2014, one of the preferred
portfolio candidates (Case 1) included a second CCCT in 2016, indicating that the decision to
acquire the CCCT in 2015 or 2016 is driven by economic considerations. From rate impact,
corporate budgeting, and procurement process perspectives, acquiring two CCCT plants in a two-
year span is problematical, and the Company would not pursue that acquisition path unless there
was strong justification from an economics or need perspective.68 The stochastic production cost
analysis described below was intended to help determine if economics justified CCCT acquisition
in 2015.
Using the original Case 3 portfolio under the $19 CO2 tax scenario, PacifiCorp developed a
portfolio with the Curant Creek 2 dr-cooled CCCT delayed one year to 2016, and included 597
MW of third quarter front offce transaction products to fill the resource gap: 100 MW from Mead,
. 200 MW from Utah, 101 MW from Mid-Columbia 101, and 196 MW from California-Oregon
Border (COB). These FOT additions are well below the limits specified for the market hubs. Table
8.11 reports the stochastic PVRR results. As indicated, the one-year CCCT deferral to 2016 results
in a $14.7 milion PVRR benefit. While variable costs increase due to FOT acquisition, this cost
increase is more than offset by the reduction in capital and fixed costs.
In terms of upper-tail cost impact, deferring the CCCT resource by one year decreased the
stochastic upper-tail mean PVRR by $19.1 millon ($40.341 bilion versus $40.360 bilion).
68 For example, if the Company could not meet its target planning reserve margin with alternative, more cost-effective
resources as determined by then-curent needs assessment and portfolio modeling.
223
PACIFiCORP-20ll IR CHAR 8 - MODELING RESULTS
Table 8.11- Dry-cooled CCCT, 2015 to 2016 PVR Deferral Value
Varible Costs
Fuel & O&M 15,729.2 15,695.6 (33.6)
Emision Cost 7,424.5 7,427.7 3.3
FOT's & Long Term Contracts 3,955.8 4,035.7 79.8
Demand Side Management $3,670 $3,670
Renewables $848 $848 0.03
System Balancing Sales (5,936.6)(5,957.4)(20.8)
System Balancing Purchases 3,168.3 3,160.8 (7.5)
Energy Not Served 137.0 137.4 0.4
Dump Power (116.8)(116.9)(0.1)
Reserve Deficienc 2.4 2.5 0.0
Total Variable Costs 28,881.8 28,903.4 21.6
Ca itl and Fixed Costs 5,953.6 5,917.3
TotalPVRR 34,835.4 34,820.7
Based on these stochastic PVRR results, the Company concluded that the 2011 IRP preferred
portfolio should reflect a second CCCT added in 2016.
Geothermal Resource Acquisition
Case 3 includes 105 MW of geothermal resources. As indicated at the December 15, 2010 IRP
public input meeting, a decision to pursue additional geothermal resources wil be dependent on a
clear signal that legislators and regulators will support full recovery of resource development costs. In
the absence of enabling cost recovery legislation and pre-approval of cost recovery from regulators,
the Company is viewing geothermal acquisition of up to 105 MW as representing an alternate
resource procurement path to be explored for the next IRP if progress is made regarding cost
recovery.
Combined Economic Impact of the CCCT Deferral and Geothermal Resource Exclusion
Based on the results of the CCCT defeITal study and geothermal resource sitution, PacifiCorp
developed a new System Optimizer portfolio using the Case 3 input assumptions along with
exclusion of geothermal resources as model options. To compel the model to defer the second
CCCT from 2015 to 2016, the Company increased the limit on Utah FOT from 200 MW to 250
MW, which is in line with the Uta market purchase depth assumed for the 2008 IRP. The
Company also made one additional resource change: it incorporated corrected capacity potentials
for the commerciai/industral sector curilment DSM product received from Cadmus after the
completion of portfolio development. The potentials were effectively doubled. For example, the
2011 Utah potential increased from 21.5 MW to 43.0 MW.
The Company simulated the resulting System Optimizer portfolio with the PaR model to compare
with the original Case 3 PVR results based on the $19 CO2 tax scenario. Table 8.12 reports the
stochastic PVR comparison with the original Case 3 portfolio. As shown, the revised portfolio
224
PACIFICORP - 20 11 IRP CHATER 8 - MODELING RESULTS
results in a $23.6 milion stochastic mean PVR improvement over the original Case 3 portfolio.
The stochastic upper-tail mean PVRR increased by $7 milion.
Table 8.12 -PVRR Comparison, Preliminary Preferred Portfolio vs. Revised Preferred
Portfolio
Varible Costs
Fue1& O&M
Emision Cost
FOT's & Long Term Contrcts
Demand Side Management
Renewables
System Balancing Sales
System Balancin Purchases
Energy Not Served
Dum Power
Reserve Deficienc
Total Variable Costs
$15,729.2
7,424.5
3,955.8
3,670
$848
(5,936.6)
3,168.3
137.0
(116.8)
2.4
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Ca itl and Fixed Costs
TotalPVR
5,953.6
34,835.4
$15,991.6
7,433.0
4,04.7
3,684
$656
(6,058.3)
3,089.4
143.1
(116.4)
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5,943.1
34,811.8
Government Compliance Risk Mitigation and Long Term Public Interest
Considerations
A key risk factor affecting resource strategies for the IRP is regulatory compliance uncertainty in
the areas of renewable energy acquisition and greenhouse gas emission control. In this section, the
Company assesses the quantity and timing of renewables appropriate for addressing long-term
regulatory risk exposure. While the action plan and acquisition path analysis in Chapter 9 make
provision for a range of renewable and emerging technologies, the Company is best positioned to
exploit wind resource potential, and thus focuses on this resource from a strategic positioning
standpoint. As noted in Chapter 7, the Company focuses on mitigation of upper-tail (worst-case)
cost outcomes as the suitable criterion for evaluating risk management benefits of renewables. This
criterion also recognizes risk management benefits stemming from less portfolio exposure to
volatile fuel prices, with subsidiary benefits arising from reduced pollution emissions and water
usage-the later becoming an increasing concern in the western u.s. This section also summarzes
sensitivity analysis of the preliminary preferred portfolio with respect to the Waxman-Markey
renewable energy targets and extension of the renewables PTC to 2020.
225
P ACIFICORP - 2011 IRP CHATER 8 - MODELING RESULTS
Risk-Mitigating Renewables
Table 8.13 shows the derivation of the optimal risk-mitigating wind quantity based on the
evaluation of stochastic upper-tail mean PVR performance across the 19 core portfolios. The
wind quantity selected was 2,100 MW. The gray highlighted cells in the table indicate the three
top-performing portfolios based on upper-tail mean PVR for each CO2 tax scenario. Since
geothermal has been excluded from the preferred portfolio, PacifiCorp then converted geothermal
capacity to an equivalent amount of wid capacity using the ratio of the resource capacity factors.
The resulting geothermal-equivalent wind capacity for each portfolio is shown in the fourh and
ninth columns. The two smaller tables at the bottom report the average wind capacity (wind plus
geothermal-equivalent wind) across the thee top-performg portfolios.
Table 8.13 - Derivation of Wind Capacity for the Preferred Portfolio
I 143 185 481 41,748 143 185 481 40,465
2 0 80 208 41,897 0 80 208 40,542
. 3 139 220 572 41,639 139 220 572 40,360
4 136 220 572 41,801 136 220 572 40,667
5 227 185 481 41,685 227 185 481 40,653
6 305 220 572 41,229 305 220 572 40,205
7 137 220 572 41,578 137 220 572 40,342
8 50 255 663 41,929 50 255 663 40,747
9 418 395 1027 41,709 418 395 1027 40,666
10 760 605 1573 41,052 760 605 1573 40,021
11 100 535 1391 41,787 100 535 1391 40,592
12 2160 535 1391 41,417 2160 535 1391 40,452
13 1700 535 1391 41,270 1700 535 1391 40,576
14 1300 675 1755 40,886 1300 675 1755 39,816
15 139 220 572 41,375 5 139 220 572 40,197
16 50 255 663 43,469 17 50 255 663 41,519 17
17 2600 535 1391 45,819 18 260 535 1391 43,692 19
18 408 220 572 46,097 19 408 220 572 42,791 18
19 1260 0 0 42,276 16 1260 0 0 41,203 16
1/ Based on the ratio of the geothenn1 resource capacit factor (9010) to the wind capacit factor (35%).
Wind Quantity Impact of Alternative Renewable Policy Assumptions
PacifiCorp generated two alternative versions of the preliminary preferred portfolio by ruing
System Optimizer with the preferred portfolio set-up along with modified renewable policy
assumptions. This portfolio development exercise was used to help allocate the 2,100 MW of wind
on an annual basis, as well as support the acquisition path analysis outlined in Chapter 9. The first
portfolio was developed by replacing the base RPS constraints (system percentage constraints
based on curent state RPS requirements) with ones reflecting the higher Waxman-Markey targets.
226
PACIFiCORP-2011 IR CHATER 8 - MODELING RESULTS
The second portfolio was developed by then layerig in renewable resources with costs that reflect
an extension of the renewable PTC to 2020.
Table 8.14 compares the preliminar preferred portfolio wind quantities with the resulting
incremental wind quantities selected for the two alternative renewable policy portfolios. For
example, 932 MW of additional wind is needed to comply with the Waxman-Markey RPS
portfolio, resulting in a total wind amount of 1,631 MW. Extending the federal PTC then increases
the amount of wind by an additional 97 MW for a total of 1,728 MW.
Table 8.14 - Wind Additions under Alternative Renewable Policy Assumptions
2011 0 0 0 0
2012 0 0 0 0
2013 0 0 0 0
2014 0 0 0 0
2015 0 0 200 147
2016 0 0 0 53
2017 0 171 0 0
2018 0 200 0 0
2019 0 200 0 0
2020 142 58 0 0
2021 200 185 0 0
2022 31 43 0 0
2023 0 36 0 0
2024 51 3 0 0
2025 200 (179 0 0
2026 21 93 0 0
2027 8 40 0 0
2028 9 83 0 0
2029 4 37 0 0
2030 34 140 0 0
TOTAL 732 200 200
Given that wind is added in every year for these alternative portfolios, and some front-loading is
necessary to comply with a federal RPS requirement along the lines of the Waxman-Markey
tagets, PacifiCorp distrbuted the 2,100 MW of wind into the annual wind schedule shown in
Table 8.15. Anual amounts were kept relatively level from year to year, recognizing the need for
rate and capital spending stability. Actual wind acquisition wil be determined as an outcome of
government mandates and constraints, transmission availability, technology costs, and the
Company's renewables procurement process.
227
P ACIFICORP - 2011 IR CHAPTER 8 - MODELING RESULTS
Table 8.15 -Wind Capacity Schedule
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
300
300
200
200
200
200
200
100
100
100
100
100
Preferred Portfolio
PacifiCorp developed the prefeITed portfolio by ruing System Optimizer with the preliminary
preferred portfolio set-up along with the fixed wind additions in Table 8.15. This modeling step
ensures that the portfolio is balanced on a capacity and energy basis with the wind schedule in
place. Figure 8.11 summarizes the steps leading from final screening to the prefeITedportfolio.
Figure 8.11 - Preferred Portfolio Derivation Steps
228
PACIFiCORP-20ll IRP CHATER 8 - MODELING RESULTS
Table 8.16 provides the detailed view of the preferred portfolio resources, while Table 8.17
presents the preferred portfolio capacity load & resource balance. (Note that wind capacity in
Table 8.17 reflects capacity contrbution at the time of peak annual load and not installed
capacity.) Figues 8.12 and 8.13 show energy and capacity resource mixes, respectively, for
representative years 2011 and 2020. The energy mix charts use the medium natual gas price
scenario, while the 2020 chart uses the medium C02 tax scenario ($24/ton in 2020). As noted in
chapter 3, the renewable energy capacity and generation reflect categorization by technology type
and not disposition of renewable energy attibutes for regulatory compliance requirements. Figue
8.14 graphically shows how PacifiCorp's capacity deficit is met through existing and IR
preferred portfolio resources.
229
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0
PACIFICORP - 2011 IR CHAPTER 8 - MODELING RESULTS
Table 8.17 - Preferred Portfolio Load and Resource Balance (2011-2020)
Calendar Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
:r -.w
Themil 6,019 6,026 6,028 6,028 6,028 6,04 6,04 6,04 6,04 6,04
Hydroelectr 133 133 13 13 133 129 129 129 129 129
Clss 1 DSM 324 329 329 329 329 329 329 329 329 329
Renewable 179 179 179 178 176 176 176 176 176 176
Purchase 655 705 60 304 304 283 283 283 283 283
Qualiing Facilties 152 187 206 20 207 206 207 207 206 206
Interrptible 281 281 281 281 281 281 281 281 281 281
Trasfers 1,002 916 1.014 623 614 578 572 542 44 284
Fat Exsting Resources 8,745 8,755 8,774 8,083 8,071 8,028 8,022 7:J92 7,894 7,734
Combined Heat and Power I 2 3 4 5 6 7 8 9 10
Class I DSM 0 65 65 85 176 176 176 176 176 176
Clss 2DSM 34 73 88 128 170 214 261 309 358 410
Front Offe Trasactions 20 368 618 590 649 325 372 517 300 545
Gas 0 0 0 625 625 1,22 1,22 1,222 1,697 1,697
Wind 0 0 0 0 0 0 0 8 21 28
Fat Planned Resources 235 509 774 1,432 1,625 1:J43 2,038 2,239 2,561 2,866
Fat Tot Resources 8,980 9,264 9,548 9,515 9,696 9:J72 10,060 10,232 10,455 10,600
Load 7,184 7,344 7,566 7,805 8,00 8,21 8,377 8.54 8,712 8,896
Sale 758 997 1,045 745 745 745 659 659 659 659
Fast Obligatiou 7,942 8,341 8,611 8,550 8,754 8,946 9,036 9,203 9,371 9,555
Planing reserves (13%)838 84 861 888 890 954 953 950 99 979
Non-owned reseives 70 70 70 70 70 70 70 70 70 70
Fat Resenes 909 918 932 959 960 1,024 1,024 1,020 1,064 1,049
Fast Obligation + Resenes 8,850 9,258 9,543 9,509 9,714 9,970 10,060 10,224 10,435 10,605
Fat Position 130 5 5 6 (18)1 1 8 19 (4)
Fat Resen" Magin 15%Í3%13%13%13%13%13%13%13%13%
:r .-.
Themi 2,552 2,552 2,556 2,556 2,556 2,556 2,541 2,550 2,550 2,550
Hydroelectric 1,103 958 958 957 958 959 958 958 90 745
Clss I DSM 0 0 0 0 0 0 0 0 0 0
Renewable 77 71 71 71 71 71 71 71 71 71
Purchase 856 247 331 226 221 225 255 269 285 242
Qualiing Facilties 136 136 136 136 136 136 136 136 136 136
Trasfers (l,(YJ3)(918)(L.0I5)(623)(615)(578)(573)(542)(44)(286)
West Exstiug Resources 3,721 3,046 3,037 3,323 3,327 3,368 3,389 3,442 3,498 3,458
Combined Heat and Power 4 8 13 17 21 25 29 34 38 42
Clss i DSM 0 0 62 62 72 72 72 72 72 72
Clss 2DSM 15 30 43 60 77 94 II 125 IMl 156
Front Offce Trasactions 150 871 81l 60 500 450 450 450 395 450
Solar 2 3 5 6 7 7 7 7 7 7
West Planued Resources 170 913 934 745 677 648 669 688 653 727
West Total Resources 3,892 3,959 3:J71 4,068 4,004 4,017 4,058 4,130 4,151 4,185
Load 3,266 3,374 3,395 3,44 3,491 3,541 3,584 3,650 3,66 3,713
Sale 290 258 258 258 158 108 108 108 108 108
West Obligatiou 3,556 3,632 3,653 3,706 3,649 3,649 3,692 3,758 3,774 3,821
Planning reserves (13%)330 323 313 359 361 365 365 369 375 377
Non-owned reserves 7 7 7 7 7 7 7 7 7 7
West Resenes 336 329 319 365 368 372 371 376 381 384
West Obligation + Reserves 3,892 3:J62 3:J73 4,071 4,017 4,020 4,063 4,134 4,155 4,204
West Position (0)(3)(2)(3)(12)(4)(5)(4)(4)(20)
West Resene Magin 13%13%13%13%13%13%13%13%13%12%-..~
Tota Resources 12,872 13,222 13,518 13,582 13,700 13:J89 14,118 14,361 14,605 14,785
Obligation 11,497 11:J73 12,264 12,256 12,403 12,595 12,728 12:J61 13,145 13,376
Resen~s 1,245 1,247 1,251 1,324 1,328 1,396 1,395 1,396 1,445 1,433
Obligation + Resenes 12,742 13,220 13,515 13,580 13,731 13,991 14,123 14,357 14,590 14,809
System Position 130 2 3 3 (31)(2)(4)4 15 (24)
Resene Magin 14%13%13%13%13%13%13%13%13%13%
231
PACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
Figure 8.12 - Current and Projected PacifCorp Resource Energy Mix for 2011 and 2020
2011 Resource Energy Mi with Preferred Portolio Resources
Front OfÍic Tiansactions
1.5%
Renewable'
7.4%
Hydroe1ectnc "
8.1%
Class i DSM +
Interrptibles
0.1%
Existing Purchases
7.8%
. Renewable resources include wind, solar and geotherl. Renewabk ener geeition refiects categorition bytecbnolog ty andnot dispositionof reneable engy attbute for reguato compliance reairents.
. * Hydroelectrc resoces include owned, qualify facilities and contac purcha
2020 Resource Energy Mix with Preferred Portfolio Resources
$24 CO2 Tax (nominal dollars)
Hydroelectric "
5.2%
Class i DSM +
Interrptibles
0.1%
Class2DSM
11.2%
Coal
36.3%
Existing Purchases
7.1%
Renewable'
10.7%
Gas
25.5%
* Renewable resources include wind, solar andgeotherI. Renewable enei geeition refects carition by tehnlog type andnot disposition of renwable enegy attbute for reguato compliace reqiren
** Hydroelectrc resoce include owned, qualify facilities and contctpurcbaes.
232
P ACIFICORP - 201 1 IRP CHATER 8 - MODELING RESULTS
Figure 8.13 - Current and Projected PacifiCorp Resource Capacity Mix for 2011 and 2020
2011 Resource Capacity Mix with Preferred Portfolio Resources
Front Offce Transactions
Class 1 DSM + 5.4%
Intenuptibles
4.7%
Renewable *
2.4%
CHP& Other
0.1%
Coal
47.5%
Existing Purchases
9.3%
Hydroelectrc **
II.%
Gas
18.3%.
* Renewable resources include wind, solar and geotherl. Wind capacity is repor as the peak load contbuton.
Renewable capacity reflects categoizaton by technology type and not disposition of renewable energ attibute for regtator compliance requirements.
.. Hydroelectrc resouees incluceownd,qualfyng facilties and contact pun:hases.
2020 Resource Capacity Mix with Preferred Portfolio Resources
Renewable *
2.6%
CHP& Other
0.3%
Coal
40.4%
Front Offce Transactions
6.5%
Class 1 DSM +
Intenuptibles
5.0%
Existing Purchases
3.2%
Hydroelectric * *
7.4%
Gas
26.4%
· Renewable resources include wind, solar and geotherml. Wind capacity is repored as the peak load contrbution.
Renewable capacity reflects categorizaton bytechnologytypeand not dispsition of renwable energ attibutes for regtator compliance requirement.
.. Hydroelectrc resouees include owned, qualifying facilities and contract pun:hases.
233
P ACIFICORP - 201 1 IR CHATER 8 - MODELING RESULTS
Figure 8.14 - Addressing PacifiCorp's Peak Capacity Deficit, 2011 through 2020
9,000
15,000 '
14,000
13,000
12,000
'"t:"I
~"I~11,000Q,~
10,000
8,000
2011 2012 2013 2014 2015 2016
- Other Additions
IILakeSide 2IIPhysicalAssets andDSM
2017 2018 2019
_CCCT2019_Genera tion Upgrdes
.. Obligation + Reserves
2020
= New Market PurchasesIICCCT20J6
IILon Term ContractsandPPA's
Preferred Portfolio Compliance with Renewable Portfolio Standard Requirements
Figue 8.15 below shows PacifiCorp's forecasted RPS compliance position for the California,
Oregon, and Washington69 progrms, along with a federal RPS program scenario7o, covering the
period 2010 through 2020 based on the preferred portfolio. Utah's RPS goal is tied to a 2025
compliance date, so the 2010-2020 position is not shown below. However, PacifiCorp meets the
Utah 2025 state target of 20 percent based on eligible Utah RPS resources, and has significant
levels of banked RECs to sustain continued futue compliance.
As an IRP plannng assumption, PacifiCorp anticipates utilizing flexible compliance mechanisms
such as banking and/or tradable RECs where allowed, to meet the RPS requirements.
69 The Washington RPS requirement is tied to January 1st of the compliance year, begining in 2012.70 The forecasted federal RPS position is a scenaro based on the Waxman-Markey legislation with targets of6 percent
begining in 2012,9.5 percent in 2014, 13 percent in 2016,16.5 percent in 2018, and 20 percent in 2020.
234
PACIFICORP - 2011 IR CHAPTER 8 - MODELING RESULTS
PacifiCorp
California RPS Compliance Forecast
Figure 8.15 - Annual State and Federal RPS Position Forecasts using the Preferred Portfolio
300 "'-'.-
250 --
j 200
:: 150
~.!l, 100 -
'" .
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
_Preferred Portolio =Additional RECs -RPS Target(GWh)
PacifiCorp
Washington RPS Compliance Forecast700 -------.-.
600 ----..---~.... ._-_._-_..-
500 .-...... ........................_-- ........__.-.__..-_....-
~., 400 ~.---_.."'-------
I 300 ......_._....__....-."'"
200 ,---
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
_Preferred Portolio ,.!1Addttional RECs ..RPS Target (GWh)
PacifiCorp
Oregon RPS Compliance Forecast
7,00 .-
~
., 4,00
1i~ 3,000 ..._.........."'"2,000
1,000
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
_Preferred Portolio rnAddttional RECs ..RPS Target(GWh)
PacifiCorp
Federal RPS Compliance Forecast
10,000
9,000
s.oo
7,000
j
i¡;
3,000
2,000
1,000
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
_RPSEligible Renewables ¡;AdditionalRECs _RPSTarget
Preferred Portfolio Carbon Dioxide Emissions
Cumulative generator C02 emissions by 2030 for the preferred portfolio under the medium C02
tax scenaro ($19/ton beginning in 2015) was 815 milion tons, compared to 838 milion tons for
the preliminary preferred portfolio, and 821 milion tons for the core case portfolio with the lowest
generator emissions among those selected for the final screening (Case 6 portfolio). These
emission quantities are reported by the PaR production cost modeL.
Regarding CO2 emission reduction trends, near-term reductions are drven by plant dispatch
changes Ìn response to assumed CO2 prices. In the longer term, cumulative energy effciency and
wind additions help offset emissions stemming from resource growth needed to meet load
obligations. Figue 8.16 ilustrates these emission trends for the preferred portfolio through 2030
under both the medium and low natual gas price scenarios. Total system emissions and generator-
only emission trends are also shown.
235
PACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
Figure 8.16 - Carbon Dioxide Generator Emission Trend, $19/ton C02 Tax
65
~=
~60..i.=.irT~=55.~
==~,;=50=..~~
'ër,~45"C.~
=
Q==40,.i.=U
-;==35=-(
..¿............li
A....:.if"\\..!!.. ".,..." "'..
1i.....II..............."""""
.........Ii.....1I
........................
...A.......... .. .................................
.....Ji....:;....~.....lé
-- i
I
30
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
"" Medium gas price forecast, total emissions.... Medium gas price forecast, generator only
_ Low gas price forecast, total emissions ...... Low gas price forecast, generator only
System Optimizer Sensitivity Cases
Coal Utilization Cases
PacifiCorp conducted five System Optimizer case rus that incorporated incremental costs
associated with existing coal plants, as well as replacement CCCT resources that includes costs
associated with existing plant decommissioning/demolition, coal contract liquidated damages, and
remaining coal plant book value recovery. Chapter 7 describes the modeling approach and cost
categories addressed in the study.
Table 8.18 shows the disposition of coal units in each of the System Optimizer case rus. No coal
units are replaced under medium case assumptions. Low natual gas prices combined with high
CO2 tax level assumptions are necessary to prompt coal unit replacements and high C02 tax levels
combined with low gas prices prompted the model to select a small number of replacement CCCTs
beginning in 2025.
236
PACIFiCORP-20ll IRP CHAPTER 8 -MODELING RESULTS
Table 8.18 - Disposition of Coal Units for the Coal Utilization Cases
Two units replaced
(2026)
Two units replaced
(2027)
One unit replaced
2030
Figues 8.17 though 8.21 show the average annual capacity factors by resource tye-eoal,
CCCT, and SCCT -for each of the cases. The capacity factors are weighted by unit megawatt
capacity, and reflect both existing and futue resources, including any replacement CCCTs.
Figure 8.17 - Gas and Coal Plant Utilization Trends, Case 20
100
90
80
~70..0..um"-60::..'0mi:m 50U
Gl
If
~40~e:
iã::c 30ce:
20
10
Case 20: Medium Gas Prices and CO2 Tax
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
~CCCT "'Coal 'l///$(//hSCCT
237
PACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
Figure 8.18 - Gas and Coal Plant Utiliation Trends, Case 21
100
90
80 ............_-_....-
~70
ls..uif~60..'ufta-ft 50U
Qltift..
~40
c(
iã:JC 30Cc(
20
10
Case 21: Low Gas Prices and Medium CO2 Tax
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
..cc __eoal """SCCT
Figure 8.19 - Gas and Coal Plant Utilization Trends, Case 22
90
80
~70..0t;ft..60~..'ufta-ft 50U
Qltift..Ql 40~c(
iã:JC 30Cc(
Case 22: Medium Gas Prices and High CO2 Tax
10
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
..CCCT __eoal -;SCCT
238
P AC!FICORP - 201 1 IRP CHAPTER 8 - MODELING RESULTS
Figure 8.20 - Gas and Coal Plant Utilization Trends, Case 23
100 -
Case 23: Low Gas Prices and High CO2 Tax
90 -----_UN~~--~~
"\A ..80
\/....
~70..r0
1::i --\........_..--_...._~_.._-----.._._..-..__.-------=-60..
I
..~Uft .--Coft 50 '---.-................__.._--_.__.~_..~...V
I
-~,
CIOIft ....CI::40 ~_...._...._...._........_._-_...__._..--~-
ci
iõ:JC 30 ---Cci -
20 -_..__.._-----_.._----_._----_._-_._------..__._-----_...__..-
10 "'NUN_-_.~'-~
,j-
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
_CCCT ..COal _SCCT
Figure 8.21 - Gas and Coal Plant Utilization Trends, Case 24
100
90
80
~70
S..u:i 60=-..'üftCoa 50
CIOIft..CI 40::ci
iõ:JC 30Cci
20
10
Case 24: Medium Gas Prices and CO2 Hard Cap
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
_CCCT ..Coal _SCCT
239
PACIFiCORP-20ll IR CHATER 8 - MODELING RESULTS
As expected, with no CO2 tax in place, annual coal plant utilization continues at a relatively steady
80 to 90 percent, except for a temporary dip in 2026 and 2027 when an influx of Alaskan gas is
forecast to cause a temporary drop in gas prices. The largest impact on coal plant utilization comes
from the combination of low gas price and high C02 tax scenaro. assumptions, which reduces the
fleet-wide utilzation rate to 35 percent by 2030.
Key conClusions from this study, notwithstading uncertinties in environmental compliance costs,
include the following:
. The Company's coal fleet remains economically viable under curently expected natural gas
prices and given a CO2 cost that is line with recent federal carbon emissions control proposals.
. Sustained low natual gas prices or imposition of C02 costs, considered individually, have a
moderate impact on the continued operation of the coal fleet.
. Assuming sustained low natual gas prices are combined with sustained high carbon costs or a
hard cap is put in place, the utilization of the coal fleet is significantly reduced. However,
CCCT replacements are cost-effective for a limited number of coal units, and the replacements
do not occur until the late-2020s.
. A C02 cost of around $40/ton and sustained gas prices in the $7 - $9/MMBtu range (both in
nominal dollars) are needed to begin to make coal plant replacements cost-effective prior to
2030.
Appendix E in Volume 2 reports stochastic analysis results for these portfolios. See Tables E.7,
E.8, and E.12 through E.14.
Out-year Optimization Impact Analysis
In its 2008 IRP acknowledgment order, the Oregon Commission directed PacifiCorp to "work with
parties to investigate a capacity expansion modeling approach that reduc.es the influence of out-
year resource selection on resource decisions covered by the IRP Action Plan, and for which the
Company can sufficiently show that portfolio performance is not unduly influenced by decisions
that are not relevant to the IRP Action Plan.,,7!
For this investigation, the Company applied a two-stage System Optimizer capacity expansion
approach. The first stage is a conventional 20-year simulation of a test portfolio ("Full
Optimization"). Case 9 was selected because it was defined with the "Low to Very High" C02 tax
scenaro, marked by an acceleration of the CO2 tax begining in 2021. . The model has perfect
foresight, and thus optimizes with knowledge of the full C02 price trajectory. The second stage
("Partial Optimization") involved developing a portfolio with two separate System Optimizer rus.
The first ru was conducted for a 12-year span, 2011-2022, rather than just 10 years to account for
optimization period end effects. The second ru involved fixing the resources from the first ru for
2011 through 202072, but allowing System Optimizer to fully optimize for 2021 through 2030.
This two-stage approach isolates the impact of giving the model perfect foresight for out-year C02
tax values and other case scenario input values.
Table 8.19 shows the resource capacity differences on an annual basis for the Full Optimization
and Partial Optimization portfolios.
71 Public Utility Commission of Oregon, Order, Modified Plan Acknowledged with an Exception, Docket No. LC 47,
p.27.72 An exception for energy effciency was made due to set-up complications in fixing these resources. The model was
allowed to optimize them for the full 20 years.
240
PACIFICORP - 2011 IRP CHAPTER 8 - MODELING RESULTS
The major resource impacts of moving to the Paral Optimization approach for this case are as
follows:
. The second CCCT was deferred by one year, from 2015 to 2016.
. The resultig CCCT deferrl capacity shortge in 2015 was made up by higher front office
transactions, the addition of utility-scale biomass (50 MW), and an acceleration of Class 2
DSM.
. Solar hot water resources, both east and west side, were eliminated, along with 82 MW of wind
added in 2024 though 2028.
As expected, the Partial Optimization portfolio had a higher PVRR relative to the fully optimized
20-year ru, an increase of $247 milion.
The main conclusion from this test case is that foreknowledge of out-year CO2 tax values and other
input assumptions affected the model's resource selection and timing in the Action Plan time
horizon. What is the implication for PacifiCorp's portfolio evaluation approach? PacifiCorp does
not use System Optimizer economic results to determine the preferred portfolio. Rather, it is used
to generate alternative portfolios for detailed stochastic production simulation. To the extent thåt a
two-stage modeling approach results in significantly different portfolios from conventional
simulations, then it may have some value from the perspective of creating a more diverse portfolio
set. However, the added complexity of settng up the model and ruing simulations in this fashion
for the entire portfolio development process is not practicaL.
Although not part of the Oregon Commission's IRP analysis requirement, the Company has
addressed the same out-year portfolio simulation concerns with regard to the stochastic simulations
used for preferred portfolio selection. As noted in Chapter 7, the Company eliminated the long-
term stochastic volatility parameters from the Monte Carlo simulations. That action was found to
decrease out-year impacts on overall portfolio costs.
Table 8.19 - Resource Differences, Full Optimization Portfolio less Partial Optimization
Portfolio, Case 9 Assumptions
(1
(3.2)4.9 5.4
(4.0)(17.4)3.6 4.2 3.8 52 5.5
3 3 3 3 3 0.3
(0)(99 21
16 (200)53 48 21
(1)28 (29)(6)(1)(1)(3)18 (0)(5)
9 28 29 (8)(74)12 3
10 9 13 46 156 22 7 47
(35)
(0.3
41.2 (8.5 (1.5 6.4 3.6
(1.8)(0.3)(0.5)(0.5)1.0 0.6 0.8 0.6 0.6
2 2 2 2 2 0.3
(102)37 32 4 119
(0.1)
(50)48
0.4 (1)
316
41 (10)(94)(21)10 53 21
241
P ACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
Alternative Load Forecast Cases
PacifiCorp ran System Optimizer for three alternative load growth scenaros: low economic
growth (Case 25), high economic growt (Case 26), and l-in-IO year extreme summer/winter
peaks (Case 27). The resulting System Optimizer portfolios for Case 25 and Case 26 were
compared with the Case 7 portolio, which is based on same medium C02 and gas price scenaros.
The period examined was for years 2011 though 2020. (Resource tables showing the full 20-year
view are included in Appendix D). Table 8.20 sumares the year-by-year resource capacity
differences between Cases 7, 25, and 26. With lower economic growt, the model eliminates gas
capacity, and increases DSM to facilitate the gas capacity reductions and defeITals. With higher
economic growth, gas resources acquisitions are accelerate the amount of DSM is increased, and
acquisition of front offce transactions is shifted from the west to the east with a net gain in
quantity.
Table 8.20 - Resource Differences, Case 7 vs. Low and High Economic Growth Portfolios
Case 7 Less Case 25 (Lw Econ. Load Growth
(475,0)(475)
0.8 0.8 2
(3.5)6.7 (7.8)2
1.9 8.8 3.0 22.6 4.1 10.3 3.4 4.8 10.1 73
4.2 75
7.4 N/A
(6.8)
0.5 0.5 0.6 0.7 0.7 0.6 0.8 0.8 6
0.5 0.5 1
(1.5)96.8 (142.0)20.5 N/A
(0.4)(0.6)N/A
50.0 (50.0)N/A
118.0
45.0 (45.0)
0.8 0.8 1.
3.2 (7.8)7.0 2.4
0.0 11.6 2.4 3.1 3.2 4.7 19.8 20.1 64.9
45.1 71.0 N/A
178.2 119.2 (56.7)(200.0)7.6 7.4 N/A
50.0 50.0
0.3 0.3
10.0 (10.0)
0.2 0.3 0.6 0.6 0.4 0.6 0.6 0.6 0.8 0.8 5.5
0.5 0.5 1.0
(0.1)96.8 (191.9)(40.2)24.1 N/A
(0.2)(0.4)N/A
50.0 (50.0)(50.0)50.0 N/A
242
PACIFICORP - 201 1 IRP CHAPTER 8 - MODELING RESULTS
For the high peak demand portfolio (Case 27), the comparison was made with the high economic
growth portfolio (Case 26). Table 8.21 summarizes the year-by-year resource capacity differences
between these two portfolios for 2011-2020. As indicated in the table, additional simple-cycle
combustion tubine capacity is needed under the high peak demand scenario, and the need is
accelerated to 2014 from 2020. Small quantities of additional Class 2 DSM in the east are also
chosen above what is selected under the high economic growth scenario.
Table 8.21 - Resource Differences, High Peak Demand vs. High Economic Growth Portfolios
Case 27 (Hgh Peak Demand) less Case 26 . h Econ. Growth)
(45.0)
(0.8)0.8 0.8 0.8 0.8 2.3
(3.5)1.6 (7.0)8.8
4.2 (8.2)1.1.2 6.6 6.9
N/A
68.8 200.0 (7.6 N/A
(0.3)0.3 0.3 0.3 0.3 0.3 1.4
(3.6)1.2.3
(0.2)(0.3)(0.2)0.3 0.1 0.1
0.1 191.9 (93.4)
Appendix E in Volume 2 reports stochastic analysis results for the low and high economic growth
portfolios. Stochastic analysis was not conducted for the high peak demand portfolio because
.resource differences are not significantly different from the high economic growth portfolio. See
Tables E.6, E.7, and E16 through E.18.
Renewable Resource Cases
This section presents System Optimizer simulation results for four sensitivity cases that test
alternative renewable energy policy assumptions and resource costs. Case 28 determines the
resource and cost impact of excluding state RPS requirements as a portfolio development
constraint. Case 29 tests an alternate wind integration cost of $5.38/MWh, versus the $9.70/M
value reported in PacifiCorp's 2010 wind integration study (Appendix I). Cases 30 and 30a
determine if System Optimizer selects Utah solar PV resources assuming a resource cost based on
alternative levels for a utility incentive program; $1,744/kW and $2,326/kW, respectively.
PacifiCorp also determined the impact of an aggressive federal RPS requirement (Waxian-
Markey targets, 20 percent by 2020) on the preferred portfolio.
Utah Utility Cost Buy-down for Solar PV Resources
For Case 3Q-$1,744/kW utilty program cost~System Optimizer selected the maximum annual
amount per year (1.2 MW for 2011 through 2028, amounting to 22 MW. The deterministic PVR
for this portfolio was $41.04 bilion.
243
PACIFICORP - 2011 IR CHATER 8 - MODELING RESULTS
For Case 30a-$2,326/kW utility program cost-System Optimizer selected the maximum annual
amount per year (1.2 MW for 2011 through 2020, amounting to 12 MW. The deterministic PVR
for this portfolio was $3 milion higher than the PVR for the Case 30 portolio.
PacifiCorp conducted accompanying System Optimier rus to determine the portfolio cost impact
on a Total Resource Cost (TRC) basis for comparbility to other resource portfolios. (As noted in
Chapter 7, comparg portfolios with generation resources specified with a different cost basis and
exhibiting such a wide gap between utility cost and total resource cost does not meet the state IR
Standards and Guidelines provision to evaluate resources "on a consistent and comparable basis".)
For these model rus, PacifiCorp fixed the Utah solarPV amounts selected in the original rus, but
used the original resource costs. Table 8.22 shows the PVR comparison between the buy-down
utility-cost-based program cost portfolios and portfolios that included the solar PV resources on a
TRC basis.
Table 8.22 - Solar PV Resource Comparison, Buy-Down Utilty Cost versus Total Resource
CostPVR
Renewable Portfolio Standard Impact
For Case 28, PacifiCorp removed the system renewable portfolio stadard constraints originally
applied to Case 7 (medium gas prices/medium C02 tax). This sensitivity determines the cost-
effective amount of renewable capacity added by System Optimizer at these gas and CO2 price
levels. With the RPS constraints removed, the model added 150 MW of geothermal capacity but
no wind. Table 8.23 compares the year by year resource capacity differences between the "no
RPS" portfolio and the Case 7 portfolio. With the RPS included, the model selected 137 MW of
wind and 70 MW of geothermal (35 MW in the east and 35 MW in the west). Portfolio PVRR
increased by $223 milion to comply with the RPS constraints.
Alternate Wind Integration Cost
For Case 29, PacifiCorp assigned the alternate wind integration cost of $5.38/MWh to wind
resources. The resulting portfolio was compared to the Case 7 portfolio, which serves as the base.
As shown in Table 8.23, which shows the annual and total resource differences between the two
portfolios, the lower wind integration cost increased the amount of wind selected by 81 MW. The
higher capacity was accompanied by a reduction in DSM, less geothermal capacity in west, and
greater reliance on out-year growth resources in the west.
244
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5
P ACIFICORP - 2011 INTEGRA TED RESOURCE PLAN CHATER 8 - MODELING RESULTS
Demand-side Management Cases
This section presents System Optimizer simulation results for three sensitivity cases that test
alternative DSM resources (Class 3 DSM and distrbution energy efficiency) and use of technical
DSM potentialin lieu of achievable potential for preferred portfolio resource selection.
DemandResponse Program (Class 3 DSM) Impact
Case .31 entailed including Class 3 DSM rate products as resource options using the medium
natual gas and C02 tax assumptions defined for Case 7. As noted in Chapter 7, the dispatchable
irrgation load control programs were assumed to be substituted by a mandatory Time of Use
(TOU) rate schedule with rates set suffciently high to induce the desired load shifting behavior.
This substitution occurs in 2015, when a TOU rate strctue is assumed to be instituted. The
resource potentials account for interaction effects between Class 1 and Class 3 resources. Table
8.24 shows the resource differences between the portfolio with Class 3 DSM selected and the
reference portfolio derived from Case 7 assumptions.
A total of 262 MW of Class 3 DSM was selected in the east and 131 MW selected in the west. The
net gain in load control resources is 122 MW, which accounts for reduced Class 1 DSM capacity
(70.MW and the displacement of the dispatchab1e irgation load control program (201 MW).
This additional DSM capacity is sufficient to defer the second and third CCCT resources by one
year. The portfolio PVR decreased by about $236 milion due to the relatively low cost of
administering 3 DSM programs.
Technical DSM Potential Supply Curve versus High Achievable Potential Supply Curve
For Case 32, PacifiCorp substituted DSM supply cures based on a high achievable potential
adjustment (85 percent) with a version for which the achievable potential adjustment is removed.
(As noted in Chapter 6, the achievable potential reflects the resource quantity available after
accounting for market and adoption bariers. Comparing the resulting portfolio with the base (Case
7 portfolio) indicates the amount of cost-effective technical potential selected by System
Optimizer. As shown in Table 8.25, which shows the year by year resource comparson of the two
portfolios, removing the achievable potential adjustment increased the cumulative amount of
energy efficiency (Class 2 DSM) by 418 MW. The model used this incremental DSM, along with
the selection of smaller resources and increased front offce transactions in certain years, to defer
the 2015 and 2019 CCCT resources by one year. Given that the 85-percent achievable potential
adjustment is aspirational, PacifiCorp considers additional DSM potential beyond the 85-percent
adjustment to be effectively a non-firm resource, and would have serious concerns about using it
as the basis for program target setting.
Washington Distribution Energy Effciency Resource
For this sensitivity case (Case 33), PacifiCorp included a proxy resource option in System
Optimizer representing Washington distrbution energy efficiency resources for the
Yakima/Sunyside and Walla Walla areas. The model selected the full amount of the Walla Walla
resource in 2013 (0.191 MW, and the full amount of the Yakma/Sunyside resource in 2016
(0.403 MW.
246
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24
8
P ACIFICORP - 201 1 IRP CHAPTER 8 - MODELING RESULTS
Cost of Energy Not Served (ENS) Sensitivity Analysis
In its 2008 IRP acknowledgment order, the Utah Commission directed the Company to "perform a
sensitivity case in its next IRP or IRP update wherein the ENS cost is flat and based on the Federal
Energy Regulatory Commission price cap.',7
Using the Case 7 portfolio, PacifiCorp applied the two ENS price strctues to the quantity of ENS
reported from the Planning and Risk simulation for the medium C02 tax scenario: the curent
FERC price cap of $750/M, and the tiered pricing approach adopted by the Company. The
tiered approach assigns a price of $4001MWh for the first 50 GWh, $200/M for ENS in the
range of 51 to 150 GWh, and $100/M for ENS above 150 GWh.
Substituting the PacifiCorp's ENS price strctue with the $750/M FERC price cap raises the
ENS cost by $158 milion for the 20-year simulation. It should be noted that the ENS price entered
into the PaR model does not affect the model's unit commitment and dispatch solution. Energy
Not Served is an outcome of the inability to meet load, and is not affected by the assigned ENS
price. In other words, the ENS price is simply used to value the unmet load for reporting puroses.
PacifiCorp's updated ENS pricing approach has been to assign a price representative of what
emergency power would be under adverse market circumstaces for ENS experienced in the short
term, and representative of the acquisition of peaking resources for ENS experienced in the long
term (in the later years of the simulation where ENS becomes significant). The upshot is that the
choice of an ENS value is fudamentally a subjective decision. The Company's view is that it is
inappropriate to assign too high an ENS price given that portfolio costs generated farer out in the
Monte Carlo simulation become increasingly influenced by stochastic outlier events. Assigning a
high ENS price increases the influence of such out-year outlier events on overall portfolio costs.
73 Public Service Commission of Uta, Report and Order, PacifiCorp 2008 Integrated Resource Plan, Docket No. 09-
2035-01, p. 24.
249
PACIFiCORP-2011 IRP CHAPTER 9 - ACTION PLAN
CHAPTER 9 - ACTION PLAN
251
P ACIFICORP - 201 1 IR CHATER 9 ~ ACTION PLAN
PacifiCörp's 2011 IRP action plan identifies the steps the Company wil take during the next two
to four years to implement the plan, coverig the 10-year resource acquisition time frame, 2011-
2020. Associated with the action plan is an acquisition path analysis that anticipates potential
major reguatory actions and other trgger events durg the action plan time horizon that could
materially impact resource acquisition strategies.
The resources included in the 2011 IRP preferred portfolio were used to help define the actions
included in the action plan, focusing on the size, tig, and tye of resources needed to meet
load obligations and curent and potential futue state regulatory requirements. The preferred
portfolio resource combination was determined to be the lowest cost on a risk-adjusted basis
accounting for cost, risk, reliability, regulatory uncertainty, and the long-ru public interest.
The 2011 IRP action plan is based upon the latest and most accurate information available at the
time of portfolio study completion. The Company recognizes that the prefeITed portfolio upon
which the action plan is based reflects a snapshot view of the futue that accounts for a wide
range of uncertainties. The curent volatile economic and regulatory environment wil likely
require near-term alteration to resource plans as a response to specific events and improved
clarity concerning the direction of governent energy and environmental policies.
Resource information used in the 2011 IRP, such as capital and operating costs, is consistent
with that used to develop the Company's business plan completed in 2010. However, it is
importnt to recognize that the resources identified in the plan are proxy resources and act as a
guide for resource procurement and not as a commitment. Resources evaluated as par of
procurement initiatives may vary from the proxy resource identified in the plan with respect to
resource tye, timing, size, cost, and location. Evaluations wil be conducted at the time of
acquirig any resource to justify such acquisition, and the evaluations wil comply with then-
curent laws and regulatory rules and orders.
In addition to the action plan and acquisition path analysis, this chapter addresses a number of
topics associated with resource risk management. These topics include the following:
. Managing carbon risk for existing plants
. The use of physical and financial hedging for electrcity price risk
. Managing gas supply risk
. The treatment of customer and investor risks for resource planning
Figue 9.1 shows annual and cumulative additions of renewable installed capacity for 2003
through 2030. As indicated, . the Company has already exceeded its MidAmerican Energy
Holdings Company and PacifiCorp commitment to acquire 1,400 MW of cost-effective
renewable resources by 2015.
252
PACIFICORP - 201 1 IRP CHATER 9 - ACTION PLAN
Figure 9.1 - Annual and Cumulative Renewable Capacity Additions, 2003-2030
4,500
4,000
3,500
3,000
2,500
Ul....II
~2,000IIIlGI
:¡1,500
1,000
500
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
I~ Annual Additions I~ Cumulative Additions
Note: the renewable energy capacity reflects categoriation by technology tye and not disposition of renewable energy
attributes for regulatory compliance requirements.
The 2011 IRP action plan, detailed in Table 9.1, provides the Company with a road map for
moving forward with new resource acquisitions. The action plan for transmission expansion is
provided as Chapter I O.
253
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25
7
PACIFiCORP-2011 IR CHAPTER 9 - ACTION PLAN
This section describes progress that has been made on previous active action plan items
documented in the 2008 Integrated Resource Plan Update report fied with the state commissions
on March 31, 2010. Many of these action items have been superseded in some form by items
identified in the current IRP action plan.
Action Item 1: Acquire an incremental 890 MW of renewable resource by 2019. Successfully add
230 MW of wind resources in 2010 and 200 MW of wind resources in 2011 that are curently
committed to.
. Procure up to an additional 460 MW of cost-effective wind resources for commercial
operation, subject to transmission availability, in the 2017 to 2019 time frame via RFPs or
other opportities.
. Monitor geothermal, solar and emerging technologies, and governent financia1
incentives; procure geothermal, solar or other cost-effective renewable resources durng the
10-year investment horizon.
. Continue to evaluate the prospects and impacts of Renewable Portfolio Standard rules and
C02 emission regulations at the state and federal levels, and adjust the renewable
acquisition timeline accordingly.
Status: PacifCorp acquired 348 MW of wind in 2010. The Company is on track to acquire an
additional 93 MW in 2011 and 2012, reaching a total of 490 MW by year end 2012. Thispositions
the Company well towards the goal of 890 MW by 2019 and takes advantage of currently available
tax incentives and renewable energy credit sales opportunities to further reduce costs for
customers. PacifCorp completed its geothermal resource study in 2010, identifing a number of
commercially viable sites for 2011 IRP modeling and further investigation. PacifCorp issued its
Oregon solar photovoltaic Request for Proposals (RFP) in November 2010 for acquisition of at
least 2 MW in 2011.
Action Item 2: Implement a bridging strategy to support acquisition deferral of long-term
intermediate/base load resource(s) in the east control area until the beginning of summer 2015,
unless cost-effective long term resources such as renewables or thermal plant assets are available
and their acquisition is in the best interests of customers.
. Acquire the following resources:
- Up to 1,250 MW of economic front offce transactions on an anual basis as needed
through 2015, taking advantage of favorable market conditions.
- At least 200 MW of long term power purchases.
Cost-effective interrptible customer load contract opportnities (focus on
opportities in Utah).
- PUR A Qualifying Facility contracts and cost-effective distrbuted generation
alternatives.
. Resources wil be procured through multiple means: (1) the All Source RFP reissued on
December 2, 2009, which seeks third quarter summer products and customer physical
259
PACIFiCORP-20ll IR CHATER 9 - ACTION PLAN
curailment contracts among other resource tyes, (2) periodic mini-RFPs that seek
resources less than five years in term, and (3) bilateral negotiations.
· Closely monitor the near term need for front offce trsactions and reduce. acquisitions as
appropriate if load forecasts indicate recessionar impacts greater than assumed for the
February 2009 load forecast, or if renewable or thermal plant assets are determined to be
cost-effective alternatives.
Status: Based on its updated resource needs assessment and all-source RFP bid evaluation, the
Company is proceeding with plans to acquire a gas-fred combined-cycle plant at the Lake Side
site in Utah by June of 2014. The Company has so far acquired front offce transactions at
favorable market prices for 2011 through 2013 (350 MW for2011, 400 MW for 2012,300 MW for
2013), and continues to consider entering into power purchase agreements. As noted in Chapter 5,
a number of Qualifing Facilty contracts have also been signed by the Company.
Action Item 3: Procure through acquisition and/or Company constrction long-term firm capacity
and energy resources for commercial service in the 2012-2016 tie frame.
· The proxy resource included in the 2010 business plan portfolio consists of a Utah wet-
cooled gas combined-cycle plant with a capacity rating of 607 MW, acquired by the
sumer of2015.
· Procure through the 2008 all-source RFP issued in December 2009.
· The Company submitted a benchmark resource, specified as the addition of a second
combined-cycle block at PacifiCorp's Lake Side Plant.
· In recognition of the unsettled U.S. economy, expected continued volatility in natual gas
markets, and regulatory uncertinty, continue to seek cost-effective resource deferral and
acquisition opportities in line with near-term updates to load/price forecasts, market
conditions, transmission plans, and regulatory developments.
· PacifiCorp wil reexamine the timing and tye of gas resources and other resource changes
as part of a comprehensive assumptions update and portfolio analysis to be conducted for
the 2008 RFP final short-list evaluation in the RFP approved in Docket UM 1360, the next
. business plan, and 2008 IRP update.
Status: As noted above, the Company is proceeding with the acquisition of a Utah wet-cooled gas-
fired combined-cycle plant located at the Lake Side site. Acknowledgment of the all-source RFP
bidder final short list was received by the Oregon Public Utilty Commission. PacifCorp filed an
application for pre-approval of the Lake Side 2 combined cycle plant with the Public Service
Commission of Utah.
Action Item 4: Pursue economic plant upgrade projects-such as tubine system improvements
and retrofits-and unit availability improvements to lower operating costs and help meet the
Company's futue CO2 and other environmental compliance requirements.
· Successfully complete the dense-pack coal plant tubine upgrade projects by 2019, which
are expected to add 86 MW of incremental capacity in the east and 48 MWin the West
with zero incremental emissions.
· Seek to meet the Company's aggregate coal plant net heat rate improvement goal of 213
BtuWh by 2018.
260
PACIFiCORP-201l IR CHATER 9 - ACTION PLAN
. Monitor tubine and other equipment technologies for cost-effective upgrade opportities
tied to futue plant maintenance schedules.
Status: This action item has been updated to reflect planned turbine upgrade projects included in
the 2011 business plan. Planned projects now total 65 MW from 2011 through 2021, a drop of 49
MW from the amount reported in the 2008 IRP Update. PacifCorp filed its second heat rate
improvement plan with the Utah Commission in April 2010. This plan increases the 2018
improvement goal by 285 Btu/kWh (213 to 498 Btu/kWh).
Action Item 5: Acquire up to 200 MW of cost-effective Class 1 demand-side management
programs for implementation in the 2010-2019 time frame.
. Pursue up to 30 MW of expanded Utah Cool Keeper program parcipation by 2019; revisit
the program's growth assumptions in light of the recent passage of Utah legislation that
permits an opt-out program design.
. Pursue up to 100 MW of additional cost-effective class 1 DSM products including
commercial curilment and customer-owned standby generation (55 MW in the east side
and 45 MW in the west side) to hedge against the risk of higher gas prices and a
faster-than-expected rebound in load growth resulting from economic recovery; procure
though the curently active 2008 DSM RFP and subsequent DSM RFPs.
. For 2010, continue to implement a standardized Class 1 DSM system benefit estimation
methodology for products modeled in the IRP. The modeling wil compliment the supply
cure work by providing additional resource value information to be used to evolve current
Class 1 products and evaluate new products with similar operational characteristics that
may be identified between plans.
Status: The Company exceeded its 2010 Class 1 DSM acquisition goal by 24 MW achieving 482
MW versus the goal amount of 458 MW This action item has been superseded by Action Item no. 5
in Table 9.1. Note that Governor Herbert vetoed the legislation permitting an opt-out program
design.
Action Item 6: Acquire 900 - 1,000 MW of cost-effective Class 2 programs by 2019, equivalent to
about 4.1 to 4.6 millon MW.
. Procure through the curently active DSM RFP and subsequent DSM RFPs
Status: The Company exceeded its 2010 Class 2 DSM acquisiton goal by 56,137 MW, achieving
499,059 MW versus the goal amount of 442,922 MW. This action item has been superseded by
Action Item no. 6 in Table 9.1.
Action Item 7: Acquire cost-effective Class 3 DSM programs by 2018
. Procure programs though the curently active DSM RFP and subsequent DSM RFPs.
. Continue to evaluate program attbutes, size/diversity, and customer behavior profies to
determine the extent that such programs provide a suffciently reliable fi resource for
long-term planning.
. Portfolio analysis with Class 3 DSM programs included as resource options indicated that
at least 100 MW may be cost-effective; continue to evaluate program specification and
cost-effectiveness in the context of IRP portfolio modeling.
261
PACIFiCORP-20ll IR CHATER 9 - ACTION PLAN
Status: This action item has been superseded by Action Item no. 3 in Table 9.1.
Action Item 8: Planing Process Improvements
. For the next IRP planing cycle, complete the implementation of System Optimizer
capacity expansion model enhancements for improved representation of C02 and RPS
regulatory requirements at the jursdictional leveL. Use the enhanced model to provide more
detailed analysis of potential hard-cap regulation of carbon dioxide emissions and
achievement of state or federal emissions reduction goals. Also use the capacity expansion
model to evaluate the cost-effectiveness of coal facilty retirement as a potential response to
futue regulation of carbon dioxide emissions.
. Refine modeling techniques for DSM supply cures/program valuation, and distributed
generation.
. Investigate and implement, if beneficial, the Loss of Load Probability (LOLP) reliability
constraint fuctionality in the System Optimizer capacity expansion model
. Continue to coordinate with PacifiCorp's transmission planing departent on improving
transmission investment analysis using the IRP models.
. For the next IRP planning cycle, provide an evaluation of, and continue to investigate,
intermediate-term market purchase resources for puroses of portfolio modeling
. Consider developing one or more scenaros incorporatig plug-in electrc vehicles and
Smar Grid technologies.
Status: PacifCorp successfully implemented the planned System Optimizer enhancements for
improved representation of C02 and RPS regulatory requirements. Carbon dioxide hard cap
scenarios for the first time incorporated assignment of emission rates to spot market system
balancing transactions. PacifCorp used for the first time System Optimizer's plant betterment
functionality to evaluate coal plant idling scenarios. Refinements to DSM supply curves included
updating the T &D investment deferral credit,. applying risk mitigation cost credits to DSM supply
curve prices (see Chapter 6), and reclassifing cost bundle breakpoints (also Chapter 6). Ventyx,
the model vendor, advised PacifCorp that the LOLP reliabilty constraint functionality requires
additional design work and is not ready for a production environment. No intermediate-term
market purchases were available for evaluation through the Company's all-source RFP. Plug-in
electric vehicles and Smart Grid technology scenarios is addressed in Action Item no. 8 in Table
9.1.
Action Item 9: Obtain Certificates of Public Convenience and Necessity and conditional use
permits for Utahlyoming/Idaho segments of the Energy Gateway Transmission Project to
support PacifiCorp loads, regional resource expansion needs, access to markets, grid reliabilty,
and congestion relief.
. Obtain Certificate of Public Convenience and Necessity for a 500 kV line between Mona
and Oquirrh.
. Obtain Certificate of Public Convenience and Necessity for 230 kV and 500 kV line
between Windsta and Populus.
. Obtain Certificate of Public Convenience and Necessity for a 500 kV line between Populus
and Hemingway.
262
PACIFiCORP~2011 IR CHAPTER 9 - ACTION PLAN
Status: The Utah Public Service Commission issued a Certifcate of Public Convenience and
Necessity for the Mona to Oquirrh project in June 2010. PacifCorp has begun permitting efforts
and right of way research for Windstar-Populus project. A contract wil be issued during the 4th
Quarter of 2011 for right-oý-way acquisition, which wil begin in 2012. The Company hopes to
complete the Environmental Impact Statement process with the Bureau of Land Management in
2012. As with the Windstar-Populus project, PacifCorp has partnered with Idaho Power to build
the Populus to Hemingway segment of Gateway West. The companies hope to complete the
Environmental Impact Statement process and all necessary permitting in 2012, and to begin
constrction as early as 2015. See Chapter 10, Transmission Expansion Action Plan, for more
details.
Action Item 10: Complete Utah/Idaho segments of the Energy Gateway Transmission Project to
support PacifiCorp loads, regional resource expansion needs, market access, grid reliability, and
congestion relief.
Permit and constrct a 345 kV line between Populus to TerminaL.
Status: PacifCorp completed the Populus to Terminal project in November 2010. See Chapter 10,
Transmission Expansion Action Plan.
Action Item 11: Permit and build Utah segment of the Energy Gateway Transmission Project to
support PacifiCorp loads, regional resource expansion needs, access to markets, grid reliability,
and congestion relief
Permit and constrct a 500 kV line between Mona and Oquirh.
Status: Right-of-way efforts are ongoing and construction is scheduled to begin in 2011. The Mona
to Oquirrh segment is scheduledfor completion in 2013, while the Oquirrh to Terminal segment is
scheduled for completion in 2014. See Chapter 10, Transmission Expansion Action Plan.
Action Item 12: Permit and build segments of the Energy Gateway Transmission Project to
support PacifiCorp loads, regional resource expansion needs, access to markets, grid reliability,
and congestion relief
. Permit and constrct 230 kV and 500 kV line between Windstar and Populus.
. Permit and constrct a 345 kV line between Sigud and Red Butte.
Status: The 2008 IRP Update reported an in-service date range of 2014-2016 for Windstar to
Populus, but delays in the BLM's Environmental Impact Statement process have delayed the
project resulting in revised plans to complete it in the 2015-2017 time frame. PacifCorp hopes to
complete all permitting and right of way acquisitions for Sigurd-Red Butte by 2012 and to place
the project in-service in 2014. See Chapter 10, Transmission Expansion Action Plan.
Action Item 13: Permit and build Northwest/ta segments of the Energy Gateway Transmission
Project to support PacifiCorp loads, regional resource expansion needs, access to markets, grd
reliabilty, and congestion relief
Permit and constrct a 500 kV line between Populus and Hemingway.
263
PACIFICORP - 2011 IR CHAR 9 - ACTION PLAN
Status: The Company has previously estimated an in-service date range of 2014-2018 for the
Populus to Hemingway project, but now plans to complete the project in the 2015-2018 timeframe.
The delay on the front end of the project is primarily the result of the BLM's delay of the draft
Environmental Impact Statement. See Chapter 10, Transmission Expansion Action Plan.
Action Item 14: Permit and build Wyomig/ta segment of the Energy Gateway Transmission
Project to support PacifiCorp loads, regional resource expansion needs, access to markets, grd
reliability, and congestion relief
Permit and constrct a 500 kV line between Aeolus and Mona
Status: The project is scheduled for completion in the 2017-2019 timeframe. The Company began
its public scoping process during the first quarter of 2011. See Chapter 10, Transmission
Expansion Action Plan.
Action Item 15: Obtain rights of way and constrct the Wallula-McNary line segment.
Status: PacifCorp has received all state and local permits and is currently pursuing the final
federal permits and interconnection at the McNary substation. The line route has been determined
and initial line design has been completed. The Company continues to work with property owners
and expects to have aU necessary rights of way for the project by April 2011. PacifCorp estimated
in its 2008 IRP Update that the line would be co,?structed and in service by late 2011. However,
due to extended lead times required to receive all federal agency approvals, the project is now
expected to be completed in the 2012-2013 timeframe. See Chapter 10, Transmission Expansion
Action Plan.
Action Item 16: For futue IRP planing cycles, include on-going financial analysis with regard to
transmission, which includes: a comparson with alternative supply side resources, deferred timing
decision criteria, the unique capital cost risk associated with transmission projects, the scenario
analysis used to determine the implications of this risk on customers, and all summaries of
stochastic anual production cost with and without the proposed transmission segments and base
case segments.
Status: See Chapter 4, Transmission Planning.
Action Item 17: By August 2, 2010, complete a wind integration study that has been vetted by
stakeholders through a public paricipation process.
Status: PacifCorp completed the wind integration study and distributed it to the public via email
and Web site posting on September 1, 2010. The Public Utilty Commission of Oregon granted a
deadline extension from August 1 to September 1, 2010. The study is included in the 2011 IRP as
Appendix I
Action Item 18: Durng the next planing cycle, work with paries to investigate carbon dioxide
emission levels as a measure for portolio performance scorig.
264
PACIFiCORP-2011 IRP CHATER 9 - ACTION PLAN
Status: PacifCorp incorporated CO2 emission levels as a final portfolio screening measure for
preferred portfolio selection. See Chapter 7, Modeling and Portfolio Evaluation Approach.
Action Item 19: In the next IRP, provide information on total C02 emissions on a year-to year
basis for all portfolios, and specifically, how they compare with the preferred portfolio.
Status: Appendix D contains System Optimizer C02 emissions on a year-by basis for each
portfolio, including the preferred portfolio.
Action Item 20: For the next IRP planning cycle, work with parties to investigate a capacity
expansion modeling approach that reduces the influence of out-year resource selection on resource
decisions covered by the IRP Action Plan, and for which the Company can sufficiently show that
portfolio performance is not unduly influenced by decisions that are not relevant to the IRP Action
Plan.
Status: PacifCorp conducted a two-phased System Optimizer simulation to test the impact of
limiting the model's optimization foresight to 12 years relative to a simulation based on the full 20
years. The results are documented in Chapter 8.
Action Item 21: In the next IRP planning cycle, incorporate assessment of distribution efficiency
potential resources for planing puroses.
Status: PacifCorp is conducting a conservation voltage reduction study, targeting 19 distribution
feeders in Washington. The study is expected to be completed by the end of May 2011. Based on
preliminary data provided by the contractor for the study, PacifCorp developed a distribution
effciency resource for testing with the System Optimizer model. Results of the portfolio
development testing are provided in Chapter 8. This action item has been superseded by Action
Item 6 in Table 9.1.
Resource Strategies
Of most concern from a planing perspective are so called regime shifts in which conditions
change abruptly and permanently, sometimes with little or no waring. The Energy Gateway
scenario analysis. outlined in Chapter 4 considered Incumbent and Green Futue scenaros defined
by combinations of associated CO2/natural gas price trajectories and regulatory intervention in the
form of a federal RPS requirement (Waxman-Markey renewable energy targets). Other scenarios,
similarly defied by a trgger event that causes sustained departe from expectations, are
considered for the acquisition path analysis. Specifically, PacifiCorp focuses on fudamentals-
based shifts in natual gas prices, enactment of regulatory policies, and different load trajectories.
For a specific resOurce already planned for acquisition, the path analysis also addresses
procurement delays.
265
PACIFiCORP-2011 IR CHATER 9 - ACTION PLAN
The path analysis is based on the portfolio development scenario and sensitivity analysis. results
outlined in Chapter 8, along with additional portfolio simulations conducted with the preliminar
prefeITed portfolio as the startg point. For each trgger event, Table 9.2 lists the associated
planning scenario and both short-term (2011-2020) and long-term (2021-2030) resource strategies.
Acquisition Path Decision Mechanism
The Utah Commission requires that PacifiCorp provide "(aJ plan of different resource acquisition
paths with a decision mechanism to select among and modify as the futue unfolds.',7 PacifiCorp's
decision mechanism is centered on the business planing and IR processes, which together
constitute the decision framework for makg resource investment decisions. The IRP models are
used on a macro-level to evaluate alternative portfolios and futues as par of the IRP process, and
then on a micro-level to evaluate the economics and system benefits of individual resources as part
of the supply-side resource procurement and DSM target-setting/valuation processes. In
developing the IRP action plan and path analysis, the Company considers common elements across
multiple resource strategies (for example, base levels of each resource tye across many least-cost
portfolios optimized according to different futues), planing contingencies and resource
flexibility, and continuous evaluation of market/regulatory developments and resource options.
Critical to this decision mechanism is the role of the anual business planning process, which
determines the impact of resource decisions on overall capital expenditues, customer rates,
earnings, cash flows, and financing requirements. The IRP and business plan serve as decision
support tools for senior management to determe the most prudent resource acquisition paths for
maintaining system reliability and low-cost electrcity supplies, and to help address strategic
positioning issues. The key strategic issues as outlined in this IRP include (1) addressing
regulatory risks in the areas of climate change and renewable resource policies, (2) accounting for
price risk and uncertinty in making resource acquisition decisions, (3) load uncertainty, and (4)
determining the appropriate level and timing of long-term transmission expansion investments,
accountig for the regulatory risks and uncertinties outlined above.
77 Public Service Commission of Utah, In the Matter of Analysis of an Integrted Resource Plan for PacifiCorp,
Report and Order, Docket No. 90-2035-01, June 1992, p. 28.
266
PACIFiCORP-20ll IRP CHATER 9 - ACTION PLAN
Table 9.2 - Near-term and Long-term Resource Acquisition Paths
Increased natual
gas prices
relative to curent
expectations,
drven by higher
oil prices,
reduced import,
delayed
unconventional
gas supply
development
Decreased
natul gas prices
relative to curent
expectations,
drven by
continued growt
of low-cost non-
conventional gas
supplies,
increased LNG
imports, and
decreased gas
demand
Significant and
persistent
reduced market
purchase
availability
Long term 50-
60% price
increases relative
to the Medium
forecast.
Long term 25-
30% price
decreases relative
to Medium
forecast.
Market tuoil,
combined with an
economic boom,
reduces
availability and
cost-effectiveness
of front offce
transactions along
the lines of the
rnarket stress test
outlined in
Appendix H. This
stress test
assumed an
unexpected 50-
percent decrease
inFOT
availabili
. Defer the second and third
CCCT resources by one to two
years if cost-effective relative to
other resources.
. Consider advanced high-
efficiency gas generation
technologies, evaluating the
trde-off between greater
effciency and higher capital
costs and project risks.
. Increase energy effciency
resources by 80-100 MW.
. Pursue additional renewables-
based distributed generation
opportities though PUR A
Qualifying Facility contracts.
. Accelerate the third CCCT
resource by one to two years if
cost-effective relative to other
resources.
. Defer wind and other renewables
acquisition if compliance with
state and federal greenhouse gas
and renewable standards ifnot at
risk.
. Depending on the duration,
severity, and breadth of market
purchase shortges:
Accelerate procurement of
futue plared CCCT
resources.
Acquire small simple-cycle
combustion tubine units
through expedited
regulatory approval
processes.
Lease mobile emergency
generators on an arual or
seasonal basis.
Pursue an accelerated
demand-side management
program expansion (e.g.,
. Expand acquisition of non-fossil
fuel generation resources to
additional clean baseload and
hybrid renewable/intermittent-
storage technologies. If sufficient
capacity can be obtained
economically, replace or defer on
a long-term basis the third CCCT
resource.
. Work with regulators to step up
demonstration/pilot project
activity using irmovative
generation and storage
technologies.
. Increase reliance on energy
effciency by an incremental 50-
200 MW by 2030, depending on
carbon regulatory developments
and energy effciency technology
advancement.
. Investigate alternative coal plant
utilization strategies for certin
units (fuel switching, idling, etc.)
depending on cost and
compliance impacts of new U.S.
EPA emissions control
requirements and federal
greenhouse gas regulations.
. Modify market depth and
pricing assumptions as
appropriate for futue IRP and
business plan support
modeling.
. On a regional plarming basis,
consider and potentially support
an enforceable resource
adequacy standard.
267
PACIFiCORP-20ll IR CHAPTR 9 - ACTION PLAN
Federal
Renewable
Portfolio
Standad
Continued
extension of the
federal renewable
production tax
credit
Diminishing
Federal
Renewable
Energy Support
combined with
higher gas prices
for 2015-2020.
A federal RPS is
instituted similar
to the Waxan-
Markey proposal
requirng 20% of
load to be met
with qualifying
resources by
2020.
The federal
renewable PTC is
extended to at
least 2020 at its
present leveL.
Due to federal
budget pressures
and a shift in
federal spending
priorities, the
federal
renewables PTC
expires within the
next several years
and other
incentives phase
out in the next
five years; no
federal renewable
standard is
Uta Cool Keeper opt-out
provision, price-response
progr, implementation
of higher-cost energy
effciency and dispatchable
load control ro s.
. Accelerate renewables
acquisition to as early as 2015 to
meet compliance tagets.
Acquire up to 400 MW by 2018
depending on compliance
provisions, or up to 150 MW of
geothermal capacity if enabling
state cost recovery legislation
and reguatory approval for
geothermal exploration &
development costs is obtained.
. Continue to issue renewable
RFPs under PacifiCorp's shelf
RFP program, and step up
consideration of unsolicited
proposals and multi-paricipant
projects as opportities arise.
· Increase reliance on energy
efficiency programs to tae
advantage of any energy credits
in federal legislation and cost-
effectively reduce the overall
com liance re uirement.
. Acquire up to 100 MW of
additional wind if the federal
PTC is extended beyond 2017.
. Consider scenaros for which the
PTC is selectively applied to
certain renewables (emerging
technologies) or phased out over
time.
. If there are no carbon reduction
regulatory requirements
expected, put on hold plans to
acquire more wind, baring
contiuig drops in tubine prices
due to improved technology and
manufactug over-capacity.
. Revisit the need for Energy
Gateway trsmission projects;
scale back or indefinitely
postpone investments depending
on the regulatory and market
outlook.
. Acquire up to 80 MW of
eothermal resources iven
. Evaluate nuclear and carbon
captue & retrofit technologies if
included as part of a broader
clean energy standad.
. Adjust transmission constrction
plans and increase regional
transmission coordination efforts
to facilitate project development
activity.
. Evaluate as scenaros
. Continue to investigate
renewable technology cost-
effectiveness and risks though
the IR process for futue
compliance with existing state
RPS requirements.
268
PACIFiCORP-20ll IRP
CO2 emission
compliance: low
to medium cost
impact
CO2 emission
compliance: high
cost impact
A federal cap-
and-trade progrm
or other CO2
pricing
mechanism is
instituted in the
2015-2017
time frame; prices
start at $ 12-
$ 15/ton and
escalate at about
5% annually.
A federal cap-
and-trade program
or other CO2
pricing
rnechanism is
implemented with
prices startng at
$25/ton and
escalate at about
7% annually.
Alternatively, an
emissions hard
cap is imposed
limiting emissions
to 15% below
2005 levels by
2020, and 80% by
2050
enabling state cost recovery
legislation and regulatory
approval for geothermal
exploration & development costs
and favorable project economics)
and other cost-effective
renewables as a hedge against
volatile fuel prices prior to
PTC/investment credit
ex iration.
. Adjust tiing of renewables
acquisition to minimize
regulatory compliance costs. The
mix of renewables is dependent
on gas price expectations,
geothermal legislative and
regulatory support, and relative
economics of technologies.
. Depending on specific CO2 costs
and gas prices, step up
acquisition of demand-side
management progrms and high-
effciency distrbuted generation
to help minimize the carbon
footprit.
. Modify the RFP bid evaluation
process (which is based on the
IRP portfolio modeling
framework) to reflect updated
CO2 reguatory expectations.
. Adjust timing of renewables
acquisition to minimize
regulatory compliance costs. The
mi of renewables is dependent
on gas price expectations,
geothermal legislative and
regulatory support, and relative
economics of technologies.
. Evaluate the economic and
operational impacts of reducing
coal plant utilization and
increasing natual gas plant
utilization as a CO2 emissions
compliance strategy.
. Increase energy effciency
resources by up to 100 MW.
. Modify the RFP bid evaluation
process to reflect updated CO2
re lato ex ectations.
CHATER 9 - ACTION PLAN
. Contiue to diversify the
resource mix, and tae advantage
of any CO2 compliance credits
that may be given to these
resource tyes.
. Increase reliance on energy
effciency by an incremental 50-
200 MW by 2030, depending on
inclusion of energy effciency
incentives in comprehensive
energy legislation, specific
carbon regulations enacted, and
energy effciency technology
advancement.
. Investigate alternative coal plant
utilization strategies for certain
units (fuel switching, idling, etc.)
depending on cost and
compliance impacts of new U.S.
EPA emissions control
requirements and detailed impact
evaluation of federal greenhouse
as re lations.
. Increase reliance on energy
efficiency by an incremental 50-
200 MW by 2030, dependig on
inclusion of energy efficiency
incentives in comprehensive
energy legislation, specific
carbon regulations enacted, and
energy effciency technology
advancement.
. Investigate alternative coal plant
utilization strategies for certin
units (fuel switching, idling,
CCCT replacement, carbon
captue & retrofit tèchnologies)
depending on cost and
compliance impacts of new U.S.
EPA emissions control
requirements and detailed impact
evaluation of federal greenouse
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P ACIFICORP - 2011 IR CHATER 9 - ACTION PLAN
Higher load
growth on a
sustained basis
1 % increase in
economic growth
drvers sustained
though 2030
Lower load
growth on a
sustained basis
1 % decrease in
economic growth
drvers sustained
through 2030
. Accelerate acuisition of the
thir CCCT by one to two year
(2019 to 2018 or 2017).
. Acquire SCCT capacity if cost-
effective.
. Increase energy effciency by
50-100MW.
. Accelerate dispatchable load
control program capacity.
. Acquire additional economic
market purchases to maintain
planing reserve margins.
. Ifhigher load growt can be
sustained with aggressive
renewables and/or CO2
regulation, orient incremental
capacity additions to a high CO2
com liance resoure strte.
. Elimiate/defer the second or
third CCCT based on revised
load growth projections.
. Increase energy effciency
reliance to help defer gas
resources if gas prices are
anticipated to increase relative to
the curent Medium forecast.
gas regulations.
. Continue to diversify the
resource mix, and take advantage
of any CO2 compliance credits
that may be given to these
resource tyes.
. Evaluate nuclear if included as
part ofa broader clean energy
standard.
. Increase energy effciency by up
to another 70 MW by 2030.
. Acquie baseload renewables (up
to 50 MW) if economic based on
governent incentives and
carbon regulations.
. Defer gas resources and market
purchases as appropriate based
on lowered load growt
expectations.
. Depending on cost and
compliance impacts of new U.S.
EPA emissions control
requiements and federal
greenhouse gas regulations,
consider coal plant idling
strate ies for certain units.
Procurement Delays
The main procurement risk is an inabilty to procure resources in the required time frame to meet
the need. There are various reasons why a particular proxy resource cannot be procured in the
timeframe identified in the 2011 IRP. There may not be any cost-effective opportities available
through an RFP, the successful RFP bidder may experience delays in permitting and/or default on
their obligations, or a material change in the market for fuels, materials, electricity, or
environmental or other electrc utility regulations, may change the Company's entire resource
procurement strategy.
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PACIFICORP ~ 2011 IR CHATER 9 - ACTION PLAN
Possible paths PacifiCorp could take if there was either a delay in the on-line date of a resource or,
if it was no longer feasible or desirable to acquire a given resource, include the following:
. Consider alternative bids if they haven't been released under a curent RFP.
. Issue an emergency RFP for a specific resource.
. Move up the delivery date of a potential resource by negotiating with the supplier/developer.
. Rely on near-term purchased power and transmission until a longer-term alternative is
identified, acquired through PacifiCorp's mini-RFPs or sole source procurement.
. Install temporary generators to address some or all of the capacity needs.
. Temporarily drop below the 13 percent planning reserve margin.
. Implement load control initiatives, including calls for load curailment via existing load
curailment contracts.
Resource differences between the 2011 IRP and the 2011 business plan approved in December
2010 relate primarily to the amount of energy effciency. For DSM resources, receipt and
modeling of the final Cadmus supply curves occured after the business plan was completed. The
IRP modeling thus reflects a more curent view of DSM efficiency potentials and costs that wil be
incorporated in portfolio modeling to support preparation of the Company's 2012 business plan.
The amount of wind in the 2011 IRP preferred portfolio reflects the comprehensive portfolio
scenario analysis, stochastic risk analysis, and clean energy policy/regulatory compliance risk
assessment conducted in December 2010 through Februar 2011, after the business plan was
approved. In both the 2011 business plan and 2011 IRP, PacifiCorp shifted Wyoming wind
capacity from 2017 to 2018 in recognition of the revised planned timeline for Energy Gateway
West. The overall wind capacity in the 2011 IRP preferred portfolio decreased by 60 MW in the
2018-2020 period relative to the 2011 business plan.
Table 9.3 compares the 2011 IRP preferred portfolio with the 2008 IRP Update portfoli078 for the
10 years covered by both portfolios (2011-2019), indicating year by year capacity differences by
major resource categories (yellow highlighted table). The major resource changes include:
. Thee CCCT resources included in the portfolio by 2019 rather than two, driven by an
increased planning reserve margin (12 to 13 percent), lowered expectations for irrgation
load control program capacity, and lower gas prices.
. Significantly more energy effciency and dispatchable load control-312 MW and 79 MW,
respectively.
78 The 2008 IR Update report is available on PacifiCorp's IR Web site:
htt://vv'Vvw.pacificom.com/ content!dam/pacificorp! doclEnergy Sources/Integrated Resource Plani2008IRPUpdateiP
acifiCorp-2008lRPUpdate 3-31-10.pdf
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PACIFICORP - 2011 IR CHAR 9 - ACTION PLAN
Table 9.3 - Portfolio Comparison, 2011 Preferred Portfolio versus 2008 IRP Update
Portfolio
2011 IR Preferred Portfolio
9
70
114
5
9
57
110
5
7
20
118
5
368
871
618
811
59060
Difference - 2011 IRP Preferred Portolio less 2008 IRPUpdate
2008 IR Update (2010 Business Plan)
To acquire resources outlined in the 2011 IRP action plan, PacifiCorp intends to continue using
competitive solicitation processes in accordance with the then-curent law, rules, and/or guidelines
in each of the states in which PacifiCorp operates. PacifiCorp wil also continue to pursue
opportnistic acquisitions identified outside of a competitive procurement process that provide
clear economic benefits to customers. Regardless of the method for acquirg resources, the
Company wil use its IRP models to support resource evaluation as part of the procurement
process, with updated assumptions including load forecasts, commodity prices, and reguatory
requirement information available at the time that the resource evaluations occur. This wil ensure
that the resource evaluations account for a long-term system benefit view in alignent with the
IRP portfolio analysis framework as directed by state procurement regulations, and with business
planning goals in mind.
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PACIFiCORP-20ll IRP CHATER 9 - ACTION PLAN
The sections below profie the general procurement approaches for the key resource categories
covered in the action plan: renewables, demand-side management, thermal plants, distrbuted
generation, and market purchases.
Renewable Resources
The Company uses a shelf RFP as the primary mechanism under which the Company wil issue
subsequent RFPs to meet most of the renewable resource acquisition goals over the IRP action
plan and business planning horizons. The shelfRFP, to be re-issued on a periodic basis, will allow
the Company to react effectively to power supply market developments and changes in the status
of RPS requirements, the production tax credit, other fmancial incentives, and C02 legislation. The
Company wil seek both cost-effective conventional and emerging renewable technologies through
the RFP process, including those coupled with energy storage. Qualifying Facilities under the
Public Utilties Regulatory Policy Act (PURP A), at least LO MW in size, are also treated as eligible
resources under this particular RFP program.
The Company wil also pursue renewable resources though means other than the shelf RFP in
recognition that strong competition for renewable projects, and the dynamic natue of renewable
construction and equipment markets, wil require the Company to respond quickly and effciently
as resource opportities arse. Other procurement strategies that PacifiCorp wil pursue in parallel
include bilateral negotiations, PUR A contracting, and self-development.
Demand-side Management
PacifiCorp uses a variety of business processes to implement DSM programs. The outsourcing
model is preferred where the supplier takes the performance risk for achieving DSM results (such
as the Cool Keeper program). In other cases, PacifiCorp manages the program and contracts out
specific tasks (such as the Energy Finswer program). A third method is to operate the program
completely in-house as was done with the Idaho Irrgation Load Control program. The business
process used for any given program is based on operational expertise, performance risk and cost-
effectiveness. With some RFP's, PacifiCorp developed a specific program design, and put that
design out to competitive bid. In other cases, as with the 2008 DSM RFP issued in November
2008, PacifiCorp opened up bidding to many tyes of Class l, 2, and 3 programs and design
options.
To support the DSM procurement program, the IRP models are used for resource valuation
puroses to gauge the cost-effectiveness of programs identified for procurement shortlists. For
Class 2 programs, PacifiCorp performs a "no cost" load shape decrement analysis to derive
program values using its stochastic production cost model, Planning and Risk, similar to what was
done for the 2008 IRP. (Although the supply cure modeling approach used for Class 1 and Class
2 DSM programs can provide a gross-level indication of program value, an avoided-cost type of
study is necessary to pinpoint precise values suitable for cost-effectiveness assessment.) The load
shape decrement analysis wil be published asa supplement to this IR once completed.
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P ACIFICORP - 2011 IR CHAR 9 - ACTION PLAN
Thermal Plants and Power Purchases
Prior to the issuance of any supply-side RFP, PacifiCorp wil determine whether the RFP should
be "all-soure" or if the RFP wil have limitations as to the amount, proposal strctue(s), fuel
tye, or other resource attbutes. The Company expects to issue an all-source RFP to support
acquisition of major resources after 2014.
Company benchmark resources wil also be determed prior to an RFP being issued and. may
consist of a self-developed resource option or a build own transfer arrangement. As with other
resource categories, the IRP models wil be used for bid evaluation, and wil reflect the latest
market prices, load forecasts, regulatory policies, and other updated information as appropriate.
Distributed Generation
Distrbuted generation, such as CHP and solar hot water heating, were found to be cost-effective
resources in the context ofIRP portolio modeling. PacifiCorp's procurement process wil continue
to provide an avenue for such new or existig resources to participate. These resources wil be
advantaged by being given a minimum bid amount (MW eligibility that is appropriate for such an
alternative, but that is also consistent with PacifiCorp's then-curent and applicable tariff filings
(QF tariffs for example).
PacifiCorp wil continue to partcipate with regulators and advocates in legislative and other
regulatory activities that help provide tax or other incentives to renewable and distrbuted
generation resources. The Company wil also continue to improve representation of distrbuted
generation resource in the IRP models.
As the Company acquires new resources, it wil need to determine whether it is better to own a
resource or purchase power from another part. While the ultimate decision wil be made at the
time resources are acquired, and wil primarily be basedon cost, there are other considerations that
may be relevant.
With owned resources, the Company would be in a better position to control costs, make life
extension improvements, use the site for additional resources in the futue, change fueling
strategies or sources, efficiently address plant modifications that may be required as a result of
changes in environmental or other laws and regulations, and utilze the plant at cost as long as it
remains economic. In addition, by owning a plant, the Company can hedge itself from the
uncertinty of relying on purchasing power from others. On the negative side, owning a facilty
subjects the Company and customers to the risk that the cost of ownership and operation exceeds
expectations, the cost of poor performance, fuel price risk, and the liabilty of reclamation at the
end of the facility's life.
Depending on contract terms, purchasing power from a third part in a long term contract may
help mitigate the risk of cost overrs durng constrction and operation of the plant, may mitigate
274
PACIFICORP - 2011 IR CHATER 9 - ACTION PLAN
some cost and performance risks, and may avoid any liabilities associated with closure of the plant.
Short-term purchased power contracts could allow the Company to defer a long term resource
acquisition. On the negative side, a long-term purchase power contract relinquishes control of
constrction cost, schedule, ongoing costs and compliance to a third part, and exposes the buyer
to default events and contract remedies that wil not likely cover the potential negative impacts.
For example, a purchase power contract could termate prior to the end of the term, requiring the
Company to replace the output of the contract at then curent market prices. In addition, the
Company and customers do not receive any of the savings that result from management of the
asset, nor do they receive any of the value that arise from the. plant after the contract has expired.
Finally, credit rating agencies impute debt associated with long-term resource contracts that may
result from a competitive procurement process, and such imputation can affect the Company's
credit ratios and credit rating.
Carbon dioxide reduction regulations at the federal, regional, or state levels would prompt the
Company to continue to look for measures to lower C02 emissions of existing thermal plants
through cost-effective means. The cost, timing, and compliance flexibility afforded by C02
reduction rules wil impact what tyes of measures would be cost-effective and practical from
operational and regulatory perspectives. As noted earlier in the IRP, prospective federal emission
control rules wil also impact coal plant utilzation and investment decisions.
For a cap-and-trade system, examples of factors affecting carbon compliance strategies include the
allocation of free allowances, the cost of allowances in the market, and any flexible compliance
mechanisms such as carbon offsets, allowance/offset banking and bOITowing, and safety valve
mechanisms. To lower the emission levels for existing thermal plants, options include changing the
fuel tye, repowering with more efficient generation equipment, lowerig the plant heat rate so it is
more efficient, and adoption of new technologies such as C02 captue with sequestration when
commercially proven. Indirectly, plant carbon risk can be addressed by acquirng offsets in the
form of renewable generation and energy effciency programs. Under an aggressive C02
regulatory environment, and depending on fuel costs, coal plant idling and replacement strategies
may become tenable options.
High C02 costs would shift technology preferences both for new resources and existing resources
to those with more effcient heat rates and also away from coal, unless carbon is sequestered.
There may be opportities to repower some of the existing coal fleet with a different less carbon-
intensive fuel such as natural gas, but as a general rule, coal units wil contiue to use the existing
coal technology until it is more cost-effective to replace the unit in total. A major issue is whether
new technologies wil be available that can be exchanged for existing coal economically.
Fuel switching and dual-fueling provide some limited opportities to address emissions, but will
require both capital investment and an understading of the trade-offs in operating costs and risks.
While these options would provide the Company a means to lower its emission profie, such
options would be extremely expensive to implement unless there is a high carbon emission penalty
to justify them.
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PACIFiCORP-2011 IR CHAR 9 - ACTION PLAN
Adding natural gas generatig resources to PacifiCorp's system requires an understanding of the
fuel supply risks associated with such resources, and the application of prudent risk management
practices to ensure the availability of suffcient physical supplies and limit price volatilty
exposure. The risks discussed below include price, availabilty, and deliverability.
Price Risk
PacifiCorp manages price risk though a documented hedging strategy. This strategy involves
nearly fully hedging price risk in the nearest 12-month forecast period and hedging less of the
exposure each year beyond that though year four. Near-term prices for forecasted volumes are
nearly fully hedged to add price certinty to near term planing horizons, budgets, andrate case
fiings. Furher out, where plans and budgets are less certin, PacifiCorp considers its most recent
ten-year business plan, curent market fudamentals, credit risk, collateral fuding, and regulatory
risk in making hedging decisions. PacifiCorp balances the benefit of hedging that plan's price
assumptions with prudent risk management for its ratepayers and shareholders.. PacifiCorp hedges
price risk through the use of financial swap transactions and/or physical transactions. These
transactions are executed with various counterparties that meet PacifiCorp' s credit and contractul
requirements.
Availabilty Risk
Availability risk refers to the risk associated with having adequate natural gas supply in the
vicinity of contemplated generating assets. PacifiCorp purchases physical supply on a forward
basis achieving contractual commitments for supply. The Company also relies on its ability to
purchase physical supplies in the futue to meet requirements. This second approach subjects
PacifiCorp to price risk resulting from swings in supply-demand balances, as well as the risk that
natual gas production in a producing region ceases regardless of price. It is reasonable that a
region-wide cease in production, given reserve estimates, could only be brought about by extreme
and unforeseen events such as natul disaster or regulatory moratoriums on the production or
consumption of natual gas-events that long-term supply commitments would not counteract.
Index prices are designed to reflect the prevailing cost of supply at various delivery locations. As
described above, PacifiCorp hedges its exposure to changes in those index prices, thereby allowing
for procurement of supply at floating index prices or waiting to acquire supply when requirements
estimates are more accurate and the premiums for longer-term commitments are no longer
demanded by suppliers.
Deliverabilty Risk
Deliverability risk refers to the risk associated with transportg natual gas supply from supply
locations to generating facilities. The 2011 IRP accounts for the cost of natual gas transporttion
service required to fuel gas plants, and uses existig tariff pipeline-defined transporttion capacity
and transporttion costs in evaluatig the need, timing, and location of new natual gas-fired
generating plants. More specifically, the 2011 IRP uses existig maximum tariff rates for demand
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PACIFiCORP-2011 IR CHATER 9 - ACTION PLAN
charges, volumetrc costs, and reimbursement of fuel and lost/unaccounted natual gas. These
taff rates are developed through cost of service filings with appropriate regulators-the FERC for
interstate pipelines and relevant state regulators for intrastate pipelines. By defmition, rates are
developed based on cost of service of existing operations, without consideration for maintenance
and operations of futue expansions. The result of this is that the 2011 IRP assumes that the
economics of a new natual gas fired generator reflect the curent cost of service for existing
natual gas transportation facilities; whereas, the cost of any new natual gas transportation
capacity is dependent on the volumetrc size of the new capacity, and prevailing costs of
constrction, maintenance, and operations (e.g. steel, labor, fmancing).
Also, the 2011 IRP accounts for the availability. of natual gas transporttion service required to
fuel new electrcity generating facilities. In selecting a gas-fired resource, the implicit assumption
is made that natural gas transportation infrastrctue exists or wil be built. This is a reasonable
assumption if one fuer assumes that the constrction of new pipeline facilities is a fuction of
cost, which is addressed above.
PacifiCorp manages this transportation cost through two transaction tyes: transporttion service
agreements and delivered natual gas purchases:
. PacifiCorp enters into transportation service agreements that offer PacifiCorp the right to
ship natual gas from prolific production basins or liquidly traded "hubs" to generatig
assets. Natual gas hubs exist where a large volume of production is gathered and
delivered into a large interstate pipeline or where large pipelines intersect. These hubs lead
to liquidly traded markets as the movement of gas from one transporting pipeline to another
lead to a large number of wiling buyers and sellers.
. PacifiCorp purchases natual gas delivered to generating plants and/or hubs. This approach
pushes the deliverability risk to the supplier by contractully committing it to making
necessary supply and/or transporttion arrangements.
PacifiCorp is confident that the risks associated with fueling curent and prospective natual gas
fueled generation can be effectively managed. Risk management involves ongoing monitoring of
the factors that affect price, availability, and deliverability. While prudence warrants the
monitoring of many factors, some issues that PacifiCorp needs to pay particular attention to, given
today's market, include the following:
. Potential counterparties need to be continually monitored for their creditwortiness and
long-term viability, especially given the curent economic dO\yntu.
. Environmental concerns could impact natual gas prices; examples include carbon
regulation and increased focus on the chemicals used for hydraulic fractuing for shale gas
production. PacifiCorp continues to monitor the regulatory environment and its potential
impact on natual gas pricing.
. As production grows in the Rocky Mountains, so does the transporttion infrastrcture.
PacifiCorp continues to monitor this activity for risks and opportities that new pipeline
infrastrctue may yield.
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PACIFiCORP-20ll IR CHATER 9 - ACTION PLAN
The IRP standards and guidelines in Utah require that PacifiCorp "identify which nsks wil be
borne by ratepayers and which wil be borne by shareholders." This section addresses this
requirement. Three tyes of nsk are covered: stochastic nsk, capital cost nsk, and scenano risk.
Stochastic Risk Assessment
Several of the uncertain varables that pose cost nsks to different IRP resource portfolios are
quantified in the IRPproduction cost model using stochastic statistical tools. The variables
addressed with such tools include retail loads, natul gas pnces, wholesale electrcity pnces,
hydroelectrc generation, and thermal unit availability. Changes in these vanables that occur over
the long-term are typically reflected in normalized revenue requirements and are thus borne by
customers. Unexpected vanations in these elements are normally not reflected in rates, and are
therefore borne by investors unless specific regulatory mechanisms provide otherwise.
Consequently, over time, these nsks are shared between customers and investors. Between rate
cases, investors bear these nsks. Over a penod of years, changes in prudently incured costs wil be
reflected in rates and customers wil bear the nsk.
Capital Cost Risks
The actual cost of a generating or trnsmission asset is expected to vary from the cost assumed in
the 2011 IRP. Capital expenditues continue to increase, drven by the need for infrastrcture
investment to support loads and maintain reliable electncity supplies, and the effects of cost
inflation. State commissions may determine that a portion of the cost of an asset was imprudent
and therefore should not be included in the determination of rates. The nsk of such a determination
is borne by investors. To the extent that capital costs var from those assumed in this IRP for
reasons that do not reflect imprudence by PacifiCorp, the nsks are borne by customers.
Scenario Risk Assessment
Scenano nsk assessment pertins to abrupt or fudamental changes to variables that are
appropnately handled by scenario analysis as opposed to representation by a statistical process or
expected-value forecast. The single most importnt scenano nsks of this tye facing PacifiCorp
continues to be government actions related to C02 emissions and renewable resources. These
scenaro nsks relate to the uncertainty in predicting the scope, timing, and cost impact of C02
emission and renewable standard compliance rues.
To address these risks, the Company evaluates resources in the IRP and for competitive
procurements using a range of C02 pnces consistent with the scenaro analysis methodology
adopted for the Company's IRP portfolio evaluation process. The Company's use of IRP
sensitivity analysis covenng different resource policy and cost assumptions also addresses the need
for consideration of scenano nsks for long-term resource planning. As noted in the sections that
descnbe the denvation of the prefeITed portfolio, augmenting the portfolio with additional wind
resources represents the most effective regulatory nsk mitigation measure at the present time,
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PACIFiCORP-2011 IRP CHAPTER 9 - ACTION PLAN
along with a significant increase in demand-side management resource acquisition. The extent to
which futue regulatory policy shifts do not align with the Company's resource investments
determined to be prudent by state commissions is a risk borne by customers.
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PACIFiCORP-2011IRP CHAPTER 10 - TRASMISSION EXPANSION ACTION PLAN
CHAPTER 10 - TRANSMISSION EXPANSION ACTION
PLAN
281
PACIFiCORP-20ll IR CHAPTER 10 - TRASMISSION EXPANSION ACTION PLAN
PacifiCorp is well underway in the ratig, permttg and constrction of its expansive Energy
Gateway transmission investment plan. Since the original anouncement of Energy Gateway in
May 2007, and as discussed fuer in Chapter 4, PacifiCorp has emphasized that significant new
transmission capacity is needed to adequately serve its customers' load and growth needs for the
long-term.
In November 2010, the Company completed and
placed into service the first major segment of
Energy Gateway - the double circuit 345 kV
Populus to Termal line ~ ahead of schedule and
within budget. This line.is a key segment of
Energy Gateway Central, which ultimately wil
connect with and enable Gateway West and
Gateway South to achieve their full 1,500 MW
capacity rating. Constrction on the Mona to
Oquirrh line - the other major segment of
Gateway Central- is scheduled to begin in 2011,
with an expected 2013 in-service date. These and other Energy Gateway segments are detailed
fuher in the Gateway Segment Action Plans section below. The in-service dates provided in the
following section are based on optimal tig of trsmission needs and best efforts to complete
constrction, and are subject to change based on permittg, environmental approvals and
constrction schedules.
PacifiCorp requests regulatory acknowledgement of the Energy Gateway projects scheduled to
be in-service in 2014 or sooner. These projects are detailed below. As the IRP is a public
document, however, the Company has not provided in this document confidential financial data
related to these projects. PacifiCorp welcomes, as it has in the past, opportities to discuss
additional project details as appropriate to support regulatory acknowledgment of this IRP.
Wallula to McNary (Energy Gateway Segment A)
This project was originally planned as a 56-mile,
single circuit 230 kV transmission line connecting
PacifiCorp's existing substations at Walla Walla
and Wallula, Washington, and Bonnevile Power
Administration's McNary substation near
Umatila, Oregon. The initial target completion
date was 2010; however, the project was put on
hold to ensure that it was still the most cost-
effective option for our customers in light of
evolving regional transmission plans and potential
generation development in the area.
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PACIFICORP - 2011 IRP CHAPTER 10 - TRASMISSION EXPANSION ACTION PLAN
In 2009, PacifiCorp received transmission service requests that require.the Company to proceed
with the Wallula to McNary portion of the Walla Walla to McNary project. This segment
consists of approximately 30 miles of single circuit 230 kV line on a 125-foot right of way, and
wil provide the capacity to add new energy to the system, improve service to customers and
improve the reliability of the regional transmission system.
The Wallula to McNary line is needed for several reasons, but primarily to enable the Company
to meet curent and projected demand in its service area, to address energy constraints on the
system and facilitate the transmission of generation resources from remote locations to customer
load centers. PacifiCorp's transmission system in the Walla Walla area curently operates at full
capacity, and the Company has informed several project developers that their proposed projects
could not be interconnected to the system without additional infrastrcture. To date, PacifiCorp
has entered into two transmission service contracts for servce from Wallula to McNary to move
a total of 120 megawatts of generation resources to market. The Company has received
additional customer requests for interconnection and transmission service on this path, and
pursuant to Federal Energy Regulatory Commission policy, public utilities are required to
expand and enlarge their transmission systems to reliably provide service to customers and to
facilitate the interconnection of generation and transmission service requests.
In Addition, PacifiCorp committed to certain transmission system improvements as par of the
settlement agreement approving its acquisition by MidAmerican Energy Holdings Company.
Acquisition Commitment 34c requires the Company to establish a link between Walla Walla and
Yakima and/or reinforce the line between Walla Walla and the Mid Columbia bus. The
commitment also provided that, in the event fuher review showed such a project to not be cost-
effective, optimal for customers or able to be completed by the target date, an alternative with
comparable system benefits may be proposed. PacifiCorp performed necessary reviews and
determined that a more feasible option would be to constrct a line from McNar to Walla
Walla, and as explained in the Overview section above, the Company is proceeding with the
Wallula to McNary portion of the project at this time.
PacifiCorp has received all state and local permits and is curently pursuing the final federal
permits and interconnection at the McNary substation. The line route has been determined and
initial line design has been completed. The Company continues to work with propert owners
and expects to have all necessar rights of way for the project by April 2011. PacifiCorp
estimated in its 2008 IRP Update that the line would be constrcted and in service by late 2011.
However, due to extended lead times required to receive all federal agency approvals, the project
is now expected to be completed in the 2012-2013 timeframe.
The remaining section from Wallula to Walla Walla is not curently scheduled to proceed but
wil remain under review for futue consideration.
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PACIFiCORP-20ll IR CHAPTER 10 - TRSMISSION EXPANSION ACTION PLAN
Mona to Oquirrh and Oquirrh to Terminal (Energy Gateway Segment C)
To meet increasing customer need for electrcity,
PacifiCorp wil constrct the Mona to Oquirh
and Oquirrh to Terminal transmission projects in
Utah. The Mona to Oquirh project consist of a
single circuit 500 kV line that wil ru
approximately 69 miles between the new Clover
substation to be built near the existing Mona
substation in Juab County to the new Limber
substation to be constrcted in Tooele County;
and a double circuit 345 kV line extendig
approximately 31 miles between. the Limber
substation and the existing Oquirrh substation in West Jordan. The Oquirrh to Terminal project
consists of a double circuit 345 kV line ruing approximately 14 miles between the OquiITh
substation and the Terminal substation.
The existing transmission system has limited capabilty to deliver energy into the largest load
center in Utah - the Wasatch Front area (including Salt Lake, Utah, Tooele, Davis, Weber,
Cache, and Box Elder Counties). The Mona substation is a critical hub through which power is
imported from PacifiCorp's southern intertie lines, and it also serves as an importnt
interconnection point with Deseret Power's Bonana generating facilty and Intermountain
Power Agency's Intermountain Power Project. Capacity nort of the Mona substation is fully
subscribed and constrained, and additional capacity is required in order for PacifiCorp to
continue to meet its load service obligations.
In addition to meeting our customers' futue energy requirements, these projects are key to
maintaining the Company's compliance with mandated North American Electric Reliability
Corporation ("NERC") and Western Electrcity Coordinating Council ("WECC") reliability and
performance standards as necessary durng normal system operations and durg certin
transmission system and generation plant outage conditions.
The Utah Public Service Commission issued a Certficate of Public Convenience and Necessity
for the Mona to Oquirh project in June 2010, and PacifiCorp has obtained all of the local
conditional use permits required for the project. The Bureau of Land Management ("BLM")
published its Final Environmental Impact Statement in April 2010 and the Record of Decision
was posted in February 2011. Right-of-way efforts are ongoing and constrction is scheduled to
begin in 2011. The Mona to Oquirrh segment is scheduled for completion in 2013 and Oquirh to
Terminal is scheduled for completion in 2014.
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PACIFiCORP-20ll IR CHAPTER 10 - TRSMISSION EXPANSION ACTION PLAN
Sìgurd to Red Butte (Energy Gateway Segment G)
The Sigud to Red Butte project, part of Gateway
South, is a single circuit 345 kV line that rus
approximately 160 miles between the Sigud
substation near Richfield, Utah, and an expanded
Red Butte substation near Central in Washington
County. When completed in 2014, it provides a
critical path to meet load obligations and maintain
transmission capacity on the TOT2C path for
contracted point-to-point service.
The capacity of the southwest Utah transmission system, including the exi:ting Sigud to Thee
Peaks to Red Butte 345 kV transmission line, is fully utilized and cannot curently provide
adequate service under all expected operatig conditions. Loads in southwestern Utah are
forecasted to surass the capabilities of the existing transmission system. Without the project,
peak load in southwestern Utah cannot be reliably served durg transmission line outages or
major equipment contingencies. New transmission facilities must be constrcted to provide
reliable capacity for load service. The Sigud to Red Butte transmission project is needed to
support both short.and long term energy demands and wil strengthen the overall reliability of the
Company's. existing transmission system.
In addition to meeting demand and supporting electrcal loads in southwestern Utah, the Sigud
to Red Butte project will also improve the transmission system's ability to transport energy into
southwest and central Utah, and to high growth urban areas in and around Salt Lake City and
along the Wasatch Front. As with other planned Energy Gateway projects, the Sigud to Red
Butte project is also key to maintaining the Company's compliance with mandated North
American Electrc Reliability Corporation ("NERC") and Western Electrcity Coordiating
Council ("WECC") reliability and performance standards durng normal system operations and
system outage conditions.
The Bureau of Land Management ("BLM") has been designated as the lead agency in the federal
environmental review process. The BLM is curently developing an environmental impact
statement ("EIS") on the Company's right of way application, a process that began in December
2008. A draft EIS is anticipated to be published for public comment during the 3rd Quarter of
2011, followed by the issuance of a fial EIS durng the second quarter of2012. The Company
anticipates that the BLM wil issue the Record of Decision durng the fourh quarter of2012. At
the conclusion of this process the BLM and the U.S. Forest Service wil issue a right-of-way
grant to build the proposed transmission line on federal propert.
PacifiCorp hopes to complete all permitting and right of way acquisitions by 2012 and to place
the project in-service for customers in 2014.
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PACIFiCORP-20ll IR CHAPTER 10- TRSMISSION EXPANSION ACTION PLAN
Segment D - Windstar to Populus (Gateway West)
The Windstar to Populus project is the first of two
major segments of Gateway West, and consists of
thee key sections: (i) two single circuit 230 kV
lines that wil ru approximately 82 and 72 miles
respectively between the recently constrcted
Windstar substation in eastern Wyoming and the
Aeolus substation to be constrcted near
Medicine Bow, Wyoming; (ii) a single circuit 500
kV line ruing approximately 141 miles from
the Aeolus substation to a new anex substation
near the existing Bridger substation in western Wyoming; and (iii) a single circuit 500 kV line
ruing approximately 205 miles between the new anex substation and the recently constrcted
Populus substation in southeast Idaho. PacifiCorp has parered with Idaho Power to build the
Windstar to Populus project, which wil improve access to existing and new generating
resources, including wind, and delivery of these resources to both utilities' customers.
As stated in Chapter 4,PacifiCorp has begu permittg efforts and right of way research for this
project. A contract wil be issued durg the 4th Quarer of 2011 for right-of-way acquisition,
which wil begin in 2012. The Company hopes to complete the Environmental Impact Statement
process with the Bureau of Land Management in 2012. The 2008 IR Update reported an in-
service date range of 2014-2016 for Windstar to Populus, but delays in the BLM's EIS process
have delayed the project resulting in revised plans to complete it in the 2015-2017 timeframe.
The Windstar to Populus project, and Gateway West in general, represents a significant
improvement in transfer capability from one of the richest areas of diverse resources in the West,
a region that curently lacks new export capacity due to severe transmission constraints.
Segment E - Populus to Hemingway (Gateway West)
The Populus to Hemingway project is the second
of two major segments of Gateway West. The
project consists primarily of two single circuit
500 kV lines that ru approximately 300 miles
each though southern Idaho, from the Populus
substation near Downey to a new Hemingway
substation located south of Boise between the
towns of Melba and Murhy The southern line is
planned to connect midway to the new Ceda
Hil substation southeast of Twin Falls; the
northern line wil connect midway to both the Borah substation near Pocatello and the Midpoint
substation south of Shoshone; and an additional single circuit 500 kV line wil be built
connecting the Cedar Hil and Midpoint substations.
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P ACIFICORP - 2011 IRP CHAPTER 10 - TRASMISSION EXPANSION ACTION PLAN
As with the Windstar to Populus project, PacifiCorp has parered with Idaho Power to build the
Populus to Hemingway segment of Gateway West. The companies hope to complete the
Environmental Impact Statement process and all necessary permitting in 2012, and to begin
constrction as early as 2015. The Company has previously estimated an in-service date range of
2014-2018 for the Populus to Hemingway project, but now plans to complete the project in the
2015-2018 timeframe. The delay on the front end of the project is primarily the result of the
BLM's delay of the draft EIS.
Once completed, the Populus to Hemingway project wil enable PacifiCorp and Idaho Powerto
access existing and new generating resources and deliver power from these sources to customers
throughout the region.
Segment F - Aeolus to Mona (Gateway South)
The project is scheduled for completion in the
2017-2019 ti:reframe, and the Company began
its public scoping process durig the first quarter of 2011. Once complete, the Aeolus to Mona
project wil connect Gateway West and Gateway Central, providing path rating support to these
segments, improving system reliability and operational flexibility for the bulk electrc network.
The Aeolus to Mona project is the pricipal
segment of Gateway South and a critical
component of the Energy Gateway project
overalL. The project consists of a single-circuit
500 kV line that rus approximately 395 miles
between the Aeolus substation near Medicine
Bow, Wyoming, and the Mona substation in
central Utah.
Energy Gateway South, as originally planned, included a single circuit 500 kV line continuing
from the Mona substation southwest to the Crystal substation north of Las Vegas, Nevada. As
discussed under "Energy Gateway Priorities" in Chapter 4 - Transmission Planning, PacifiCorp
included in its original Energy Gateway announcement the potential for "up sizing" the project to
address regional needs, including the Mona to Crystal segment and higher-capacity build options
of other segments. While there was significant interest by third parties to paricipate in the
Gateway South project, there was a lack of requisite financial commitment needed to maximize
the project's capacity for broader regional needs, and PacifiCorp made the decision to proceed
with the portions of the project required for reliability and customer needs. PacifiCorp informed
the Nevada Public Utility Commission in Januar 2011 that the Mona to Crystal segment would
be postponed indefinitely.
287
P ACIFICORP ~ 20 11 IRP CHAPTER 10 - TRSMISSION EXPANSION ACTION PLAN
Segment H - Hemingway to Captain Jack
The Hemingway to Captain Jack project was
planned as par of the Energy Gateway
transmission investment to signficantly improve
the connection between PacifiCorp' s east and
west control areas and to help deliver more
diverse energy resources to serve PacifiCorp' s
Oregon, Washington and California customers.
As planned, the project would be a single circuit
500 kV line ruing approximately 375 miles
between the Hemingway substation south of
Boise, Idaho, and the Captain Jack substation near Klamath Falls, Oregon. This project and other
proposed lines in the area have been reviewed as par of the Western Electrcity Coordinating
Council regional planning process.
As part of its ongoing review of the Hemingway to Captain Jack project, PacifiCorp has
cqnsidered the prudence of this project in light of other proposed lines, including the Boardman
to Hemingway line initiated by Idaho Power Company (IPC) and Portland General Electric's
(PGE) proposed Cascade Crossing transmission line between Boardman and the Salem, Oregon
area. Recognizing the potential mutual benefits and value for customers of jointly developing
transmission, PacifiCorp has entered into Memorandums of Understanding with IPC and PGE to
explore potential parership opportities for the proposed Hemingway to Boardman and
Cascade Crossing transmission projects. Should the customer and system benefits of these
potential parterships exceed those of PacifiCorp's proposed Hemigway to Captain Jack
project, the Company wil pursue these joint development opportities in place of Hemingway
to Captain Jack.
288
PACIFICORP - 2011 IR CHATER 10 - TRASMISSION EXPANSION ACTION PLAN
Figure IO.I-Energy Gateway Transmission Expansion Plan
. PacifCorp service area
Planned transmission lines:
~ 500 kV minimum voltage
~ 345 kV minimum voltage
-,~ 230 kV minimum voltage
.. ~ Lines under consideration
o Transmission hub
. Exsting substation
Thîsmap Isfor gehéra.lreferenqe ørily and refiectcurrerit plans.
It may not refect the final routes. construction sequence or exct line configuraon.
289
P ACIFICORP - 2011 IR CHAPTER 10- TRSMISSION EXPANSION ACTION PLAN
Figure 10.2 - 2012-2014 Energy Gateway Additions for Acknowledgement
. PadfiCorp service area
Planned transmission lines:
~ 500 kV minimum voltage
~ 345 kV minimum voltage
~~ 230 kV minimum voltage
Lines under consideration
Q TransmÎssion hub
. Existing substation
This map is for general léfelénce only and reflect currnt plans.
lt ma not refectthe final routes. constuction sequence or exct line configuration.
(A) Wallula to McNar 230 kV, single circuit 2012-2013 400MW (hi)400 MW (hi)
(C) Mona to Limber 500 kV, single circuit 2013
Limber to Oquirh 345 kV, double circuit 2013 700 MW (bi)1,000 MW (bi)
Oquirrh to Terminal 345 kV, double circuit 2014
(G) Sigud to Red Butte 345 kV, single circuit 2014 550 MW (s-n)550 MW (s-n)
400 MW (n-s)400 MW (n-s)
(hi) =' bi-directional;(n-s) =' nort-to-south;(s-n) =' south-to-nor;(e-w) =' east-to-west;(w-e) =' west-to-east
290
PACIFiCORP-2011 IR CHATER 10- TRASMISSION EXPANSION ACTION PLAN
Figure 10.3 - 2015-2018 Energy Gateway Additions for Information Only
. PacífiCorp service area
Planned transmission lines:
~ 500 kV minimum voltage
~ 345kV minimunivoltage
w~#, 230 kV minimum voltage
"''' Lines under consideration
() Transmission hub
. Existing substation
This map is for general reference only and refleetcurrnt plans.
It may not reflect the final routes, construction sequence or exact line configuration.
(D) Windstar to Aeolus
Aeolus to Populus
(E) Populus to Hemingway
2-230 kV, single circuii19
500 kV, single circuit
500 kV, single circuit
2015-2017
2015-2018
700 MW (e-w)
700MW (hi)
600 MW (e-w)
800 MW (w-e)
1,200 MW (e-w)
1,500 MW (bi)
600 MW (e-w)
800MW (w-e)
(hi) = hi-directional; (n-s) = nort-to-south; (s-n) = south-to-north; (e-w) = east-to-west; (w-e) = west-to-east
79 Plus rebuild of existing Windstar to Aeolus 230 kV line
291
PACIFICORP - 2011 IR CHAPTER 10- TRASMISSION EXPANSION ACTION PLAN
Figure 10.4 - 2017-2019 Energy Gateway Additions fOr Information Only
. PacifiCorp service area
Planned transmission lines:
~ 500 kV minimum voltage
~ 345 kV minimum voltage
~ 230 kV minimum voltage
~ = Lines under consideration
o Transmission hub
. Existing substation
This mii ¡stor general reference only and reflect current plans.
It ma not reflecttheJinalroutes.construetion sequence orexet line configuration.
(bi) = bi-directional; (n-s) = nort-to-south; (s-n) = south-to-north; (e-w) = east-to-west; (w-e) = west-to-east
292