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Home My WebLink About20110401Vol I 2011 IRP.pdfPACIFICORP Rocky Mountn Powr Paific Power PacifiCorp Energ 1.1' ,II , Int r te s urce I n d~ ~~ ~~ ~/' -¿.(Ç-- 'r"'~ -~.*alumel 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 PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 1 - E X E C U T I V E S U M M A R Y Ta b l e E S . 4 - 2 0 1 1 I R P A c t i o n P l a n Ac t i o n i t e m s a n t i c i p a t e d t o e x t e n d b e y o n d t h e n e x t t w o y e a r s , o r o c c u r a f t e r t h e n e x t t w o y e a r s , a r e i n d i c a t e d i n b l u e i t a l i c f o n t . Tr a n s m i s s i o n a c t i o n D I a n i t e m s h a v e b e e n m o v e d to C h a D t e r 1 0 . T r a n s m i s s i o n A c t i o n P l a n . 1 Re n e w a b l e s / Di s t r i b u t e d Ge n e r a t i o n 20 1 1 - 2 0 2 0 Wi n d . A c q u i r e u p t o 8 0 0 M W o f wi n d r e s o u r c e s b y 2 0 2 0 , d i c t a t e d b y r e g u l a t o r y a n d m a r k e t d e v e l o p m e n t s s u c h a s (I ) r e n e w a b l e / c l e a n e l 1 e r g y s t a n d a r d s , ( 2 ) c a r b o n r e g u l a t i o l 1 s , ( 3 ) f e d e r a l t a x i n c e n t i v e s , ( 4 ) e c o n o m i c s , ( 5 ) na t u r a l g a s p r i c e f o r e c a s t s , ( 6 ) r e g u l a t o r y s u p p o r t f o r i n v e s t m e n t s n e c e s s a r y t o i n t e g r a t e v a r i a b l e e n e r g y re s o u r c e s , a n d ( 7 ) t r a n s m i s s i o n d e v e l o p m e n t s . T h e S O O - m e g a w a t t l e v e l i s s u p p o r t e d b y c o n s i d e r a t i o n o f re g u l a t o r y c o m p l i a n c e r i s k s a m i p u b l i c p o l i c y i n t e r e s t i n c l e a n e n e r g y r e s o u r c e s . Ge o t h e r m a l . T h e C o m p a n y i d e n t i f i e d o v e r 1 0 0 M W o f g e o t h e r m a l r e s o u r c e s a s p a r o f a l e a s t - c o s t r e s o u r c e p o r t f o l i o . Co n t i n u e t o r e f i n e r e s o u r c e p o t e n t i a l e s t i m a t e s a n d u p d a t e r e s o u r c e c o s t s i n 2 0 1 1 - 2 0 1 2 f o r f u r h e r e c o n o m i c ev a l u a t i o n o f re s o u r c e o p p o r t u n i t i e s . C o n t i n u e t o i n c l u d e g e o t h e r m a l p r o j e c t s a s e l i g i b l e r e s o u r c e s i n f u t u r e al l - s o u r c e R F P s . So l a r . E v a l u a t e p r o c u r e r n e n t o f Or e g o n s o l a r p h o t o v o l t a i c r e s o u r c e s i n 2 0 1 1 v i a t h e C o m p a n y ' s s o l a r R F P . . A c q u i r e a d d i t i o n a l O r e g o n s o l a r r e s o u r c e t h r o u g h R F P s o r o t h e r m e a n s i n o r d e r t o m e e t t h e C o m p a n y ' s 8. 7 M W c o m p l i a n c e o b l i g a t i o n . . W o r k w i t h U t a h p a r t i e s t o i n v e s t i g a t e s o l a r p r o g r a m d e s i g n a n d d e p l o y m e n t i s s u e s a n d o p p o r u n i t i e s i n l a t e 20 1 1 a n d 2 0 1 2 , u s i n g t h e C o m p a n y ' s o w n a n a l y s i s o f Wa s a t c h F r o n t r o o f t o p s o l a r p o t e n t i a l a n d e x p e r i e n c e wi t h t h e O r e g o n s o l a r p i l o t p r o g r a m . A s r e c o m m e n d e d i n t h e C o m p a n y ' s r e s p o n s e t o c o m m e n t s u n d e r D o c k e t No . 0 7 . 0 3 5 - T l 4 , t h e C o m p a n y r e q u e s t e d t h a t t h e U t a h C o m m i s s i o n e s t a b l i s h " a p r o c e s s i n t h e f a l l o f 2 0 1 1 t o de t e r m i n e w h e t h e r a c o n t i n u e d o r e x p a n d e d s o l a r p r o g r a m i n U t a h i s a p p r o p r i a t e a n d h o w t h a t p r o g r a m m i g h t be s t r u c t u e d . , , 5 . I n v e s t i g a t e , a n d p u r s u e i f c o s t - e f f e c t i v e f r o m a n i m p l e m e n t a t i o n s t a n d p o i n t , c o m m e r c i a l / r e s i d e n t i a l s o l a r ho t w a t e r h e a t i n g p r o g r a m s . Th e 2 0 1 1 I R P p r e f e r r e d p o r t f o l i o i n c l u d e s 3 0 M W o f so l a r h o t w a t e r h e a t i m t r e s o u r c e s b v 2 0 2 0 ( / 8 5 R o c k y M o u n t a i n P o w e r , " R e : D o c k e t N o . 0 7 - 0 3 5 - T l 4 - T h r e e y e a r a s s e s s m e n t o f th e S o l a r I n c e n t i v e P r o g r a m " , D e c e m b e r 1 5 , 2 0 1 0 . 14 PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 1 - E X E C U T I V E S U M M A R Y 2 In t e r m e d i a t e I Ba s e - l o a d Th e r m a l Su p p l y - s i d e Re s o u r c e s 20 1 4 - 2 0 1 6 3 Fi r m M a r k e t Pu r c h a s e s 20 1 1 - 2 0 2 0 MW i n t h e e a s t s i d e a n d 1 2 M W i n t h e w e s t s i d e ) . Co m b i n e d H e a t & P o w e r ( C H P ) 1I P u r s u e o p p o r t u n i t i e s f o r a c q u i r i n g b i o m a s s C L L P r e s o u r c e s , p r i m a r i l y t h r o u g h t h e P U R P A Q u a l i j ý i i i g Fa c i l i t y c o i i t r a c t i n g p r o c e s s . Th e p r e f e r r e d p o r t f o l i o c o n t a i n s 5 2 M W o f C I J P r e s o u r c e s f o r 2 0 1 1 - 2 0 2 0 ( 1 0 M W i n t h e e a s t s i d e a n d 42 M W i n t h e w e s t s i d e ) En e r g y S t o r a g e . P r o c e e d w i t h a n e n e r g y s t o r a g e d e m o n s t r a t i o n p r o j e c t , s u b j e c t t o U t a h C o m m i s s i o n a p p r o v a l o f th e Co r n p a n y ' s p r o p o s a l t o d e f e r a n d r e c o v e r e x p e n d i t u r e s t h r o u g h t h e d e m a n d - s i d e m a n a g e m e n t s u r c h a r g e . . I n i t i a t e a c o n s u l t a n t s t u d y i n 2 0 1 1 o r 2 0 1 2 o n i n c r e m e n t a l c a p a c i t y v a l u e a n d a n c i l a r y s e r v i c e b e n e f i t s o f en e r g y s t o r a g e . Re n e w a b l e P o r t f o l i o S t a n d a r d C o m p l i a n c e . D e v e l o p a n d r e f i n e s t r a t e g i e s f o r r e n e w a b l e p o r t f o l i o s t a n d a r d c o m p l i a n c e i n C a l i f o r n i a a n d W a s h i n g t o n . . A c q u i r e a c o r n b i n e d - c y c l e c o m b u s t i o n t u r b i n e r e s o u r c e a t t h e L a k e S i d e s i t e i n U t a h b y t h e su m m e r o f 2 0 1 4 ; th e p l a n t i s p r o p o s e d t o b e c o n s t r u c t e d b y C H 2 M H i l E & C , I n c . ( " C H 2 M H i l " ) u n d e r t h e t e r m s o f a n en g i n e e r i n g , p r o c u r e m e n t , a n d c o n s t r u c t i o n ( E P C ) c o n t r a c t . T h i s r e s o u r c e c o r r e s p o n d s t o t h e 2 0 1 4 C C C T pr o x y r e s o u r c e i n c l u d e d i n t h e 2 0 1 1 I R P p r e f e r r e d p o r t f o l i o . . I s s u e a n a l l - s o u r c e R F P i n l a t e 2 0 1 1 o r e a r l y 2 0 1 2 f o r a c q u i s i t i o n o f pe a k i n g / i n t e r m e d i a t e /b a s e lo a d r e s o u r c e s by t h e s u m m e r o f 2 0 1 6 . Th i s a c q u i s i t i o n c o r r e s p o n d s t o t h e 5 9 7 M W 2 0 1 6 C C C T p r o x y r e s o u r c e ( F C l a s s 2 x l ) . . P a c i f i C o r p w i l r e e x a m i n e t h e t i m i n g a n d t y p e o f p o s t - 2 0 1 4 g a s r e s o u r c e s a n d o t h e r r e s o u r c e c h a n g e s a s p a r t of th e 2 0 1 1 b u s i n e s s p l a r m i n g p r o c e s s a n d p r e p a r a t i o n o f th e 2 0 1 1 I R P U p d a t e . Co n s i d e r s i t i n g a d d i t i o n a l g a s - f i r e d r e s o u r c e s i n l o c a t i o n s o t h e r t h a n U t a h . I n v e s t i g a t e r e s o u r c e av a i l a b i l i t y i s s u e s i i i e l u d i n g w a t e r a ~ ' t l Ì l a b i l t y , p e r m i t t i n g , t r a l l m i s s i o n c o n s t r t l Ì n t s , a c c e s s t o n a t u r a l ga s , a n d p o t e n t i a l i m p a c t s o f e l e v a t i o n . Ac q u i r e u p t o 1 , 4 0 0 M W o f e c o n o m i c f r o n t o f f c e t r a n s a c t i o n s o r p o w e r p u r c h a s e a g r e e m e n t s a s n e e d e d u n t i l th e b e g i r m i n g o f su m m e r 2 0 1 4 , u n l e s s c o s t - e f f e c t i v e l o n g - t e r m r e s o u r c e s a r e a v a i l a b l e a n d t h e i r a c q u i s i t i o n i s in t h e b e s t i n t e r e s t s o f c u s t o m e r s . Re s o u r c e s w i l b e p r o c u r e d t h r o u g h m u l t i p l e m e a n s , s u c h a s p e r i o d i c m i n i - R F P s t h a t s e e k r e s o u r c e s l e s s th a n f i v e y e a r s i n t e r m , a n d b i l a t e r a l n e g o t i a t i o n s . Cl o s e l y m o n i t o r t h e n e a r - t e r m a n d l o n g - t e r m n e e d f o r f r o i i t o J J i c e t r a n s a c t i o i i s a n d a d j u s t p l a i i i i e d ac q u i s i t i o n s a s a p p r o p r i a t e b a s e d o n m a r k e t c o n d i t i o n s , r e s o u r c e c o s t s , a n d l o a d e x p e c t a t i o n s . .. 15 PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 1 - E X E C U T I V E S U M M A R Y 5 Cl a s s 1 D S M 20 1 1 - 2 0 2 0 . C o n t i n u e t o p u r s u e e c o n o m i c p l a n t u p g r a d e p r o j e c t s - s u c h a s t u b i n e s y s t e m i m p r o v e m e n t s a n d r e t r o f i t s - an d u n i t a v a i l a b i l i t y i m p r o v e m e n t s t o l o w e r o p e r a t i n g c o s t s a n d h e l p m e e t t h e C o m p a n y ' s f u t u r e C O 2 a n d ot h e r e n v i r o n m e n t a l c o m p l i a n c e r e q u i r e m e n t s . Su c c e s s f u l l y c o m p l e t e t h e d e n s e - p a c k c o a l p l a n t t u r b i n e u p g r a d e p r o j e c t s s c h e d u l e d f o r 2 0 1 1 a n d 2 0 1 2 , to t a l i n g 3 1 M W . 20 1 1 - 2 0 2 0 I C o m p l e t e t h e r e m a i n i n g t u r b i n e u p g r a d e p r o j e c t s b y 2 0 2 1 , t o t a l i n g a n i n c r e m e n t a l 34 . 2 M J V s u b j e c t t o co n t i n u i n g r e v i e w o f pr o j e c t e c o n o m i c s . Se e k t o m e e t t h e C o m p a n y ' s u p d a t e d a g g r e g a t e c o a l p l a n t n e t h e a t r a t e i m p r o v e m e n t g o a l o f 4 7 8 Bt u / W h b y 2 0 1 9 . 6 Co n t i n u e t o l 1 u m i t o r t u r b i n e a n d o t h e r e q u i p m e n t t e c h n o l o g i e s f o r c o s t - e f f e c t i v e u p g r a d e o p p o r t u n i t i e s ti e d t o f u t u r e p l a n t m a i n t e n a m : e s c h e d u l e s . Ac q u i r e u p t o 2 5 0 M W o f c o s t - e f f e c t i v e C l a s s 1 d e m a n d - s i d e m a n a g e m e n t p r o g r a m s f o r i m p l e m e n t a t i o n i n t h e 20 1 1 - 2 0 2 0 t i m e f r a m e . . F o r 2 0 1 2 - 2 0 1 3 , p u r s u e u p t o 8 0 M W o f th e c o m m e r c i a l c u r a i l m e n t p r o d u c t ( w h i c h i n c l u d e s c u s t o m e r - o w n e d st a n d b y g e n e r a t i o n o p p o r t n i t i e s ) b e i n g p r o c u r e d a s a n o u t c o r n e o f t h e 2 0 0 8 D S M R F P . . D e p e n d i n g o n f i n a l e c o n o m i c s , p u r s u e t h e r e m a i n i n g 1 7 0 M W f o r 2 0 1 2 - 2 0 2 0 , c o i i . v i s t i n g o f a d d i t i o n a l cu r t a i l m e n t o p p o r t u n i t i e s a i i d i r r i g a t i o n / r e s i d e n t i a l d i r e c t l o a d c o n t r o l . 4 Pl a n t Ef f c i e n c y Im p r o v e m e n t s 6 Cl a s s 2 D S M . A c q u i r e u p t o 1 , 2 0 0 M W o f c o s t - e f f e c t i v e C l a s s 2 p r o g r a m s b y 2 ( ) 2 0 , e q u i v a l e n t t o a b o u t 4 , 5 3 3 G W h . T h i s in c l u d e s p r o g r a m s i n O r e g o n a c q u i r e d t h r o u g h t h e E n e r g y T r u s t o f Or e g o n . Pr o c u r e t h r o u g h t h e c u r r e n t l y a c t i v e D S M R F P a n d s u b s e q u e n t D S M R l i ' P s . . A p p l y t h e 2 0 1 1 I R P c o n s e r v a t i o n a n a l y s i s a s t h e b a s i s f o r t h e C o m p a n y ' s n e x t W a s h i n g t o n 1 - 9 3 7 c o n s e r v a t i o n ta r g e t s e t t i n g s u b m i t t a l t o t h e W a s h i n g t o n U t i l i t i e s a n d T r a n s p o r t a t i o n C o m m i s s i o n f o r t h e 2 0 1 2 - 2 0 1 3 20 1 1 - 2 0 2 0 I b i e n n i u m . T h e C o m p a n y m a y r e f i n e t h e c o n s e r v a t i o n a n a l y s i s a n d u p d a t e t h e c o n s e r v a t i o n f o r e c a s t a n d bi e n n i a l t a r g e t a s a p p r o p r i a t e p r i o r t o s u b m i t t a l b a s e d o n f i n a l a v o i d e d c o s t d e c r e m e n t a n a l y s i s a n d o t h e r n e w in f o r m a t i o n . . L e v e r a g e t h e d Ù ! i t r i b u t i o n e n e r g y e f f c i e n c y a n a l y s i s o f 1 9 d i s t r i b u t i o n f e e d e r s i n W a s h i n g t o n ( c o n d u c t e d f o r Pa c l f i C o r p b y C o m m o m v e a l t h A s s o c i a t e s , I n c . ) f o r a n a l y s i s o f po t e n t i a l d i s t r i b u t i o n e n e r g y e f f i c i e n c y i n ot h e r a r e a s o f P a c l f i C o r p ' s s y s t e m . ( T h e W a s h i n g t o n d i s t r i b u t i o n C I e r g y e f f i c i e n c y s t u d y f i n a l r e p o r t i s sc h e d u l e d f o r c o m p l e t i o n b y t h e e n d o f M a y 2 0 1 1 . ) 6 P a c i f C o r p E n e r g y H e a t R a t e I m p r o v e m e n t P l a n , A p r i l 2 0 1 0 . 16 PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 1 - E X E C U T I V E S U M M A R Y . 7 Cl a s s 3 D S M 20 1 1 - 2 0 2 0 . Pl a n n i n g a n d . 8 I Mo d e l i n g 20 1 1 - 2 0 1 2 Pr o c e s s Im p r o v e m e n t s I.. Co n t i n u e t o e v a l u a t e C l a s s 3 D S M p r o g r a m o p p o r t n i t i e s . Ev a l u a t e p r o g r a m s p e c i f i c a t i o n a n d c o s t - e f f e c t i v e n e s s i n t h e c o n t e x t o f I R P p o r t f o l i o m o d e l i n g 7 , a n d mo n i t o r m a r k e t c h a n g e s t h a t m a y r e m o v e t h e v o l u n t a r y n a t u e o f C l a s s 3 p r i c i n g p r o d u c t s . Co n t i n u e t o r e f i n e t h e S y s t e m O p t i m i z e r r n o d e l i n g a p p r o a c h f o r a n a l y z i n g c o a l u t i l i z a t i o n s t r a t e g i e s u n d e r va r i o u s e n v i r o n r n e n t a l r e g u l a t i o n a n d m a r k e t p r i c e s c e n a r i o s . Co n t i n u e t o c o o r d i n a t e w i t h P a c i f i C o r p ' s t r a n s m i s s i o n p l a n n i n g d e p a r t m e n t o n i m p r o v i n g t r a n s m i s s i o n in v e s t m e n t a n a l y s i s u s i n g t h e I R P m o d e l s . In c o r p o r a t e p l u g - i n e l e c t r i c v e h i c l e s a n d S m a r t G r i d t e c h n o l o g i e s a s a d i s c u s s i o n t o p i c f o r t h e n e x t I R P . Co n t i n u e t o r e f i n e t h e w i n d i n t e g r a t i o n m o d e l i n g a p p r o a c h ; e s t a b l i s h a t e c h n i c a l r e v i e w c o m m i t t e e a n d a sc h e d u l e a n d p r o j e c t p l a n f o r t h e n e x t w i n d i n t e g r a t i o n s t u d y . 7 S u p p l y C u r v e d e v e l o p m e n t i n d i c a t e s t h a t w h e n t h e s t a c k i n g e f f e c t o f C l a s s 1 a n d C l a s s 3 r e s o u r c e i n t e r a c t i o n s a r e c o n s i d e r e d , t h e s e l e c t e d r e s o u r c e s w i t h i n b o t h Cl a s s e s o f D S M d i m i n i s h . 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 _'_U'__~_'N__'_""$20 $19 $18 $17 $16 $15 $14 $13 $12 = $11 I $~: $8 $7 $6 $5 $4 $3 $2 $1 $0 . Most active hurcane season in recorded history . Katrna, Rita, and Wilma cause significant shut-ins and eventul production losses in the Gulf Region . Tight supplies . Oil price spike coinciding with Nort Korean missile launch into the Sea of Japan . War rhetoric building in advance of Iraq . Epic rise in oil prices and general rush to commodities . Fear of storage shortalls going into .the heating season .Deceased demand from economic down tum . Technological advancements yield growth in shale gas supply ......N N N ......~~~ir ir ir IC IC IC r-r-r-QC QC QC =-=-=-==============================......==============================~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~SS ~~~~~~~~~~~~~~~~~QC N ~QC N ~QC N ~QC N ~N ~QC N ~QC N ~QC N ~QC N ~N.................... ¡¡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 "i..30i.u CQ 20 10 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 I II Conventional II Shale II Coal Bed Methane Lm.'..'.."....,..."..".."_m"''''''..". 'mmmm".....................,....,.....'.""mm.......,..................................... ....mmm .m...".....,........................_..,,""""""m"mm'.'"""'''m..m.....m''.m. Source: U.S. Deparment of Energy, Energy Information Admistration Figure 3.3 - Shale Plays in Lower 48 States _: l:WJtlfl_ØflMlml Il.øiii æiir_ .¡¡_fI,iiu _". 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 Ozone (03)1 ISOxfNOx I Revise Ozone HAMS CAIR Vai:wcl ¡:¡ri¡Ir¡!1~~it Rule Expectcl ¡CAIRR.plOt...eI¡ oze 1 SOxiNOxN,Q$ ,Secooiliy Revision I NMQS BeginCQIplianCé Requirements undr Final CeB Rule (ground walé monitnng, doube tiners, cloure. dry ash conversion) ;ç;;;;:;;;;;;;;;;:'I Ash I - Adptedfi Wegan(EPA20)Upiam 01.12.11 f!.._EdiSOfi:5tedrk;li.ln$titute 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 32 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. 33 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. 37 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 39 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. 40 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. 41 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. 42 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. 43 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 &ltemid 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 P A C I F i C O R P - 2 0 1 1 l R P CH A P T E R 6 - R E S O U R C E Û P T I O N S Ta b l e 6 . 1 - E a s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s Ut a h 20 1 4 10 20 4,9 7 4 10 . 0 % 8.0 % $4 , 2 5 0 $2 3 . 2 9 $1 . 8 6 0. 0 0 0 0. 0 5 0 0. 2 5 5 ll 8 Ut a h 20 1 3 5 30 7,2 6 2 2.0 % 3.0 % $1 , 5 9 3 $0 . 0 3 $8 . 4 0 0. 0 0 0 0. 0 5 0 0. 2 5 5 lI 8 Ut a h 20 1 4 ll 8 30 9,7 7 3 3.8 % 2.6 % $1 , 0 0 $5 . 6 3 $9 . 9 5 0. 0 0 6 O.O L L 0. 2 5 5 ll 8 Ut a h 20 1 4 27 9 30 9,3 7 9 3.8 % 2.9 % $1 , 1 7 4 $3 . 9 3 $7 . 0 1 0. 0 0 0 6 O.O L L 0. 2 5 5 ll 8 Ut a h 20 1 4 27 9 30 9,3 7 9 3.8 % 2.9 % $1 1 7 4 $3 . 9 3 $7 . 0 1 0. 0 0 0 6 Om i 0, 2 5 5 ll 8 Wy o m i g 20 1 4 25 7 30 9,3 7 9 3$ % 2.9 " 1 0 $1 , 2 7 3 $4 . 2 6 $7 . 6 0 0. 0 0 O.O L L 0, 2 5 5 ll 8 Ut a h 20 1 4 30 1 30 8,8 0 6 5.0 % 1.0 % $1 , 1 5 0 $5 . 5 0 $6 . 4 9 0.0 0 6 0. 0 1 7 0. 2 5 5 ll 8 Ut a h 20 1 4 36 2 35 10 , 4 4 6 3.8 % 2.7 % $9 9 1 $7 . 1 6 $5 . 4 1 0.0 0 6 0. 0 5 0 0. 2 5 5 lI 8 Wy o m i g 20 1 4 33 0 35 10 4 6 3.8 % 2.7 % $1 , 0 7 4 $7 . 7 6 $5 . 8 7 0.0 0 6 0. 0 5 0 0. 2 5 5 ll 8 Ut a h 20 1 4 27 0 40 7,3 0 2 3.8 % 2.7 % $1 , 1 8 1 $2 . 9 8 $1 3 . 4 8 0,0 0 6 O.O L L 02 5 5 ll 8 Ut a h 20 1 4 43 40 8,8 6 9 3.8 % 2.7 % $4 8 2 $0 . 5 5 $0 . 0 0 0. 0 0 0 6 O.O L L 0. 2 5 5 lI 8 Ut a h 20 1 4 53 9 40 6,8 8 5 3.8 % 2.7 % $1 , 0 6 7 $2 . 9 8 $8 . 1 9 0. 0 0 0 6 O.O L L 0. 2 5 5 ll 8 Ut a h 20 1 4 86 40 8,6 8 1 3.8 % 2.7 % $5 3 8 $0 . 5 5 $0 . 0 0 0. 0 0 0 6 O.O L L 0. 2 5 5 lI 8 Ut a h 20 1 5 51 2 40 6,9 6 3 3.8 % 2.7 % $1 , 1 0 4 $3 . 3 5 $9 . 6 9 0. 0 0 6 O.O L L 0. 2 5 5 lI 8 Ut a h 20 1 5 85 40 8,9 3 4 3.8 % 2.7 % $5 3 8 $0 . 5 5 $0 . 0 0 0. 0 0 0 6 O.O L L 0. 2 5 5 ll 8 Ut a h 20 1 5 33 3 40 6,7 5 1 3.8 % 2.7 % $1 , l I 7 $4 . 5 6 $6 . 7 5 0. 0 0 0 6 O.O L L 0. 2 5 5 lI 8 Ut a h 20 1 5 72 40 90 2 1 3.8 % 2,7 % $4 7 3 $0 . 3 6 $0 . 0 0 0. 0 0 0 6 O.O L L 0. 2 5 5 lI 8 Ut a h 20 1 8 40 40 66 0 2 3.8 % 2.7 % $1 2 3 3 $4 . 5 6 $6 . 7 5 0. 0 0 0 O.O L L 0. 2 5 5 lI 8 Ut a h 20 1 8 75 40 9.0 2 1 3.8 % 2.7 % $6 5 $0 . 3 6 $0 . 0 0 0. 0 0 0 O.O L L 0. 2 5 5 lI 8 Wy o m i g 20 1 2 10 0 25 nl a nl a nl a $2 , 2 3 9 $0 . 0 0 $3 1 . 4 3 0. 0 0 0. 0 0 0. 0 0 0 Ut a h 20 1 2 10 0 25 n/ . nl a nl a $2 . 2 9 $0 . 0 0 $3 1 . 4 3 0. 0 0 0. 0 0 0. 0 0 0 Ut a h 20 1 5 35 40 nl a 5. 0 % 5.0 % $4 , 2 7 7 $5 . 9 4 $L I O . 8 5 0.0 0 0. 0 0 0. 0 0 0 Ut a h 20 1 7 45 40 nl a 5.0 % 5.0 % $6 , 1 3 2 $5 . 9 4 $2 0 9 . 4 0 0.0 0 0. 0 0 0. 0 0 0 Al l 20 1 5 5 30 li 0 0 0 1.9 " 1 0 5.0 % $2 0 2 5 $1 0 . 0 0 $1 . 0 0 0.1 0 0 0. 4 0 3. 0 0 20 5 Ne v a d a 20 2 0 25 0 50 12 5 0 0 5.0 % 5.0 % $1 7 2 3 $4 . 3 0 $4 . 3 0 0.1 0 0 0. 4 0 3, 0 0 20 5 Co m i r e s s e d A i r E n e r g y S t o r a g e ( C A E S ) I W y o m i g 20 1 5 35 0 30 ll , 9 8 0 3.8 % 2.7 % $1 , 3 0 7 $5 . 5 0 $3 . 8 0 0.0 0 1 O. O L L 0. 2 5 5 ll 8 Id a h o 20 3 0 1, 6 0 40 10 , 7 1 0 7.3 % 7.7 % $5 , 3 0 7 $1 . 6 3 $1 4 6 . 7 0 0. 0 0 0. 0 0 0. 0 0 0 Ut a h 20 1 2 5 25 nl a nl a nl a $4 1 9 1 $0 . 0 0 $5 9 . 5 0 0.0 0 0. 0 0 0. 0 0 0 Ut a h 20 1 4 25 0 30 nl a nla nl a $4 , 0 3 3 $0 . 0 0 $1 2 0 . 9 9 0. 0 0 0. 0 0 0. 0 0 0 Ut a h 20 1 4 25 0 30 nl a nla nl a $4 , 5 1 9 $0 . 0 0 $1 3 . 5 6 0.0 0 0. 0 0 0. 0 0 0 11 5 lZ êto ¡i ~lZ ~ I1.-~ ~U B ~ ¡;-..'"..Cl..~0N i Ip.M -¡~æ0v:u Clti-0 ,.1,~eo ..i:~.. ~ e= ~ ~ 00 Ô Eo ¡J ~ 5!Z ~ I\0 c: ¡:i:-. 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PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 6 - R E S O U R C E O P T I O N S Ta b l e 6 . 5 - T o t a l R e s o u r c e C o s t f o r E a s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s , $ 1 9 C 0 2 T a x Uti l i t v C o ø e n e m t i o n $ 4. 2 5 0 9. 9 1 % $4 2 1 . 2 3 $ 1. 8 6 $ 0. 5 0 $ 2.3 6 $ 4 2 3 . 5 9 -8 2 % 58 . 9 53 9 . 0 0 26 . 8 1 $ 23 . 2 9 $ 3.3 3 4.1 9 Fu e l C e l l - L a m e ( s o l i d o x i d e f u e l c e l l $ 1,5 9 3 8. 5 5 0 1 0 $1 3 6 J 5 $ 8. 4 0 $ 0. 5 0 $ 8.9 0 $ 14 5 . 0 5 95 % 17 . 4 3 53 9 . 0 0 39 . 1 4 $ 0. 0 $ 4.8 7 6.1 2 se e r A e r o $ 1. 0 0 8. 8 8 % . $8 8 . 7 7 $ 9. 9 5 $ 0. 5 0 $ 10 . 4 5 $ 99 . 2 2 21 % 53 . 9 4 53 9 . 0 0 52 . 6 8 $ 5Æ 3 $ 6.5 5 8.2 4 In t e r c o o l e d A e r o s e C T ( U t a h , 1 8 6 M W $ 1,1 7 4 8. S S O / o $1 0 4 . 2 5 $ 7.0 1 $ 0. 5 0 $ 7.5 1 $ 11 1 . 7 6 21 % 60 . 7 5 53 9 . 0 0 50 . 5 5 $ 3.9 3 $ 6.2 8 7,9 1 In t e r c o o l e d A e r s e e f l l t a h , 2 ' 7 9 M W $ 1,1 7 4 8. 8 8 % $1 0 4 2 5 $ 7.0 1 $ 0. 5 0 $ , 7 . 5 1 $ 11 1 . 7 6 21 % 60 . 7 5 53 9 . 0 0 50 . 5 5 $ 3.9 3 $ 6.2 8 7.9 1 ln t e r c o o l e d A e r o S e C T W y o m i n g , 2 5 7 M W $ 1,2 7 3 8. 8 8 % $1 1 3 . 0 4 $ 7. 6 0 $ 0. 5 0 $ 8.1 0 $ 12 1 . 4 21 % 65 . 8 5 53 9 . 0 0 50 . 5 5 $ 4.2 6 $ 5.4 6 7.9 1 In t e r n a l C o m b u s t i o n E n i i i n e s $ 1.1 5 0 8. 8 8 " 1 0 $1 0 2 . 1 1 $ 6. 4 9 $ 0. 5 0 $ 6.9 9 $ 10 9 . 1 0 21 % 59 . 3 0 53 9 . 0 0 47 . 4 6 $ 5.5 0 $ 5.9 0 7.4 2 se e r F r a l 2 F r a m e " F " $ 99 1 8. 4 1 % $8 3 3 6 $ 5.4 1 $ 0. 5 0 $ 5.9 1 $ 89 . 2 7 21 % 48 . 5 3 53 9 . 0 0 56 . 3 0 $ 7J 6 $ 7.0 0 8.8 1 se e r F r a m e ( 2 F r a m e " F " $ 1.0 7 4 8. 4 1 % $9 0 . 3 9 $ 5, 8 7 $ 0. 5 0 $ 6.3 7 $ %.7 6 21 % 52 . 6 0 53 9 . 0 0 56 . 3 0 $ 7.7 6 $ 6.0 8 8.8 1 CC C ( W e t " F " I x l l $ 1,1 8 1 8. 3 7 " 1 0 $9 8 . 9 2 $ 13 . 4 8 $ 0. 5 0 $ 13 . 9 8 $ 11 2 . 9 0 56 % 23 . 0 1 53 9 . 0 0 39 . 3 6 $ 2.9 8 $ 4.8 9 6,1 6 cc D u c t F i r n 2 i W e t " F " t x t ) $ 48 2 8. 3 7 % $4 . 3 7 $ 0. 5 0 $ 0.5 0 $ 40 . 8 7 16 % 29 J 6 53 9 . 0 0 47 . 8 0 $ 0.5 5 $ 5.9 4 7,4 8 =I W e l " F " 2 x $ 1.0 6 7 8. 3 7 % . $8 9 . 3 4 $ 81 9 $ 0. 5 0 $ 8.6 9 $ 98 . 0 4 56 % 19 . 9 8 53 9 . 0 0 37 J I $ 2.9 8 $ 4.6 1 5.8 0 cc c r D u c t F i r . I W e t " F " 2 x $ 53 8 8. 3 7 % $4 5 , 0 8 $ 0. 5 0 $ 0.5 0 $ 45 . 5 8 16 % 32 . 5 2 53 9 , 0 0 46 . 7 9 $ 0.5 5 $ 5.8 2 7.3 2 cc c r t D l v " F " 2 x 1 $ 1.1 0 4 8. 3 7 0 / 0 $9 2 . 4 8 $ 9. 6 9 $ 0. 5 0 $ IO J 9 $ 10 2 . 6 7 56 % 20 . 9 3 53 9 . 0 0 37 . 5 3 $ 3.3 5 $ 4.6 7 5.8 7 cc c r D u c t F i r n o I D r " F " 2 x 1 $ 53 8 8. 3 7 % . $4 5 . 0 8 $ 0. 5 0 $ 0.5 0 $ 45 . 5 8 16 % 32 . 5 2 53 9 , 0 0 48 J 5 $ 0.5 5 $ 5.9 9 7.5 3 cc c r l W e t " G " I X I $ 1, 1 l 8. 3 7 " 1 0 $9 3 . 5 3 $ 6. 7 5 $ 0. 5 0 $ 7.2 5 $ 10 0 . 7 8 56 % 20 . 5 4 53 9 . 0 0 36 . 3 9 $ 4.5 6 $ 4.5 2 5.6 9 cc c r D u c t F i r . I W e t " G " L X I ' $ 47 3 8. 3 7 % $3 9 . 6 0 $ 0. 5 0 $ 0.5 0 $ 40 . 1 0 16 % 28 . 6 1 53 9 . 0 0 48 . 6 2 $ 0.3 6 $ 6.0 4 7.6 1 CC C A d v a n c e d ( W e t " H " l x l $ 1,2 3 3 8. 3 7 0 1 0 $1 0 3 . 2 8 $ 6. 7 5 $ 0. 5 0 $ 72 5 $ 11 0 . 5 3 56 % 22 . 5 3 53 9 . 0 0 35 . 5 8 $ 4.5 6 $ 4.4 2 5.5 7 cc c A d v a n c e d D u c t F i r n l Z ( W e t " H i t l x l $ 60 5 8.3 7 % $5 0 . 8 $ 0. 5 0 $ 0.5 0 $ 51 . 8 16 % 36 . 5 1 53 9 . 0 0 48 . 6 2 $ 0. 3 6 $ 6.0 4 7.6 1 . 31 . 4 3 $ 0. 5 0 $ Wv o m i l ! W i n d 3 5 % C F $ 2,2 3 9 8.5 5 % $1 9 1 . 3 $ 31 . 9 3 $ 2 2 3 2 6 35 % n8 2 $ 9.7 0 (2 0 . 6 9 ) 61 . 8 2 Ut a h W i n d 2 9 % C F $ 2,2 3 9 8.5 5 % $1 9 1 . 3 $ 31 . 4 3 $ 0, 5 0 $ 31 . 9 3 $ 2 2 3 . 2 6 29 % , 87 . 8 8 $ 9.7 0 (2 0 . 6 9 76 , 8 9 Bln n d e l l G e o t h e r l ( D u a l F l h $ 4,2 7 7 7. 2 4 % $3 0 9 . 6 8 $ 11 0 . 8 5 $ 0.5 0 $ 1 1 1 . 5 $ 4 2 1 . 0 3 90 % 53 . 4 0 $ 5.9 4 (2 0 . 9 38 , 6 5 Gre n f i e l d G e o t h e r m l ( B i n a r v ) $ 6,1 3 2 7. 2 4 % $4 . 0 3 $ 2 0 . 4 0 $ 05 0 $ 2 0 9 . 9 0 $ 6 5 3 . 9 3 90 % 82 9 4 $ 5.9 4 (2 0 . 6 9 68 . 1 9 Ad v a n c e B a t t e N S t o r a Q : e $ 2.0 2 5 8.1 1 % $1 6 4 3 4 $ 1.0 0 $ 0. 5 0 $ 1. 5 0 $ 16 5 . 8 4 21 % 90 . 1 5 53 9 . 0 0 59 . 2 9 $ 10 . 0 0 $ 7.3 7 16 . 1 4 18 2 . 9 5 Pu m p e d S t o r a 2 e $ 1,7 2 3 7,9 7 " 1 0 $1 3 7 2 5 $ 4. 3 0 $ 1. 5 $ 5. 6 5 $ 14 2 9 0 20 0 ! o 81 . 5 6 53 9 . 0 0 67 . 3 8 $ 4.3 0 $ 8.4 1 18 . 3 4 17 9 . 9 9 Co r m r e s s e d A i r E n e m v S t o r a 2 : e C A E S $ 1,3 0 7 8.1 1 % $1 0 6 . 0 2 $ 3. 8 0 $ 1. 5 $ 5. 1 5 $ 11 1 . 7 47 % 27 . 1 8 53 9 . 0 0 64 . 5 7 $ 5.5 0 $ 6.9 7 10 J O 11 4 . 3 2 Nu c l e a r A d v a n c e F i s s i o n ) $ 5.3 0 7 8J ) 9 / o $4 2 9 . 4 8 $ 1 4 6 . 7 0 $ 6.0 0 $ 1 5 2 . 7 0 $ 5 8 2 . 1 8 85 % 78 . 1 9 81 . 4 8.6 9 $ 1.6 3 88 . 5 0 So l a r hi n F i h P V \ - 1 9 % C F $ 4,1 9 1 8.5 5 % $3 5 8 . 2 4 $ 59 . 5 0 $ 6. 0 0 $ 65 5 0 $ 4 2 U 4 19 % 25 4 . 5 9 (2 0 . 6 9 .. 23 3 . 9 0 So l a r Co n c e n t r t i n 2 : ( T h e n m l T r o u a h , N G b a c k u n ) ø 2 5 % s o l a $ 4,0 3 3 9.5 3 % $3 8 4 . 2 1 $ 12 0 . 9 9 $ 6.0 0 $ 1 2 6 . 9 9 $ 5 1 1 . 2 0 33 % 17 6 . 8 4 53 9 . 0 0 14 . 6 2 $ 1.8 2 (2 0 . 6 9 17 2 . 5 8 So l a r C o n c e n t r a t i n g ( T e n m l T r o u g h ) - 3 0 0 / 0 s o l a r $ 4,5 1 9 7.9 3 % $3 5 8 . 4 3 $ 1 3 . 5 6 $ 6.0 0 $ 1 4 1 . 5 6 $ 4 9 9 . 9 9 30 % 19 0 . 2 6 $ 1.8 2 (2 0 , 6 9 ) 17 1 . 3 8 11 9 ti § l;o~ ~oti ~ I\0 ~a oC"- ~= E-..oU =-.,V7 ~--oN i ! r= ~¡: r£=o...- Q"o Q,~i.=o"- ~ Q,"0...00i.. §:=00 Q,"0... 00-"- ~i...-"-oU Q,~i.=o"- ~-=-o E- i \C\I Q,-,.= E- 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 P A C I F i C O R P - 2 0 1 1 I R P CH A P T E R 6 - R E S O U R C E O P T I O N S Ta b l e 6 . 7 - D i s t r i b u t e d G e n e r a t i o n R e s o u r c e S u p p l y - S i d e O p t i o n s Uta h 20 1 1 0. 7 5 Na t u r a l Ga s Or o n I C a l i f o r n i a 20 1 1 0. 3 3 Na t u r a l Ga s Wa s h i n t o n 20 1 1 0.0 1 Na t u r a l Ga s W o m i 20 1 1 0. 3 0 Na t u r a l Ga s No t Mo d e l e d 20 1 1 0. 0 6 Na t u r a l Ga s No t Mo d e l e d 20 1 l 0. 0 9 Na t u r a l Ga No t Mo d e l e d 20 1 1 0. 0 5 Na t u r a l Ga No t Mo d e l e d 20 1 1 0.0 5 Bi o r m s s Ut a h 20 1 1 3. 7 8 Bi o m a s s Or o n I C a l i f o r n i a 20 1 1 3. 2 0 Bi o m i s s Id a h o 20 1 1 1.2 2 Bio m a s s Wa s h i n t o n 20 1 1 0. 9 9 Bi o r m s s W o m i LO L L 1.4 8 Bi o r m s s Ro o f t o P h o t o vo l t a i c Ut a h 20 1 l 1. 0 0 So l a r 30 $ 5,6 9 1 $ 23 . 8 3 Ro o f t o P h o t o v o l t a i c W o m i 20 1 1 0.1 0 5 So l a r 30 $ 5,6 9 1 $ 23 . 8 3 Ro o f t o P h o t o v o l t a i c Or o n I C a l i f o r n i a 20 1 1 1. 7 2 So l a r 30 $ 56 9 1 $ 23 . 8 3 Ro o f t o P h o t o v o l t a i c Id a h o 20 1 1 0.0 5 0 So l a r 30 $ 5,6 9 1 $ 23 . 8 3 Ro o f t o P h o t o v o l t a i c Wa s h i n t o n 20 1 1 0. 1 7 So l a r 30 $ 5,6 9 1 $ 23 . 8 3 Wa t e r H e a t e r s Ut a h 20 1 1 2.3 7 2 So l a 20 $ 1, 4 2 0 $ 11 . 8 Wa t e r H e a t e r s W o m i 20 1 1 0.4 6 6 So l a 20 $ 1, 4 2 0 $ 1l . 1 8 Wa t e r H e a t e r s Or o n I C a l i f o r n i a 20 1 1 0.5 1 6 So l a r 20 $ 1, 4 2 0 $ 11 . 8 Wa t e r H e a t e r s Id a h o 20 1 1 0.2 6 5 So l a r 20 $ 1, 4 2 0 $ 11 . 8 Wa t e r H e a t e r s Wa s h i n t o n 20 1 1 12 9 0 So l a r 20 $ 1, 4 2 0 $ 11 . 8 At t i c F a n s Ut a h 20 1 1 0. 3 5 So l a r 10 $ 16 , 9 3 9 12 2 PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 6 - R E S O U R C E O P T I O N S Ta b l e 6 . 8 - D i s t r i b u t e d G e n e r a t i o n T o t a l R e s o u r c e C o s t , $ 0 C O 2 T a x Re c I Re d Re d ~i p r o c a t i n g E n g i n e Ga T u i b i n e Mic r o t u r b i n e Fu e l C e U Co l I i a i B i ~ r o b i c D . In d u s t r i l Bio m a s , W a s t e In d u s t r i l B i o m a s , W a s t e In d u s t r i l B i o m a s s . W a s t e In d u s t r i l B i o m a s , W a s t e ht d u s t r i a l B i o i m s , W a s t e Ro o f t o p P h o t o v o l t a i e Ro o f t o p P h o t o v o l t a i c Ro o f t o p P h o t o v o l t a i c Ro o f t o p P h o t o v o 1 t a i c Ro o f t o p P h o t o v o l t a i c Wa t e r H e a t e r Wa t e r H e a t e r Wa t e r H e a t e r s Wa t e r H e a t e r Wa t e r H e a t e r s At t i c F a n s 32 5 . 5 8 $ 5,6 9 1 . 3 7. 9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 17 % 31 1 . 8 0 32 5 . 5 8 $ 5,6 9 1 . 3 7. 9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 16 % 33 9 , 0 8 32 5 . 5 8 $ 5,6 9 1 . 3 7. 9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 12 % 46 7 . 7 0 32 5 . 5 8 $ 5, 6 9 1 . 1 3 7. 9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 Æ $ 47 5 . 2 5 lS O / o 35 4 . 5 9 32 5 . 5 8 $ 5, 6 9 1 . 1 3 7. 9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 14 % 37 9 . 3 9 10 6 . 8 8 $ 1,4 1 9 . 9 2 9. 5 3 % $ 13 5 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 11 % 96 . 0 8 10 6 . 8 8 $ 1,4 1 9 . 9 2 9. 5 3 % $ 13 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 16 % 10 4 . 4 9 10 6 . 8 8 $ 1,4 1 9 . 9 2 9. 5 3 % $ 13 5 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 12 % 14 4 . 1 2 10 6 , 8 8 $ 14 1 9 . 9 2 9. 5 3 % $ 13 5 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 15 % 10 9 . 2 7 10 6 . 8 8 $ 1,4 1 9 . 9 2 9. 5 3 % $ 13 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 14 % 11 6 . 9 1 32 5 . 5 8 $ 16 , 9 3 8 . 6 8 14 . 7 9 ' 1 0 $ 2 , 5 0 5 , 9 1 $ 2 , 5 0 5 . 9 1 11 % 1, 6 4 , 0 4 31 1 . 8 0 33 9 . 0 8 46 7 . 7 0 35 4 . 5 9 31 9 . 3 9 96 . 0 8 10 4 . 4 9 14 4 . 1 2 10 9 . 2 7 11 6 . 9 1 1,6 4 . 0 4 12 3 PA C I F i C O R P - 2 0 l l l R P CH A P T E R 6 - R E S O U R C E O P T I O N S Ta b l e 6 . 8 a - D i s t r i b u t e d G e n e r a t i o n T o t a l R e s o u r c e C o s t , $ 1 9 C O 2 T a x Re c i p r o c a t i n Re c i p r o c a t i n Re c i p r o c a t i n Re c i p r o c a t i n g F n g i n e Gis T u r b i n e Mic r o t u r b i n e Fu e l Ce l l Co m r r c i a l B ~ r o b i c D i g e s t e r In d u s t r i l Bio i m s s , W a s t e In d u s t r í l B i o i m s s , W a s t e In d u s t r i l Bio i m s s , W a s t e In d u s t r i l Bio i m s s . W a s t e In d u s t r i l Bio m i s s . W a s t e Ro o f t o p P h o t o v o l t a i c Ro o f t o p P h o t o v o l t a Î c Ro o f t o p P h o t o v o l t a i c Ro o f t o p P h o t o v o h a i c Ro o f t o p P h o t o v o l t a i c W a l e c H e a t e n Wa t e r H e a t e r s Wa t e r H e a t e r s Wa t e r H e a t e r s Wa t e r H e a t e r s Att i c F a n s 31 1 . 8 0~46 7 . 7 0 35 4 5 9 37 9 . 3 9 .. 10 4 . 4 9~10 9 . 2 7 11 6 . 9 1 1, 6 4 . 0 4 32 5 5 8 $ 56 9 1 . 1 3 7.9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 17 % 31 1 . 8 0 32 5 5 8 $ 56 9 1 . 3 7.9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 16 " 1 0 33 9 . 0 8 32 5 5 8 $ 56 9 1 . 3 7.9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 12 % 46 U O 32 5 5 8 $ 56 9 1 . 3 7.9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 15 % 35 4 5 9 32 5 5 8 $ 56 9 1 . 1 3 7.9 3 % $ 45 1 . 4 2 $ 23 . 8 3 $ 23 . 8 3 $ 47 5 . 2 5 14 % 37 9 3 9 10 6 . 8 8 $ 14 1 9 . 9 2 95 3 % $ 13 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 17 % 9M 8 10 6 . 8 8 $ 1. 4 1 9 . 9 2 95 3 % $ 13 5 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 16 % 10 4 A 9 10 6 . 8 8 $ 14 1 9 , 9 2 9.5 3 % $ 13 5 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 12 % 14 4 . 1 2 10 6 , 8 8 $ 14 1 9 , 9 2 95 3 % $ 13 5 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 15 % 10 9 . 2 7 10 6 , 8 8 $ i 4 1 9 , 9 2 9. 5 3 % $ 13 5 . 2 8 $ 11 . 8 $ 11 . 8 $ 14 6 . 4 5 14 % 11 6 . 9 1 32 5 5 8 $ 16 , 9 3 8 . 6 8 14 . 7 9 % $ 2,5 0 5 . 9 1 $ 2.5 0 5 . 9 1 17 % 1, 6 4 . 0 4 12 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 90 .i:tlto.i ~. 70""on ~N ii 50'i:0. QI"t'š Õi: .8 a 80 &0 -,----,-".---- 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 PA C I F i C O R P - 2 0 l l I R P CH A P T E R 7 - M O D E L I N G A p P R O A C H Ta b l e 7 . 5 - P o r t f o l i o C a s e D e f i n i t i o n s en ê r ¡ j y G á EG 1 C0 2 T a x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i l Æ s No n e EG 2 C0 2 Ta x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi a h A c h i e \ 9 b l e Cu r r e n t I n c e n l i l Æ s No n e EG 3 C0 2 T a x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n t i l Æ s No n e EG 4 C0 2 Ta x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i l Æ s No n e EG 5 C0 2 Ta x Me d i u m Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i l Æ s No n e EG 6 C0 2 T a x Me d i u m Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i l Æ s No n e EG 7 C0 2 Ta x Me d i u m Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i l Æ s No n e EG 8 C0 2 T a x Me d i u m Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu i r n t R P S Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i l Æ s No n e EG 9 C0 2 Ta x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i l Æ s No n e EG 1 0 C0 2 Ta x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i l Æ s No n e EG 1 1 C0 2 Ta x Hi a h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i _ No n e EG 1 2 C0 2 T a x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e v b l e Cu r r n t I n c e n l i l Æ s No n e EG 1 3 C0 2 T a x Hi g h Hi g h Me d , E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi g h A c h i e \ 9 b l e Cu r r t I n c e n l i l Æ s No n e EG 1 4 C0 2 Ta x Hi g h Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r e n t R P S Hi g h A c h i e v b l e Cu r r n t I n c e n l i l Æ s No n e EG 1 5 C0 2 T a x Hi g h Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h i e v b l e Cu r r e n t I n c e n l i _ No n EG 1 6 C0 2 T a x Hi a h Hi g h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Cu r r n t R P S Hi g h A c h l e \ 9 b l e Cu r r n t I n c e n l i l o s No n EG 1 - W M C0 2 T a x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h l e \ 9 b l e Cu r r n t I n c e n l i l o s No n e EG 2 - W M C0 2 T a x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 .. . . . . . F e d e i . Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i l Æ s No n e EG 3 - W M C0 2 T a x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i l Æ s No n e EG 4 W M C0 2 T a x Me d i u m Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 ~ Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n t i l o s No e EG 5 - W M C0 2 T a x Me d i u m Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h l e \ 9 b l e Cu r r n t I n c e n l i l o s No n e EG 6 - W M C0 2 Ta x Me d i u m Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 -~ Hig h A c h i e v a b l e Cu r r n t I n c e n l i l o s No n e EG 7 . W M C0 2 Ta x Me d i u m Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e v a b l e Cu r r e n t I n c e n l i l o s No n e EG 8 - W M C0 2 T a x Me d i u m Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e v a b l e Cu r r e n t I n c e n l i l o s No n e EG 9 - W M CO 2 T a x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n t i l Æ s No n e EG 1 D - W M C0 2 T a x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e \ 9 b l e Cu r r n t I n c e n l i _ No n e EG 1 1 . W M C0 2 T a x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 \h B Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i _ No n e EG 1 2 - W M C0 2 T a x Hi g h Me d i u m Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i l o s No n e EG 1 3 - W M C0 2 T a x Hi g h Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hi g h A c h i e \ 9 b l e Cu r r e n t I n c e n l i _ No n e EG 1 4 - W M C0 2 T a x Hi g h Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 .. Hi g h A c h i e v a b l e Cu r r e n t I n c e n l i l Æ s No n e EG 1 5 - W M C0 2 Ta x Hi g h Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hig h A c h i e v a b l e Cu r r e n t I n c e n l i l o s No n e EG 1 6 - W M C0 2 Ta x Hig h Hig h Me d . E c o n . G r o w t h Ex t e n s i o n t o 2 0 1 5 Hig h A c h i e v a b l e Cu r r e n t I n c e n l i l o s No n e 16 4 PA C I F i C O R P - 2 0 l l I R P CH A P T E R 7 - M O D E L I N G A p P R O A C H 1 :2 3 ¡'5 '6 "7 8 9 9a 10 11 12 13 14 15 16 17 18 19 as e o r Ba s e o r S c e n a n o Ba s e o r S c e n a r i o Ba s e o r S c e n a n o Ba s e o r S c e n a r i o Ba s e o r S c e n a r i o Ba s e o r S c e n a r i o Ba s e o r S c e n a r i o Ba s e o r S c e n a r i o :% k ' ¡ t l ~ ~ ~ 1 l 9 : : ! l 0 ¡ ¡ : Ex t e n s i o n t o 2 0 1 5 Ex t e n s i o n t o 2 0 1 5 Me d . E c o n . G r o w h Me d . E c o n . G r o h Me d . E c o n . G r o h Ex t e n s i o n t o 2 0 1 5 Ex t e n s i o n t o 2 0 1 5 Ex t e n s i o n t o 2 0 1 5 16 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 ~ i ~ 120.00 100.00 i ., i = 60.00 I '~. -= Z 40.00 20.00 ......_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 1 175 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. 176 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. 177 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. 178 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. 179 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. 180 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 iL_ 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. 182 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. 183 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. 184 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. 185 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 1.000 186 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 rI r-ti 0::C'rI ~ c:z:i¡¡Q0:: i00 !i¡.Il-o:iu =~=M I....=M orC.~ E- i:~-=Q.,i:~'t==i:.,=U~.c.,=Q........'t't~~.....~=c.=Ui:".....=-=e=u Q...-~..-Q ~~-l-=-..-Q ~0 E-š:N ~ i I iIl..i:0 OÖ 11Ui:6 ti -i! 0 .c . -o =fp.E- 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 PA C I F i C O R P - 2 0 1 1 I R P CH A P T E R 8 - M O D E L I N G R E S U L T S Ta b l e 8 . 1 0 - P o r t f o l i o R e s o u r c e D i f f e r e n c e s , T o p T h r e e P o r t f o l i o s Ta b l e 8 . 1 0 a - C a s e H e s s C a s e 3 R e s o u r c e C o m 4.9 Ql 1 1 . 1 1 4 . 2 1 1 4. 9 1 i. 1 1. I 1. 1 1. 1 2.2 1 I i: ¡ ' i (0 . 1 ) 1 3 i . I 1 1 9 . 6 I 7 8 , 9 1 ( 1 . 4 1 1 1 8 2 . 9 1 1 ( 9 . 5 1 1 1 8 5 . 2 1 1 1 3 6 . 5 1 1 1 2 . 1 31 . 6 ( 1 6 7 , 8 1 1 6 7 . 5 1 1 1 7 . 4 1 1 8 6 . J l N/A 2. 2 52 . 8 4. 8 26 5 . 2 1 1 - 1 2 6 . 7 1 1 4 9 . 2 1 1 3 2 7 . 9 N/A - - I - 1 . - - (0 . 3 - T - - - I - 1 - I - 1 - 1 (0 3.6 - 13 . 6 - - - 1 . 1 - 1 - I - 1 O. 3 r 0 . 2 1 0 . 6 1 O . 4 T 0 . 5 0.6 0.6 0. 6 0.1 1. 4 1.5 1. 2 1. 1. 1.0 1 0. 9 1 . 0 . 2 l 0. 4 1 0. 4 J - 1. 1. 1 0 . 3 0.3 1.0 1. 0 8. 3 31 3 5 33 0 . 9 (0 , 2 1 1 - 1 - - - - 52 . 2 \ 1 1 1 0 . 7 \ 1 L O l l 1 7 7 . 2 12 . 5 1 1 5 . 1 12 7 . 4 1 1 1. 4 - (1 8 . 4 1 1 - . 72 0 . 9 (3 1 8 . 1 ) 1 ( 3 6 8 . 6 ) 1 1 7 . 8 1 1 ( 1 0 . 9 1 1 ( 2 . 4 ) 12 5 . 3 ~ 1 8 3 . 9 1 1 0 1 . 6 . L 1 7 6 . 2 . L 1 9 0 . 7 Ta b l e 8 . 1 0 b - C a s e 1 le s s C a s e 3 R e s o u r c e C o m D a r i s o n En e 99 . 1 20 0 . 0 53 . 5 44 . 1 9. 1 1.8 2.3 83 . 2 34 . 9 16 . 6 (4 7 . 8 ) 14 . 2 72 . 4 ) (3 3 . 5 ) 0. 8 - 1 - 1 ( 1 1 . ) (8 0 . 8 17 0 . 7 ) 16 . 2 26 9 . 5 1 H i 63 . 9 1 6 . 0 i ( 2 0 4 . 0 ) 15 5 . 7 (1 5 1 . 0 (1 3 . 6 26 3 . 0 1 N / A (3 5 ) 50 . o T - - - - - 50 50 0. 3 r 0. 3 1 - (0 . 3 0 0 10 . 0 1 - 1 - 16 . 4 - 13 . 6 - 2. 1 i - i- i 0. 4 1 0. 4 1 1 1 . 2 ) (1 . 2 ) 1. ) 12 . 2 (2 . 4 ) 0.3 ) (0 . 4 ) (0 . 6 10 . 6 ) (0 . 7 ) (0 . 5 ) (0 . 5 ) (1 . 2 ) (u ) (1 . 1 ) (6 ) (1 3 ) (0 . 8 ) (0 . 5 ) (0 . 8 ) (0 . 8 ) (0 . 8 ) - 1.0 - (4 ) (3 ) lO u T - (3 3 . 7 30 9 . 3 33 0 . 9 - - - 7 35 (I . S ) r - T - - - (0 (0 ) 50 . 0 I ( 4 7 . 8 ) - - 33 . 4 50 , 0 50 . 0 50 . 0 50 . 0 50 . 0 50 . 0 50 , 0 50 . 0 0 22 52 . 2 ) (1 3 0 . 7 ) (2 6 . 9 ) 14 0 . 4 (9 4 . 9 ) 17 4 . 5 1.5 (1 1 . 8 N/ A 0 27 9 . 1 37 . 4 (7 2 0 . 9 N/ A (9 6 ) 1 31 8 . 1 ) 1 ( 3 6 8 . 6 ) 1 ( 7 7 8 ) (1 0 . 9 ) (4 . 4 ) 11 7 . 7 28 4 . 1 18 1 . 6 17 6 . 8 21 0 . 3 N/A 19 22 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 28,881.8 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) 1.9 28,868.7 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 P A C I F I C O R P - 2 0 1 1 I R P CH A P T E R 8 - M O D E L I N G R E S U L T S Ta b l e 8 . 1 6 - P r e f e r r e d P o r t f o l i o , D e t a i l L e v e l 1,2 2 2 il 12 . I T 18 . 9 1.8 18 . 0 2.4 51 -- 30 0 30 0 20 0 20 0 20 0 20 0 20 0 10 0 10 0 10 0 10 0 10 0 80 0 2,1 0 0 1. 0 1.0 1.0 1. 0 1. 0 1.0 1. 0 1.0 1.0 1.0 1.0 1. 0 1. 0 1.0 1.0 1.0 1.0 1.0 1. 0 1.0 10 20 5.5 1 5 It II 20 2 20 22 43 29 71 71 22 62 85 85 3 3 6 70 20 91 5 18 7 19 1 I 2 2 3 3 4 4 4 4 5 5 5 6 6 6 6 6 6 6 6 33 II 42 47 39 40 41 44 45 46 . 48 50 48 55 51 53 53 57 52 55 54 56 44 2 97 6 3 4 5 5 6 6 7 8 8 8 10 10 12 15 16 20 24 28 35 37 60 26 7 47 53 46 48 51 54 56 58 60 63 62 70 69 74 75 84 82 89 95 99 53 6 1,3 3 4 2.6 4 2.6 4 2.6 4 2.6 4 2. 6 4 2. 6 4 2. 6 4 18 18 16 8 26 4 26 4 99 25 82 41 20 0 I 20 0 20 4 26 25 0 72 21 7 24 5 14 1 71 15 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 30 0 22 5 26 3 14 9 29 3 10 8 21 5 23 2 3 N/ A 10 0 24 20 1 21 1 30 3 26 1 N/ A 10 0 20 6 55 34 6 39 2 N/ A 10 0 3.7 8.3 12 12 4. 2 T 4.2 T 4. 2 4. 2 4.2 4.2 U 4.2 4.2 4. 2 4.2 4.2 4.2 4.2 4.2 4. 2 4. 2 4,2 4.2 4.2 42 84 5 5 5 13 36 36 36 ,l i T 2 6 9 9 57 6 63 63 7 8 8 8 8 8 8 8 8 8 9 10 10 10 10 8 8 8 8 9 79 17 0 i 1 I I I i I 1 I 2 I I 2 2 2 2 2 2 2 2 53 53 56 61 62 61 60 52 52 52 52 52 52 52 52 52 44 36 36 36 56 2 1,0 2 8 61 61 65 70 71 70 70 62 62 62 63 63 .6 4 65 65 63 54 46 46 46 65 3 1,2 2 8 2 2 2 3 9 9 2 2 I 10 10 1.8 1 1.8 1 1.8 1 1.8 1 1.8 1 1.8 1 0. 9 7 12 12 15 0 T 15 0 15 0 15 0 50 65 32 40 0 40 0 40 0 40 0 40 0 40 0 40 0 39 5 40 0 40 0 40 0 40 0 40 0 40 0 40 0 40 0 40 0 40 0 40 0 36 0 38 0 e n r e m i T 27 1 21 1 48 24 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 40 43 11 2 57 20 20 5 20 2 20 3 20 1 N/ A 10 0 N/ A 10 0 N/A 10 7 ¡ ~ \ ~ ~ C i i R 8 \ , , , , ~ ' " , " , . Th :* , l : : " ~': ,i l 11 F r o n t o f f c e t r s a c t i o n a n d g r w t h r e s o u r c e a m o u n t s r e f l e c t o n e - y e a r t r a n s a c t i o n p e r o d s , a n d a r n o t a d d i t i v e . F r o n t o f f i c e t r n s a c t i n s a r e r e o r t a s a 2 0 - y e a r a n u a l a v e r g e . G r o w t r e s o u r e s a r e r e o r t a s a l O - y e a r a v e m g e . 21 P a c i f i C o r p e x c l u d e d f r o m t h e p o r t o l i n e w p r o g r u n d e r a f i v e - m e g a w a t t i m p l e m e n l a l i n f e a s i b i l i t t h s h o l d . T h e p r o g r s e x c l u d e d c o n s i s t o f d i r c t l o a d c o n t r l p r o g r a m s f o r W a s h Ù 1 g t o , O r e g o n , a i d C a t i f o m i a . 23 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 P A C I F i C O R P - 2 0 1 1 I R P CH A P T E R 8 - M O D E L I N G R E S U L T S Ta b l e 8 . 2 3 - R e s o u r c e D i f f e r e n c e s , R e n e w a b l e P o r t f o l i o S t a n d a r d a n d A l t e r n a t e W i n d I n t e g r a t i o n C o s t I m p a c t Ca s e 7 L e s s C a s e 2 8 ( N o R P S R e q u i r e m e n t s ) 0. 0 I - I - I - I- 1 0 . 1 1 - 1 - 1 - 1 - 1 - I - 1 - 1 - - - - (2 . 5 ) 0 (2 ) 1 2 - - - - 13 oT - T - T - T - T - T - T - - - - 0 0 01 - i - r ( 4 ) 1 ( 4 ) f - T - - T - T - - - - - (7 (7 ) 1 (0 ) 1 3 1 1 96 48 (3 8 ) (5 8 ) (0 ) (4 9 ) (3 0 ) (0 ) 01 - 28 (2 ) 28 (5 3 ) N/ A (0 ) 1 2 53 7 (3 7 ) - 13 (2 6 ) (1 2 ) N/ A 0 ; - 35 1 - L - - . - 1 - l - J i - I 35 - - - - - - 3. 6 0. 6 - - - - - (O . i ) l - T - T ( 0 . 1 i f ( 0 . 3 ) 0 . 2 - - 10 . 3 ) - - - - (0 . 2 - (0 . 2 ) (0 ) - - i i I I I - - - - - 0 - - - (4 ) 31 4 13 2 23 5 - - - - (0 ) en r e i n 1 - 1 - 1 - 1 - 1 - - - - - - - - - - - - - (2 1 ) - - 44 49 22 5 19 44 N/ A - - - - - (6 7 ) - - - N/ A (3 1 5 ) 1 ( 1 4 5 ) ( 1 2 6 ) ( I I I ) ( 8 2 ) (5 1 ) (2 4 ) (4 1 ) (5 9 ) (4 6 ) N/ A 81 . 1 (4 . 9 ) 4.9 (5 A ) (5 A ) (0 . 0 ) 1 I ( 0 . 6 ) L - T i i i ) l ( 3 . 2 t ( 3 . . r ( 4 . 8 ¡ r 1 s . 5 i (2 0 . 7 ) (2 0 . 7 ) - 1 - - T 1 2 . 6 ) (2 . 6 ) (H ) (2 . 6 ) 12 A (1 2 . 9 3. 1 I - 1 - 1 - 3.1 3,1 0. 6 1 -I 7.1 9. 8 1 - 7.2 1 1 10 . 3 10 . 3 0.2 (3 0 . 9 ) 11 5 . 7 ) (6 3 , 9 ) 64 . 1 61 . 9 0.4 45 . 1 3M OA (0 . 0 ) (1 8 . 0 ) (1 6 . ) (8 . 6 43 . 0 N/A 0. 0 52 . 8 16 . 6 12 . 7 10 . 3 25 . 6 13 . 1 N/A 0. 0 (3 5 . 0 ) (3 5 . 0 ) (1 . 6 ) (1 . 6 ) (1 . 6 ) 0.1 1 I ( O A ) I - T ( 0 . 1 ) 1 ( ü . i 1 ( 0 . 5 ) (0 . 6 ) (0 . 8 ) (0 . 8 ) 0.3 0. 2 (3 . 7 ) (3 . 2 ) _ I _ (0 . 8 ) (0 . 8 (0 . 3 ) (1 . (1 . 3 ) (1 . ) (1 . 0 ) (1 . 7 ) 6. 8 ) 0. 6 1 - 14 . 0 19 6 . ) (1 1 9 . 2 ) (1 1 . ) 1.5 (1 5 . 6 ) e p r e m i I . 1 i 0. i T - T - 1 - 0.0 0, 0 1.8 10 7 . 6 11 0 2 5 13 7 5 5.1 83 . 2 38 . 1 N/A (3 7 . 2 ) , 56 . 1 N/A 5.6 19 0 A I 1 4 3 , 6 12 5 . 9 11 4 . 9 ilL S 10 7 A 42 A 32 . 2 89 . 0 42 . 8 N/A 10 0 . 0 24 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 P A C I F I C O R P - 2 0 1 1 I R P CH A P T E R 8 - M O D E L I N G R E S U L T S Ta b l e 8 . 2 4 - R e s o u r c e D i f f e r e n c e s , Cl a s s 3 D S M P o r t f o l i o ( C a s e 3 1 ) l e s s C a s e 7 P o r t f o l i o 35 - - - (3 5 ) (1 9 . 8 ) - - - - (4 . 9 (2 0 ) (2 5 ) Sto r a e e 1 1 ( 3 . 5 i f - T - - - - - - - (3 ) (3 ) - 1 - 1 - (4 . 9 ) - - - - - (5 ) (5 ) (3 . 2 ) 1 - 1 - 13 . 0 ) - (6 ) (6 ) 3. 6 - - - 4 4 14 1 . 8 - - - - 14 2 14 2 16 . 9 - 9.1 - - 26 26 6. 2 1 - T 3. 0 9 9 35 . 1 - 35 35 5. 3 - - 5 5 10 . 5 - 10 . 1 - - - - 21 21 4. 8 T - T - - 4.8 - - - - 10 10 5. 3 - - - - 5 5 2. 7 - 2.7 - - - - - 5 5 4. 3 T - T 2 0 1 . - (7 . 8 ) 29 . 6 - - - (4 . 9 ) - 22 7 22 2 12 . 2 1 1 0 . Ü 5. 2 ~ - (0 . 7 10 . 8 ) - - - - - - 26 26 - (0 - - - - - (0 (6 0 r 9 9 (2 8 ) - - - - - 11 ii (2 i i - T ( 2 2 ) 1 1 5 1 - (5 7 ) (1 1 2 19 4 (I l ) - - - - - 22 22 (2 7 ) (5 1 ) (6 0 ) 76 (2 8 ) 25 59 0 N/ A 0 N/ A 0 li o 1 1 . I (5 . 5 ) - - - - - (5 ) (5 ) (1 . 4 ) - - - - - . ( 1 ) (I ) \3 . 2 ) - (1 (\ 3 ) (4 . 2 ) - - (4 ) (4 ) (2 . 1 ) (6 . 4 ) - (9 ) (9 ) (0 . 1 (3 . 6 ) - - - - - (4 (4 72 . 0 - - - - - 72 72 25 . 9 - - - 26 26 27 . 6 - - - - - 28 28 5. 9 - - - - - - - - 6 6 (2 6 . 5 r 1 3 1 . 5 - - (1 0 . 0 ) . - - - - - - 95 95 0. 1 1 0. 2 I ( 0 . 4 (0 . 4 ) (0 . 4 ) (0 . 1 ) (0 . 2 ) (0 . 3 - (0 . 2 ) - (1 ) (2 - - - I (0 ) - - (0 ) - - 0 0 (9 ) r - T - T - 97 (5 2 ) (6 ) - 24 10 6 39 12 - 5 11 ¡r i c e n r e m i n T I 01 01 - - - - - - - 0 0 ~O ) 50 (5 0 ) (5 0 ) - 50 - (5 ) (3 ) (3 2 ) 7 N/ A (6 ) N/ A (4 1 ) N/ A (1 0 0 ) II F r o n t o f f e t r l 1 a c t i n a n d g r w t h r e s o u r a t r i i t s r e f l t o n e - y e a r t r a c t i n p e r d s , a n d a r r o t a d d i t . F O T a r e r e p o r t e d a s a 2 0 - y e r a i m l a v e a g . G r w t h r e s o u r e s a r e r e p o r t e d a s a I O - y e a r a v e g e . 24 7 PA C I F I C O R P - 2 0 1 1 I R P CH A P T E R 8 - M O D E L I N G R E S U L T S Ta b l e 8 . 2 5 - R e s o u r c e D i f f e r e n c e s , T e c h n i c a l D S M P o t e n t i a l v s . E c o n o m i c D S M P o t e n t i a l Ca s e 3 2 ( T e c h n i c a l D S M P o t e n t i a l ) l e s s C a s e 7 ( H i g h A c h i e v a b l e P o t e n t i a l ) 35 . 0 I I (3 5 . 0 ) 8.2 ) 9.1 (3 , 6 (2 6 . 8 ) (4 7 . 6 ) e I ( 0 . 8 ) 1 ( 0 . 8 ) (1 . 5 ) (1 . 5 ) (3 . 5 ) 0.8 2. 4 (7 , 8 ) (4 , 9 ) 4. 9 (8 . 1 ) (8 . 1 ) 0.3 0.3 0. 4 0. 5 M 0.7 0, 8 0. 8 0. 8 0. 9 0. 9 i. i. 1.2 i. 1.2 i. i. 1.0 6.1 16 . 7 8. 4 4.2 (4 . 9 ) 11 . 0 11 . 8 13 . 1 13 , 6 14 . 0 14 . 7 15 . 9 19 . 6 18 . 3 18 . 5 18 . 0 20 . 5 19 . 0 20 . 1 19 . 2 20 . 0 10 1 . 8 29 3 . 1 0,6 1.2 1.2 1.6 1.5 0.8 1.9 2. 2 2.1 2.3 2. 7 3. 2 4. 0 4. 2 5. 5 5. 9 6. 8 8, 6 9.1 15 . 3 67 . 9 9.3 5.7 (3 . 3 ) 13 , 1 13 . 9 14 . 6 16 . 3 17 . 0 17 . 6 19 . 0 23 . 2 22 . 6 23 . 6 23 . 4 27 . 1 26 . 1 28 . 0 29 . 0 30 . 1 12 3 . 2 37 7 7 2. 4 ) (0 . 0 (4 . 8 99 . 1 28 . 1 71 0 71 . 0 20 0 . 0 (5 6 . 7 ) (1 0 8 , 7 ) 18 1 . 3 (1 1 1 . 4 ) 76 . 3 76 . 3 13 . 0 36 . 1 04 . 9 ) ( 9 2 . 8 ) 15 . 2 15 5 . 1 99 . 5 35 . 8 54 . 1 0.0 (1 3 4 . 1 13 3 . 0 15 3 . 0 N/ A (4 2 . 0 53 . 4 ) 20 6 . 3 49 . 5 57 . 6 45 . 8 N/A 0.0 Vi ' B i o s s 50 , 0 50 . 0 50 . 0 CH P - R e c ' o c a t i E . e (0 . 3 ) (0 . 3 ) (0 . 2 ) (0 . 9 0.9 DS M C l a s s 1 6. 4 0. 9 (1 0 . 0 ) (2 . 7 ) (2 . 7 DS M C l a s s 2 C a l i o r n i a 0.2 0. 1 0.1 0. 2 0. 2 0.3 0.3 0.3 0. 3 0.3 0.3 0. 3 0. 4 0. 4 0. 4 0. 3 0. 4 0. 3 0. 3 0. 3 2.1 5.5 DS M C l a s s 2 W a s h i O I 1. 1. 2. 0 1.7 1.6 1.5 1.4 1. 4 1. 7 1. 7 1.9 2.1 2. 0 2.1 2. 2 1.8 1. 1.6 1.6 1.7 16 . 0 34 . 6 DS M C l a s s 2 T o t a l 1. 7 1. 6 2. 1 1.9 1.8 1.8 1.7 1.7 1.9 2. 0 2. 2 2. 4 2. 4 2. 5 2. 6 2.1 1.9 2. 0 2. 0 2. 0 18 . 1 40 . 1 Mic r o S o l a r - H o t W a t e r H e a t i R 0. 5 0. 3 ) 1.0 1.0 ) 0. 2 (1 . ) (7 . 1 96 . 8 (1 7 . 9 ) 24 . 1 (9 5 , 6 29 1 . ) 38 7 . 7 37 8 . 7 ) 9. 6 (5 2 . 9 ) e ø r r n i (1 . 6 ) (2 . 3 ) (0 . 4 ) (0 . 2 ) 50 . 0 (5 0 . 0 ) (3 6 . 5 ) 50 . 0 1.4 0.7 (1 2 . 0 (5 5 . 9 ) (1 6 4 . 6 N/A 48 . 3 ) N/A (4 1 . 2 N/A (0 . 0 ) 11 F r o n t o f f i c e t r n s a c t i o n a n d g r o w t h r e s o u c e a m o i m t s r e f l c t o n e - y e a r t r a n s a c t i n p e r i o , a n d a r e n o t a d d i i v e . 2/ F r o n t o f f i c e t r a n s a c t i n s a r e r e p o r t e d a s a l O - y e a r a n n u l a v e r a g e . G r o w r e s o u r e s a r e r e p o e d a s a l O - y e a r a v e r a g e . ' 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 P A C I F i C O R P - 2 0 1 1 I R P CH A P T E R 9 - A C T I O N P L A N Ta b l e 9 . 1 - I R P A c t i o n P l a n U p d a t e Ac t i o n i t e m s a n t i c i p a t e d t o e x t e n d b e y o n d t h e n e x t t w o y e a r s , o r o c c u r a f t e r t h e n e x t t w o y e a r s , a r e i n d i c a t e d i n b l u e i t a l i c f o n t . Tr a n s m i s s i o n a c t i o n D I a n i t e m s h a v e b e e n m o v e d t o C h a p t e r 1 0 , T r a n s m i s s i o n A c t i o n P l a n . 1 Re n e w a b l e s / Di s t r i b u t e d Ge n e r a t i o n 20 1 1 - 2 0 2 0 Wi n d · A c q u i r e u p t o 8 0 0 M W o . f w i n d r e s o u r C e S b y 2 0 2 0 , d i c t a t e d b y r e g u l a t o r y a n d m a r k e t d e v e l o p m e n t s s u c h a s (1 ) r e n e w a b l e / c l e a n e n e r g y s t a n d a r d s , ( 2 ) c a r b o n r e g u l a t i o n s , ( 3 ) fe d e r a l t a x i n c e n t i v e s , ( 4 ) e c o n o m i c s , ( 5 ) na t u r a l g a s p r i c e f o r e c a s t s , ( 6 ) r e g u l a t o r y s u p p o r t f o r i n v e s t m e n t s n e c e s s a r y t o i n t e g r a t e v a r i a b l e e n e r g y re s o u r c e s , a n d ( 7 ) t r a n s m i s s i o n d e v e l o p m e n t s . T h e B O O - m e g a w a t t l e i ' e l i s s u p p o r t e d b y c o n s i d e r a t i o n o f re g u l a t o r y c o m p l i a n c e r i s k s a n d p u b l i c p o l i c y i n t e r e s t i n c l e a n e n e r g y r e s o u r c e s . Ge o t h e r m a l . T h e C o m p a n y i d e n t i f i e d o v e r 1 0 0 M W o f g e o t h e r m a l r e s o u r c e s a s p a r t o f a l e a s t - c o s t r e s o u r c e p o r t f o l i o . Co n t i n u e t o r e f i n e r e s o u r c e p o t e n t i a l e s t i m a t e s a n d u p d a t e r e s o u r c e c o s t s i n 2 0 1 1 - 2 0 1 2 f o r f u r h e r e c o n o m i c ev a l u a t i o n o f r e s o u r c e o p p o r t n i t i e s . C o n t i n u e t o i n c l u d e g e o t h e r m a l p r o j e c t s a s e l i g i b l e r e s o u r c e s i n f u t u e al l - s o u r c e R F P s . So l a r · E v a l u a t e p r o c u r e m e n t o f Or e g o n s o l a r p h o t o v o l t a i c r e s o u r c e s i n 2 0 1 1 v i a t h e C o m p a n y ' s s o l a r R F P . . A c q u i r e a d d i t i o n a l O r e g o n s o l a r r e i w u r c e t h r o u g h R F P . s o r o t h e r m e a n s i n o r d e r t o m e e t t h e C o m p a n y ' s 8. 7 M W c o m p l i a n c e o b l i g a t i o n . · W o r k w i t h U t a h p a r t i e s t o i n v e s t i g a t e s o l a r p r o g r a m d e s i g n a n d d e p l o y m e n t i s s u e s a n d o p p o r t n i t i e s i n l a t e 20 1 1 a n d 2 0 1 2 , u s i n g t h e C o m p a n y ' s o w n a n a l y s i s o f Wa s a t c h F r o n t r o o f t o p s o l a r p o t e n t i a l a n d e x p e r i e n c e wi t h t h e O r e g o n s o l a r p i l o t p r o g r a m . A s r e c o m m e n d e d in t h e C o r n p a n y ' s r e s p o n s e t o c o m m e n t s u n d e r D o c k e t No . 0 7 - 0 3 5 - T l 4 , t h e C o m p a n y r e q u e s t e d t h a t t h e U t a h C o m m i s s i o n e s t a b l i s h " a p r o c e s s i n t h e f a l l o f 2 0 1 1 t o de t e r m i n e w h e t h e r a c o n t i n u e d o r e x p a n d e d s o l a r p r o g r a m i n U t a h i s a p p r o p r i a t e a n d h o w t h a t p r o g r a m m i g h t be s t r u c t u r e d . , , 7 4 · I n v e s t i g a t e , a n d p u r s u e l f c o s t - e f f e c t i v e fr o m a n i m p l e m e n t a t i o n s t a n d p o i n t , c o m m e r c i a l / r e s i d e n t i a l s o l a r ho t w a t e r h e a t i n g p r o g r a m s . Th e 2 0 1 1 I R P p r e f e r r e d p o r t f o l i o i n c l u d e s 3 0 M W o . t s o l a r h o t w a t e r h e a t i n g r e s o u r c e s b y 2 0 2 0 ( 1 8 MW i n t h e e a s t s i d e a n d J 2 M W i n t h e w e s t s i d e ) . Co m b i n e d H e a t & P o w e r ( C H P ) . P u r s u e i i p p o r t u n i t i e s f o r a c q u i r i n g b i o m a s s C L I P r e s o u r c e s , p r i m a r i l y t h r o u g h t h e P U R P A Q u a l t f ý i n g Fa c i l i t y c o n t r a c t i n g p r o c e s s . 74 R o c k y M o u n t a i n P o w e r , " R e : D o c k e t N o . 0 7 - 0 3 5 - T l 4 - T h r e e y e a r a s s e s s m e n t o f t h e S o l a r I n c e n t i v e P r o g r a m " , D e c e m b e r 1 5 , 2 0 1 0 . 25 4 P A C I F I C O R P - 2 0 1 1 I R P CH A P T E R 9 - A C T I O N P L A N En e r g y S t o r a g e . P r o c e e d w i t h a n e n e r g y s t o r a g e d e m o n s t r a t i o n p r o j e c t , s u b j e c t t o U t a h C o r n m i s s i o n a p p r o v a l o f t h e Co m p a n y ' s p r o p o s a l t o d e f e r a n d r e c o v e r e x p e n d i t u e s t h r o u g h t h e d e m a n d - s i d e m a n a g e m e n t s u r c h a r g e . . I n i t i a t e a c o n s u l t a n t s t u d y i n 2 0 1 1 o r 2 0 1 2 o n i n c r e m e n t a l c a p a c i t y v a l u e a n d a n c i l a r y s e r v i c e b e n e f i t s o f en e r g y s t o r a g e . Re n e w a b l e P o r t f o l i o S t a n d a r d C o m p l i a n c e . D e v e l o p a n d r e f i n e s t r a t e g i e s f o r r e n e w a b l e p o r t f o l i o s t a n d a r d c o m p l i a n c e i n C a l i f o r n i a a n d W a s h i n g t o n . . A c q u i r e a c o m b i n e d - c y c l e c o m b u s t i o n t u r b i n e r e s o u r c e a t t h e L a k e S i d e s i t e i n U t a h b y t h e s u m m e r o f 2 0 1 4 ; th e p l a n t i s p r o p o s e d t o b e c o n s t r u c t e d b y C H 2 M H i l l E & C , I n c . ( " C H 2 M H i l " ) u n d e r t h e t e r m s o f a n en g i n e e r i n g , p r o c u r e m e n t , a n d c o n s t r u c t i o n ( E P C ) c o n t r a c t . T h i s r e s o u r c e c o r r e s p o n d s t o t h e 2 0 1 4 C C C T pr o x y r e s o u r c e i n c l u d e d i n t h e 2 0 1 1 I R P p r e f e r r e d p o r t f o l i o . . I s s u e a n a l l - s o u r c e R F P i n l a t e 2 0 1 1 o r e a r l y 2 0 1 2 f o r a c q u i s i t i o n o f p e a k i n g / i n t e r m e d i a t e / b a s e 1 o a d r e s o u r c e s by t h e s u m m e r o f 2 0 1 6 . Th i s a c q u i s i t i o n c o r r e s p o n d s t o t h e 5 9 7 M W 2 0 1 6 C C C T p r o x y r e s o u r c e ( F C l a s s 2 x l ) . . P a c i f i C o r p w i l r e e x a m i n e t h e t i m i n g a n d t y p e o f p o s t - 2 0 1 4 g a s r e s o u r c e s a n d o t h e r r e s o u r c e c h a n g e s a s p a r t of th e 2 0 1 1 b u s i n e s s p l a n n i n g p r o c e s s a n d p r e p a r a t i o n o f th e 2 0 1 1 I R P U p d a t e . Co n s i d e r s i t i n g a d d i t i o n a l g a s : f r e d r e s o u r c e s i n l o c a t i o n s o t h e r t h a n U t a h . I n v e s t i g a t e r e s o u r c e av a i l a b i l t y i s s u e s i n c l u d i n g w a t e r a v a i l a b i l t y , p e r m i t t i n g , t r a n s m i s s i o n c o n s t r a i n t s , a c c e s s t o n a t u r a l ga s , a n d p o t e n t i a l i m p a c t s o f e l e v a t i m i . . A c q u i r e u p t o 1 , 4 0 0 M W o f e c o n o m i c f r o n t o f f c e t r a n s a c t i o n s o r p o w e r p u r c h a s e a g r e e m e n t s a s n e e d e d u n t i l th e b e g i n n i n g o f s u r n m e r 2 0 1 4 , u n l e s s c o s t - e f f e c t i v e l o n g - t e r m r e s o u r c e s a r e a v a i l a b l e a n d t h e i r a c q u i s i t i o n i s in t h e b e s t i n t e r e s t s o f c u s t o m e r s . 20 1 1 - 2 0 2 0 I R e s o u r c e s w i l b e p r o c u r e d t h r o u g h m u l t i p l e m e a n s , s u c h a s p e r i o d i c m i n i - R F P s t h a t s e e k r e s o u r c e s l e s s th a n f i v e y e a r s i n t e r m , a n d b i l a t e r a l n e g o t i a t i o n s . . C l o s e l y m o n i t o r t h e ne a r - t e r m a n d l o n g - t e r m n e e d f o r f r o n t o f f i c e t r a n s a c t i o n s a n d a d j u s t p l a n n e d ac q u i s i t i o n s a s a p p r o p r i a t e b a s e d o n l 1 u i r l c e t c o n d i t i o n s , r e s o u r c e c o s t s , a n d l o a d e x p e c t a t i o n s . 2 In t e r m e d i a t e / Ba s e - l o a d Th e r m a l Su p p l y - s i d e Re s o u r c e s 20 1 4 - 2 0 1 6 3 Fi r m M a r k e t Pu r c h a s e s Th e p r e f e r r e d p o r t f ò l i o c o n t a i n s 5 2 M W o f C I J P r e s o u r c e s f o r 2 0 1 I - 2 0 2 0 ( l 0 M W i n t h e e a s t s i d e t l i d 42 M W i n t h e w e s t s i d e ) 4 Pl a n t Ef f c i e n c y Im p r o v e m e n t s . C o n t i n u e t o p u r s u e e c o n o m i c p l a n t u p g r a d e p r o j e c t s - s u c h a s t u r b i n e s y s t e r n i m p r o v e m e n t s a n d r e t r o f i t s - an d u n i t a v a i l a b i l t y i m p r o v e m e n t s t o l o w e r o p e r a t i n g c o s t s a n d h e l p m e e t t h e C o m p a n y ' s f u t u r e C O 2 a n d 20 1 1 - 2 0 2 0 I o t h e r e n v i r o n m e n t a l c o m p l i a n c e r e q u i r e m e n t s . Su c c e s s f u l l y c o m p l e t e t h e d e n s e - p a c k c o a l p l a n t t u b i n e u p g r a d e p r o j e c t s s c h e d u l e d f o r 2 0 1 1 a n d 2 0 1 2 , to t a l i n g 3 1 M W . 25 5 P A C I F i C O R P - 2 0 1 1 I R P CH A P T E R 9 - A C T I O N P L A N 5 Cl a s s 1 D S M Co m p l e t e t h e r e m a i n i n g t u r b i n e u p g r a d e p r o j e c t s b y 2 0 2 1 , t o t a l i n g a n i n c r e m e n t a l 34 . 2 M J ¥ , s u b j e c t t o co n t i n u i n g r e v i e w o f p r o . ì e c t e c o n o m i c s . Se e k t o m e e t t h e C o m p a n y ' s u p d a t e d a g g r e g a t e c o a l p l a n t n e t h e a t r a t e i m p r O l ' e m e n t g o a l o f 4 7 8 Bt u / W h b y 2 0 1 9 / 5 Co n t i n u e t o m o n i t o r t u r b i n e a n d o t h e r e q u i p m e n t t e c / l 1 o l o g i e s . f o r c o s t - e f f e c t i v e u p g r a d e o p p o r t u n i t i e s ti e d t o f u t u r e p l a n t m a i n t e n a n c e sc h e d u l e s . Ac q u i r e u p t o 2 5 0 M W o f c o s t - e f f e c t i v e C l a s s 1 d e m a n d - s i d e m a n a g e r n e n t p r o g r a m s f o r i m p l e m e n t a t i o n i n t h e 20 1 1 - 2 0 2 0 t i m e f r a r n e . . F o r 2 0 1 2 - 2 0 1 3 , p u r s u e u p t o 8 0 M W o f th e c o m m e r c i a l c u r t a i l m e n t p r o d u c t ( w h i c h i n c l u d e s c u s t o m e r - o w n e d st a n d b y g e n e r a t i o n o p p o r t n i t i e s ) b e i n g p r o c u r e d a s a n o u t c o m e o f th e 2 0 0 8 D S M R F P . . D e p e n d i n g o n f i n a l e c o n o m i c s , p u r s u e t h e r e m a i n i n g 1 7 l ) l i J W J o r 2 0 1 2 - 2 0 2 0 , c o m i s t i n g o f a d d i t i o n a l cu r t a i l m e n t o p p o r t u n i t i e s a n d i r r i g a t i o n / r e s i d e n t i a l d i r e c t l o a d c o n t r o L . A c q u i r e u p t o 1 , 2 0 0 M W o f c o s t - e f f e c t i v e C l a . . . s 2 p r o g r a m s b y 2 0 2 0 , e q u i v a l e n t t o a b o u t 4 , 5 3 3 G W h . T h i s in c l u d e s p r o g r a m s i n O r e g o n a c q u i r e d t h r o u g h t h e E n e r g y T r u s t o f Or e g o n . Pr o c u r e t h r o u g h t h e c u r r e n t l y a c t i v e D S M R F P a n d s u b s e q u e n t D S M R F P s . . A p p l y t h e 2 0 1 1 I R P c o n s e r v a t i o n a n a l y s i s a s t h e b a s i s f o r t h e C o m p a n y ' s n e x t W a s h i n g t o n 1 - 9 3 7 c o n s e r v a t i o n ta r g e t s e t t i n g s u b m i t t a l t o t h e W a s h i n g t o n U t i l i t i e s a n d T r a n s p o r t a t i o n C o m m i s s i o n f o r t h e 2 0 1 2 - 2 0 1 3 20 1 1 - 2 0 2 0 I b i e n n i u m . T h e C o m p a n y m a y r e f i n e t h e c o n s e r v a t i o n a n a l y s i s a n d u p d a t e t h e c o n s e r v a t i o n f o r e c a s t a n d bi e n n i a l t a r g e t a s a p p r o p r i a t e p r i o r t o s u b m i t t a l b a s e d o n f i n a l a v o i d e d c o s t d e c r e m e n t a n a l y s i s a n d o t h e r n e w in f o r m a t i o n . . L e v e r a g e t h e d i s t r i b u t i o n e n e r g y e f f i c i e n c y a n a l y s i s o f 1 9 d i s t r i b u t i o n f e e d e r . . . i n W a . o ¡ h i n g t o n ( c o n d u c t e d f o r Pa c i f C o r p b y G m i m O l i w e a l t h A s s o c i a t e s , I n c . ) f o r a n a l y ~ ; i s o f po t e n t i a l d i s t r i b u t i o n e n e r g y e f f i c i e n c y i n ot h e r a r e a s o f P a e i f C o r p ' s s y s t e m . ( T h e W a s h i n g t o n d i s t r i b u t i o n e n e r g y e f f i c i e n c y s t u d y f i n a l r e p o r t i s sc h e d u l e d f o r c o m p l e t i o n b y t h e e n d o f M a y 2 0 1 1 . ) 20 1 1 - 2 0 2 0 6 Cl a s s 2 D S M 7 Cl a s s 3 D S M . C o n t i n u e t o e v a l u a t e C l a s s 3 D S M p r o g r a m o p p o r t n i t i e s . Ev a l u a t e p r o g r a m s p e c i f i c a t i o n a n d c o s t - e f f e c t i v e n e s s i n t h e c o n t e x t o f I R P p o r t f o l i o m o d e l i n g 7 6 , a n d 20 1 1 - 2 0 2 0 I m o n i t o r m a r k e t c h a n g e s t h a t m a y r e m o v e t h e v o l u n t a r y n a t u r e o f C l a s s 3 p r i c i n g p r o d u c t s . 75 P a c i f C o r p E n e r g y H e a t R a t e I m p r o v e m e n t P l a n , A p r i l 2 0 l O . 76 S u p p l y c u r v e d e v e l o p m e n t i n d i c a t e s t h a t w h e n t h e s t a c k i n g e f f e c t o f C l a s s 1 a n d C l a s s 3 r e s o u r c e i n t e r a c t i o n s a r e c o n s i d e r e d , t h e s e l e c t e d r e s o u r c e s w i t h i n bo t h C l a s s e s o f D S M d i m i n i s h . 25 6 P A C I F i C O R P - 2 0 1 1 I R P CH A P T E R 9 - A C T I O N P L A N 8 Pl a n n i n g a n d Mo d e l i n g Pr o c e s s Im p r o v e m e n t s . C o n t i n u e t o r e f i n e t h e S y s t e m O p t i m i z e r m o d e l i n g a p p r o a c h f o t a n a l y z i n g c o a l u t i l i z a t i o n s t r a t e g i e s u n d e r va r i o u s e n v i r o n m e n t a l r e g u l a t i o n a n d r n a r k e t p r i c e s c e n a r i o s . . C o n t i n u e t o c o o r d i n a t e w i t h P a c i f i C o r p ' s t r a n s r n i s s i o n p l a n n i n g d e p a r t m e n t o n i r n p r o v i n g t r a n s r n i s s i o n 20 1 1 - 2 0 1 2 I i n v e s t m e n t a n a l y s i s u s i n g t h e I R P m o d e l s . . I n c o r p o r a t e p l u g - i n e l e c t r i c v e h i c l e s a n d S m a r t G r i d t e c h n o l o g i e s a s a d i s c u s s i o n t o p i c f o r t h e n e x t I R P . . C o n t i n u e t o r e f i n e t h e w i n d i n t e g r a t i o n m o d e l i n g a p p r o a c h ; e s t a b l i s h a t e c h n i c a l r e v i e w c o m m i t t e e a n d a sc h e d u l e a n d p r o j e c t p l a n f o r t h e n e x t w i n d i n t e g r a t i o n s t u d y . 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 269 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. 270 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 271 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. 272 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. 273 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. 275 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 276 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. 277 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, 278 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. 279 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. 282 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. 283 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. 284 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. 285 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. 286 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