The URL can be used to link to this page

Home My WebLink About200705302007 IRP.pdf~~~~OUNTAIN " (~ .. ,~ ..~ ; , ? i r ' \' ' :, lJ I:, , IJ: C~;201 South Main, Suite 2300 Salt Lake City, Utah 84111 May 30, 2007 VL4 OVERNIGHT DELIVERY Li~~i i":;;J Idaho Public Utilities Commission 472 West Washington Boise, ID 83702 PAc-I: o~- Attn: Jean Jewell . Commission Secretary Re:Order No. 22299, Biennial Filing of Electric Integrated Resource Plan Order No. 30262, Case No. P AC-07-03; Compliance Filing - Commitment 30, Case No. PAC-05- Dear Ms. Jewell: Enclosed are an original and seven (7) copies ofPacifiCorp s 2007 Integrated Resource Plan (IRP). Copies of the report and appendices are available electronically and will be posted on PacifiCorp s web site, at www.pacificorp.com. In compliance with Order No. 30262, Case No. PAC-07-, dated March 6, 2007, the Idaho Public Utilities Commission (the "Commission ) approved an extension of time to file its IRP no later than May 30, 2007. PacifiCorp submits this IRP to the Commission as the Resource Management Report on the company s resource planning status. The IRP fully complies with the resource planning requirements in the Commission s rules, and respectfully requests that the Commission acknowledge the IRP in accordance with those rules and fully support the IRP conclusions, including the proposed action plan. Additionally, PacifiCorp submits the IRP filing to meet the MidAmerican Energy Holdings Company ("MEHC") and PacifiCorp commitment that was part of the Commission s Order in Case No. PAC-05-8. Specifically, Commitment 30 provides that: 30) PacifiCorp will continue to produce Integrated Resource Plans according to the then current schedule and the then current Commission rules and orders. The IRP also addresses other MEHC and PacifiCorp transaction commitments related to renewable resources, transmission and advanced coal technologies. These commitments are specifically addressed in Chapter 2, Table 2.4 of the IRP report. As the Commission is aware, the purpose ofPacifiCorp s IRP is to:(1) determine future long term resource needs and develop an informed and comprehensive assessment of the cost and risk implications of alternatives for meeting those needs, and (2) develop a framework of future actions to ensure PacifiCorp continues to provide reliable, least-cost service with manageable and reasonable risk to its customers. PacifiCorp expects its obligations to provide electricity to its customers to continue to grow. Moreover, rapidly evolving state resource policies aimed at reducing the carbon footprint of utilities and expanding renewable energy use will increase system planning complexity and cost uncertainty.PacifiCorp s IRP and associated action plan recognize these important challenges. It is respectfully requested that all formal correspondence and Staff requests regarding this filing be address to the following: Bye-mail (preferred):datareq uest~pac ifi corp. com By Fax:(503) 813-6060 By regular mail:Data Request Response Center PacifiCorp 825 NE Multnomah, Suite 2000 Portland, OR 97232 If there are informal inquiries concerning the filing, or if someone in your agency/organization did not receive a copy of the filing and would like to have one, please contact Pete Warnken Manager Integrated Resource Planning at (503) 813-5518 or Brian Dickman, Idaho Regulatory Affairs Manager, at (801) 220-4975. PacifiCorp sincerely appreciates all the time and effort Idaho participants have dedicated to helping in the development of the IRP. Sincerely, ~(p.A. Jeffrey K. Larsen Vice President, Regulation Cc: Service List PAC-05-8 (w/out enclosures) CERTIFICATE OF SERVICE I hereby certify that on this 30th day of May, 2007, I caused to be served, via E-mail, if address available or U.S. Mail a true and correct copy of the Cover Letter regarding PacifiCorp s 2007 Integrated Resource Plan (Commitment 30) in PAC-05-, to the following: Andrea L. Kelley Vice President, Regulation PACIFICORP 825 NE Multnomah, Suite 2000 Portland, OR 97232 Mail: andrea.kell y~paci ficorp. com Douglas L. Anderson Senior Vice President & General Counsel MidAmerican Energy Holdings Company 302 S. 36th Street, Suite 400 Omaha, NE 68131 E- Mail: danderson~midamerican. com Eric L. Olsen Racine, Olson, Nye, Budge & Bailey, Chartered 201 E. Center O. Box 1391 Pocatello, ID 83204-1391 Mail: elo~racinelaw.net Barton L. Kline, Senior Attorney Monica B. Moen, Attorney II Idaho Power Company O. Box 70 Boise, ID 83707 E- Mail: bkline~idahopower.com mmoen~idahopower.com Brad M. Purdy Attorney at Law 2019 N. 17th Street Boise, ID 83702 Mail: bm urd hotmail.com R. Scott Pasley Assistant General Counsel lR. Simplot Company O. Box 27 Boise, ID 83702 Mail: spasley~simplot.com Mark C. Moench I Senior Vice President - Law MidAmerican Energy Holdings Company 201 S. Main, Suite 2300 Salt Lake City, UT 84111 Mail: mcmoench~midamerican.com Anthony Yankel 29814 Lake Road Bay Village, OH 44140 Mail: tonv~yankel.net John R. Gale Vice President, Regulatory Affairs Idaho Power Company O. Box 70 Boise, ID 83707 Mail: rgale~idahopower.com Arthur F. Sandack, Esq. 8 E. Broadway, Suite 510 Salt Lake City, UT 84111 Mail: asandack itower.net Donald L. Howell, II Deputy Attorney General Idaho Public Utilities Commission 472 W. Washington (83702) O. Box 83720 Boise, ID 83720-0074 E- Mail: donlhowell~puc.idaho. gov Randall C. Budge Racine, Olson, Nye, Budge & Bailey, Chartered 201 E. Center O. Box 1391 Pocatello, ID 83204-1391 Mail: rcb~racinelaw.net Terri Carlock Accounting Supervisor Idaho Public Utilities Commission 472 W. Washington O. Box 83720 Boise, ID 83720-0074 Mail: terri.carlock~puc.idaho.gov James R. Smith Monsanto Company Highway 34 North O. Box 816 Soda Springs, ID 83726 Mail: iim.r.smith~monsanto.com I Alan Herzfeld Herzfeld & Piotrowski LLP 713 W. Franklin O. Box 2864 I Boise, ID 83701 Mail: aherzfeld~hpll p .net Katie Iverson Brubaker & Associates 17244 W. Cordova Court Surprise, AZ 85387 Mail: kiverson~consultbai.com David Hawk Director, Energy Natural Resources R. Simplot Company O. Box 27 Boise, ID 83702 Mail: dhawk~simplot.com R. Scott Pasley Assistant General Counsel lR. Simplot Company O. Box 27 Boise, ID 83702 Mail: spasley~simplot.com Debbie DePetris Regulatory Analyst PAC-O7- :: '' "" , / i", I '' U C. .: ".,;. ~ Ii ,. )! ~ ' - I, i . , ~=, E I This 2007 Integrated Resource Plan (IRP) Report is based upon the best available information at the time of preparation. The IRP action plan will be implemented as described herein, but is subject to change as new information becomes available or as circumstances change. It is PacifiCorp intention to revisit and refresh the IRP action plan no less frequently than annually. Any refreshed IRP action plan will be submitted to the State Commissions for their information. For more information , contact: PacifiCorp IRP Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 (503) 813-5245 IRP(g) PacifiCorp.com http://www.PacifiCorp.com This report is printed on recycled paper Cover Photos (Left to Right): Wind: Foot Creek J Hydroelectric Generation: Yale Reservoir (Washington) Demand side management: Agricultural Jrrigation Thermal-Gas: Currant Creek Power Plant Transmission: South Central Wyoming line PacifiCorp 2007 IRP Table afContents T ABLE'OFCONTENTS Table of Contents............................................. ......................................................................................... Index of Tables.............................................. .........................................................................................vii Index of Figures ....................................................................................................................................... 1. Ex ec u ti ve Summary............. ............. ........................ .... ....... ..... .......... ...... ............... ..... ........ ........ ......... 1 Introduction.............................................................................................................................................. I Planning Principles and Objectives....... ..... ................. ................................... .......................................... The Planning Environment ...................................................................................................................... Resource Needs Assessment.................................................................................................................... Resource Options ......................................................"""""""""""""""""""""""""""......................... Modeling and Risk Analysis Approach ................................................................................................... Modeling and Portfolio Selection Results................................................................................................ 7 Action Plan............................................................................................................................................. 2. IRP Components, Planning Principles, Objectives, and Approach ................................................ Introduction........ .............. ..... .................... ...................... ....... ............. .................. ............ ....... ........ ...... II 2007 Integrated Resource Plan Components ......................................................................................... 12 The Role ofPacifiCorp s Integrated Resource Planning ....................................................................... Planning Principles ..........................,..................................................................................................... Key Analytical and Modeling Objectives .............................................................................................. 14 Integrated Resource Planning Approach Overview............................................................................... 16 Analytical Process.............. ........."....................................... ........... ......... ....... .............. ....., .............. 16 Public Process ................................................................................................................................... 17 Stakeholder Engagement............................................"""""""""""""""""""""""""""..................... MidAmerican Energy Holdings Company IRP Commitments.............................................................. 19 Treatment of Customer and Investor Risks.... .............................. .............. ..... .................... ..... .............. 24 Stochastic Risks ................................................................................................................................ Capital Cost Risks ............................................................................................................................. 25 Scenario Risks................................................................................................................................... 3. Th e Plan n in g Environment ................................................................................................................. 27 Introduction """"""""""""""""""""""""""'"..................................................................................... Marketplace and Fundamentals......................................................................,....................................... Electricity Markets ........ .......... .......... .................. ................... ......... ............... .......... ..... ........... ......... 29 Natural Gas Supply and Demand Issues ........................................................................................... 30 Future Emission Compliance Issues.. .."....... ................. ....... ................................ ............. .................... 31 Currently Regulated Emissions................. ............................... ....................................... ............. "'" 32 ClilTIate Change......... ............. ................................... ..... .................................................... ............... 32 Impacts and Sources ...................................................................................................................... International and Federal Policies.................................................................................................. 33 Regional Initiatives .......... ........................ ..... ................ ...... ................... ......... .......................... ..... State Initiatives .............................................................................................................................. 35 Corporate Greenhouse Gas Mitigation Strategy............................................................................41 Renewable Portfolio Standards.... ..... ............ ................. ...................... ................ .............. ......... ........... California .......................................................................................................................................... Oregon............................................................................................................................................... Washington ....................................................................................................................................... Federal Renewable Portfolio Standard................ ..... ............. ........... .......... ...................... ................. 44 Transmission Planning........................................................................................................................... Integrated Resource Planning Perspective ........................................................................................ 44 PacifiCorp 2007 IRP Table afContents Interconnection-Wide Regional Planning ............................. ................... ................... ...... ......... ....... Sub-regional Planning Groups .......................................................................................................... Hydroelectric Relicensing ...................................................................................................................... Potential Impact ................................................................................................................................ Treatment in the IRP ......................................................................................................................... 48 PacifiCorp s Approach to Hydroelectric Relicensing ........... ..... ........ ..................... .......................... 49 Energy Policy Act of2005..................................................................................................................... Clean Coal Provisions ....................................................................................................................... Renewable Energy Provisions........................................................................................................... Hydropower ............................................................ :......................................................................... Public Utility Regulatory Policies Act Provisions ............................................................................ 51 Metering Provisions ....................................................................................................................... Fuel Source Diversity ................................................................................................................... 52 Fossil Fuel Generation Efficiency Standard .................................................................................. Transmission and Electric Reliability Provisions ............................................................................. 53 Section 368a, Energy Corridors..................................................................................................... Section 1221 , National Transrrllssion Congestion Study.......... ................ .......................... ...... ..... Climate Change................................................................................................................................. Recent Resource Procurement Activities ..................... ................................. ........... ........... .......... ......... Supply-Side Resources...................................................................................................................... 2012 Request for Proposals for Base Load Resources .................................................................. 57 Renewables Request for Proposal2003B ...................................................................................... Demand-side Resources .................................................................................................................... The Impact of State Resource Policies on System-Wide Planning........................................................ 58 4. Resource Needs Assessment ................................................................................................................ Introduction............................................................................................................................................ Load Forecast......................................................................................................................................... Methodology Overview ...........,........................................................................................................ Integrated Resource Planning Load Forecasts .................................................................................. 62 Energy Forecast................................................................................................................................ System-Wide Coincident Peak Load Forecast .................................................................................. Jurisdictional Peak Load Forecast ................ ........ ....... ........ ......................... ................... ............ ...... 66 May 2006 Load Forecast Comparison .............................................................................................. 67 Existing Resources ...............................................................,................................................................. Thermal Plants ................................................................,................................................................. Renewables ....................................................................................................................................... Wind............................................................................................................................................... GeothermaL..................................................................,................................................................. Biomass.......................................................................................................................................... Solar ............................................................................................................................................... Hydroelectric Generation .................................................................................................................. Demand-side Management................................................................................................................ Class 1 Demand-side Management................................................................................................ Class 2 Demand-side Management............................................................................................... Class 3 Demand-side Management............................................................................................... Class 4 Demand-side Management.... ...... ...... ..................... ............................... ......... ................... Contracts ........................................................................................................................................... Load and Resource Balance ................................................................................................................... 76 Capacity and Energy Balance Overview........................................................................................... 76 Load and Resource Balance Components......................................................................................... 76 Existing Resources......................................................................................................................... PacifiCorp 2007 IRP Table afContents Obligation ...................................................................................................................................... 78 Reserves ......................................................................................................................................... Position ............................................................,............................................................................. Reserve Margin..................................................................................................,........................... Capacity Balance Determination....................................................................................................... Methodology ................................................. .................................................................................. Load and Resource Balance Assumptions ..................................................................................... Capacity Balance Results............................................................................................................... Energy Balance Determination ......................................................................................................... Methodology .................................................................................................................................. Energy Balance Results..................................................................................................................... Load and Resource Balance Conclusions ......................................................................................... 87 5. Reso urce Options............................... .......... ............. ....... ....... ...................... ...... ......................... ........ 89 Introduction............................................................................................................................................ Supply-Side Resources .......................................................................................................................... Resource Selection Criteria..................................................................,............................................ Derivation of Resource Attributes..................................................................................................... 90 Handling of Technology Improvement Trends and Cost Uncertainty .............................................. 91 Resource Options and Associated Attributes .................................................................................... Resource Descriptions....................................................................................................................... Coal...............................................................................................,................................................ Natural Gas ..............................................................................................,..................................... Wind...................................................",""""""""""""""""""""""""'"....................................100 Other Renewable Resources ........................................................................................................101 Combined Heat and Power and Other Distributed Generation Alternatives ...............................102 Energy Storage.............................................................................................................................102 Nuclear ......... .......... ................................ ..... ................................... ................. ..... ........ ...... .......... 103 Demand-side Resources.......................................................................................................................103 Resource Selection Criteria. ................ ............ ....................... .................... ........ ........ ..................... 103 Class 1 Demand-side Management..............................................................................................103 Class 2 Demand-side Management..............................................................................................104 Class 3 Demand-side Management..............................................................................................104 Class 4 Demand-side Management..............................................................................................104 Resource Options and Attributes................................ ....... ....... ......... ............. ......... ........ ....... ......... 104 Class 1 Demand-side Management..............................................................................................104 Class 2 Demand-side Management..............................................................................................106 Class 3 Demand-side Management..............................................................................................109 Resource Descriptions..................................................................................................................... 110 Class 1 Demand-side Management..............................................................................................110 Class 2 Demand-side Management..............................................................................................112 Class 3 Demand-side Management..............................................................................................112 Transmission Resources.......................................................................................................................113 Resource Selection Criteria.............................................................................................................113 Resource Options and Attributes..................................................................................................... 113 Market Purchases .................................................................................................................................114 Resource Selection Criteria .............: ......... ................. ......... ..... ...... ............. ...... ................ ........ ...... 114 Resource Options and Attributes..................................................................................................... 115 Resource Description...................................................................................................................... 116 Proposed Use and Impact of Physical and Financial Hedging........................................................ 116 6. Modeling and Risk Analysis Approach............................................................................................117 Introduction............................................................................................,.............................................118 111 PacifiCorp 2007 IRP Table Of Contents Resource Screening..............................................................................................................................118 Alternative Future Scenarios.......................................................................................................... 119 Carbon Dioxide Regulation Cost................................................................................................. 121 Commodity Coal Cost................................................................................................................ 122 Natural Gas and Electricity Prices....................... ........................................... ............................. 122 Retail Load Growth................................................................................................ ,..................... 123 Renewable Portfolio Standards....................................................................................................123 Class 1 and Class 3 DSM Potential.............................................................................................. 123 Sensitivity Analysis Scenarios for the Capacity Expansion Module .............................................. 124 Sensitivity Analysis Scenarios for the Planning and Risk Module ................................................. 126 Capacity Expansion Module Optimization Runs ............................................................................ 126 Risk Analysis Portfolio Development.................................................................................................. 127 Determination of Fixed Resource Investment Schedules.................. ........... ............... ....... ...... ....... 128 Alternative Resource Strategies ............ ......... ......... ................ ..................... ...... .......... ......... .......... 128 Optimization Runs for Risk Analysis Portfolio Deve1opment........................................................ 128 Stochastic Simulation of Risk Analysis Portfolios ..............................................................................129 Stochastic Risk Analysis ........................................................ ............................................... ~........ 129 Scenario Risk Analysis................................................................................................................... 130 Portfolio Performance Measures..........................................................................................................131 Stochastic Mean Cost .......... ..................... ......................... .......... ........ ......... ..... ........... ................... 131 Customer Rate Impact..................................................................................................................... 132 Environmental Externality Cost......................................................................................................132 Risk Exposure ................................................................................................................................. 134 Capital Cost..................................................................................................................................... 134 Production Cost Variability ......... ....... ............................... ............ ........ ..... ..... ......... ................. ...... 134 Carbon Dioxide Emissions.............................................................................................................. 134 Supply Reliability............................................................................................................................ 134 Energy Not Served.......................................................................................................................134 Loss of Load Probability.. ........................... ......... .............. ........... ............... ..... .............. ...... ....... 135 Preferred Portfolio Selection................................................................................................................136 Class 2 Demand-side Management Program Analysis ..................................... :.................................. 136 Decrelnent Analysis ........................................................................................................................ 136 Public Utility Commission Guidelines for Conservation Program Analysis in the IRP ................. 137 7. Modeling and Portfolio Selection Results ........................................................................................139 Introduction..........................................................................................................................................140 Alternative Future and Sensitivity Scenario Results............................................................................ 140 Altcrnati ve Future Scenario Results............. ..................... ............ ............. .............. ......... ........ ...... 140 Demand-side Management Program Selection Patterns ......... ...................... ............................... 142 DSM Potential Scenarios ............. ........... ............ ..................................... .......... .......... ......... ....... 143 Load Growth Scenarios................................................................................................................143 Gas/Electricity Price Scenarios.................................................................................................... 145 Carbon Dioxide Adder/Coal Cost Scenarios ............................................................................... 146 Sensitivity Analysis Results............................................................................................................ 147 Resource Selection Conclusions..................................................................................................... 151 Risk Analysis Portfolio Deve1opment- Group 1 ................................................................................153 Fixed Resource Additions for Risk Analysis Portfolios ................................................................. 154 Renewables ..................................................................................................................................154 Class 1 Demand-side Management Programs ............................................................................. 155 Combined Heat and Power Resources .......... .............................. ............... ............... ........... ........ 157 Alternative Resource Strategies ...................................................................................................... 158 Stochastic Simulation Results - Group 1 Portfolios ............................................................................161 PacifiCorp 2007 IRP Table Of Contents Stochastic Mean Cost...................................................................................................................... 162 Customer Rate Impact.....................................................................................................................164 Emissions Externality Cost ............................................................................................................. 165 Capital Cost.....................................................................................................................................165 Stochastic Risk Measures................................................................................................................166 CostlRisk Tradeoff Analysis ........................................................................................................... 169 Resource Strategy Risk Reduction..................................................................................................171 Carbon Dioxide and Other Emissions.... ...................................... "'" .............................................. 171 Supply Reliability............................................................................................................................ 176 Energy Not Served.......................................................................................................................176 Loss of Load Probability..............................................................................................................177 Portfolio Resource Conclusions ....................................................................................................~. 179 Risk Analysis Portfolio Development - Group 2 ................................................................................179 Alternative Resource Strategies ...................................................................................................... 181 Stochastic Simulation Results............ ............ ..... .......... ....... ........... ........ ..... .......... ...... ..... ..... .............. 186 Stochastic Mean Cost...................................................................................................................... 186 Customer Rate Impact.....................................................................................................................187 Emissions Externality Cost .............................................................................................................187 Capital Cost............ ............ .................................. ........ ..................... ....... ....... ................................ 188 Stochastic Risk Measures................................................................................................................190 Cost/Risk Tradeoff Analysis ......................................................................................................... 191 Carbon Dioxide and Other Emissions.......................................................................................,..... 193 Supply Reliability............................................................................................................................198 Stochastic Simulation Sensitivity Analyses ......................................................................................... 200 12-Percent Planning Reserve Margin with Class 3 Demand-side Management Programs............. 201 Plan to an 18-Percent Planning Reserve Margin............................................................................. 201 Replace a 2012 Base Load Resource with Front Office Transactions ............................................ 201 Replace a Base Load Pulverized Coal Resource with a Carbon-Capture-Ready IGCC .................201 Replace a Base Load Resource with CHP and Dispatchable Customer Standby Generation......... 202 Preferred Portfolio Selection and Justification ....................................................................................202 Planning Reserve Margin Selection ................................................................................................ 203 The Role of Front Office Transactions and Market Availability Considerations ...........................205 Fuel Diversity Planning .......................................................................................................................205 Forecasted Fossil Fuel Generator Heat Rate Trend .............................................................................209 Class 2 DSM Decrement Analysis.......................................................................................................210 Modeling Results ......................".................................................................................................... 210 Regulatory Scenario Risk Analysis - Greenhouse Gas Emissions Performance Standards ................ 213 Scenario Study Approach................................................................................................................213 Stochastic Cost and Risk Results .................................................................................................... 214 Carbon Dioxide Emissions Results.................................................................................................217 8. A cti 0 n Plan............. .............. .......................................... ......... .......... ..... ......... ............... ..... ............... 221 Introduction..........................................................................................................................................222 The Integrated Resource Plan Action Plan ..........................................................................................223 Resource Procurement .........................................................................................................................229 Overall Resource Procurement Strategy ......................................................................................... 229 Renewable Resources......................................................................................................................229 Demand-side Management.............................................................................................................229 Combined Heat and Power..............................................................................................................230 Distributed Generation """""""""""""""""""""""""""..............................................................230 Thermal Base Load/Intermediate Load Resources ......................................................................... 230 Front Office Transactions ............................................................................................................... 231 PacifiCorp 2007 IRP Table Of Contents Transmission Expansion ................................................................................................................ 231 Other Issues..........................................................................................................................................232 Global Climate Change .................................................................................................................. 232 Carbon Reducing Technologies...................................................................................................... 232 Modeling Improvements ................................................................................................................ 232 Cost Assignment and Recovery .............................................. ........................................................ 233 Assessment of Owning Assets versus Purchasing Power ...................................... ..............................233 Resource Acquisition Plan Path Analysis............................................................................................ 233 PacifiCorp 2007 IRP Index of Tables and Figures INDEXOFT ABLES Table 1.1 - Historical and Forecasted Average Energy Growth Rates for Load ........................... 3 Table 1.2 - Capacity System Position for 12% and 15% Planning Reserve Margin ..................... 3 Table 1.3 - PacifiCorp s 2007 IRP Preferred Portfolio.................................................................. 8 Table 2.1 - IRP and Public Process Timeline............................................................................... 17 Table 2.2 - Participation in Regional Planning Organizations and Working Groups .................. 18 Table 2.3 - Public Process Recommendations Implemented for the 2007 IRP ........................... 19 Table 2.4 - MidAmerican/PacifiCorp Transaction Commitments Addressed in the IRP ............ 20 Table 3.1 - State Resource Policy Developments for 2006 and 2007.......................................... 58 Table 4.1 - Historical and Forecasted Average Energy Growth Rates for Load ......................... 63 Table 4.2 - Annual Load Growth in Megawatt-hours for 2006 and forecasted 2007 through 2016 ............................................................................................................................................... Table 4.3 - Historical and Forecasted Coincidental Peak Load Growth Rates ............................ 64 Table 4.4 - Historical Coincidental Peak Load - Summer ........................................................... 65 Table 4.5 - Forecasted Coincidental Peak Load in Megawatts .................................................... 65 Table 4.6 - Historical Jurisdictional Peak Load ........................................................................... 66 Table 4.7 - Jurisdictional Peak Load in Megawatts for 2006 and forecast 2007 through 2016... 66 Table 4.8 - Changes from May 2006 to March 2007: Forecasted Coincidental Peak Load ........ 67 Table 4.9 - Changes from May 2006 to March 2007: Forecasted Load Growth ......................... 68 Table 4.10 - Capacity Ratings of Existing Resources.................................................................. 68 Table 4.11- Existing DSM Summary, 2007-2016....................................................................... 73 Table 4.12 - Capacity Load and Resource Balance (12% Planning Reserve Margin)................. 81 Table 4.13 - System Capacity Load and Resource (15% Planning Reserve Margin).................. 82 Table 5.1 - East Side Supply-Side Resource Options .................................................................. 93 Table 5.2 - West Side Supply-Side Resource Options................................................................. 94 Table 5.3 - Total Resource Cost for East Side Supply-Side Resource Options........................... 95 Table 5.4 - Total Resource Cost for West Side Supply-Side Resource Options ......................... 96 Table 5.5 - CHP Potential Prospects .......................................................................................... 102 Table 5.6 - Sample Load Shapes Developed for 2007 IRP Decrement Analysis ...................... 104 Table 5.7 - Class 1 DSM Program Attributes, West Control Area............................................ 105 Table 5.8 - Class 1 DSM Program Attributes, East Control Area ............................................. 106 Table 5.9 - Class 3 DSM Program Attributes, West Control Area............................................ 109 Table 5.10 - Class 3 DSM Program Attributes, East Control Area ........................................... 110 Table 5.11 - Transmission Options ............................................................................................ 113 Table 5.12 - Maximum Available Front Office Transaction Quantities by Market Hub........... 115 Table 6.1 - Alternative Future Scenarios ................................................................................... 120 Table 6.2 - Scenario Input Variable Values and Sources........................................................... 121 Table 6.3 - Sensitivity Scenarios................................................................................................ 125 Table 6.4 - CEM Sensitivity Scenario Capital Cost Values....................................................... 125 Table 6.5 - Planning Decrement Design .................................................................................... 137 Table 7.1 - Alternative Future Scenarios ......... ....... ........ .................... ........ .......... ............ ......... 141 Table 7.2 - Alternative Future Scenario PVRR and Cumulative Additions for 2007-2018...... 141 Table 7.3 - DSM Resource Selection by Alternative Future Type """""""""""""""""""""" 143 Table 7.4 - Resource Additions for Load Growth Scenarios ..................................................... 143 Table 7.5 - Resource Additions for Scenarios with Low Load Growth..................................... 144 Vll PacifiCorp 2007 IRP Index of Tables and Figures Table 7.6 - Resource Additions for Scenarios with Medium Load Growth .............................. 144 Table 7.7 - Resource Additions for Scenarios with High Load Growth.................................... 144 Table 7.8 - Resource Additions for Scenarios with Low Gas/Electricity Prices ....................... 145 Table 7.9 - Resource Additions for Scenarios with High Gas/Electricity Prices....................... 145 Table 7.10 - Resource Additions for Scenarios with Low CO2 Adder/Coal Costs.................... 146 Table 7.11- Resource Additions for Scenarios with High CO2 Adder/Coal Costs................... 146 Table 7.12 - Sensitivity Analysis Scenarios.......... .............." "'" ............ ....... .............. ............... 147 Table 7.13 - Sensitivity Analysis Scenario PVRR and Cumulative Additions, 2007-2018 ...... 148 Table 7.14 - Wind Resource Additions Schedule for Risk Analysis Portfolios ........................155 Table 7.15 - Class 1 DSM Cumulative Resource Additions for Candidate Portfolios .............. 157 Table 7.16 - Risk Analysis Portfolio Descriptions (Group 1).................................................... 159 Table 7.17 - Generation and Transmission Resource Additions................................................ 161 Table 7.18 - Portfolio Cost by CO2 Adder Case ........................................................................ 162 Table 7.19 - Cost Impact of Portfolio Resource Strategies........................................................ 163 Table 7.20 - Portfolio Emissions Externality Cost by CO2 Adder LeveL................................. 165 Table 7.21 - Average Risk Exposure and Standard Deviation for CO2 Adder Cases................ 166 Table 7.22 - Risk Measure Results by CO2 Adder Case '(Million $) .........................................167 Table 7.23 - Resource Strategies and Test Portfolios for Cost-Risk Exposure.......................... 171 Table 7.24 - Cumulative CO2 Emissions by Cost Adder Level, 2007-2016.............................. 172 Table 7.25 - Cumulative CO2 Emissions by Cost Adder Level, 2007-2026..............................173 Table 7.26 - System Generator Emissions Footprint, Cumulative Amount for 2007-2026...... 175 Table 7.27 - Average Loss of Load Probability During Summer Peak .....................................177 Table 7.28 - Y ear-by- Year Loss of Load Probability ................................................................ 178 Table 7.29 - Wind Resource Additions Schedule for Risk Analysis Portfolios ........................ 180 Table 7.30 - Risk Analysis Portfolio Descriptions (Group 2).................................................... 182 Table 7.31 - Resource Investment Schedule for Portfolio RA13........:...................................... 183 Table 7.32 - Resource Investment Schedule for Portfolio RA14............................................... 184 Table 7.33 - Resource Investment Schedule for Portfolio RA15............................................... 184 Table 7.34 - Resource Investment Schedule for Portfolio RA16............................................... 185 Table 7.35 - Resource Investment Schedule for Portfolio RA17............................................... 185 Table 7.36 - Transmission Resource Investment Schedule for All Group 2 Portfolios............. 186 Table 7.37 - Stochastic Mean PVRR by CO2 Adder Case......................................................... 186 Table 7.38 - Portfolio Emissions Externality Cost by CO2 Adder Level and Regulation Type 188 Table 7.39 - Stochastic Risk Results.. ........................ ............ .............. ..................... ................, 190 Table 7.40 - CO2 Emissions by Adder Case and Time Period (1,000 Tons) ............................. 193 Table 7.41 - Total Emissions Footprint by CO2 Adder Case ..................................................... 197 Table 7.42 - Average Loss of Load Probability During Summer Peak ..................................... 199 Table 7.43 - Y ear-by- Year Loss of Load Probability ................................................................ 200 Table 7.44 - Sensitivity Analysis Scenarios for Detailed Simulation Analysis.......~................. 201 Table 7.45 - Combined Heat and Power Replacement Resources .............................................202 Table 7.46 - Preferred Portfolio Capacity Load and Resource Balance .................................... 204 Table 7.47 - Annual Nominal Avoided Costs for Decrements, 2010-2017...............................211 Table 7.48 - Annual Nominal Avoided Costs for Decrements, 2018-2026............................... 211 Table 7.49 - Capacity Additions for the Initial CEMGHG Emissions Performance Standard Portfolio. ..... ..................... ....... ........... ..................... .... ............ ................. ......... .................. 214 Table 7.50 - Resource Investment Schedule for the Final GHG Emissions Performance Standard Portfolio.. ................................ ........... ............... .......... .... ............... ....... .............. ..... ...... ..... 215 Vlll PacifiCorp 2007 IRP Index of Tables and Figures Table 7.51 - Stochastic Cost and Risk Results for the Final GHG Emissions Performance Standard Portfolio. ................................................................................... ........................... 215 Table 8.1 - Resource Investment Schedule for Portfolio RA14................................................. 222 Table 8.2 - 2007 IRP Action Plan .............................................................................................. 224 PacifiCorp 2007 IRP Index of Tables and Figures , , , , .. -.. .. ... INDEX OF FIGURES 7 Figure 1.1 - System Capacity Chart ............................................................................................... Figure 1.2 - Monthly and Annual Average Energy Balance.......................................................... 4 Figure 1.3 - Projected PacifiCorp Resource Energy Mix............................................................... 9 Figure 2.1 - Integrated Resource Planning Analytical Process Steps .......................................... 16 Figure 3.1 - Sub-regional Transmission Planning Groups in the WECC .................................... 47 Figure 3.2 - Western Interconnection Transmission Congestion AreasIPaths............................. 55 Figure 3.3 - Conditional Constraint Areas ................................................................................... 56 Figure 4.1 - Contract Capacity in the 2007 Load and Resource Balance .................................... 75 Figure 4.2 - Changes in Contract Capacity in the Load and Resource Balance .......................... 75 Figure 4.3 - System Coincident Peak Capacity Chart.................................................................. 82 Figure 4.4 - West Coincident Peak Capacity Chart ..................................................................... 83 Figure 4.5 - East Coincident Peak Capacity Chart....................................................................... 84 Figure 4.6 - Average Monthly and Annual System Energy Balances ......................................... 86 Figure 4.7 - Average Monthly and Annual West Energy Balances ............................................. 86 Figure 4.8 - Average Monthly and Annual East Energy Balances .............................................. 87 Figure 5.1 - Proxy Wind Sites and Maximum Capacity Availabilities...................................... 101 Figure 5.2 - DSM Decrement, Daily End Use Shape (megawatts)............................................ 107 Figure 5.3 - DSM Decrement, Weekly Peaks (megawatts) .......................................................108 Figure 5.4 - Transmission Options Topology............................................................................ 114 Figure 6.1 - Modeling and Risk Analysis Process ........ .................... ........ .......... ............ ..... ...... 118 Figure 6.2 - System Average Annual Natural Gas Prices: Low, Medium, and High Scenario Values.......................................................................................................o......................... 122 Figure 6.3 - System Average Annual Electricity Prices for Heavy and Light Load Hour Natural Gas Prices: Low, Medium, and High Scenario Values....................................................... 123 Figure 6.4 - Two-Stage Risk Analysis Portfolio Development Process .................................... 129 Figure 7.1 - Cumulative Resource Additions by Year for Alternative Future Studies .............. 142 Figure 7.2 - Cumulative Wind Additions for CAF07 and SAS16 ............................................. 151 Figure 7.3 - CEM Fossil Fuel Resource Selection Frequency................................................... 152 Figure 7.4 - Wind Capacity Preferences for Alternative Future Scenarios................................ 154 Figure 7.5 - Wind Location Preferences for Alternative Future Scenarios................................ 155 Figure 7.6 - Class 1 DSM Selection Frequency for Alternative Future Scenarios, 2007-2016.156 Figure 7.7 - Class 1 DSM Average Megawatts for Alternative Future Scenarios, 2007-2016.. 157 Figure 7.8 - CHP Quantities Selected for Each Alternative Future Scenario, 2007-2016......... 158 Figure 7.9 - Stochastic Mean Cost by CO2 Adder Case............................................................. 163 Figure 7.10 - Customer Rate Impact............ .................. ......... ............... ........ ............................ 164 Figure 7.11 - Total Capital Cost by Portfolio............................................................................. 166 Figure 7.12 - Average Stochastic Cost versus Risk Exposure ...................................................169 Figure 7.13 - Stochastic Cost versus Risk Exposure for the $0 CO2 Adder Case ..................... 170 Figure 7.14 - Stochastic Cost versus Risk Exposure for the $61 CO2 Adder Case ...................170 Figure 7.15 - Generator CO2 Emissions by Cost Adder Level, Cumulative for 2007-2016...... 174 Figure 7.16 - Generator CO2 Emissions by Cost Adder Level, Cumulative for 2007-2026...... 174 Figure 7.17 - Stochastic Average Annual Energy Not Served................................................... 176 Figure 7.18 - Upper-Tail Stochastic Mean Energy Not Served ................................................. 177 Figure 7.19 - Customer Rate Impact.... .......... .................. ............... ...... .................. ................... 187 Figure 7.20 - Total Capital Cost by Portfolio............................................................................. 189 PacifiCorp 2007 IRP Index of Tables and Figures Figure 7.21 - Average Stochastic Cost versus Risk Exposure ................................................... 191 Figure 7.22 - Stochastic Cost versus Risk Exposure for the $0 CO2 Adder Case .....................192 Figure 7.23 - Stochastic Cost versus Risk Exposure for the $61 CO2 Adder Case ...................192 Figure 7.24 - Annual CO2 Emission Trends, 2007-2026, ($8 CO2 Adder Case)....................... 194 Figure 7.25 - Annual CO2 Emission Trends , 2007-2026, ($61 CO2 Adder Case)..................... 195 Figure 7.26 - Annual CO2 Emissions Trends, 2007-2016 ($8 CO2 Adder Case) ...................... 195 Figure 7.27 - Annual CO2 Emissions Trends, 2007-2016 ($61 CO2 Adder Case) .................... 196 Figure 7.28 - Annual CO2 Emissions Trends, 2007-2016 ($8 CO2 Adder Case) ...................... 196 Figure 7.29 - Annual CO2 Emissions Trends, 2007-2016 ($61 CO2 Adder Case) ....................197 Figure 7.30 - Energy Not Served for the $8 CO2 Adder Case ................................................... 198 Figure 7.31 - Upper-Tail Mean Energy Not Served for the $8 CO2 Adder Case ......................199 Figure 7.32 - Current and Projected PacifiCorp Resource Energy Mix..................................... 207 Figure 7.33 - Current and Projected PacifiCorp Resource Capacity Mix.................................. 208 Figure 7.34 - Fleet Average Fossil Fuel Heat Rate Annual Trend by Generator Type ............. 210 Figure 7.35 - East Decrement Price Trends ............................................................................... 212 Figure 7.36 - West Decrement Price Trends........ ...................... .......... ........ ........ ............ .......... 212 Figure 7.37 - Average Stochastic Cost versus Risk Exposure Across All CO2 Adder Cases.... 216 Figure 7.38 - Stochastic Cost versus Risk Exposure for the $0 CO2 Adder Case ..................... 216 Figure 7.39 - Stochastic Cost versus Risk Exposure for the $61 CO2 Adder Case ................... 217 Figure 7.40 - Annual CO2 Emission Trends, 2007-2026 ($0 CO2 Adder Case)........................ 218 Figure 7.41 - Annual CO2 Emission Trends, 2007-2026 ($61 CO2 Adder Case)...................... 218 Figure 7.42 - Annual CO2 Emission Trends, 2007-2026 (Average for all CO2 Adder Cases).. 219 PacifiCorp 2007 IRP Index of Tables and Figures XlI PacifiCorp 2007 IRP Chapter 1 - Executive Summary 1. EXECUTIVE SUMMARY INTRODUCTION PacifiCorp s 2007 Integrated Resource Plan (IRP) presents a framework of future actions to en- sure PacifiCorp continues to provide reliable, least-cost service with manageable and reasonable risk to its customers. Active public involvement from customer interest groups, regulatory staff regulators and other stakeholders provided considerable guidance in the development of this IRP. The analytical approach used conforms to all State Standards and Guidelines, and resulted in a preferred portfolio that represents a balance of resource additions that meet future customer needs while minimizing cost, balancing diverse stakeholder interests and addressing environ- mental concerns. This IRP builds on PacifiCorp s prior resource planning efforts and reflects significant advancements in portfolio modeling and risk analysis. PLANNING PRINCIPLES. AND OBJECTIVES ' The mandate for an IRP is to assure, on a long-term basis, an adequate and reliable electricity supply at the lowest reasonable cost and in a manner "consistent with the long-run public inter- est." 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 current view of the planning environment, corporate business goals, and MidAmerican Energy Holdings Company (MEHC) transaction commitmentsthat related to IRP activities. As a business planning tool, it supports informed decision-making on resource procurement by providing an analytical framework for assessing resource investment tradeoffs. As an external communications tool, the IRP engages numerous stakeholders in the planning process and guides them through the key decision points leading to PacifiCorp' s preferred portfolio of generation demand-side, and transmission resources. The emphasis of the IRP is to determine the most robust resource plan under a reasonably wide range of potential futures as opposed to the optimal plan for some expected view of the future. The modeling is intended to support rather than overshadow the expert judgment of Pacifi Corp decision-makers. The preferred portfolio is not meant to be a static planning product, but rather is expected to evolve as part of the ongoing planning process. As a multi-objective planning ef- fort, the IRP must reach a balanced position upon considering several priorities and accounting for diverse and sometimes conflicting stakeholder views. In short, the IRP cannot be all things to all people. As the owner of the IRP, PacifiCorp is uniquely positioned to determine the resource plan that best accomplishes IRP objectives on a system-wide basis, thereby meeting customer community, and investor obligations collectively. THE PLANNING ENVIRONMENT There are many significant external influences that impact PacifiCorp s long-term resource plan- ning, as well as recent procurement activities driven by the company s past IRPs. External influ- ences are comprised of events and trends in the power industry marketplace, along with govern- PacifiCorp 2007 IRP Chapter 1 - Executive Summary ment policy and regulatory initiatives that influence the environment in which PacifiCorp oper- ates. One major issue within the power industry marketplace is capacity resource adequacy and asso- ciated standards for the Western Electricity Coordinating Council (WECC). The pace of new generation additions has begun to slow again in the west, raising the question of future resource adequacy in certain areas. The Western Electricity Coordinating Council 2006 Power Supply Assessment indicates that the Rocky Mountain sub-region will show a resource deficit by 2010. Another significant issue is the prospect for long-term natural gas commodity price escalation and continued high volatility. Following an unprecedented increase in natural gas commodity escalation and volatility, forecasters expect a medium-term, temporary drop in natural gas com- modity prices due to liquefied natural gas (LNG) facility expansion. Price uncertainty will con- tinue because greater LNG imports will strengthen the linkage to volatile global gas arid energy markets. One of the largest issues emerging from governmental policy and regulatory initiatives is how to plan given an eventual, but highly uncertain, climate change regulatory regime. Not only have there been significant policy developments for currently-regulated pollutants, but there have also been important state-level climate change regulatory initiatives. Other regulatory issues include state renewable portfolio standards, hydropower relicensing, and major relevant provisions of the Energy Policy Act of 2005. In conjunction with resource planning efforts, PacifiCorp has a greenhouse gas mitigation strat- egy that includes a public working group to consider emission reduction best practices, carbon dioxide scenario analysis for the IRP and procurement programs, renewable generation and de- mand-side management resource acquisition plans, and emissions accounting. Transmission constraints, and the ability to address them in a timely manner, represent important planning considerations for ensuring that peak load obligations are met on a reliable basis. Vari- ous regional transmission planning processes in the Western Interconnection have developed over the last several years to serve as the primary forums where major transmission projects are developed and coordinated. PacifiCorp is engaged in a number of these planning initiatives. The Energy Policy Act of 2005, the first major energy law enacted in more than a decade, in- cludes numerous provisions impacting electric utilities. Keyprovisions include (1) the promotion of clean coal technology, renewable energy, and nuclear power, (2) the encouragement of more hydroelectric production through streamlined relicensing procedures and increased efficiency, (3) the use of time-based metering options, and (4) the provision of mandatory reliability stan- dards. PacifiCorp s recent resource procurement activities include requests for proposal for east-side base load resources and renewable resources. In addition, requests for proposals have been is- sued for demand-side resource programs. PacifiCorp 2007 IRP Chapter 1 - Executive Summary PacifiCorp s planning process is further impacted by the rapid evolution of state-specific re- source policies that place, or are expected to place, constraints on PacifiCorp s resource selection decisions, and disparate state interests that complicate the company s ability to address state IRP requirements to the satisfaction of all stakeholders. RESOURCE NEEDS ASSESSMENT The total net control area load forecast used in this IRP reflects PacifiCorp s forecasts of loads growing at an average rate of 2.4 percent annually from 2007 to 2016, which is slightly faster than the average annual historical growth rate (See Table 1.1). The eastern portion of the Pacifi- Corp system continues to grow faster than the western system, with an average annual energy growth rate of 3.2 percent and 0.8 percent, respectively, over the forecast horizon. Table 1.1 - Historical and Forecasted Average Energy Growth Rates for Load Average Annual Growth Rate 1995-2005 2007-2016 On both a capacity and energy basis, load and resource balances are calculated using existing resource levels, obligations and reserve requirements. Based on load and resource balance calcu- lations, the company projects a summer peak resource deficit for the PacifiCorp system begin- ning in 2008 to 2010, depending on the capacity planning reserve margin assumed. Table 1.2 shows the annual capacity position (megawatt resource surplus or deficit) for the system using a 12 percent and 15 percent planning reserve margin, while Figure 1.1 shows the corresponding annual resource and obligation levels. Table 1.2 - Capacity System Position for 12% and 15% Planning Reserve Margin 2010 091)i!8i'l (1,073) 2016 (2,446) (2 563) \2,794) (2.842) (3,171) 768) (2.890) (3J26) (3,176) (3 5J3)1147) The PacifiCorp deficits prior to 2011 to 2012 will be met by additional renewables, demand-side programs, and market purchases. The company will consider other options during this time frame if they are cost-effective and provide other system benefits. This could include accelera- tion of a natural gas plant to complement the accelerated and expanded acquisition of renewable wind facilities. On an average annual energy basis, the system becomes deficient beginning in 2009 (Figure 1.2), based on a 12 percent planning reserve margin. To address these widening deficits in a cost-effective and risk-informed manner, a mix of resource types is anticipated. ' PacifiCorp 2007 IRP Chapter 1 - Executive Summary Figure 1.1- System Capacity Chart 000 000 000 000 ;;: :2i 000 000 000 Obligation '" Reserves (15%) Obligation + Reserves (12%) ..._~ Existing Resources 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Figure 1.2 - Monthly and Annual Average Energy .Balance 000 500 000 500 ;;: :2i (500) 11,()OO, 11,500 (2.000) (2,5G0) (;; 000) Annual Balance -Monthly Balance (;;, 501)) 9 ~ ~ 9 ~ ~ ~ 2 ~ ~ ~ 1 ~ ~ ~ ~ ~ f ~ ~ ~ f ~ ~ ~ f ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 8 ~ ~ ~ & ~ ~ ~ & ~ ~ ~ 8 ~ ~ ~ 8 ~ ~ ~ 8 ~ ~ ~ 8 ~ ~ ~ 8 ~ ~ ~ 8 ~ ~ ~ 8 PacifiCorp 2007 IRP Chapter 1 - Executive Summary RESOIJIubiE'tJPTIONS The company developed cost and performance profiles for supply-side resources, demand-side management programs, transmission expansion projects, and firm market purchases (front office transactions) for use in portfolio modeling. Each supply-side option also included the estimation and use of capital cost ranges for each supply-side option. These cost ranges reflect cost uncer- tainty, and their use in this plan acknowledges the significant construction cost increases that are occumng. PacifiCorp used the Electric Power Research Institute s Technical Assessment Guide (TAG(ID), along with recent project experience and consultant studies, to develop its supply-side resource options. The purpose of using TAG data is to rely on consistently-derived cost estimates from a well-respected independent outside source. The TAG database is considered the default source for developing the supply-side resource alternatives used in the 2007 IRP. Values are adjusted as necessary using information from PacifiCorp or other sources that reflects corporate or location- specific considerations. TAG capital costs for certain technologies were adjusted to be more in line with PacifiCorp s recent cost studies and project experience. In addition, TAG emission estimates were adjusted based on permitting expectations in PacifiCorp s service territory. The use of TAG information is new to PacifiCorp s integrated resource planning process. The company also developed transmission resources to support meeting loads with new genera- tion options, to integrate wind, to enhance transfer capability and maintain reliability across PacifiCorp s system, and to boost import/export capability with respect to external markets. These transmission resources were entered as options in PacifiCorp s capacity expansion optimi- zation tool, and were thus allowed to compete directly with other resources for inclusion in port- folios. MOD ELIN G AND RISK. ANA.LYSISAPPROACH The IRP modeling effort seeks to determine the comparative cost, risk, supply reliability, and emissions attributes of resource portfolios. PacifiCorp used two modeling tools for portfolio analysis: the Capacity Expansion Module (CEM) and the Planning and Risk (PaR) Module. The CEM performs a deterministic least-cost optimization with resource options over the twenty-year study period. The CEM operates by minimizing for each year the operating costs for existing resources subject to system load bal- ance, reliability and other constraints. Over the study period, it also optimizes resource additions subject to resource investment and capacity constraints (monthly peak loads plus a planning re- serve margin for a 24-zone model topology). The PaR module is a chronological commit- ment/dispatch production cost model that was operated in probabilistic (stochastic) mode to de- velop risk-adjusted portfolio performance measures. The 2007 IRP modeling effort consisted of resource screening, risk analysis portfolio develop- ment, and detailed production cost and stochastic risk analysis. For resource screening, the com- pany used the CEM to evaluate generation, load control, price-responsive demand-side manage- ment, market purchases, and transmission resources on a comparable basis with the use of "alter- PacifiCorp 2007 lRP Chapter 1 - Executive Summary native future" scenarios. The main purpose of these scenarios is to identify general resource pat- terns attributable to changes in assumptions, and to help identify robust resources-those that frequently appear in the model's optimized portfolios under a range of futures. PacifiCorp sought assistance from public stakeholders to construct the alternative future scenarios, which capture variations in potential CO2 regulatory costs, natural gas prices, wholesale electricity prices, retail load growth, and the scope of renewable portfolio standards. Using the results from the alternative future scenario studies, PacifiCorp defined risk analysis portfolios for stochastic simulation. The CEM was used to help build fixed resource investment schedules for wind and distributed resources, and to optimize the selection of other resource op- tions according to specific resource strategies. Other key portfolio development criteria included diversity among the major new resource types and the impact of evolving state resource policies. The resulting portfolios were then simulated using the PaR model. The PaR simulations incorpo- rate stochastic risk in its production cost estimates by using Monte Carlo random sampling of five stochastic variables: loads, commodity natural gas prices, wholesale power prices, hydro energy availability, and thermal unit availability. PacifiCorp devoted considerable effort to model the effect of CO2 emission compliance strate- gies. Stochastic simulations were conducted with various CO2 emission cost adders to capture the risks associated with potential CO2 emission compliance regulations. Since the probability of realizing a specific CO2 emissions cost cannot be determined with a reasonable degree of accu- racy, potential CO2 emission costs were treated as a scenario risk in this IRP. PacifiCorp defines a scenario risk as an externally-driven fundamental and persistent change to the expected value of some parameter that is expected to significantly impact portfolio costs. This risk category is intended to embrace abrupt changes to risk factors that are not amenable to stochastic analysis. The practice of combining stochastic simulation with CO2 cost adder scenario analysis represents advancement with respect to the modeling approach used for PacifiCorp s 2004 IRP. All risk analysis portfolios were simulated with five CO2 adder levels-$O/ton, $8/ton, $15/ton $38/ton, and $611ton (in 2008 dollars)-and associated forward gas/electricity price forecasts. The company modeled both a cap-and-trade and emissions tax compliance strategy, and ex- panded its reporting of CO2 emissions impacts. Portfolio performance was assessed with the following measures: (1) stochastic mean cost (Pre- sent Value of Revenue Requirements), (2) customer rate impact, measured as the levelized net present value of the change in the system average customer price due to new resources for 2007 through 2026, (3) emissions externality cost, (4) capital cost, (5) risk exposure, (6) CO2 and other emissions, (7) and supply reliability statistics. The preferred portfolio is selected from among the risk analysis portfolios primarily on the basis of relative cost-effectiveness, customer rate impact, and cost/risk balance across the CO2 adder levels. The preferred portfolio represents the most robust resource plan under a reasonably wide range of potential futures. PacifiCorp 2007 IRP Chapter 1 - Executive Summary , "" """ """ """, , "" '" "'" rl\IOD ELING~))!iF,() RTFO LIOSELECTI 0 NRESULTS PacifiCorp assessed "alternative future" scenarios to determine resources and capacity quantities suitable for inclusion in risk analysis portfolios. Based on the Capacity Expansion Module s op- timized investment plans, the company selected wind (as a proxy for all renewable resources), combined heat and power, supercritical pulverized coal, combined cycle combustion turbine single-cycle combustion turbine, integrated gasification combined cycle (IGCC), load control programs, transmission additions and short-term market purchases in subsequent portfolio stud- Ies. The company studied portfolios using its stochastic production cost simulation model. These portfolios were distinguished by a variety of resource strategies intended to address major portfo- lio risks, such as carbon regulations and natural gas/electricity price volatility. These resource strategies were distinguished by the planning reserve margin level and the quantity and timing of wind, pulverized coal, front office transactions, and IGCC resources included. The portfolio analysis yielded the following general conclusions: Diversification of resources helps to balance costs and risks. A combination of supercritical pulverized coal, additional renewable generation, and gas-fired resources is desired to achieve a low-cost portfolio that effectively addresses all major sources of risk; conversely, portfolios dominated by a single resource type were found to be more expensive and risky for customers. Studies also demonstrated that increasing wind capacity and reducing reliance on market purchases promotes a better balance of portfolio cost and risk. Eliminating front office transactions after 2011 decreased risk exposure and increased portfo- lio cost. To maintain planning flexibility and resource diversity, PacifiCorp will continue to rely on them as needed to support energy requirements in the west control area, and use them as needed to address peak load requirements in the east control area. While the portfolio analysis indicated that lowering the planning reserve margin increased portfolio stochastic risk and reduced reliability, the decision on what margin to adopt is a subjective one that depends on balancing portfolio risk against affordability. The portfolio modeling also showed that reducing the planning reserve margin from 15% to 12% increased CO2 and other emissions due to greater reliance on the company s existing coal fleet. Based on superior performance with respect to stochastic cost, customer rate impact, cost-versus- risk balance , and supply reliability, a portfolio with the following characteristics was chosen as the preferred portfolio: . A total of2 000 megawatts of renewable resources by 2013 . An additional 100 megawatts of load control (Class 1 demand-side management) beginning in 2010 . A west-side combined cycle combustion turbine in 2011 . High-capacity-factor resources in the east in 2012 and 2014 East-side combined cycle combustion turbines in 2012 and 2016 Balance of system need fulfilled by front office transactions beginning in 2010 Transmission additions between 2010 and 2014 to support integration of the resource portfo- lio with loads PacifiCorp 2007 IRP Chapter 1 - Executive Summary The preferred portfolio s specific proxy resources and acquisition timing are shown in Table 1.3. Table 1.3 - PacifiCorp s 2007 IRP Preferred Portfolio , , StltiolvandDeOtand..sid~ProxvRes6urces, .,... ' ' :.ma'lame lateCaoaci rv. Typ ~" "' ".,. 2007 2008 2009 201'0 2011 2013 2014 2015 2016Resource'2012 East Utah pulverized coal Supercritical 340 "..' Wyoming pulverized coal Supercritical 527 Combined cycle CT 2xl F class with duct firing 548 Combined cycle CT Ixl G class with duct firing 357 Combined Heat and Power Generic east-wide Renewable Wind, Wvoming 200 200 200 300 Class I DSM*Load control, Sch. irrigation Front office transactions Heavv Load Hour, 3rd Otr 393 272 149 192 165 West CCCT 2xl F Type with duct firing 602 Combined Heat and Power Generic west-wide Renewable Wind, SE Washington 300 100 Renewable Wind, NC Oregon 100 100 100 Class I DSM*Load control, Sch. irrigation Front office transactions Flat annual Product 219 555 657 247 246 249 Annual Additions, LOqJiTerm;Re$ouh,e!i 300:600 100 :312,839 125 318 527 357 Annua.I.'AdditiOhs/ShortTetrIlRfs6l1ftes ' ",." .d"612:336 652 660 396.438 414 ' '.. ", ' " TotaIAnnuaJ,1\dd1tions..30m ;30.0..100 924 175 777 978 923 438 771 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. y"';;;,. ,, ,' ,' " 1'ransmissionProxvRe$ourccs'"TransferCaoabilitv, Megawatts " ,.. ", , , Re!iourc~ "" .J,2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 East Path C Upgrade: Borah to Path-C South to Utah North 300 Utah - Desert Southwest (Includes Mona - Oquirrh)600 ;"' Mona - Utah North 400 Craig-Hayden to Park City 176 Miners - Jim Bridger - Terminal 600 , Jim Bridger - Terminal 500 West Walla Walla - Yakima 400 West Main - Walla Walla 630 ' ," ' ' Total AnnualAdditions ' ' 70()630 776 500 * Transmission resource proxies represent a range of possible procurement strategies, including new wheeling con- tracts or construction of transmission facilities by PacifiCorp or as a joint project with other parties. The preferred portfolio reflects a diverse resource mix, as evidenced by the increasing contribu- tion of renewables, gas-fired, and front office transactions to system generation. Figure 1.3 com- pares the system energy mixes for 2007 and 2016, which include preferred portfolio resources and reflect the average generation across the five CO2 cost adders modeled. While the preferred portfolio is based on a target planning reserve margin of 12 percent, Pacifi- Corp is targeting a reserve margin range of 12 to 15 percent to increase planning flexibility given a time of rapid public policy evolution and wide uncertainty over the resulting down-stream cost impacts. The preferred portfolio also is consistent with the company s strategic view on the role of firm market purchases for meeting capacity needs: that limited use of such purchases is bene- ficial by increasing planning flexibility and portfolio diversity, but that the company seeks less PacifiCorp 2007 IRP Chapter 1 - Executive Summary reliance on them for the long term. Market availability to support the level of firm purchases in the preferred portfolio is adequate as evidenced by recent purchase offer activity. For example requests in 2007 for third-quarter projects for 2007-2012 yielded over 5 000 megawatts in offers. Figure 1.3 - Projected PacifiCorp Resource Energy Mix 2007 Resource Energy Mix with Preferred Portfolio Resources (Average for five CO2 Adder Case~) Interruptible Class 1 DSM '0, Existing Purchases Gas-CHP System Balancing Purchases 2016 Resource Energy Mix with Preferred Portfolio Resources (Average for five CO2 Adder Cases) Interru~tible Class 1 DSMYo Renewable ~O, Pulverized Coal 43.4% Gas.CCCT 17.4% System Balancing Purchases 14,2% Front Office Transactions PacifiCorp 2007 IRP Chapter 1 - Executive Summary The integrated resource plan is intended to provide guidance for the company s resource pro- curement activities over the next few years. To follow through on the findings of this resource plan, PacifiCorp s action plan includes: Reaffirming commitments to renewable resources: Accelerate its previous commitment to acquire 1,400 megawatts of cost-effective renew- able resources from 2015 to 2010 Increase the amount of cost-effective renewable resources to 2 000 megawatts by 2013 Actively seek to add transmission infrastructure to deliver wind power to key load areas. Investigate adding flexible generating resources, such as natural gas, to integrate new wind resources Enhance its integrated resource planning modeling to address renewable portfolio stan- dards and the impacts of adding large quantities of wind resources to its system Increased focus on energy efficiency: Continue to run programs to acquire 250 average megawatts of cost-effective energy effi- ciency, and Add an additional 200 average megawatts of cost-effective energy efficiency initiatives Maintaining and expanding load control programs: Maintain and build upon the existing 150 megawatts of irrigation and air conditioning load control in Utah and Idaho Add 100 megawatts of additional load control split between East and West beginning in 2010 Leverage voluntary demand-side measures, such as demand buyback, to improve system reliability during peak load hours, and Incorporate the results of the demand-side management potentials study into the com- pany s demand-side management programs and future integrated resource plans. Studying and addressing environmental issues: Enhance its integrated resource planning modeling to address new carbon regulations and Take a leadership role in discussions on global climate change and continue to investigate carbon reduction technologies, including nuclear power. Addressing transmission constraints: Expand its transmission system to allow the resources identified in the preferred portfolio to serve customer loads in a cost-effective and reliable manner Adding a diverse mix of base load / intermediate load resources: Acquire up to 1 700 megawatts of base load / intermediate load resources on the east side of its system for the term 2012 through 2014, through a mix of thermal resources and purchases, consistent with the April 2007 filed request for proposal, and Acquire 200 to 1 350 megawatts of base load / intermediate load resources on the west side of its system from 2010 to 2014 through a mix of thermal resources and purchases. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach IRP COMPONENTS, PLANNING PRINCIPLES, OBJECTIVES, AND APPROACH .'. , .. . P~cifiCorp s IRPmandateis to assure, on a long-term basis ~n~deqll.a:t~,#id.relia~le~lec- tJ.-jcity,supp lYl:\t .'(l1"~a.S:()I1a:blecostand in a manner ~oI1siste:#.twiththe 1911.gtrunpiil;J~~9 jn- .terese' . " ,; ", ... . . ' A:~a mul~i '-objectivepll:\nni:n.geffqrt, the JRP. must r~ach a~a.I,!~cedP()s#ii?JllJlP()n.P9nSid- e~gseveraLpriQritiesandac(;ounting ,for divers~"an.dso.ine.t#n~~s ,CQPll.icfingst~elI.B~~er . VIews. ' .' .' '. .- ', .' '. . , J'qeIRP isa rQadr11aR.forPacifiQorp slong~termresource,sti)i.t~gy"gevel()p~d.a.9Qofo,ip. g ., . to seven planning principles." One()ftheprinciplesisthati!.str~t~gic~lly~ngnsWi!h.pusi-' riess priorities ,and !l1eets,MEHCtransaction c0111mit111erits. , , ', .' ,. ,, ., .,.. i(.ey analyti cal and Illodeling ,obj ectiveswere to (1 )evaluate it.l1.resollJ:ces()n.ac()n5para.ble ~asisllsing thec0111pany's ne\V"r~source exPCillSion, optimiz;ati()nt()oli ~rid J.2J'enl1,M-ce l.ll1- cedaint)randriskanalysis. " . ""...- ., .. ,. , ' - . Theoutco.rneofPacifiCorp s portfolio. ana1ysisis,apreferredpOI1:folioth4tyepresentSthe lo.West -cost diversified resource plan thataccountsfor cost/risktrade-offs $ystern relicibil- ' ity, ratepayer impacts, arid. CO2' emissions. The "preferredpqI1:folio is al~o tl1emQstr()bust resourceplanundera:rea~onablywide range ofpoteritialfutures. , ' PacifiCorp continuously seeks to improve the IRPpllblic.prpcess;an.uIllber of recbnt ini- tiativesto enhance stakeholder engagement for this IRPareprofileg. , INTRODUCTION This chapter outlines the components of this Integrated Resource Plan (IRP), and describes the groundwork for its development: the set of planning principles and analysis objectives that un- derpin the IRP development effort, and the overall approach for building it. This IRP builds on PacifiCorp s prior resource planning efforts and reflects significant advance- ments in portfolio modeling and risk analysis. It was developed in a collaborative public process with involvement from regulatory staff, advocacy groups, and other interested parties. PacifiCorp is filing this IRP with its state regulatory agencies, and requests that they acknowledge and sup- port its conclusions, including the Action Plan. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles Objectives, and Approach 20D7INl'EG-RAl'ED'RESOUR~E'~tAN:e()~PONENTS , ' The basic components ofPacifiCorp s 2007 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 market trends and fundamentals, leg- islative and regulatory developments, and current procurement activities (Chapter 3) . A resource needs assessment covering the company s load forecast, status of existing re- sources, resource expansion alternatives, and determination of the load and energy positions for the lO-year resource acquisition period (Chapter 4) Profiles and background infonnation for the resource options considered for addressing fu- ture capacity deficits (Chapter 5) . A description of the IRP modeling and risk analysis approach (Chapter 6) . A summary of modeling results and PacifiCorp s preferred portfolio (Chapter 7) . An action plan linking the company s preferred portfolio with specific implementation ac- tions (Chapter 8) The IRP appendices, included as a separate volume, comprise base modeling assumptions, sup- porting technical infonnation, detailed Capacity Expansion Module (CEM) modeling results supplementary portfolio information, studies intended to meet certain state commission IRP ac- knowledgement requirements, and status reports on IRP regulatory compliance and action plan progress. PacifiCorp s response to written comments on the draft IRP report is incorporated in Appendix F. THE,ROLE OF PACIFICO RP 'SINTEG RATEDRESOUR CE "PLANNING 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-run public interest.l The main role of the IRP is to serve as a roadmap for determining and implementing the company long-term resource strategy according to this IRP mandate. In doing so, it accounts for state commission IRP requirements, the current view of the planning environment, corporate business goals, risk, and uncertainty. As a business planning tool, it supports informed decision-making on resource procurement by providing an analytical framework for assessing resource investment I The Oregon and Utah Commissions cite "long run public interest" as part of their definition of integrated resource planning. Public interest pertains to adequately quantifying and capturing for resource evaluation any resource costs external to the utility and its ratepayers. For example, the Utah Commission cites the risk of future internalization of environmental costs as a public interest issue that should be factored into the resource portfolio decisionmaking process. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach tradeoffs. As an external communications tool, the IRP engages numerous stakeholders in the planning process and guides them through the key decision points leading to PacifiCorp s pre- ferred portfolio of generation, demand-side, and transmission resources. Given this role and the long-term planning focus, it is important to note the qualifications associ- ated with the IRP so that the planning outcome can be placed in the proper context. First, re- source portfolio analysis seeks to help clarify the unknown future as opposed to predicting it. Consequently, the emphasis of the IRP is to determine the most robust resource plan under a reasonably wide range of potential futures as opposed to the optimal plan for some expected view of the future. In tandem with the robustness concept is the view that selection of the pre- ferred portfolio should not be overly influenced by any particular set of quantitative results given the complexity and inherent imprecision of the modeling effort. In other words, modeling is in- tended to support and not overshadow the expert judgment ofPacifiCorp s decision-makers. A second IRP qualification is that the preferred portfolio is not meant to be a static planning product, but rather is expected to evolve as part of the ongoing planning process. As resources are a~quired and new planning information comes in, the company refreshes the preferred portfo- lio and action plan based on the set of planning principles enumerated below. Because the IRP is a road mapping effort, it is not intended as a referendum on specific resource decisions. The pre- ferred portfolio represents a snapshot view of PacifiCorp ' s long-term resource planning strategy informed by current infonnation. As emphasized in this IRP and prior ones, specific resource acquisition decisions stem from PacifiCorp s competitive procurement process. A third qualification is that as a multi-objective planning effort, the IRP must reach a balanced position upon considering several priorities and accounting for diverse and sometimes conflict- ing stakeholder views. In short, the IRP cannot be all things to all people. As the owner of the IRP, PacifiCorp is uniquely positioned to determine the resource plan that best accomplishes IRP objectives on a system-wide basis, thereby meeting customer and investor obligations collec- tively. PLANNIN GPRIN CIPUES PacifiCorp subscribed to a number of planning principles that guided the overall IRP develop- ment effort and resource decision-making process. Development of the IRP is guided by the state commission rules and guidelines for integrated resource planning, as well as specific IRP process and analysis requirements arising from state commission acknowledgement proceedings. At the same time, the company conducted its IRP process with the understanding that commission IRP rules and acknowledgement pro- ceedings are not intended to usurp its decision-making authority for resource acquisition. PacifiCorp continues to plan on a system-wide basis. However, newly enacted state energy and environment policy mandates (and those under consideration) present considerable chal- lenges for planning on this basis. This IRP considers such state mandates as part of the port- folio development and analysis process, acknowledging that the definition of an "optimal" portfolio must be extended to accommodate sometimes disparate state policy goals. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach With portfolio costs increasing due to rapid construction price increases and the move to- wards more expensive alternative technologies to meet new state resource acquisition poli- cies, PacifiCorp is more mindful of rate impact considerations for this IRP. The IRP and associated action plan was developed with PacifiCorp and MidAmerican En- ergy Holding Company (MEHC) business principles in mind, and meets MEHC transaction commitments. The business principles that relate to long-term resource planning include (1) improving electricity system reliability, (2) investing in physical assets that bolster corporate strength and competitiveness, and (3) protecting the environment in a cost-effective manner. The company subscribes to a portfolio management approach for acquiring resources to meet its future load obligations. It seeks a diversified, low-cost mix of resources that minimizes price and environmental risk for its customers while enhancing value for its investors. PacifiCorp continues to plan using the proxy resource approach, whereby resource options included in the IRP models are constituted with generic cost and performance attributes and assume PacifiCorp ownership for supply-side alternatives to simplify the analysis. (Some ad- justments are made to resource attributes to reflect corporate experience or location-specific considerations, such as elevation for gas-fired resources.) With this proxy approach, mod- eled resources are only indicative of the resources that might be procured, the specific attrib- utes of which may be modified to account for conditions at procurement time. Wind was se- lected as the proxy resource for all renewables based on wide availability in PacifiCorp service territory, relative cost-effectiveness and cost certainty, and technological maturity. In the case of modeled transmission options, these are proxies representing a range of procure- ment strategies, including new wheeling contracts or construction of transmission facilities by PacifiCorp or as joint projects with other parties. PacifiCorp believes that CO2 regulation will come into play during the 10-year resource ac- quisition period that is the focus of this IRP (2007 through 2016). Potential carbon dioxide emission costs serve as a major source of portfolio risk that is addressed through scenario analysis and balancing this risk against others. PacifiCorp also believes that given the state knowledge concerning prospective CO2 regulations, it is prudent to not assign probabilities to specific CO2 cost outcomes as part of portfolio risk analysis. The company continues to seek improvements in the stakeholder engagement process and enhance the level of transparency of the overall process. KEY ANAL YTICALANDMODELINGOBJECTlVES The main analytical objective of the IRP is to determine the preferred resource portfolio for the next ten years (2007-2016) based on a finding of need and a comparative assessment of available resource opportunities. The preferred portfolio represents the resource plan that has the best bal- ance of cost and risk. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach A key analytical objective for this IRP was to treat all resource options on a comparable basis when developing alternative portfolios. To that end, PacifiCorp added a resource expansion op- timization tool (the Capacity Expansion Module, or CEM) into its portfolio modeling frame- work. This model perfonns automated economic screening of resources and determines the op- timal resource expansion plan based on planning scenarios. This tool enabled thermal generation renewable generation, market purchases, demand-side management, and transmission to compete against each other on the basis of their impact on Present Value of Revenue Requirements (PVRR), the key measure of a portfolio s performance. Important caveats associated with the CEM are that it does not capture stochastic risks in its op- timization algorithm, and that it is designed as a high-level screening tool. In contrast to the Planning and Risk Module (PaR)-PacifiCorp s detailed production costing and market simula- tion model, the CEM cannot incorporate stochastic variables in its solution algorithm and is in- stead meant to address high-level system operational details. (For example, unlike the PaR, it does not capture hourly chronological commitment constraints). Consequently, a modeling ob- jective for this IRP was to exploit the complementary but different capabilities of the CEM and PaR. Chapter 6 describes the roles that each of these models played throughout PacifiCorp s re- source portfolio analysis. An additional analytical and modeling objective for this IRP was to enhance uncertainty and risk analysis. PacifiCorp accomplished this objective by making the following data and modeling methodology changes, which are detailed later in this report. Incorporated stochastic simulation of candidate portfolios at various CO2 adder levels, in contrast to running deterministic simulations with CO2 adder levels independently as was done for the 2004 IRP. Introduced stochastic analysis of front office transactions (market purchases), which includes comparing stochastic risk measures of a portfolio with front office transaction resources against a portfolio in which these resources are replaced with an asset-based coal plant. Development of low and high capital cost estimates for supply-side resources in recognition of increased construction cost volatility trends. Extensive expansion of the number of input sensitivity studies relative to the 2004 IRP, in- cluding 36 studies using the CEM and 27 stochastic studies using PaR. Incorporated probability-weighted forward gas price curves into the IRP models; the curves are based on a weighted average ofPIRA Energy s low, medium, and high gas price cases. A final analytical objective for this IRP was to determine an appropriate level of reliance on market purchases given their flexibility benefits and risks. As opposed to the 2004 IRP, where market purchases were treated as a fixed resource, for this IRP they were handled as a competing resource option with associated prices modeled as stochastic variables to capture price risk. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach INTEGRATED ,RESO UR CE.PLMmINhiPPReicH'.O VER VIEW);;; j, . m The 2007 IRP approach consisted of both analytical and public processes that occurred in tan- dem. These two processes are described below. Analytical Process The analytical process is comprised of nine major steps that are summarized in Figure 2.1. Chap- ter 3 addresses Step 1 , " review the planning environment". Step 2 , " update inputs and assump- tions , is covered largely in Appendices A and J. Chapter 4 covers Step 3 , " develop load and resource balance . Step 4 , " define candidate resource list" is treated in Chapter 5. Steps 5 through 8 , which address the modeling and risk analysis process and results, are covered in Chapters 6 and 7. Figure 2.1 - Integrated Resource Planning Analytical Process Steps D pdateinptitsandass\n1"lptions , . 1)eve1op joa.darigresc)tll'te 1)alance' t~ ' , jd'entifya.11iiua.JpapaCity/~n:etgypositions ' i~; .DeflD~c;~di~t~.t~sq~il1elist inc1uding' trahsti1issi()l1pr()j~cts 5. Developp1annillg and sensitivity a.na1YBissceriatiq~;llseth~c~pacityexpansion . optimization tool (CENf)todeteITDinethEioptirnalpottfolio foreacl.lscenapothat eliminates aiml1alcapacitY:def1citsa(jCordingtoC~pacity reseryernarginr~quirements/" 6. Use planning scenarioresnlts t()he1p;determineadiv~rsified resource mix that is robust across, the:ra.ngeofa1termitivefutur~s 7. Create risk analysisportfo1iosbasedori a1tenia!iv~ strategies,formanagirig , portfolio risks that, can bedifferentiated throughS(()"hastic(Monk "Carlo) ,simulation Modelriskanalysis:poi:1;folios using'stochastitsllrmlations 9. Seh::(:ta.prefe,J:r~gportf~Jj() 11Singe:y'~Ina.tioncrit~,rja:. . Cost,fisk;sys teif1reliabilitj;,; ratepayer impact, 992emissiqflS As shown in the diagram, the outcome of the analytical process is a preferred portfolio that represents the lowest-cost diversified resource plan that accounts for cost, risk, system reliability, ratepayer impacts, and CO2 emissions. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles Objectives, and Approach Public Process The core of the 2007 IRP public process was a series of 13 public meetings 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. PacifiCorp held three of the meetings in 2005-two load forecasting workshops (August 3 and October 5) and a 2007 IRP kick-off meeting on December 7. Table 2.1 shows the timeline of the public meetings in relation to the overall IRP timeline, commencing with the December 7 IRP kick-off meeting. Appendix F, in the separate appendix volume, provides more details concern- ing the public meeting process and individual meetings. Stakeholder engagement efforts are chronicled in the last section of this chapter. Table 2.1 - IRP and Public Process Timeline LA"oiOS\V&Dt,.oS,OCtiOJF (lIIov.;05::!Jm'os" 'CJiiii;O(F ::"F~Ii'OJi', J\l8f~ I. :A.Dr'Mi "Mav~'VJuit4!6! IRP Timeline PrepareIRP Assumptions and Models 1 Technical Workshop - Load Forecastin!!, Au!!ust 3, 2005 2 Technical Workshop - Load Forecastin", October 5, 2005 3 General Public Input Meetim" December 7, 2006 4 Technical WorkshoD - Renewables, Jan 13,2006 5 Technical Workshop - Load Forecasting, Jan. 24, 2006 6 Technical Works hoD - DSM, Feb 10, 2006 7 General Public Meeting, April 20, 2006 8 General Public Meeting, Mav 10, 2006 9 General Public Meeting, June 7, 2006 General Public Meeting, August 23, 2006 General Public Meeting, October 31, 2006 General Public Meeting, February 1,2007 General Public Meeting, ADri118, 2007 \JUt4)i':t'Aiio'4)6: HSeiWI6..I::o.t'!JJi..!I!j,"'IW!'J:)ne~"!JJi!U;.1i4I7n:IF.b'O7&:. MiIi'iQ7::" ,;!Aiir'O'l MaY;O7: IRP Timeline Conduct Analysis Prepare IRP Report File 1 Technical WorkshoD - Load Forecasting, August 3, 2005 2 Technical Workshop - Load Forecasting, October 5, 2005 3 General Public InDut Meeting, December 7, 2006 4 Technical Workshop - Renewables, Jan 13, 2006 5 Technical WorkshoD - Load Forecasting, Jan. 24, 2006 6 Technical Workshop - DSM, Feb 10,2006 7 General Public Meeting, April 20, 2006 8 General Public Meeting, Mav 10, 2006 9 General Public Meeting, June 7, 2006 General Public Meeting, August 23, 2006 General Public Meeting, October 31, 2006 12 General Public Meetin!!, Februarv 1, 2007 13 General Public Meeting, April 18, 2007 In addition to the public meetings, PacifiCorp used other channels to facilitate resource planning- related information sharing and consultation throughout the IRP process. The company maintains website (http://w\vw.pacificorp.comINavigationINavigation23807 .html), e-mail "mailbox irp(ZV,pacificorp.com), and a dedicated IRP phone line (503-813-5245) to support stakeholder communications and address inquiries by public participants. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles Objectives, and Approach PacifiCorp and its parent company, MidAmerican Energy Holdings Company (MEHC), also participated in numerous organizations and working groups that address regional planning issues in the areas of supply, system coordination, energy management, and transmission resources. Table 2.2 lists a number of these organizations by focus area. Table 2.2 - Participation in Regional Planning Organizations and Working Groups()r anizaUoll 'FocusArea . Western Electricity Coordinating CounciVSeams Steering Group System reliability and adequacy - Western Interconnection (SSG-WI) Northwest Power Pool Northwest Power and Conservation Council Pacific Northwest Utilities Conference Committee (PNUCC Northwest Wind Inte ration Technical Work rou Big Sky Carbon Sequestration Partnership Energy Future Coali- tion Global Climate Chan e Workin Grou (MEHC commitment Climate chan e Integrated Gasification Combined Cycle Working Group (MEHC Clean coal technology commitment) Northwest Ener Efficienc Alliance Conservation Adviso Council (Ener Trust of Ore on) Utah DSM Adviso Grou Washin ton DSM Adviso Grou Northwest Transmission Assessment Committee (NT AC) Roc Mountain Area Transmission Stud RMA TS) Northern Tier Transmission Grou (NTTG Western Re ional Transmission Ex ansion Partnershi Ely Energy Center / Robinson Summit - Harry Allen 500 kV Transmission Pro' ect Re iona1 P1annin Review Grou Utah Resource Forum Peak ower demand issues Finally, PacifiCorp provided IRP participants the opportunity to critique the draft IRP document in April 2007. STAKER () LDE RENGA GEMENT PacifiCorp maintains a strong commitment to improve the value of the IRP public process to external stakeholders as well as the company. This is evidenced by a number of initiatives taken by PacifiCorp during 2005 and 2006. First, PacifiCorp instituted a stakeholder satisfaction sur- vey in the spring of 2005. The purpose of this survey was to determine if the company was on the right track with respect to execution of the IRP public process, and to solicit recommenda- tions on improvements to better support stakeholder needs.2 PacifiCorp implemented several recommendations for the 2007 IRP, as detailed in Table 2. 2 A presentation summarizing the survey results can be found on PacifiCorp s Web site. The link to the presentation is httP://\vww.paciticoro.com/File/File52811.pdf. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach Table 2.3 - Public Process Recommendations Implemented for the 2007 IRP Po blicP:tocessRecomm endatio n Distribute model run results during the course of the IRP modeling phase rather than waiting to distribute them at the pub- lic meetings. Distribute appendices for review along with the main draft IRP document. Work to ensure that the participant base is more evenly balanced as far as representa- tion is concerned; issue personal invita- tions to stakeholders as necessary. Send information out earlier to prepare for meetings. Outcome. " " . PacifiCorp distributed via e-mail a document pack- age to participants on October 4, 2006 with updated CEM modeling results and other documentation including an updated paper that describes the plan- ning scenarios and associated input assumptions. The company also distributed a paper on candidate portfolio development on October 12, 2006 and Februa 5 2007. PacifiCorp distributed for review the draft appendi- ces to su ort the review of the main document. PacifiCorp expanded its meeting invitation and contact list from about 80 individuals for the 2004 IRP to 135 for the 2007 IRP. PacifiCorp also added a video-conference site in Cheyenne, Wyoming, to facilitate meeting attendance. This list expansion also encompasses IRP meeting invitations to MEHC transaction stakeholders per Commitment #48, de- scribed in the next section. PacifiCorp maintains a policy of distributing meet- ing handouts at least two days in advance of a meet- ing. Exceptions may occur due to the need for last- minute management reviews of meeting materials. Only one ofthe 13 public meetings was impacted in this wa . Another PacifiCorp initiative was to front-load public meetings during the 2007 IRP schedule and to focus those meetings on the more contentious, technical, or complex issues. This meeting plan was prompted by the company s concern during the 2004 IRP process that critical stake- holder input was provided well after the point where recommendations and concerns could be easily addressed in the process. Based on the outcome of these meetings, the company found the front-loading approach beneficial as an early sounding board for its proposed modeling assump- tions and approaches, and intends to build on this approach for the next IRP. MID AMERICAN ENERGY HOLDINGSCOMPANYJRPCOMMITMENTS MEHC and PacifiCorp committed to continue to produce IRPs according to the schedule and Commission rules and orders at the time the transaction was in process. Other commitments were made to (1) encourage stakeholders to participate in the integrated resource planning proc- ess and consider transmission upgrades, (2) develop a plan to achieve renewable resource com- mitments, (3) consider utilization of advanced coal-fuel technology such as IGCC technology when adding coal-fueled generation, (4) conduct a market potential study of additional demand- side management and energy efficiency opportunities, (5) evaluate expansion of the Blundell Geothermal resource, and (6) include utility "own/operate" resources as a benchmark in future request for proposals. A detailed description of these commitments and a description of how they are addressed in the 2007 Integrated Resource Plan are provided in Table 2.4 below. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach Table 2.4 - MidAmerican/PacifiCorp Transaction Commitments Addressed in the IRP MERG" Commitment. Number ' , ',... ,, '., , . RowtheCommitmenlisj~d~, ' . dressed:intlte2001iIRP , ::: ' This plan complies with various Commission rules and orders. , ... ." ,, . . . MEHCComniitinentDescn' tion PacifiCorp will continue to produce Integrated Resource Plans according to the then-current schedule and the then-current Commission rules and orders. IRP Stakeholder Process: PacifiCorp will pro- vide public notice and an invitation to encourage stakeholders to participate in the Integrated Re- source Plan (IRP) process. The IRP process will be used to consider Commitments 34, 39 52 and 53. PacifiCorp will hold IRP meetings at locations or by using communica- tions technologies that encourage broad partici- pation. Transmission Investment: MEHC and Pacifi- Corp have identified incremental transmission projects that enhance reliability, facilitate the re- ceipt of renewable resources, or enable further system optimization. Subject to permitting and the availability of materials" equipment and rights-of-way, MEHC and PacifiCorp commit to use their best efforts to achieve the following transmission system infrastructure improve- ments: . Path C Upgrade (-$78 million) - Increase Path C capacity by 300 MW (from S.E. Idaho to Northern Utah). The target completion date for this project is 2010. . Mona - Oquirrh (-$196 million) - Increase the import capability from Mona into the Wasatch Front (from Wasatch Front South to Wasatch Front North). This project would enhance the ability to import power from new resources . delivered at or to Mona, and to import from Southern California by "wheeling" over the Ade1anto DC tie. The target completion date for this project is 2011. . Walla Walla - Yakima or Mid-C (-$88 mil- lion) - Establish a link between the "Walla Walla bubble" and the "Yakima bubble Public notice for each Integrated Resource Planning meeting was provided to stakeholders. For all Integrated Resource Planning meetings, video conference facili- ties were made available in Port- land, Oregon and Salt Lake City, Utah in addition to a telephone link. Several of the meetings also included video conference facilities in Cheyenne, Wyoming. Consid- eration of commitments 34, 39, 40 52 and 53 are described be- low. Each of these three transmission upgrades has been included in the company s modeling. The Path C upgrade is included as a planned transmission upgrade while the other two projects are options that can be selected by the Capacity Expansion Module. PacifiCorp 2007 IRP ... MEHC ommitnient Nuniber Chapter 2 - IRP Components, Planning Principles Objectives, and Approach ' , MEH C Comltiifillen. and/or reinforce the link between the "Walla Walla bubble" and the Mid-Columbia (at Van- tage). Either of these projects presents oppor- tunities to enhance PacifiCorp s ability to ac- cept the output from wind generators and bal- ance the system cost effectively in a regional environment. The target completion date for this project is 2010. (Footnote): It is possible that upon further review, a particular invest- ment might not be cost-effective, optimal for customers or able to be completed by the tar- get date. If that should occur, MEHC pledges to propose an alternative to the Commission with a com arable benefit. In Commitment 31 , MEHC and Pacifi- Corp adopt a commitment to source future PacifiCorp generation resources consistent with the then-current rules and regulations of each state. In addition to that commitment, for the next ten years, MEHC and PacifiCorp commit that they will submit as part of any commission approved RFPs for resources with a dependable life greater than 10 years and greater than 100 MW-including renewable energy RFPs-a 100 MW or more utility "own/operate" alternative for the particular resource. It is not the intent or objective that such alternatives be favored over other options. Rather, the option for PacifiCorp to own and operate the resource which is the subject of the RFP will enable comparison and evaluation of that option against other viable al- ternatives. In addition to providing regulators and interested parties with an additional viable option for assessment, it can be expected that this commitment will enhance PacifiCorp s abil- ity to increase the proportion of cost-effective renewable energy in its generation portfolio based upon the actual experience of MEC and the "Renewable Energy" commitment offered below. MEHC reaffirms PacifiCorp s commitment to acquire 1 400 MW of new cost-effective renew- able resources, representing approximately 7% ofPacifiCorp s load. MEHC and PacifiCorp commit to work with de- velopers and bidders to bring at least 100 MW of cost-effective wind resources in service within one ear of the close of the transaction. . , HowtbeCommitmenUs Ad,;, dressed .intbe20071RP This commitment is being ad- dressed in the company s request for proposals. This Integrated Resource Plan re- flects the commitment to acquire 1,400 megawatts of new cost- effective renewable resources. The 100 megawatt goal has been met and the company is within 54 megawatts of reaching the 400 me awatt oa1 at the time of this PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach 1\ 4~ ~~;~iflllen Number '" ' , , , iiM)i1HCColDmitmerit Desert tion MEHC and PacifiCorp expect that the commit- ment to build the Walla-Walla and Path C transmission lines will facilitate up to 400 MW of renewable resource projects with an expected in-service date of201O. MEHC and PacifiCorp commit to actively work with developers to identify other transmission improvements that can facilitate the delivery of cost-effective wind energy in PacifiCorp s ser- VIce area. In addition, MEHC and PacifiCorp commit to work constructively with states to implement re- newable energy action plans so as to enable PacifiCorp to achieve at least 1 400 MW of cost-effective renewable energy resources by 2015. Such renewable energy resources are not limited to wind ener resources. MEHC supports' and affirms PacifiCorp s com- mitment to consider utilization of advanced coal-fuel technology such as super-critical or IGCC technology when adding coal-fueled gen- eration. MEHC and PacifiCorp commit to conducting a company-defined third-party market potential study of additional DSM and energy efficiency opportunities within PacifiCorp s service areas. The objective of the study will be to identify opportunities not yet identified by the company and, if and where possible, to recommend pro- grams or actions to pursue those opportunities found to be cost-effective. The study will focus on opportunities for deliverable DSM and en- ergy efficiency resources rather than technical potentials that may not be attainable through DSM and energy efficiency efforts. On-site so- lar and combined heat and power programs may be considered in the study. During the three- month period following the close of the transac- tion, MEHC and PacifiCorp will consult with DSM advisory groups and other interested par- ties to define the proper scope of the study. The findings of the study will be reported back to DSM advisory groups, commission staffs, and other interested stakeholders and will be used by the Com an in hel in to direct on oin DSM ('",'i' , , How"t1ie:~olll '" (Jt;cssc€l'htt report. The company has included several transmission upgrades in 2007 In- tegrated Resource Planning analy- ses that can facilitate additional re- newable resource develQpment. A Renewables Action Plan to achieve at least 1,400 megawatts of cost- effective renewable energy re- source by 2015 was filed concur- rently with the 2007 IRP. IGCC technology is included as a resource option in the 2007 Inte- grated Resource Planning process. Chapter 5 details various clean coal , project activities, including the joint Wyoming Infrastructure Au- thori /PacifiCo IGCC ro ect. The demand side management po- tential study is underway and is expected to be completed on schedule. The results of the study will be used to inform future Inte- grated Resource Plans. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles Objectives, and Approach MERC. Commitment , ' Nu.mb~r and energy efficiency efforts. The study will be completed within fifteen months after the clos- ing on the transaction, and MEHC shareholders will absorb the first $1 million of the costs of the study. PacifiCorp further commits to meeting its por- tion of the NWPPC's energy efficiency targets for Oregon, Washington and Idaho, as long as the targets can be achieved in a manner deemed cost-effective by the affected states. In addition, MEHC and PacifiCorp commit that PacifiCorp and MEC will annually collaborate to identify any incremental programs that might be cost-effective for PacifiCorp customers. The Commission will be notified of any additional cost-effective ro rams that are identified. Upon closing, MEHC and PacifiCorp commit to immediately evaluate increasing the generation capacity of the Blundell geothermal facility by the amount determined to be cost-effective. Such evaluation shall be summarized in a report and filed with the Commission concurrent with the filing ofPacifiCorp s next IRP. This incre- mental amount is expected to be at least 11 MW and may be as much as 100 MW. All cost effec- tive increases in Blundell capacity, completed before January 1 2015 , should be counted to- ward satisfaction ofPacifiCorp s 1 400 MW re- newable energy goal, in an amount equal to the capacity of geothermal energy actually added at the lant. MEHC or PacifiCorp commit to commence as soon as practical after close of the transaction a system impact study to examine the feasibility of constructing transmission facilities from the Jim Bridger generating facilities to Miners Sub- station in Wyoming. Upon receipt of the results of the system impact study, MEHC or Pacifi- Corp will review and discuss with stakeholders the desirability and economic feasibility of per- forming a subsequent facilities study for the Brid er to Miners transmission ro ect. .. Rowth eCommitm1mt Is A.d- , , ' dtcssedIlltbe 2007 IRP , . A report describing the Blundell evaluation was filed in March 2007 with all six states. This commitment was completed by the company on August 23 2006. The Miners substation to Jim Bridger transmission upgrade is in- cluded as an option in the 2007 In- tegrated Resource Planning analy- SIS. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach ,MERC Commitment , ; Number" C22a, 026a Wy21a C22b, 026b Wy21b 123, V17 Wy20 , , - ,, '" , ~ ' ." , , MEUdComfuirinentDescHii6tt Concurrent with its next IRP filing, PacifiCorp commits to file a ten-year plan for achieving the 400 MW renewables target, including specific milestones over the ten years when resources will be added. The filing will include a ten-year plan for installing transmission that will facili- tate the delivery of renewable energy and the achievement of its 2015 goal of at least 1,400 MW of cost-effective renewable energy. Within six (6) months after the close of the transaction MEHC and PacifiCorp will file with the Com- mission a preliminary plan for achieving the 400 MW renewable tar et. PacifiCorp commits to address as part of its next IRP the appropriate role of incremental hydro- power projects in meeting the 1400 MW renew- abIes target. PacifiCorp agrees to include the following items in the 2006 IRP (2007 IRPJ: a) a wind penetration study to reappraise wind integration costs and cost-effective renewable energy levels; and b) an assessment of transmission options for PacifiCorp s system identified in the RMATS scenario 1 related to facilitating additional gen- eration at Jim Bridger and, on equal footing, new cost-effective wind resources. A Renewab1es Action Plan to achieve at least 1 400 megawatts of cost-effective renewable energy re- sources by 2015 was concurrently with the 2007 IRP. It will address hydropower projects in the docu- ment. a) Wind supply curves were devel- oped and used to select wind on a comparable basis with other re- sources in the Capacity Expansion Module. Appendix J addresses the company s wind resource method- ology used in this plan. b) The company included trans- mission options in southwest and southeast Wyoming as potential upgrades in its modeling in order to facilitate wind development in Wyoming. TREATMENT OF CUSTOMER ANDINVESTOR RISKS The IRP standards and guidelines in Utah require that PacifiCorp "identify which risks will be borne by ratepayers and which will be borne by shareholders " This section addresses this re- quirement. Three types of risk are covered: stochastic risk, capital cost risk, and scenario risk. 3 Since PacifiCorp is now a subsidiary of a privately-owned company, this section will refer to PacifiCorp s "inves- tors" as opposed to "shareholders. PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach Stochastic Risks One of the principle sources of risk that is addressed in this IRP is stochastic risk. Stochastic risks are quantifiable uncertainties for particular variables. The variables addressed in this IRP include retail loads, natural gas prices, wholesale electricity prices, hydroelectric generation, and thermal unit availability. Changes in these variables that occur over the long-term are typically reflected in normalized revenue requirements and are thus borne by customers. Unexpected variations in these elements are normally not reflected in rates, and are therefore borne by inves- tors unless specific regulatory mechanisms provide otherwise. Consequently, over time, these risks are shared between customers and investors. Between rate cases , investors bear these risks. Over a period of years, changes in prudently incurred costs will be reflected in rates and custom- ers will bear the risk. Capital Cost Risks PacifiCorp uses proxy resources in its portfolio evaluation and determination of the preferred portfolio. These proxy resources are characterized with generic capital cost estimates that are adjusted to reflect recent project experience and company-specific financial parameters. The actual cost of a generating or transmission asset is expected to vary from the cost assumed in this plan. 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 risk of such a determination is borne by investors. To the extent that capital costs vary from those assumed in this IRP for rea- sons that do not reflect imprudence by PacifiCorp, the risks are borne by customers. Scenario Risks Scenario risks pertain to abrupt or fundamental changes to model inputs that are appropriately handled by scenario analysis as opposed to representation by a statistical process or expected- value forecast. The single most important scenario risk facing PacifiCorp are government actions to regulate CO2 emissions. This scenario risk relates to the uncertainty in predicting the scope timing, and cost impact of CO2 emission compliance rules. At the present time, the issue of how the risk associated with uncertain CO2 regulatory costs should be allocated to customers and investors is an open one. Complicating factors include the following: The prospect that a supercritical coal plant that is part of the company s preferred portfolio could receive IRP acknowledgement in one state and not another. The need to weigh resource CO2 cost risk against the opportunity costs of investing in alter- native resources with their own attendant cost risks (In this IRP, PacifiCorp shows that coal plants provide important portfolio risk diversification benefits when paired with other low- CO2 emitting resources. Ratepayer/investor risk allocation may be treated differently among PacifiCorp s jurisdic- tions depending on state resource policies and the evolution of inter-jurisdictional cost alloca- tion approaches designed to address them. At the combined Climate Change and Integrated Gasification Combined Cycle Working Group meeting on November 28, 2006, PacifiCorp facilitated a public discussion on ratepayer/investor risk allocation in the event that the company acquires a coal unit that is not able to capture and PacifiCorp 2007 IRP Chapter 2 - IRP Components, Planning Principles, Objectives, and Approach store CO2 emissions.4 The outcome of the discussion was that no consensus could be reached on the risk allocation issue and how the company can effectively proceed with resource planning given the regulatory uncertainties; more questions were raised than answers provided. 4 PacifiCorp arranged this discussion on CO2 regulatory risk in fulfillment of an MEHC transaction commitment. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment 3. THE PLANNING ENVIRONMENT Thep~B'eofriewgeneration additiollshasbegunto 'slow, ag~iriinthe west; raisingtl1e questiqtloffuturer~sburce adequacy in certauliareas.'fheWestern Electricity (joordi..: . natil1g:QOl,1rlci1'2QO6 !?()wetSl,1pply" Assessmenf;,iIlgi8ates that,the,Rockies ,s1Jbcregio#, , willsl1ow,aresbufC~'4ef1(;ifbYtOrp:' , '" ," . (jbapterHighlights . Fo nbwiqg;'fti1ilIiptecedel1ted,iriCre~s~in Ilatuf~bg~sc;ornmbdityescalation an~. ;Yolatil- , . ity"f ()r~Fasters~~p~c~'8ljnedi u1Il-t~nn, ,;tempo.iaryd.rop ;;iri .'natllra1'gas 'coml1l0dity"p~ce~J " due to li~uef1~a:#~ti.I:rargas (L~(j)' facility '.expansion.Pricellncertaintyw,ill cbntihlle " . b;ecallse 'greater~'N(j itnpOrtswi1lstiengtherit1ielitlk~ge. to "; volatile ' . globalgas.alldien- , ergy 111arkets. Iliconjlli).ctip11. 9urcep~alJ.t:iing efforts Pacifi (Jorphas ' agreenhou~~gas,riiitiga- , t~()n.stt:at~gyt ' ' . esalmbi:fSWorkinggroup to consider efnissionieductioilhest practices;icc#'~b#tli()~ide~cenarioanalysisf6itheIRP ,and. procurementprpgrams, n~- newabl~.~;;..~ncl';.Heia.lii41.side,mai1agement resource acquisition plans, arid ;.emissioris;;.ac: cbuntilig:: " , ' . . , . TransrIlis~i()hconstrairi.ts ' a11dtp~,~bili ty tpadclressthem. inatiniel yfna1lI1er represel1t important: plarinirigconsiderati oils lor ensuring thatpe(ik .;load obligatiorls are "met ORa ' reliable.ba.sis.Yario-ps regionaltra.nsmission p la1lI1ing 'processes in theWesternIl1ter~ , connection ' have,deye10pedoyerthe lastseveraljrears~oserve'as thepnmaryforu111s wheremajof trans.mis~ion ,projects , '" aredevelppedal1dcoordinated. PacifiCorpisen-: gaged in anumbeipfth.ese planning initiatives. + The Bnergy Policy 1\ct bf2005, theftrstmajor,eriergy law enacted in more than a, dec- ade'includesnulI1eiotiSprovisionsimpacting electric utilities.Keyprovisiorisinclride thc'pmmbtion pfClean coal techllologyandrenewable energy, the encouragement of morehydroelec$c'productibn through streamlined re1icensing "procedures and in,;, creaseq effibiency, the use of time1.based metering options and the provision of manda- tory reliability standards. . q PaciftQOtp'sp\anhiliigprocess is impacted by (l)rapid evolution of state~specific sourcepblic;iesth~tplace , , or are expected top lace ~onstraints onPacifi Corp's resource . selectiotlt.ieCisiOri~,';arid(2) disparate state interests that complicate.the company s aDil.,. ity t()addressst~ttfIRPrequiremelltsto the satisfaCtion of all stakeholders. q . PacifiCorp 2007 IRP Chapter 3 - The Planning Environment INTRODUCTION This chapter profiles the major external influences that impact PacifiCorp s long-term resource planning as well as recent procurement activities driven by the company s past IRPs. External influences are comprised of events and trends in the power industry marketplace, along with government policy and regulatory initiatives that influence the environment in which PacifiCorp operates. Concerning the power industry marketplace, the major issues addressed include capacity re- source adequacy and associated standards for the Western Electricity Coordinating Council (WECC) and the prospects for long-term natural gas commodity price escalation and continued high volatility. As discussed elsewhere in the IRP, future natural gas prices and the role of gas- fired generation and market purchases are some of the critical factors impacting the determina- tion of the preferred portfolio that best balances low-cost and low-risk planning objectives. On the government policy and regulatory front, the largest emerging issue facing PacifiCorp is how to plan given an eventual, but highly uncertain, climate change regulatory regime. While this chapter reviews the significant policy developments for currently-regulated pollutants, it focuses on climate change regulatory initiatives, particularly at the state level. A high-level summary of the company s greenhouse gas emissions mitigation strategy follows. Other regula- tory topics covered include state renewable portfolio standards, hydropower relicensing, and major relevant provisions of the Energy Policy Act of 2005; namely, those pertaining to clean coal technologies, renewable energy, demand response programs and advanced metering, fossil fuel generation efficiency standards, and transmission reliability. MARKETPLACE AND.FUNDAMENTALS PacifiCorp s system does not operate in an isolated vacuum. Operations and costs are tied to a larger electric system known as the Western Interconnection which functions, on a day-to-day basis, as a geographically dispersed marketplace. Each month, millions of megawatt-hours of energy are traded in the wholesale electricity marketplace of the Western Interconnection. These transactions yield economic efficiency by assuring that resources with the lowest operating cost are serving demand in a region and by providing reliability benefits that arise from a larger port- folio of resources. PacifiCorp has historically participated in the wholesale marketplace in this fashion, making pur- chases and sales to keep its supply portfolio in balance with customers' constantly varying needs. This interaction with the market takes place on terms and time scales ranging from hourly to years in advance. Without it, PacifiCorp or any other load serving entity would need to construct or own an unnecessarily large margin of supplies that would go unutilized in all but unusual cir- cumstances and would substantially diminish its capability to efficiently match delivery patterns to the profile of customer demand. The market is not without its risks, as the experiences of the 2000-2001 market crisis and several more recent but briefer periods of price escalation in the west have underscored. Marketplace risks have been amplified in recent years by the growing role of natural gas fired generation in the Western Interconnection that have tied electricity mar- ket prices increasingly to natural gas commodity prices. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Electricity Markets Two overriding issues will tend to influence western electricity markets over the term of this plan s decision horizon. One of those is the evolution of natural gas prices, which is discussed in the next section. The other is the overall balance of generating resources in the Western Inter- connection in relation to demand. A slow pace of generating resource additions during the 1990s and robust growth in demand across the West were the main ingredients that set up the market crises of 2000-2001 , although there were many other well documented contributing factors. Since that crisis , a wave of new capacity additions and demand side actions have righted the resource imbalance and restored aggregate planning and operating reserve margins. However, the pace of new generation addi- tions has begun to slow again, raising the question of future resource adequacy and associated marketplace turmoil. The WECC currently reports adequate reserve margins for the Western Interconnection in aggre- gate, based on existing resources. Currently, the Western Interconnection maintains an adequate margin of generation over projected demand through 2011 with the existing resource base and new generation projects currently under construction or in advanced development. However Southern California, the desert southwest and the Rocky Mountain sub-regions show narrower projected margins and are more vulnerable to resource shortfalls or unexpected demand growth spurts, with the potential to propagate market upsets. Indeed, widespread and extremely hot tem- peratures in summer 2006 tested resource adequacy and caused a period of elevated market prices and a few instances of supply inadequacy near misses. The pace and location of future resource additions have the potential to balance supply and de- mand adequately, but could also significantly undershoot or overshoot demand growth. Major transmission additions could also contribute to overall supply adequacy, but these have generally lagged generation additions and demand growth in the Western Interconnection., Underlying these issues is the unresolved question of resource adequacy and responsibility throughout the Western Interconnection. The WECC does not have a regional planning reserve requirement. Without a system-wide binding standard for resource adequacy and responsibility with a multi-year horizon consistent with the multi-year time frame for most resource additions there is elevated risk that the WECC or some of its sub-regions will experience demand growth in excess of supplies. Uncertainty in magnitude of demand and uncertainty in availability of resources compound the resource adequacy issue. Resource uncertainty is especially important in the Northwest, where hydro accounts for more than half of installed capacity and the average energy availability from hydro can vary substantially from year to year. The current WECC 2006 Power Supply Assessment analyzes resource adequacy for a number of possible future conditions for sub-regions of the Western Interconnection. Under base summer conditions, this assessment indicates that three of the WECC's sub-regions (Southern California the desert southwest and Rockies) show resource deficits by 2010. More adverse conditions ac- celerate the deficits for these sub-regions to 2008. These results suggest that, even for utilities or PacifiCorp 2007 IRP Chapter 3 - The Planning Environment sub-regions that maintain adequate reserve margins, there is an elevated risk of periods of expo- sure to high and volatile market prices, and that these risks must be carefully examined in re- source plans. Natural Gas Supply and Demand Issues Over the last four years North American natural gas markets have demonstrated unprecedented price escalation and volatility. Spot gas prices averaged $3.34/MMBtu at the Henry Hub benchmark in 2002 but more than doubled by 2005, averaging $8.80/MMBtu. Several factors have contributed to these market conditions and their interaction will playa ma- jor role in setting natural gas prices over the medium-term future. In particular, domestic United States production has reached a plateau, with growth from the Rocky Mountain region and from unconventional resources largely offset by declining volumes from conventional mature produc- ing regions. The higher finding and development costs of unconventional resources have also raised the price level necessary to stimulate such marginal supply growth. On the demand side substantial growth of gas-fired generating resources has more than offset declines in industrial demand for natural gas. This shift has reduced the amount of industrial demand that is most price-elastic and increased inelastic generation demand. Substantial oil price escalation over this same time period has also supported higher natural gas prices, lifting the price of marginally competitive gas substitutes and the value of natural gas liquids. Combined, the above factors created a pronounced supply/demand imbalance in North American markets, raising prices sufficiently high to discourage marginal demand and to attract imports from an equally tight global market. This imbalance also made North American markets more susceptible to upset from weather and other event shocks and tied them more directly to global gas and energy markets. Most forecasters expect a gradual restoration of better supply/demand balance to North Ameri- can markets over the next five years, and this profile is reflected in New York Mercantile Ex- change (NYMEX) futures prices. The primary factor contributing to the forecasted price decline is a substantial growth in liquefied natural gas imports over this period. For example, the u.S. Energy Information Administration s Annual Energy Outlook projects 2010 liquefied natural gas (LNG) imports to grow by 300% over 2005 levels. This growth in LNG imports will be supported by rapid expansion of LNG regasification capac- ity that is well underway in North America, but will still take several years to reach fruition. It also requires parallel growth in capital-intensive liquefaction capacity in major producing re- gions, which is also underway, and sufficient LNG shipping capacity, which is currently over- built. North American regasification capacity is now forecasted to be more than adequate within five years, and has the potential to substantially overshoot demand for these facilities early in the next decade. On the other hand, recent delays and cost escalation in major liquefaction facilities has added some uncertainty to the forecasted downward price pressure. The momentum behind LNG growth explains the medium-term trend of declining natural gas prices seen in both forward prices, such as natural gas futures prices on the New York Mercantile Exchange, and in forecasts of prices such as the Department of Energy s Annual Energy Outlook PacifiCorp 2007 IRP Chapter 3 - The Planning Environment and other proprietary forecasts. Besides the downward price trend, the growth in reliance on LNG has other implications for North American natural gas markets. With a larger fraction of North American supply coming from LNG, a stronger linkage to global gas and energy markets is solidified. How this translates to U.S. gas price volatility is by no means clear, as the contract- ing structure and terms and role of LNG spot cargos in global LNG markets is evolving. Re- cently, delays in commercial arrangements for Alaska North Slope natural gas pipeline develop- ment have escalated the potential for LNG market share gains to indefinitely delay Alaska North Slope and Mackenzie Delta arctic frontier sources, although these are not now expected to con- tribute to supplies before 2015 and 2011 , respectively, in any case. Several factors besides potential LNG supply delays contribute to a wide range of price uncer- tainty over the next five years, including constraints on U.S. production infrastructure, linkages to oil prices, and supply and demand elasticities. PacifiCorp relies on PIRA Energy s Scenario Service, which describes and quantifies a range of forecasts, as a measure of future natural gas price uncertainty. Over time PIRA's natural gas scenarios have depicted a widening range of price uncertainty. Given the range of uncertainty over future natural gas prices, it is prudent to recognize possible high and low gas prices as well as the most likely prices. PacifiCorp lays out such cases in Chap- ter 5, describing low, medium, and high scenarios for both gas and wholesale electricity prices. In addition, the IRP has adopted a probability-weighted or expected value forecast case, shown in Appendix A, which is higher than the reference or most likely forecast case, implying risk asymmetry towards the up-side. Western regional natural gas markets are likely to remain well-connected to overall North American natural gas prices for the medium term outlook. Although Rocky Mountain region production is forecasted to be among the fastest growing in North America, major pipeline ex- pansions to the mid-west and east are slated for the next five years and these should maintain market price correlations between Cheyenne/Opal and Henry Hub. A number of west coast LNG regasification facilities have been proposed, and one in Ensenada, Mexico, is under construction and expected to begin operation in 2008. Of the other facilities proposed for the west coast there is relatively low probability that more than one will reach completion over the next five years. In any case, the presence of west coast LNG regasification facilities is not likely to cause large or abrupt disruptions in the relationship between western regional prices and overall North American natural gas prices. FUTURE EMISSION COMPLIANCE ISSUES Over the next decade, PacifiCorp faces a changing environment with regard to electricity plant emission regulations. Although the exact nature of these changes remains uncertain, they are expected to impact the cost of future resource alternatives and the cost of existing resources in PacifiCorp s generation portfolio. No greater uncertainty exists in this area than the potential for global climate change and policy actions to control carbon dioxide, the principal emission asso- ciated with climate change. The section below briefly summarizes issues surrounding currently PacifiCorp 2007 IRP Chapter 3 - The Planning Environment regulated air emissions. The potential for future regulation of CO2 emissions due to climate change concerns and PacifiCorp s climate change strategy are then discussed in detail. Currently Re2ulated Emissions Currently, PacifiCorp s generation units must comply with the federal Clean Air Act (CAA) which is implemented by the States subject to Environmental Protection Agency (EPA) approval and oversight. The Clean Air Act directs EP A to establish air quality standards to protect public health and the environment. PacifiCorp s plants must comply with air permit requirements de- signed to ensure attainment of air quality standards as well as the new source review (NSR) pro- visions of the CAA. NSR requires existing sources to obtain a permit for physical and opera- tional changes accompanied by a significant increase in emissions. Within the current federal political environment there exists a contentious debate over establish- ing a new energy policy and revising the CAA in order to reduce overall emissions from the combustion of fossil fuels. Currently, the debate focuses on emission standards and compliance measures for sulfur dioxide (SO2), nitrogen oxides (NOx), mercury (Hg), particulate matter (PM), and regulation of carbon dioxide emissions. Several proposals to amend the Clean Air Act to limit air pollution emissions from the electric industry are being discussed at the national level. Specifically, a number of alternative proposals for federal multi-pollutant legislation would require significant reductions in emissions of SO2, and NOx, and establish new definitive stan- dards for mercury. Some proposals also contain measures to limit CO2 and to revise certain other regulatory requirements such as NSR. Within existing law, EPA's Regional Haze Rule and the related efforts of the Western Regional Air Partnership will require emissions reductions to improve visibility in scenic areas. Addition- ally, newly proposed administrative rulemakings by EPA, including the Clean Air Interstate Rule and the Clean Air Mercury Rule will require significant reductions in emissions from electrical generating units. The outcome of the current debate, manifested in new legislation or rulemak- ings, will shape PacifiCorp s emission requirements over the coming decade. Compliance costs associated with anticipated future emissions reductions will largely depend on the levels of re- quired reductions, the allowed compliance mechanisms, and the compliance time frame. PacifiCorp is committed to responding to environmental concerns and investing in higher levels of protection for its coal-fired plants. PacifiCorp and MEHC anticipate spending $1.2 billion over the next ten years to install necessary equipment under future emissions control scenarios to the extent that it's cost-effective. The company has started its clean air projects, such as the in- stallation of a baghouse, flue gas desulfurization and low nitrogen-oxide burners at the Hunting- ton 2 plant. Climate Chan2e Climate change has emerged as an issue that requires attention from the energy sector, including utilities. Because of its contribution to United States and' global carbon dioxide emissions , the S. electricity industry is expected to playa critical role in reducing greenhouse gas emissions. In addition, the electricity industry is composed of large stationary sources of emissions that are thought to be often easier and more cost-effective to control than from numerous smaller sources. PacifiCorp and parent company MidAmerican Energy Holdings Company recognize PacifiCorp 2007 IRP Chapter 3 - The Planning Environment these issues and have taken voluntary actions to reduce their respective CO2 emission rates. PacifiCorp s efforts to achieve this goal include adding zero-emitting renewable resources to its generation portfolio such as wind, landfill gas, combined heat and power (CHP) and investing in on-system and customer-based energy efficiency and conservation programs. PacifiCorp also continues to examine risk associated with future CO2 emissions costs. The section below summa- rizes issues surrounding climate change policies. Impacts and Sources As far as sources of emissions are concerned, according to the u.s. Energy Information Admini- stration, CO2 emissions from the combustion of fossil fuels are proportional to fuel consumption. Among fossil fuel types, coal has the highest carbon content, natural gas the lowest, and petro- leum in-between. In the Administration Annual Energy Outlook 2006 reference case, the shares of these fuels change slightly from 2004 to 2030, with more coal and less petroleum and natural gas. The combined share of carbon-neutral renewable and nuclear energy is stable from 2004 to 2030 at 14 percent. As a result, CO2 emissions increase by a moderate average of 1.2 percent per year over the period - 5 900 million metric tons in 2004 to 8 114 million metric tons by 2030 slightly higher than the average annual increase in total energy use. At the same time, the econ- omy becomes less carbon intensive: the percentage increase in CO2 emissions is one-third the increase in GDP, and emissions per capita increase by only 11 percent over the 26-year period. According to the Administration Annual Energy Outlook 2006 report, the factors that influence growth in CO2 emissions are the same as those that drive increases in energy demand. Among the most significant are population growth; increased penetration of computers, electronics, ap- pliances, and office equipment; increases in commercial floor space; growth in industrial output; increases in highway, rail, and air travel; and continued reliance on coal and natural gas for elec- tric power generation. The increases in demand for energy services are partially offset by effi- ciency improvements and shifts toward less energy-intensive industries. New CO2 mitigation programs, more rapid improvements in technology, or more rapid adoption of voluntary pro- grams could result in lower CO2 emissions levels than projected here. PacifiCorp carefully tracks CO2 emissions from operations and reports them in its annual emis- sions filing with the California Climate Action Registry. International and Federal Policies Numerous policy activities have taken place and continue to develop. At the global level, most of the world's leading greenhouse gas (GHG) emitters, including the European Union (EU), Japan China, and Canada, have ratified the Kyoto Protocol. The Protocol sets an absolute cap on GHG emissions from industrialized nations from 2008 to 2012 at 7% below 1990 levels. The Protocol calls for both on-system and off-system emissions reductions. While the U.S. has thus far re- jected the Kyoto Protocol, numerous proposals to reduce greenhouse gas emissions have been offered at the federal level. The proposals differ in their stringency and choice of policy tools. The Bush Administration has proposed an 18% voluntary carbon intensity reduction target, i. emissions per unit of economic output. Such an approach could translate into a tons/MWh ap- proach in the electricity sector. Democratic victories on November 7 , 2006 in the House and Senate appear likely to boost efforts to strengthen U.S. global warming policy, but it is far from certain whether the 110th Congress PacifiCorp 2007 IRP Chapter 3 - The Planning Environment and President Bush will work together over the coming two years to enact a first-ever federal law to cap greenhouse gas emissions. With Democrats taking over the House and the Senate in January, experts and lawmakers alike expect an emboldened legislative branch to advance an entirely new of set environment and en- ergy proposals unlike anything seen during President Bush's previous six years in the White House. The Senate Environment and Public Works Committee, chaired by Senator Barbara Boxer (D-CA), has committed to having a set of intensive hearings on the issue of global wann- ing during 2007. On January 5 , 2007, Senator Bingaman (D-NM) circulated a discussion draft which identifies his current proposal for mandatory greenhouse gas reduction legislation. On January 12, 2007, Sena- tors Lieberman (I-CT) and McCain (R-AZ) reintroduced their proposed federal carbon legisla- tion.s Senate legislation has also been released by Senators Sanders (I-VT) and Boxer (D-CA)6 and Senators Feinstein (D-CA) and Carper (R-DE). On January 18, 2007, House Speaker Pelosi (D-CA) announced the formation of a new Select Committee on Energy Independence and Global Warming. The panel will draw on members from as many as nine existing panels that already have authority over the issue. Rep. Ed Markey (D-Mass.) is expected to lead the new committee, which will only be commissioned for the 110th Congress. The speaker also expressed her intent to have legislation through the committees by July 4, 2007. Regional Initiatives Western regional state initiatives were significant in 2006. The most notable developments have been the Western Public Utility Commissions' Joint Action Framework on Climate Change and the Western Regional Climate Action Initiative. On December 1 , 2006, California utility regulators and their counterparts in New Mexico, Ore- gon and Washington pledged to coordinate efforts to limit greenhouse gas emissions. The regula- tors in those four states will work together to address climate change, from promoting energy efficiency to encouraging the use of clean energy. The respective heads of the California Public Utilities Commission, the Washington Utilities and Transportation Commission, the Oregon Public Utility Commission, and the New Mexico Regulation Commission signed the agreement. The Joint Action Framework on Climate Change outlines a commitment to regional cooperation to address climate change. On February 26, 2007, during the annual winter meeting of the National Governors Association Governors Arnold Schwarzenegger (California), Janet Napolitano (Arizona), Bill Richardson (New Mexico), Ted Kulongoski (Oregon) and Christine Gregoire (Washington) signed the West- ern Regional Climate Action Initiative8 that directs their respective states to develop a regional target for reducing greenhouse gases by August 2007. By August 2008, they are expected to de- 5 S.280, the "Climate Stewardship and Innovation Act of200T' 6 S.309, the "Global Warming Pollution Reduction Act" 7 S.319, the "Electric Utility Cap and Trade Act of 2007" 8 See http;l/gov.ca.gov!mp3/press!O22607 WesternClimateAgreementFinaLpdf PacifiCorp 2007 IRP Chapter 3 - The Planning Environment vise a market-based program, such as a load-based cap-and-trade program to reach the target. The five states also have agreed to participate in a multi-state registry to track and manage greenhouse gas emissions in their region. The Initiative builds on existing greenhouse gas reduc- tion efforts in the individual states as well as two existing regional efforts. In 2003 , California Oregon and Washington created the West Coast Global Warming Initiative, and in 2006, Ari- zona and New Mexico launched the Southwest Climate Change Initiative. In response to limited federal activity, state policy has grown in prominence. While some states have adopted policies that address power plant emissions directly by either capping emissions or setting an emissions rate limit (such as the Northeastern Regional Greenhouse Gas Initiative), other states have sought to reduce carbon emissions through resource selection either by adopt- ing renewable portfolio standards or requiring utilities to consider potential carbon costs within their integrated resource planning. Within PacifiCorp s service territory, only California has adopted specific legislation directly regulating utility greenhouse gas emissions. Washington and Oregon are expected to consider and possibly adopt climate legislation modeled after the Cali- fornia legislation during the 2007 legislative session. Wyoming has its Carbon Committee and Utah's Governor recently convened a climate council to discuss the state climate policies. Cali- fornia s greenhouse gas emissions policies are profiled below. State Initiatives California Emissions Performance Standard (SB1368) California Senate Bill 1368 (SB 1368), signed into law on September 29, 2006, is an emissions performance standard law designed to effectuate a rulemaking at the California Public Utilities Commission, Docket No. R.06-04-009 , and grants authority to the California Energy Commis- sion to promulgate a similar emissions performance standard for publicly-owned utilities. PacifiCorp has been an active participant within the Commission docket. SB 1368 establishes a greenhouse gas emissions performance standard that prohibits any load serving entity, including electrical corporations, community choice aggregators, electric service providers, and local pub- licly owned electric utilities, from entering into a long-term financial commitment unless base load generation complies with a greenhouse gases emission performance standard not exceed the rate of emissions of a combined-cycle natural gas facility. A long-term financial commitment is defined as a new ownership investment in base load gen- eration or a new or renewed contract with a term of five or more years, which includes procure- ment of base load generation. Base load generation includes electricity generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent. SB 1368 precludes the California Public Utilities Commission and the California Energy Com- mission from approving the construction of or contract for base load generation that does not meet the greenhouse gas emissions performance standard. Costs incurred for electricity purchase agreements that are approved by the Public Utilities Commission that comply with the green- house gas emission performance standard are recognized as procurement costs incurred pursuant 9 The California PUC final Emissions Perfonnance Standard Staff Workshop Report, which includes the latest staff straw proposal, is posted on the PUC website at: www.cpuc.ca.govistatic!energyielectric/climate+change.The direct link to the Report is W\Vw.cpuc.ca,gov/published/REPORT/60350.htm. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment to an approved procurement plan and the Public Utilities Commission is required to ensure timely cost recovery of those costs. Long-term financial commitments entered into through a contract approved by the Public Utilities Commission for electricity generated by a zero- or low- carbon generating resourcelO that is contracted for on behalf of consumers in California on a cost-of-service basis is recoverable in rates, and the Public Utilities Commission may, after hear- ing, approve an increase from one-half to one percent in the return on investment by the third party entering into the contract with an electrical corporation relating to its investment in zero- orlow-carbon generation resources. On January 25, 2007, the California Public Utilities Commission approved the decision of Presi- dent Peevey and Administrative Law Judge Gottstein in Rulemaking 06-06-009 , " Order Insti- tuting Rulemaking to Implement the Commission s Procurement Incentive Framework and to examine the Integration of Greenhouse Gas Emissions Standards into Procurement Policies The decision adopts an emissions performance standard of 1 100 pounds per megawatt-hour for new long-term base load (60%) financial commitments. The term "long-term financial commit- ments , will also include new financial investments by utilities in their own existing base load generation that extends the life of a plant by five years or more. The Commission also adopted an interpretation of ~~ 8341(d)(2) and (5) and clarified that it will determine compliance with the standard based on the reasonably projected net emissions over the life of a facility, but in calculating the net emissions rate, the Commission will not count carbon dioxide that is sequestered through injection in geological formations. This allows for a seques- tration project to become operational after the power plant comes on line or the load serving en- tity enters into the contract. PacifiCorp had argued for such an interpretation as a means of al- lowing advanced coal projects to demonstrate compliance with the greenhouse gas emissions performance standard even though their carbon sequestering equipment may not be operational during the first few years of a project. Regarding ~ 8341 (d)(9)' s multi-jurisdictional utility qualification requirements for alternative compliance, the Commission adopted the tests proposed by PacifiCorp. In fact, the Commission went further and concluded that the information provided by PacifiCorp during the rulemaking process and the Oregon Public Utilities Commission s January 8 , 2007 Order #07-002 , which establishes a proceeding to examine carbon dioxide risk associated with resource decisions, were sufficient for the Commission to conclude that PacifiCorp meets the alternative compliance re- quirements. As a result, PacifiCorp is not obligated to submit an alternative compliance applica- tion and is only required to file an annual attestation advice letter affirming that it still satisfies the alternative compliance requirements by February 1 of each year, beginning in 2008. The California Energy Commission must adopt regulations for municipal utilities consistent with the Public Utilities Commission rules by June 30, 2007.13 Enforcement of the emission perform- 10 Zero- or low-carbon generating resource is defined as an electrical generating resource that will generate electric" ity while producing emissions of greenhouse gases at a rate substantially below the greenhouse gas emission per- formance standards, as determined by the PUC. 11 See hUp:/iwww.cDuc.ca.gov/PUBLISHEDiAGENDA DECISION!63931.htm 12 See hap :I! aDDS. Duc.stat e.or. us! edockets! orders .asp? ordernumber=07 -00213 SB1368 supra note 42. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment ance standard begins immediately upon the establishment of the standard. Existing combined- cycle power plants that are in operation, or have a California Energy Commission final permit decision to operate as of June 30, 2007, are grandfathered under the bill and deemed to be in compliance with the greenhouse gas emission performance standard. California Global Warming Solutions Act of 2006 (AB32) On September 27, 2006, California Governor Arnold Schwarzenegger signed into law Assembly Bill 32 (AB 32), known as the California Global Warming Solutions Act of 2006. California has since become the focus of climate change policy due to its massive economy, the fact that it is the 1 th largest emitter of greenhouse gases in the world, and has had a history of catalyzing the formation of national environmental policy and regulation. The bill itself is fairly performance-oriented and could result in a comprehensive, and thus effec- tive, greenhouse gas mitigation strategy beyond the traditional focus solely on utilities. Under the legislation, greenhouse gas emissions would be reduced to 1990 levels by 2020 (a 25% reduc- tion) and further reduced to 80% below 1990 levels by 2050. In determining and measuring these levels, the protocols of the California Climate Action Registry are to be incorporated to the maximum extent feasible. AB 32 also sets forth the following milestones for the California Air Resources Board: By July 1, 2007, the Air Resources Board forms Environmental Justice and Economic Technology Advancement advisory committees. By July 1 , 2007, the Air Resources Board adopts list of discrete early action measures that can be adopted and implemented before January 1 2010. By January 1, 2008, the Air Resources Board adopts regulations for mandatory greenhouse gas emissions reporting. The Air Resources Board defines a 1990 emissions baseline for California (including emissions from imported power) and adopts that as the 2020 statewide cap. By January 1, 2009 , the Air Resources Board adopts plan indicating how emission reduc- tions will be achieved from significant sources of greenhouse gas emissions via regulations market mechanisms and other actions. During 2009, the Air Resources Board staff drafts rule language to implement its plan and holds a series of public workshop on each measure (including market mechanisms). By January 1, 2010, early action measures take effect. During 2010 , the Air Resources Board conducts series of rulemakings, after workshops and public hearings, to adopt greenhouse gas regulations including rules governing market mechanisms. By January 1, 2011, the Air Resources Board completes major rulemakings for reducing GHGs including market mechanisms. The Air Resources Board may revise the rules and adopt new ones after January 1 2011 in furtherance of the 2020 cap. By January 1 2012, greenhouse gas rules and market mechanisms adopted by the Air Re- sources Board take effect and are legally enforceable. (Note: This deadline dovetails well with the post-2012 Kyoto Protocol negotiations. December 31, 2020, is the deadline for achieving the 2020 greenhouse gas emissions cap enforced by the Air Resources Board. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Furthermore, prior to creating enforceable mandates or market mechanisms (i.e. cap-and-trade programs), AB 32 specifies that the Air Resources Board must evaluate at least the following factors: Impacts on California s economy, the environment, and public health Equity between regulated entities Electricity reliability, Confonnance with other environmental laws, and To ensure that the rules do not disproportionately impact low-income communities. Although AB 32 does not specify a specific market-based policy tool to address greenhouse gas emissions, Governor Schwarzenegger has steered the state regulatory agencies in the direction of an international cap-and-trade type program by issuing a new executive order related to AB 32 in October 2006. The executive order14 specifies that: The California Secretary for Environmental Protection shall create a Market Advisory Com- mittee of national and international experts to make recommendations to the State Air Re- sources Board on or before June 30, 2007, on the design of a market-based compliance pro-gram. The Air Resources Board shall collaborate with the California Secretary for Environmental Protection and the Climate Action Team to develop a comprehensive market-based compli- ance program with the goal of creating a program that permits trading with the European Un- ion, the Regional Greenhouse Gas Initiative and other jurisdictions. The executive order appears to be well in line with the text of AB 32 and cites "numerous stud- ies" by institutions such as U.C. Berkeley, Stanford, and the Pew Center on Global Climate Change that indicate that market-based policy mechanisms, such as emissions trading, are the most efficient and effective policy tools to address climate change. California Governor Schwarzenegger has already met with New York Governor Pataki to discuss ways that the California market mechanism for climate change can potentially tie in with the Regional Greenhouse Gas Initiative s market-based cap and trade system. Nonetheless, the ex- tent to which these two systems can be integrated remains to be seen. In light of the passage of AB 32, on November 1 2006 the California Public Utilities Commis- sion indicated via an administrative law judge s ruling that they will develop a model rule to effectuate a state-wide load-based greenhouse gas cap-and-trade program for the electricity sec- tor. The rulemaking will be undertaken as part of the Commission s existing Docket No. R.06- 04-009.15 PacifiCorp has been an active participant within this docket. 14 http://gov,ca.gov!index.php?/press-release/444 7 /15 The California PUC final Emissions Performance Standard Staff Workshop Report, which includes the latest staff straw proposal, is posted on the PUC website at: www.cPl1c.ca.gov/static/ellergy!electric/climate+change. The direct link to the Report is \Vww.cpuc.ca.gov!published!REPORT/60350.htm PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Washington s Act Mitigating the Impacts of Climate Change 2007 (SB6001) Washington Governor Christine Gregoire on May 3, 2007 signed Senate Bill 6001 , which con- tains provisions aimed at reducing the state s greenhouse gas (GHG) emissions. First, the Act established the following goals for statewide GHG emissions: by 2020, reduce emissions to 1990 levels; by 2035, reduce emissions to 25 percent below 1990 levels; and by 2050, reduce emissions to 50 percent below 1990 levels, or 70 percent below the state s expected emissions that year. It then established en employment goal that by 2020, increase the number of clean energy sector jobs to 25 000 from the 8,400 jobs the state had in 2004. The bill also requires by December 31 , 2007 , Department of Energy (DOE) and Department of Community, Trade & Economic Development (CTED) must report to the appropriate commit- tees of the Legislature the total GHG emissions for 1990, and totals in each major sector for 1990. By December 31 of each even-numbered year beginning in 2010, DOE and CTED must report to the Governor and the Legislature the total GHG emissions for the preceding two years and totals in each major source sector. The Governor is also directed to develop policy recommendations on how the state can achieve the specified GHG emissions reduction goals. The recommendations must include such issues as how market mechanisms would assist in achieving the goals. The recommendations must be submitted to the Legislature during the 2008 Legislative Session. The bill also establishes a GHG Emissions Performance Standard (EPS). Beginning July 1 2008 the GHG emissions performance standard for all baseload electric generation for which electric utilities enter into long-term financial commitments on or after such date is the lower of: , I 00 pounds of GHG per megawatt-hour; or the average available GHG emissions output as updated by CTED. In general, all baseload electric generation that begins operation after June 30, 2008 , and is lo- cated in Washington, must comply with the performance standard. The following facilities are deemed to be in compliance with the performance standard: all baseload electric generation facilities in operation as of June 30, 2008, until they are the subject of long-term financial commitments; all electric generation facilities or power plants powered exclusively by renewable re- sources; and all cogeneration facilities in the state that are fueled by natural gas or waste gas in opera- tion as of June 30, 2008 , until they are the subject of a new ownership interest or are up- graded. The following emissions produced by baseload electric generation do not count against the per- formance standard: emissions that are injected permanently in geological formations; PacifiCorp 2007 IRP Chapter 3 - The Planning Environment emissions that are permanently sequestered by other means approved by DOE; and emissions sequestered or mitigated under a plan approved by the EFSEC, as specified in the act. Unlike California s EPS, the Washington proposal offers some potential emissions mitigation options to allow energy from new coal plants to be used in the state. These provisions allow coal power as long as operators reduce emissions from other sources to meet the EPS. For example, a new base-load coal plant has up to five years after commencing operation to initiate a CO2 cap- ture-and-sequestration process to meet the law. If the technology is not available at that time, the plant owner has options to mitigate the CO2 emissions to meet the EPS and stay in the Washing- ton energy market. For example, a plant owner can purchase "verifiable GHG emission reduc- tions" from another power plant located within the Western Interconnection that would not have occurred otherwise. Coal plant operators could also purchase CO2-emitting power generators with the intent to shut them down, and use the avoided CO2 emissions as offsets to meet the EPS for a new power plant project. By June 30, 2008, DOE and Washington State Energy Facility Site Evaluation Council (EFSEC) must coordinate and adopt rules to implement and enforce the GHG emissions performance standard, including the evaluation of sequestration and mitigation plans. In addition, CTED must consult with specified groups, such as the Bonneville Power Administration, and consider the effects of the standard on system reliability and the overall costs to electricity customers. In order to update the standard, CTED must conduct a survey every five years of new combined- cycle natural gas thermal electric generation turbines commercially available and offered for sale by manufacturers and purchased in the United States. CTED must use the survey results to adopt by rule the average available GHG emissions output. The survey results must be reported to the Legislature every five years, beginning June 30, 2013. Electric utilities may not enter into long-term financial commitments for baseload electric gen- eration unless the generation complies with the performance standard. For an investor-owned utility (IOU), the Washington Utilities and Transportation Commission (WUTC) must review a long-term financial commitment in a general rate case. The WUTC must also review an IOU's proposed decision to acquire electric generation or enter into a power purchase agreement for electricity, upon application of the utility. The process for reviewing proposed decisions must be specified in rule and conducted under the Administrative Procedures Act. The WUTC must con- sult with DOE when verifying compliance with the performance standard. The WUTC must adopt all implementing rules by December 31 , 2008. The WUTC may exempt a utility from the performance standard for unanticipated electric system reliability needs, catastrophic events, or threat of significant financial harm arising from unforeseen circumstances. DOE, in consultation with CTED, EFSEC, the WUTC, and the governing boards of consumer- owned utilities, must review the GHG emissions performance standard no less than every five years or upon the implementation of a federal or state law or rule regulating CO2 emissions of electric utilities, and report to the Legislature. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment By December 31 , 2007, the Governor must report to the Legislature the potential benefits of cre- ating tax incentives to encourage base load electric facilities to upgrade their equipment to re- duce CO2 emissions, the nature and level of tax incentives likely to produce the greatest benefits and the cost of providing such incentives. Oregon Examination of Treatment of CO2 Policy Risk within IRP Planning On January 8, 2007, the Oregon Public Utilities Commission issued an order within the Inte- grated Resource Planning docket UM 1056.16 As part of the Order, the Commission announced it was opening an investigation to review the treatment of carbon dioxide risk in Integrated Re- source Plans (per footnote 11 , this will apply to future Requests for Proposals), which will ulti- mately replace the analysis required in Order 93-695. Next, the Commission noted in footnote five that it had committed to explore a carbon dioxide emissions performance standard for long- term power supplies in adopting the Joint Action Framework on Climate Change, and that this investigation would follow the proceeding on carbon dioxide risk in Integrated Resource Plans. On February 8, 2007, the Oregon Public Utilities Commission announced it would begin work under docket UM-1302 17 investigating the treatment of carbon dioxide risk in Integrated Re- source Plans. Corporate Greenhouse Gas Mitigation Strategy PacifiCorp is committed to engage proactively with policymaking focused on GHG emissions issues through a strategy that includes the following elements. Policy - PacifiCorp has established a Global Climate Change Working Group, meant to ex- amine best utility practices for addressing carbon risk. The company has also supported legis- lation that enables GHG reductions while addressing core customer requirements. PacifiCorp will continue to work with regulators, legislators, and other stakeholders to identify viable tools for GHG emissions reductions. Planning - PacifiCorp has incorporated a reasonable range of values for the cost of CO2 in the 2007 IRP in concert with numerous alternative future scenarios to reflect the risk of fu- ture regulations that can affect relative resource costs. Additional voluntary actions to miti- gate greenhouse gas emissions could increase customer rates and represent key public policy decisions that the company will not undertake without prior consultation with regulators and lawmakers at state and federal levels. Procurement - PacifiCorp recognizes the potential for future CO2 costs in requests for pro- posal (RFPs), consistent with its treatment in the IRP. Commercially available carbon- capturing and storage technologies at a utility scale do not exist today. Carbon-capturing technologies are under development for both pulverized coal plant designs and for coal gasi- fication plant designs, but require research to increase their scale for electric utility use. Accounting - PacifiCorp has adopted transparent accounting of GHG emissions by joining the California Climate Action Registry. The Registry applies rigorous accounting standards 16 See http:!/apps.puc.state,or. us/edockets/orders.asP'?ordernumber=07 -002 17 See http://apps.puc.state.or.us/edockets/docketasp'?DocketlD= 13896 PacifiCorp 2007 IRP Chapter 3 - The Planning Environment based in part on those created by the World Business Council on Sustainable Development and the World Resources Institute, to the electric sector. The current strategy is focused on meaningful results, including installed renewables capacity and effective demand-side management programs that directly benefit customers. While these efforts provide multiple benefits of which lower GHG emissions are a part, they are clearly at- tractive within an effective climate strategy and will continue to playa key role in future pro- curement efforts. As part of PacifiCorp s Global Climate Change Working Group effort, a Pre- liminary Global Climate Change Action Plan will be completed by the company in 2007 and filed with the six state utility commissions. Within the Plan, PacifiCorp expects to propose sig- nificant changes to its corporate greenhouse gas mitigation strategy. RENEWABLE PORTFOLIO STANDARDS A renewable portfolio standard (RPS) is a policy that obligates each retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of electricity 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 electricity 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 someone else has generated the required amount of renewable energy. RPS policies are currently implemented at the state level18, and vary considerably in their re- quirements with respect to time frame, resource eligibility, treatment of existing plants, arrange- ments for enforcement and penalties, and whether they allow trading of renewable energy cred- itS.l9 As of late 2006 , 23 states and the District of Columbia had adopted RPS regulations. The most recent adoption occurred in Washington, which passed a ballot measure in November 2006. Two states in PacifiCorp s service territory-California and Washington-now have an RPS in place. Recent RPS legislative and regulatory activities in California, Washington, and Oregon are summarized below. California In 2006 , the California legislature approved, and Governor Schwarzenegger signed into law, a bill that codifies an earlier deadline for reaching the state s renewable energy goals. Existing law had established the RPS program and a goal of 20% of retail electric sales from renewable re- sources by 2017. The new legislation, Senate Bill 107 , accelerates the target date to December 18 Interest in a federal RPS policy is expanding. For example, a bipartisan group of Senators and Representatives have re-introduced the 25x 25 House and Senate Concurrent Resolutions in January 2007 calling for a new national renewable energy supply goal of25% by 2025. 19 See, http://www .eere.energy.gov/states/maps/renewable --'portfolio - states.cfm20 SB 107 as enacted and chaptered is posted on the legislature s web site at: PacifiCorp 2007 IRP Chapter 3 - The Planning Environment 2010. The law now comports with earlier decisions by the California Public Utilities Com- mission that established the "20% by 2010" target. Senate Bill 1 07 requires compliance with the standard by investor-owned utilities, community choice aggregators, and electric service provid- ers. Municipal utilities are exempt, but must meet expanded reporting requirements on their plans and accomplishments in supporting the development and use of renewable resources. Other provisions of the bill authorize the use of renewable energy credits , " flexible compliance" ap- proaches, and program eligibility for renewable power produced outside the state if it is deliv- ered to California locations. Existing law requires the California Energy Commission to certify eligible renewable resources to develop a regional accounting system to verify compliance, and to allocate and award supple- mental energy payments (SEPs) to cover above-market costs of renewables. The bill requires the Energy Commission to recover all costs of the regional accounting system from user fees. The bill also requires the Energy Commission to develop tracking, accounting, verification, and en- forcement mechanisms for renewable energy credits (RECs). Certain renewable resource facili- ties located outside the state can be eligible for SEPs, but awards to those facilities are limited to 10% of total funds available. PacifiCorp filed a proposed compliance plan for meeting the California RPS requirements in 2006. In its filing, PacifiCorp cited its 2001 eligible21 renewable resource generation as approxi- mately 4% of its retail sales in California. PacifiCorp is currently required to deliver 20% of its California load from eligible renewable resources by 2010. It is also worth noting that the Cali- fornia legislature is currently considering legislation that would establish a 33% requirement by 2020. Ore20n At the request of Governor Kulongoski, a number of state agencies were asked to develop a Re- newable Energy Action Plan (REAP) with input from stakeholders. These agencies- Agriculture, PUC, Economic Development, Energy, Environmental Quality, Forestry and Water Resources-prepared several drafts, which were sent to interested individuals, businesses and organizations and posted on the Oregon Department of Energy Web site. Public comment and stakeholder input was taken and a series of public meetings were held before finalizing the document. The final Renewable Energy Action Plan was released in April of2005. The REAP contains numerous renewable energy policy goals for the state and also a mandate to support a Renewable Energy Working Group to be coordinated through the Governor s Office and the Oregon Department of Energy to guide the implementation of this Plan." A long list of actions for state agencies is included in the Plan, as well as numerous tasks for the Renewable Energy Working Group. A Renewable Energy Working Group was formed through a collaborative process involving the Oregon Department of Energy and the Governor s Office. The primary mission of the Renewable Energy Working Group (REWG) was to guide implementation of the Renewable Energy Action http://www.1eginfo.ca.gov/pub/bilVsen/sb O 1 0 1-0 l50/sb _107- bill- 20060926 - chaptered.pdf21 The California RPS stipulated resources eligible for inclusion in meeting the RPS requirement. It should be noted that the only eligible hydro resources are those with capacity less than 30 megawatts. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Plan. Group members were tasked by the Governor to develop a legislative proposal for a RPS that would be 25 percent of retail sales by 2025. The Renewable Energy Working Group s legis- lative proposal was introduced during the 2007 legislative session and is currently under consid- eration. The proposal would establish an RPS with the schedule of at least 5% of load by January 2011 , at least 15% by January 1 2015, at least 20 percent by January 1 2020, and at least 25 percent by January 1 2025. In addition to its renewable energy focus, Oregon s proposed RPS also provides the framework for the further expansion of cost-effective conservation activity in the state by electric utilities. It allows the Commission to authorize an electric company to include in its rates the costs of fund- ing or implementing cost-effective energy conservation measures beyond those currently funded through the state s public purpose charge-established under the state s restructuring legislation in 2002-and delivered by the Energy Trust of Oregon. If approved, Oregon s portfolio stan- dard may allow conservation investments up to the potential conservation opportunity within the state, further adding to the demand-side resources available to address PacifiCorp s demand growth in the state. Washinf!ton In November 2006, Washington voters approved ballot initiative 1-937 , which would establish an RPS with the schedule of at least 3% of load by January 1 , 2012, at least 9% by January 1 2016 , and at least 15% by January 1 , 2020. The annual targets are based on the average of the utility's load for the previous two years. The Washington Utilities and Transportation Commis- sion undertook rulemaking UE-061895 to effectuate the referendum. Federal Renewable Portfolio Standard Congress is expected to take up federal energy policy legislation, including the possibility of a federalRPS, as early as summer 2007. On the House side, Rep. Tom Udall (D-) has intro- duced legislation creating a 20% standard by 2020. Senate Energy and Natural Resources Com- mittee Chairman Jeff Bingaman (D-) has indicated he is planning legislation with a level of 15 percent by 2020. The Senate has approved an RPS several times, most recently as part of the 2005 energy bill, but it died in conference with the House. Even so, environmentalists see the Democratic Congress as an opportunity for a host of initiatives that have failed in recent years. But the fate and timing an RPS in the Energy and Commerce Committee, which has jurisdiction over the issue, is far from clear because a key committee leader and others have been skeptical of the need for an RPS. TRANSMISSION' PLANNING Intef!rated Resource Planninf! Perspective Transmission constraints, and the ability to address them in a timely manner, represent important planning considerations for ensuring that peak load obligations are met on a reliable basis. With 22 See, http://www.secstate. wa.gov/elections/initiatives/text/i93 7.pdf PacifiCorp 2007 IRP Chapter 3 - The Planning Environment this in mind, PacifiCorp s IRP team has increased its coordination with transmission planning personnel to more closely align long-term generation and transmission planning activities. The result for this IRP is a set of transmission resources for portfolio modeling that addresses Pacifi- Corp s control area needs as well as enables a first-cut evaluation of the impacts of a large multi- state transmission project. As discussed in the next section, PacifiCorp is engaged in a number of regional transmission planning initiatives intended to address transmission issues and project opportunities. Future IRP analysis efforts will be informed by these transmission planning initia- tives. Interconnection-Wide Re!!ional Planninl! Various regional planning processes have developed over the last several years in the Western Interconnection. It is expected that, in the future, these processes will be the primary forums where major transmission projects are developed and coordinated. In the Western Interconnec- tion, regional planning has evolved into a two tiered approach where an interconnection-wide entity, Western Electricity Coordinating Council (WECC) conducts regional planning at a very high level and several sub-regional planning groups focus with greater depth on their specific areas. Last year, WECC took on the responsibility for interconnection-wide transmission expansion planning. WECC's role in meeting the region s need for regional economic transmission plan- ning and analyses is to provide impartial and reliable data, public process leadership, and ana- lytical tools and services. The activities of WECC in this area are guided and overseen by a board-level committee, the Transmission Expansion Planning Policy Committee (TEPPC). TEPPC's three main functions include: (1) overseeing database management, (2) providing pol- icy and management of the planning process, and (3) guiding the analyses and modeling for Western Interconnection economic transmission expansion planning. These functions compli- ment but do not replace the responsibilities of WECC members and stakeholders to develop and implement specific expansion projects. TEPPC organizes and steers WECC regional economic transmission planning activities. Spe-cific responsibilities include: steering decisions on key assumptions and the process by which economic transmission expansion planning data are collected, coordinated and validated; approving study plans, including study scope, objectives, priorities, overall meth- ods/approach, deliverables, and schedules; steering decisions on analytical methods and on selecting and implementing production cost and other models found necessary; ensuring the economic transmission expansion planning process is impartial, transparent properly executed and well communicated; ensuring that regional experts and stakeholders participate, including state/provincial en- ergy offices, regulators, resource and transmission developers, load serving entities, envi- ronmental and consumer advocate stakeholders through a stakeholder advisory group; steering report writing and other communications that include communications be- tween the TEPPC and the sub-regional planning groups; advising the WECC Board on policy issues affecting economic transmission expansion planning; PacifiCorp 2007 IRP Chapter 3 - The Planning Environment recommending budgets for WECC's economic transmission expansion planning process; organizing and coordinate activities with sub-regional planning processes; and approving recommendations to improve the economic transmission expansion planning process. TEPPC analyses and studies will focus on plans with west-wide implications and will include a high level assessment of congestion and congestion costs. The analyses and studies will 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 con- gestion, minimizing and stabilizing regional production costs, diversifying fuels, achieving re- newable resource and clean energy goals, or other purposes. Alternatives may draw from state energy plans, integrated resource plans, large regional' expansion proposals, sub-regional plans and studies, and other sources such as individual control areas if relevant in a regional context. TEPPC's role does not include: 1. conducting sub-regional or detailed project-specific studies2. prioritizing and advocating specific economic expansion projects 3. identifying potential "winners" and "losers 4. developing or advocating cost allocations 5. developing or advocating cost allocation criteria 6. providing mechanisms to obtain funding, 7. assigning transmission rights 8. providing backstop permitting or approval authority, or 9. performing reliability analysis outside of what is being done today, TEPPC includes 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 planning processes. Sub-ree:ional Plannine: Groups Recognizing that planning the entire interconnection in one forum is impractical due to the overwhelming scope of the task, a number of smaller sub-regional groups have been formed to address specific problems in various areas of the interconnection. Generally all of these forums provide similar regional planning functions, including the development and coordination of ma- jor transmission plans within their areas. It is these sub-regional forums where the majority of transmission projects are expected to be developed. These forums will be informally coordinated with each other directly through liaisons and through TEPPC. A current list of sub-regional groups is provided below. CCPG - Colorado Coordinated Planning Group CG - Columbia Grid NTAC - Northwest Transmission Assessment Committee NTTG - Northern Tier Transmission Group STEP - Southwest Transmission Expansion Planning SWAT - Southwest Area Transmission Study PacifiCorp 2007 IRP Chapter 3 - The Planning Environment The geographical areas covered by these sub-regional planning groups are approximately as shown in Figure 3.1 below. In addition to the above groups, California is attempting to coordi- nate the overall planning for their state. Figure 3.1 - Sub-regional Transmission Planning Groups in the WECC Northwest Transmission Assessment Committee Columbia Grid Northern Tier Transmission Group CCPO Colorado Coordinated Planning Group STEP Southwest Transmission Expansion Planni Southwest Area Transmission Study HYDROELECTRIC, RELICENSING' The issues involved in relicensing hydroelectric facilities are multifaceted. They involve numer- ous federal and state environmental laws and regulations, and participation of numerous stake- holders including agencies, Indian tribes, non-governmental organizations, and local communi- ties and governments, The value to relicensing hydroelectric facilities is continued availability of hydroelectric genera- tion. Hydroelectric projects can often provide unique operational flexibility as they can be called upon to meet peak customer demands almost instantaneously and provide back-up for intermit- tent renewable resources such as wind. In addition to operational flexibility, hydroelectric gen- eration does not have the emissions concerns of thermal generation. Relicensing or decommis- sioning of many of PacifiCorp s projects are nearing completion as Federal Energy Regulatory Commission (FERC) licenses or Orders are expected to be issued for the majority of the portfo- lio over the next 1 to 3 years. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment FERC hydroelectric 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 surrounding environment and natural 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 reso- lution of issues cannot be 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 certain criteria. The FERC must find that the project is in the broad public interest. This requires weigh- ing, with "equal consideration " the impacts of the project on fish and wildlife, cultural 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 envi- ronmental equation. For example, the National Oceanic and Atmospheric Administration Fisher- ies agency and the U.S. Fish and Wildlife Service have the authority within the relicensing to require installation of fish passage facilities (fish ladders and screens) at projects. This is often the largest single capital investment that will be made in a project and can render some projects uneconomic. Also, because a myriad of other state and federal laws come into play in relicens- ing, most notably the Endangered Species Act and the Clean Water Act, agencies ' interests may compete or conflict with each other leading to potentially contrary, or additive, licensing re- quirements. PacifiCorp has generally taken a proactive approach towards achieving the best pos- sible relicensing outcome for its customers by engaging in settlement negotiations with stake- holders, the results of which are submitted to the FERC for incorporation into a new license. Potential Impact Relicensing hydroelectric facilities involves significant process costs. The FERC relicensing process takes a minimum of five years and generally takes nearly ten or more years to complete depending on the characteristics of the project, the number of stakeholders, and issues that arise during the process. As of December 31 , 2006, PacifiCorp had incurred $79.0 million in costs for ongoing hydroelectric relicensing, which are included in Construction work-in-progress on PacifiCorp s Consolidated Balance Sheet. As relicensing efforts continue, additional process costs are being incurred that will need to be recovered from customers. Also, new requirements contained in FERC licenses or decommissioning Orders could amount to over $2 billion 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, cultural and flood man- agement measures as well as project operational changes such as increased in-stream flow re- quirements to protect fish resulting in lost generation. About 90 percent of these relicensing costs relate to PacifiCorp s three largest hydroelectric projects: Lewis River, Klamath River and North Umpqua. Treatment in the IRP The known or expected operational impacts mandated in the new licenses are incorporated in the projection of existing hydroelectric resources discussed in Chapter 4. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment PacifiCorp s Approach to Hydroelectric Relicensin2: As noted, PacifiCorp continues to manage this process by pursuing negotiated settlements as part of the 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. ENERGY POLICY ACT;OF20Q5 The Energy Policy Act of 2005 (EP Act), the first major energy law enacted in more than a dec- ade, documents the tone of the current political/social environment. More than 1 700 pages long, the Act has hundreds of provisions. With respect to electric utilities the major provisions of the act include the following. Promote clean coal technology and provides incentives for renewable energy such as bio- mass, wind, solar and hydroelectricity and by requiring net metering options Encourage more hydropower production by improving current procedures for hydroelectric project licensing and calling for plans to improve the efficiency of existing projects. Requires state commissions to consider adopting five new standards dealing with net meter- ing, interconnection, fossil fuel generation efficiency, time-based metering and telecommuni- cation, and fuel sources. Provide for enforceable mandatory reliability standards, incentives for transmission grid im- provements and reform of transmission siting rules. These improvements will attract new in- vestment into the industry and ensure the reliability of our nation s electricity grid in order to stop future blackouts. Provides research and development support and a production tax credit for advanced nuclear power facilities This section covers the major EP Act provisions that impact PacifiCorp and how the company is addressing them. Clean Coal Provisions The EP Act contains a number of provisions to encourage development of clean coal technolo- gies. These provisions cover not only power generation technologies, but other coal-based tech- nologies to encourage national energy security, reduced dependency on premium fossil fuels such as oil and natural gas, increased efficiency, and reductions in emissions. The primary focus of the clean coal provisions of the EP Act is on gasification, but other advanced technologies such as ultra-supercritical boiler technologies are also considered. Under Title IV of the EP Act, financial assistance is made available to qualifying projects. The primary focus for the financial assistance is for advanced combustion systems and processes that reduce air pollution. Financial assistance can consist of cost sharing or loans. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Under Title XIII of the EP Act, a number of tax incentives are established. These incentives are primarily focused on development of gasification technologies both for electric power generation and coal-based gasification processes that produce liquid and gaseous fuels as well as primary chemical feedstocks. Available credits will be allocated on a first-come, first-served basis taking into account Department of Energy (DOE) balancing of the EPAct policy goals (fuel diversity, location, technology, CO2 capture, project economics), i.e. integrated gasification combined cy- cle (IGCC) projects that include greenhouse gas capture, increase by-product utilization, and other benefits will be given high priority in the allocation of credits for IGCC projects. Under the guidelines there are three separate application periods (2006, 2007, and 2008); the application date for each application period is June 30 of each year. Based on the overwhelming response the DOE received in 2006, the availability of investment tax credits (ITCs) is expected to diminish with time. PacifiCorp submitted confidential applications on June 29, 2006 to the DOE for ITCs under this section of the Act for IGCC facilities at both the Hunter and Jim Bridger plant sites. PacifiCorp also indicated an interest in Energy Northwest's planned development of the Pacific Mountain Energy Center IGCC project. The proposed location for this project is in Port Kalama, Washing- ton. Energy Northwest submitted a confidential application to the DOE for ITCs under this por- tion of the Act for that portion of the plant which would not be owned by public power entities. Section 413 of EP Act also authorizes, subject to appropriations, funding support for a demon- stration project to be built in the Western U.S. The Wyoming Infrastructure Authority (WIA) issued an RFP for a Wyoming Coal Gasification Demonstration Project on July 17, 2006. The WIA's intent for this RFP process was to identify one or more Wyoming based projects for the purpose of seeking Section 413 funding. PacifiCorp provided an expression of interest in re- sponse to this RFP on August 17, 2006, followed by a confidential proposal to the WIA in Octo- ber 2006. As described in Chapter 5, the WIA recently selected PacifiCorp to participate in the joint IGCC project. In addition to the ITC programs available for qualifying IGCC or advanced clean coal technolo- gies, the EP Act makes available $350 million for ITCs for qualifying industrial gasification pro- jects (not necessarily for power generation). Title XVII of the EP Act provides for loan guarantees for innovative technologies, such as (IGCC) or technologies that reduce or sequester pollutants or greenhouse gases. PacifiCorp has reviewed the potential application of loan guarantees for potential IGCC projects under consid- eration and has determined that loan guarantees provide little value to the company and would entail significant regulatory complications. Renewable Enen!v Provisions The renewable energy production tax credit (PTC), which was set to expire at the end of 2005 was extended through the end of 2007. (The U.S. Congress extended it again through the end of 2008 as part of the Tax Relief and Health Care Act of 2006.) Additionally, the eligibility period for power production from open-loop biomass, geothennal, small irrigation, landfill gas and mu- nicipal solid waste projects is increased from 5 to 10 years. Finally, incremental hydropower 50 ' PacifiCorp 2007 IRP Chapter 3 - The Planning Environment production resulting from efficiency improvements or capacity expansion at existing dams was added to the list of production technologies eligible for the PTC. PacifiCorp expects that extension of the PTC should aid the procurement of new wind and other renewable resources with a relatively short development lead-time. Nevertheless, dependence on year-to-year extensions represents a significant challenge for developing renewable resources with longer design/procure/construction periods, such as geothermal projects. Given the uncer- tain future of the PTC, PacifiCorp, along with other utilities, is attempting to acquire as much economic renewables as possible prior to the expiration date. Hvdropower The bill includes a major reform of the federal licensing procedure for hydroelectric dams. The modifications allow an applicant to propose an alternative to mandatory conditions placed on hydropower licenses by federal resource agencies (Departments of Interior, Commerce and Agri- culture). If a proposed alteIpative met the statutory environmental and resource protection stan- dards, the alternative would be accepted. Hydro licensing reform has been a goal of the industry for years , but has been highly controversial with the environmental community. The bill also includes incentives for improving the efficiency of existing hydroelectric dams and for modifying existing dams to produce electricity. (See Renewable Energy Provisions, above. Public Utility Re2ulatorv Policies Act Provisions The bill establishes market conditions necessary to eliminate the Public Utility Regulatory Poli- cies Act's (PURPA) mandatory purchase obligation. The EPAct also includes amendments that establish market conditions that eliminate the requirement for utilities to buy power from inde- pendent renewable energy and cogeneration plants where FERC determines that competitive market conditions exist, and revises the criteria for new qualifying facilities seeking to sell power under the mandatory purchase obligation. Unfortunately, competitive markets may not support the long-term contracts that many renewable generators need to secure financing at affordable rates. Title XII of EP Act also amends a section of PURP A by adding five new ratemaking standards for electric utilities. State regulatory commissioners are to determine whether the new standards are appropriate for their states. The five standards include net metering, fuel source diversity, fossil fuel generation efficiency and interconnection service to customers with their own on-site generating facilities. Metering Provisions Section 1252 , " Smart Metering , of the EPAct requires that all utilities provide a time-based rate to all customer classes within 18 months of the enactment. In all states, PacifiCorp has met the basic requirements of the EP Act in regards to time-based rate schedule offerings. Furthermore, the EP Act requires state commissions to conduct an investigation as to whether a time-based rate schedule and accompanying meter equipment is appropriate to implement and install within 18 months after date of enactment. The following time-based rates must be consid- ered: PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Time-of-use pricing" - Prices for specific periods and typically changed twice a year Critical peak pricing" - Prices for peak days, discounts for reducing peak period con- sumption Real-time pricing" - Prices may change hourly Credits" - Large load customers who reduce a utility's planned capacity obligations PacifiCorp has actively participated in all requested state commission investigations and/or tech- nical conferences. These meetings must be completed by February 2007 with the commission recommendations provided by August 2007. Section 110 , " Daylight Savings , amends the Uniform Time Act of 1966 by extending Daylight Savings Time (DST) by four weeks beginning in 2007. DST will begin the second Sunday of March and end the first Sunday of November. This section also requires the Department of En- ergy to file a report to Congress nine months after enactment on the impact of this section on energy consumption in the u.S. Congress retains the right to revert DST back to the 2005 time once the report is complete. To meet the requirements of Section 110, all of PacifiCorp ~ time-of-use and interval meters would be required to be replaced and/or reprogrammed to align the internal calendars with the new dates. With the possibility of Congress reverting to 2005 time, the exposure for cost to re- program the meters is significant. To mitigate the costs of meter replacement and programming until such time as a formal decision is made, PacifiCorp has filed, or will be filing, interim tariff modifications in all states. If ac- cepted, the modifications will keep the existing 2005 DST dates within the applicable tariffs until such time that a formal decision is made. PacifiCorp will comply with the requirements of the decision at that time. Fuel Source Diversity Section III (d)(12), "Fuel Sources , requires electric utilities to develop "a plan to minimize de- pendence on I fuel source and to ensure that the electric energy it sells to consumers is generated using a diverse range of fuels and technologies, including renewable technologies." Within three years of enactment, state regulatory authorities must decide whether to enact this standard or determine that a comparable standard meets this objective. During 2006, PacifiCorp reviewed this amendment with states and other interested parties through technical conferences sponsored by the state commissions. PacifiCorp believes that the state I RP standards and guidelines reflect a comparable standard that fulfills the requirement for a fuel source diversity plan. The Public Service Commission of Utah concurred with this view issuing a determination that the current Utah IRP guidelines constitute a comparable standard. During the October 17, 2006 technical conference, the company agreed to include a section in the IRP that discusses how fuel diversity is addressed in the planning process. This section is included in Chapter 8 , " Action Plan. 23 Public Service Commission of Utah , " Detennination Concerning the PURPA Fuel Sources Standard" (Docket No. 06-999-03), issued March 13,2007. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Fossil Fuel Generation Efficiency Standard The PURP A amendments include a requirement that each electric utility develop and implement a 10-year plan to increase the efficiency of its fossil fuel generation plants. States must deter- mine whether to adopt this standard by August 8 , 2008. States do not have to comply if the state has already adopted or considered a comparable provision.24 PacifiCorp has been reviewing this amendment with states and other interested parties through technical conferences sponsored by the state commissions. PacifiCorp believes that the IRP currently serves as a comparable provi- sion with respect to fleet efficiency improvements arising from new generation and retirement old, less efficient fossil units. In discussions with Utah Public Service Commission staff, PacifiCorp agreed to report in this IRP the 20-year forecasted average heat rate trend for the company s fossil fuel generator fleet. This forecasted average heat rate represents the individual generator heat rates weighted by their annual generation, accounting for new IRP resources and current planned retirements of existing fossil fuel generators. For existing fossil fuel resources, four-year average historical heat rate curves are used, whereas new resources use expected heat rates accounting for degradation over time. This fleet-wide heat rate trend information is provided in Figure 7.34 in Chapter 7 , " Re- sults. In PacifiCorp s subsequent integrated resource plans, the company will summarize its efficiency improvement plans, as well as report heat rate trends using forward-looking heat rates that ac- count for these plans. Transmission and Electric Reliabilitv Provisions This portion of the EP Act is intended to: Help ensure that consumers receive electricity over a dependable, modern infrastructure; Remove outdated obstacles to investment in electricity transmission lines; Make electric reliability standards mandatory instead of optional; and Give Federal officials the authority to site new power lines in DOE-designated national corridors in certain limited circumstances. Two sections of this legislation pertain specifically to the development of major new transmis- sion lines: Section 368a, which defines "energy corridors , and Section 1221 , which attempts to identify and address transmission congestion. Section 368a, Energy Corridors Section 368a directs the Secretaries of Agriculture, Commerce, Defense, Energy, and the Interior (the Agencies) to designate under their respective authorities corridors on Federal land in the 11 Western States for oil, gas and hydrogen pipelines and electricity transmission and distribution facilities (energy corridors). The legislation sets the timetable for corridor designation in the eleven Western States at no later than two (2) years after enactment, or August 2007. Edison Electric Institute Energy Policy Act of 2005, Summary of Title XII Electricity. Title XVIII Studies, and Related Provisions (August 3, 2005), page 10. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment The Agencies determined that designating corridors as required by Section 368a of the Act con- stitutes a major Federal action which may have a significant impact upon the environment within the meaning of the National Environmental Policy Act (NEPA), For this reason, the Agencies are preparing a draft Programmatic Environmental Impact Statement (PElS) to identify the impacts associated with designating energy corridors. Based upon the information and analyses devel- oped in the PElS, the Agencies will designate energy corridors by amending their respective land use plans. Public scoping meetings were held in October and November 2005. Potential energy corridor locations were depicted on draft maps and circulated for comment (See the following DOE web site for these maps: http://corridoreis.anl.gov/eis/pdmaplindex.cfm). The draft PElS was released for comments last fall. Final energy corridors will be identified in the final EIS which is sched- uled to be released in August 2007. The majority of the preliminary energy corridors utilize ex- isting corridors and/or rights-of-way; however, there are a small number of potential new corri- dor locations. Section 1221, National Transmission Congestion Study Section 1221 of the EP Act of 2005 required DOE to issue a national transmission congestion study for comment by August 2006 and every three years thereafter. Based on the study and pub- lic comments, DOE may designate selected geographic areas as "National Interest Electric Transmission Corridors." Applicants for projects proposed within designated corridors that are not acted upon by state siting authorities within one year may request FERC to exercise federal backstop" siting authority. For the Western Interconnection, DOE relied on the Western Con- gestion Assessment Task Force (WCA TF), which is an ad-hoc group formed primarily by WECC members, to complete the congestion study. The WCA TF produced several work prod- ucts for DOE including a summary of major studies, a report describing historical congestion and the results of SSG-WI production cost studies conducted for the years 2008 and 2015. Figure 2 is a map provided to DOE showing the major areas of congestion in the Western Intercon- nection. Based on the WCA TF report and other information, the DOE produced a national transmission congestion report that shows congested areas across the Western Interconnection. The only criti- cal congestion area highlighted in the Western Interconnection was in southern California. In addition to the congestion in southern California, it was noted that there are conditional con- straints in the PacifiCorp area in association with exporting potential new coal and wind re- sources from the states of Montana and Wyoming (See Figure 3. The effect of Section 1221 on PacifiCorp is unclear at this point, but it is expected to be benefi- cial as it should speed up the permitting process for new transmission facilities. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Figure 3.Western Interconnection Transmission Congestion Areas/Paths Western Interconnect Transmission Congestion Areas/Paths ldentifioo IJj the1M:ATF For,Subnission ID USDOE Mi1J 8. 2006 ,congestedWECC Path ........- Congestion Area tSeeTab!eJI Direction of Congestion .-, , .,,-.,..-",. '" '" = Source: Western Congestion Analysis Task Force Western Interconnection Congestion Areas: Summary Tables , 2 and with Congestion Area Map, prepared for the u.S. Department of Energy, May 8, 2006. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment Figure 3.3 - Conditional Constraint Areas )tITL:~Jf'iDi Pc'tentiel re-soun:e etmCl1n1T8tion ......... W~v dil'e(:\il:" or Electrici!y IPm; JIIIII'7"" ~rom 'e-""I'~S !o w.ds I!,'!'I':_~!C, ~'!:.""~~'..'~'':"'. ~~I~~I Source: U.S. Department of Energy, National Electric Transmission Congestion Study, August 2006. Climate Chanf!e The EPAct established a Climate Change Technology Advisory Committee to identify statutory, regulatory, economic and other barriers to the commercialization and deployment of technolo- gies and practices that would reduce the intensity of greenhouse gas production. Additionally, the new law directs the State Department to act as lead agency for integrating into U.S. foreign policy the goal of reducing greenhouse gas intensity in developing countries, and directs DOE to conduct an inventory of greenhouse gas intensity reducing technologies for transfer to develop- ing countries. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment '" "'" ,.., ,......,..'.. .. .............. ,....,.. ......'.... RECENTImSOuRCEPR OCUREMENT ActFVI'I'mS:"" Supply-Side Resources 2012 Request for Proposals for Base Load Resources As a consequence of the update to the 2004 Integrated Resource Plan (filed in November 2005), PacifiCorp suspended the 2009 Request for Proposal and is preparing a new RFP for acquisition of east-side base load resources for 2012 2013, and 2014. The base load RFP seeks to acquire up to 1 700 megawatts of cost-effective resources for the term of 2012 through 2014, consisting of a combination of generation assets, generation assets on the company s sites and market purchases (i., front office transactions),25 The company has included two benchmark resources in the RFP. The benchmark resource for 2012 is 340 mega- watts, representing the Intermountain Power Plant Unit 3 and the benchmark resource for 2014 is 575 megawatts, representing Bridger 5. The company issued its base load RFP on April 5, 2007. Renewables Request for Proposal 2003B PacifiCorp amended the renewables Request for Proposal 2003B in March 2006 to assist in meeting renewable procurement targets, including those related to the MidAmerican transaction commitment to acquire economic renewable resources. As a result of the bids received, Pacifi- Corp considered nearly twenty competing offers. Demand-side Resources The 2005 DSM RFP to procure Class 1 , 2 and 3 resources was issued according to the action plan in the 2004 IRP (See 2004 IRP, Table 9.3). The RFP was structured to solicit proposals for both specific resources types-for example, comprehensive residential equipment and service program-as well as an "all comers" request for each resource type. The most notable program addition originating from the 2005 DSM RFP is the Home Energy Savers program, filed and approved in 2006 in Idaho, Washington and Utah, and, pending commission approval, to be of- fered in California and Wyoming in 2007. The company also accepted a proposal to enhance business program penetration of the new construction market. In addition, there remain a select few program proposals from the 2005 DSM RFP that may be pursued provided the Company receives supporting information through their system-wide demand-side management potential study indicating that sufficient opportunity, customer interest, and delivery price points exist to support the proposals. The system-wide demand-side management potential study, a Mid- American Energy Holdings Company commitment made during its acquisition of PacifiCorp in March 2006, is scheduled to be completed in June 2007. The Company intends to use the infor- mation from this study to assist in the refinement of their current demand-side programs (expand and improve their performance) as well as identify additional cost-effective and system relevant program opportunities across all program types, e., energy efficiency, demand control or man- agement, and demand response. 25 The RFP covers power purchase agreements, tolling service agreements, asset purchases, load curtailment con- tracts, and Qualifying Facility contracts. See Chapter 4, Action Plan, for more details concerning the Base Load RFP. PacifiCorp 2007 IRP Chapter 3 - The Planning Environment ffi-tE IMPACT OF S TATE'RES()URCEPOI1J:CIESO SYSTEM#WJD)E:PLANNINU' " "" " X . ...."'" ",", ", ,..,,, ....,.. ", """"""""""""'" ," " '.... ' .., ", " " ..,..c..., " "'...' , A new planning issue that PacifiCorp is dealing with for this IRP cycle is the rapid evolution state-specific resource policies that place, or are expected to place, constraints on PacifiCorp' s resource selection decisions. As discussed earlier in this chapter, these policies cover CO2 emis- sions, renewable energy, energy efficiency, load control, distributed generation, and the promo- tion of advanced clean coal and carbon sequestration technologies. Table 3.1 represents an in- ventory of state policy actions and events that occurred in 2006, and so far in 2007, that impact PacifiCorp s integrated resource planning process now and in the future. Considerable complexity is added to system-wide resource planning and the supporting model- ing process as a result of these policies. In addition, disparate state interests, as expressed in prior IRP acknowledgement proceedings and throughout the 2007 IRP development cycle, compli- cates the company s ability to address state IRP requirements to the satisfaction of all stake- holders. Table 3.1 - State Resource Policy Developments for 2006 and 2007 2006 January: Oregon PUC, in its 2004 IRP ac- knowledgement order, does not acknowl- edge a near-term "high-capacity-factor" re- source, and requires that PacifiCorp explore coal deferral options until IGCC is commer- cialized January: Oregon PUC rejects the 2004 IRP U date Action Plan February: Oregon Renewable Energy Work- ing Group is formed March:Oregon, California, and Washington join other petitioners in asking the U.S. Su- preme Court whether the U.S. Environ- mental Protection Agency has the authority to regulate carbon dioxide and other air pol- lutants associated with climate chan e April: Idaho moratorium on coal-fired plants is issued. August: Utah Blue Ribbon Advisory Coun- cil on Climate Change formed September: California adopts a carbon cap (AB 32) 2007' January: The California PUC adopts a greenhouse gas emission performance standard for generators January: The Oregon PUC rejects Pacifi- s 2012 RFP January: The Oregon Carbon Allocation Task Force recommends a CO2 load-based ca -and-trade model rule February: The Washington Governor signs Executive Order 07-02 setting climate change-related rules, including greenhouse gas emISSIOns caps February: Washington introduces legisla- tion setting carbon caps and a GHG emis- sions erformance standard February: the Western Regional Climate Change Action Initiative announced by California, Oregon, Washington, New Mexico, and Arizona February: Utah, Wyoming, Nevada, and North Dakota announce the N extGen En- er Alliance, which is to romote ad- PacifiCorp 2007 IRP Chapter 3 - The Planning Environment 2006 November: the Oregon governor announces a renewable portfolio standard plan November: Washington adopts a renewable portfolio standard December: Western Public Utility Commis- sion Joint Action Framework on Climate Change (California, Oregon, Washington New Mexico launched December: The Utah PSC issues suggested modifications to PacifiCorp s 2012 base load RFP 2007 vanced coal technologies and economic utilization of carbon dioxide March: Oregon RPS and carbon-related legislation introduced (a cap and green- house as emissions erformance standard April: The u.S. Supreme ruled that the EP A has the authority to regulate CO2 emIssIons PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment 4. RESOURCE NEEDS ASSESSMENT -, '" , " - 011 anel1ergybasis ~a~ift Qol"pexpects " a 'system--wi de~yerage16adgrowth of 2 .5 per- cent ,peryearfrom20Pl lht()ijgh 201().WY()r!Mng' sh6wsthe,Jargeslload gro~h6'Ver the ,2007 t()2016 .at5;6per~e#t'a'Ver~geaIlI:1'LlaJ:rate. , , Utal1"load. ispl"ojeCted. .,t() ,grow anaverageanl1ualiat:eOfabo'iIt 3 perc~i1t;whilethe,otnerstateswherethecornPanY ()p ~ ' erate s-Oreg ol1 WashillgtOli I dahp,andCalifo mia ""::: have 16 ad growth p rojec fed ', ataboutlpercellt. ' , Systetnpeak 10adis~f'cpectedt()gro\Vat a fasterrate.thanoveralLload due to the chang- ing mix of ,applianc.es .q:y~rtime":e.aciftCorp'seastern..~ystem,peil,Kisexpectedt6con,. tin u egro wing" faster tq,a.n.i tsMres terpsys t~ll1 P~ak" witlla yera g~ "~nnual' ,growth.rate ~ " . 32 percent and Q.8percent;respectiy:ely"iover;theforecast horizon ' , .Near..termTesourc~change~includethe t'qlloWiIig: " Conversion 6ftheCurrant(jteei( fap'ility,froma "singlecycle,combustionturbine aco m bin~dcy cleo oJIlb tl~ ti pntul" bitle(Jtu:I~i:2006) The additioIlofitheLakeSidec;6tnbinedcycle combustion, ttirbine( expected com-mercialoperation iniJune2007) ' - The additionoftbeLeanll1g Junip~rl and~arengo wind projeCts , ' Expiration of the 400--megawattpi)werpllrchase agreemeritwithTransAltaEnergy MarketingexpiresinJune2007 """"' " " Ex--piration ofthe $'75 meg(iwatt BJ?A peaking contractinAugust20 11 Expiration of the WestValleyplalltleasein May 2008 . On both a capacity and energy ,basis, lejad and Tesourcebalarices are calculated . using existing resource lev~ls, ob ligatioris, anpTesetverequirements . Contract expirations also impacfthesecalculations. ' , The coll1panyprojectsa ,~ummerpeakresourc~deficitfor the Pacifiporp system begin- ning,in 2008to 2010, depending, on the, capacity ,planning reserve margin assumed. Be- ginning in 2009, the coll1pallYlJecomes energy deftc;ienti:manannlla1 basis. - - ThePacifiCorpdeftcitspriorto 2011 t02q12willbe met Byaqditional renewables demand side programs, andrIlarketpurchases.'rhenbeginning in 2011 to 2012 , base 1Qad int~I'IIlediaiel(),()rboth tYP~sofresQllrce. additions wi11b~necessaryto cover thewidelling_ca~acitY~rid~Ilergydeficit~. ' ' '" -. , PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment INTRODUCTION This chapter presents PacifiCorp ' s assessment of resource need, focusing on the first 10 years of the IRP's 20-year study period, 2007 through 2016. The company s long-term load forecasts (both energy and coincident peak load) for each state and the system as a whole are addressed first, followed by a profile ofPacifiCorp s existing resources. Finally, load and resource balances for capacity and energy are presented. These balances are comprised of a year-by-year compari- son of projected loads against the resource base without new additions. This comparison indi- cated when PacifiCorp is expected to be either deficit or surplus on both a capacity and energy basis for each year of the planning horizon. LOAD. FORECAST Methodolot!V Overview PacifiCorp estimates total load by starting with customer class sales forecasts in each state and then adds line losses to the customer class forecasts to determine the total load required at the generators to meet customer demands. PacifiCorp uses different approaches in forecasting sales for different customer classes. PacifiCorp also employs different methods to forecast the growth over different forecast horizons. Near-term forecasts rely on statistical time series and regression methodologies while longer term forecasts are dependent on end-use and econometric modeling techniques. These models are driven by county and state level forecasts of employment and in- come that are provided by public agencies or purchased from commercial econometric forecast- ing services.26 Appendix A provides additional details on methodologies and state level forecasts. Inte2rated Resource Plannin2 Load Forecasts Through the course of the 2007 integrated resource planning cycle, PacifiCorp relied on two load forecasts for the development of the load and resource balance and portfolio evaluations. The first official load forecast used in this IRP cycle, released in May 2006, was used to support port- folio analysis from May 2006 to February 2007. Between May 2006 and March 2007, events transpired that resulted in the need to revise the load forecast. Because of the magnitude of the forecast changes and the extended IRP filing schedule granted by the state commissions, the company decided that it was prudent to incorporate load forecast updates in the IRP. Conse- quently, PacifiCorp s IRP analysis from February 2007 onward reflects the new March 2007 load forecast. The primary changes to the original May 2006 load forecast result from recent trends and condi- tions on the east side of PacifiCorp s service territory. Growth in Utah was slowing from what was previously planned; therefore, its growth rates were reduced. This was mainly associated with the growth in the commercial class and a slowing of the service activity in the state. Offset- ting this were requests for service in the oil and gas industries of Wyoming. Higher prices, fuel supply uncertainty both nationally and worldwide resulted in plans to increase the development of the fields in Wyoming. Additionally, portions of Wyoming are experiencing air quality prob- lems with existing extraction practices that require electrification of the existing services in the 26 PacifiCorp relies on county and state level economic and demographic forecasts provided by Global Insight, in addition to state office of planning and budgeting sources. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment fields. The load requests from customers in these areas total over 1 000 megawatts in 2012. While these state trends largely offset each other on a total projected load basis, the revised Wyoming load growth affects the timing of the resource need. That is why the company decided to incorporate the new load forecast in the IRP. The following sections describe the March 2007 energy and coincident peak load forecasts, as well as summarize the differences with respect to the original May 2006 forecast. Enerev Forecast Table 4.1 shows average annual energy load growth rates for the PacifiCorp system and individ- ual states. Growth rates are shown for the historical period 1995 through 2005, and the forecast period 2007 through 2016. Table 4.1- Historical and Forecasted Average Energy Growth Rates for Load A ver~ge Anntl;l1 . GroWth Rate . 1995-2005 2007-2016 The total net control area load forecast used in this IRP reflects PacifiCorp s forecasts ofloads growing at an average rate of 2.4 percent annually from fiscal year 2007 to 2016, This is slightly faster than the average annual historical growth rate experienced from 1995 to 2005. During this historical period the total load for these states increased at an average annual rate of 1.6 percent. Table 4.2 shows the forecasted load for each specific year for each state served by PacifiCorp and the average annual growth (AAG) rate over the entire time period. Table 4.2 - Annual Load Growth in Megawatt-hours for 2006 and forecasted 2007 through 2016 '. Year ,TotaL.WA. .., CA "ID ' 2006 58,466,744 388 512 637 218 818 396 991 346 958 123 673 149 2007 58,244,203 745 256 556 816 043 776 944 252 23,407 514 546 589 2008 60,003,127 774 141 577 294 035 331 948 959 070,475 596 927 2009 824 270 813 056 608 889 157 044 953 801 653 183 638 297 2010 63,939 431 927 068 821 004 019 398 979 509 25,494 009 698 443 2011 65,638,416 041 955 900 526 842 214 988 843 114 702 750 176 2012 67,027,436 157 677 944 106 347 838 998 372 767 715 811 728 2013 68,304,861 274 258 988 967 718 417 008 170 453 851 861 198 2014 525,861 391 817 033 291 991 101 018 178 175 184 916 290 2015 70,776,423 510 250 077 689 245 983 028 365 938 113 976 023 2016 72,305 522 629 572 125 690 712 173 038 612 745 665 053 810 : , , 0 " " ,'" .., ".. ' AAG 2.4%1.3%1.1%1.0%2007-2016 AAG 1.3%1.3%1.6%1.1%2016-2026 PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment As can be seen from the average annual growth rates at the bottom of the Table 4., the eastern system continues to grow faster than the western system, with an average annual growth rate of 3.2 percent and 0.8 percent, respectively, over the forecast horizon. Svstem- Wide Coincident Peak Load Forecast The system peaks are the maximum load required on the system in any hourly period. Forecasts of the system peak for each month are prepared based on the load forecast produced using the methodologies described in Appendix A. From these hourly forecasted values, forecast peaks for the maximum usage on the entire system during each month (the coincidental system peak) and the maximum usage within each state during each month are extracted. The system peak load is expected to grow from the 2005 peak of 8 937 megawatts at a faster rate than overall load due to the changing mix of appliances over time. Table 4.3 shows that for the same time period the total peak is expected to grow by 2.6 percent. The system peak, which pre- viously occurred in the winter, has switched to the summer as a result of these changes in appli- ance mix. The change in seasonal peak is due to an increasing demand for summer space condi- tioning in the residential and commercial classes and a decreasing demand for electric related space conditioning in the winter. This trend in space conditioning is expected to continue. There- fore, the disparity in summer and winter load growth will result in system peak demand growing faster than overall load. However, once the demand in space conditioning equipment stabilizes the total load and system peak growth rates should equalize. Table 4.3 - Historical and Forecasted Coincidental Peak Load Growth Rates Average Annual Growth Rate 1995-2005 2007-2016 (0.9)%,1.9% Again, PacifiCorp s eastern system peak is expected to continue growing faster than its western system peak, with average annual growth rates of 3.2 percent and 1.2 percent, respectively, over the forecast horizon. This is similar to historical growth patterns as Table 4.3 reflects. East sys- tem peak growth during this time has been faster than west system peak growth. Of course, peak growth is somewhat masked in Table 4.3 if you consider that the peak has shifted from winter months to summer months. Table 4.4 shows the average annual coincidental peak growth occurring in the summer months for 1995 through 2005. This shows that some of what appears to be a decrease in peak load in many states is due to the shift from winter to summer, and that growth in peak is truly occurring. It also shows that faster growth is continuing to occur in the eastern portion of the system where average historical growth has been 2.8 percent, while the western portion of the system grew at 1 percent on average. This pattern is expected to continue as discussed previously. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Table 4.4 - Historical Coincidental Peak Load - Summer 1\.v~rijge t\:liijtlal , . ' Growth Ra.te Total 1995-2005 2.5.2% The system peak load is expected to grow at a slightly faster rate than the overall load due to the changing mix of appliances over time. Table 4.5 below shows that for the same time period the total peak is expected to grow by 2.6 percent. Until recently, the system peak occurred in the winter months. Due to a changing appliance mix from an increasing demand for summer space conditioning in the residential and commercial classes, and a reduction in electric related space conditioning in winter months, the system peak has started occurring in summer months. Pacifi- Corp expects this condition to continue. Therefore, the increasing summer load and decreasing winter loads are expected to result in a faster growing system peak than total load until changes in space conditioning equipment mix ends. Table 4.5 - Forecasted Coincidental Peak Load in Megawatts Year Total"'WA,CA 'HI' "1D"I SE-ID , 2006 577 684 816 094 156 011 561 256 2007 243 076 699 044 147 298 632 347 2008 440 075 702 145 147 409 631 331 2009 752 235 702 282 159 420 678 276 2010 10,261 254 729 1,416 141 720 696 305 2011 10,488 314 757 473 128 932 573 311 2012 836 320 766 569 155 973 686 367 2013 989 328 767 613 156 061 693 371 2014 11,157 331 773 648 158 184 708 355 2015 296 326 774 669 171 337 719 300 2016 619 314 775 733 163 547 745 342 " . -c- :': ,' ,, , AAG 2007-2016 1.2%1.2% AAG 2016-2026 1.5%1.9%0.4%1.4%1.0% One noticeable aspect of the states contribution to the system coincidental peak forecast is that they do not continuously increase from year to year, even though the total system peak and each state s individual peak loads generally increase from year to year. This behavior occurs because state level coincident peaks do not occur at the same time as the system level coincident peak and because of differences among the states with regard to load growth and customer mix. While each state s peak load is forecast to grow each year when taken on its own, its contribution to the system coincident peak will vary since the hour of system peak does not coincide with the hour of peak load in each state. As the growth patterns of the class and states change over time, the peak will move within the season, month or day, and each state s contribution will move accord- ingly, sometimes resulting in a reduced contribution to the system coincident peak from year to year in a particular state. This is seen in a few areas in the forecast as well as experienced in his- tory. For example, the Idaho state load is driven in the summer months by the activity in the irri- gation class. The planting and irrigating practices usually cause this state to experience the PacifiCorp - 2007 IRP Chapter 4 - Resource Needs Assessment maximum load in late June or early July. This load then quickly decreases week by week. Con- sequently, there can be as much as 150 megawatts ofload difference between the maximum load and the loads during the last weeks of July. This anomaly can be seen when comparing the Idaho contribution to the system coincident peak in 2010 and 2011. Another noticeable aspect is the decline in the loads from the actual period to the first forecast year. This is noticeable in Oregon when the 2007 is compared to the 2006 value. There may be several things that can impact this. In the Oregon case, a large industrial customer is expected to cease operations during 2007. This large customer and the associated multiplier effect of this customer will cause a decline in load for Oregon. Other factors contributing to the decline in- clude the changing time of the system peak demand in 2007, variability in jurisdictional contri- bution to the peak demand over time, and weather effects to the Oregon contribution in 2006. Jurisdictional Peak Load Forecast The economies, industry mix, appliance and equipment adoption rates, and weather patterns are different for each jurisdiction that PacifiCorp serves. Because of these differences the jurisdic- tional hourly loads have different patterns than the system coincident hourly load. In addition the growth for the jurisdictional peak demands can be different from the growth in the jurisdic- tional contribution to the system peak demand. Table 4.6 reports the historical growth rates for each of the jurisdictional peak demands, while Table 4.7 reports the jurisdictional peak demand growth over the forecast horizon. Table 4.6 - Historical Jurisdictional Peak Load Average Annmil Growth Rate 1995-2005 Table 4.7 - Jurisdictional Peak Load in Megawatts for 2006 and forecast 2007 through 2016 OR "Year ' " 2006 730 818 208 179 357 723 2007 393 751 185 191 347 678 2008 405 744 372 190 4,409 680 2009 2,457 750 572 194 483 736 2010 2,455 782 1 ,627 199 791 755 2011 2,472 795 681 201 932 770 2012 536 807 757 200 044 747 2013 533 807 778 205 172 757 2014 541 805 817 207 267 770 2015 552 808 844 209 5,416 780 2016 536 803 908 208 658 811 " ' i, \, , ' i"",:'i, , ," , i' ;' ,;,, ' PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Year'I','or..... !.': AAG 2007-2016 5.4%1.0% AAG 2016-2026 1.4%1.9%1.8% Additional detailed information about the load forecast can be found in Appendix A, Base As- sumptions. May 2006 Load Forecast Comparison Tables 4.8 and 4.9 show the respective state annual peak load and energy differences between the March 2007 forecast and those for the May 2006 forecast. The impacts of slowing service activity in Utah and greater forecasted demand in Wyoming mentioned above are evident for both capacity and energy trends. For example, Utah continues to have one of the strongest economies in the nation and will likely continue to do so; however, there have been subtle signs of some slowing of very robust growth. As published in the Salt Lake City Tribune , the Utah Department of Workforce Services reported job growth of 4.5 percent for the year that ended in March 2007, which is down significantly from a peak of 5.4 percent in June 2006. An additional indicator of slightly slowing growth is in residential building permits in Utah, which declined 9 percent in 2006 from the 2005 level. Statistics from the Bureau of Economic and Business Research at the University of Utah continue to show slowing when compared to 2006 through February 2007. This trend is also evident in PacifiCorp sales growth in Utah from 2006 into 2007. Taken together, these trends helped drive the slight slowing of the peak growth from a 3. percent average annual growth rate from 2007 to 2016 in the May 2006 forecast to a 2.9 percent average annual growth in the March 2007 forecast. From an energy perspective, the average annual load growth rate from 3.0 percent in the May 2006 forecast decreased to a 2.7 percent average annual growth rate for 2007 to 2016 in the March 2007 forecast. Regarding the energy forecast difference for Oregon, the March 2007 forecast is based on an expected lower growth rate for residential electric heating usage. This lower usage is causing an impact on energy while the coincident peak demand remains relatively unchanged. In addition long-term industrial retail sales are expected to be lower due to a further deterioration in the pa- per products and lumber industries in the west. This deterioration has less of an impact on peak weather responsive demand than on total energy. Table 4.8 - Changes from May 2006 to March 2007: Forecasted Coincidental Peak Load Me2awatts) Year Total VI"JD ' ."','," 2007 (182)(41)(76)(2)(43)(21) 2008 (338)(36)(36)(23)(4)(216)(23) 2009 (273)( 1 07)(254) 27 Mitchell, Lesley. "Utah's job growth rate stays ahead of nation.Salt Lake City Tribune. April 17, 2007. hUp:!!w""w.sltrib.com!search/ci 5691499 PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Year 2010 2011 2012 2013 2014 2015 2016 (21 (53) (13 ) (20) (56) ( 167) ( 140) AAG 2007-2016 AAG 2016-2026 (0.3)%\ 0.2 % ! 6)0'(0,9)0/0 (0.1)% (0.5Y:,0 1.2%2.3% Table 4.9 - Changes from May 2006 to March 2007: Forecasted Load Growth(A tt )verae;e e:sawa . Year Total OR/.WV CA --UT0 " In, 2007 (49)(21)(1)(25)(8) 2008 (l01)(34)(1)(67)(7) 2009 (70)(12)(9)(l)(62)(13) 2010 (4)(20)(65)(12) 2011 (26\152 (75)(10) 2012 C'"192 (93)(11)J5) 2013 (40)222 (107)(11) 2014 (47)242 (117)(12) 2015 109 - '1)277 (121\(l 1 ) 2016 128 (67)315 (0)026)(12) ..i ,. ,:, ---. ,.,.:. " AAG 2007-2016 (0.4)%0 ")0/(0,1)%, ( .. , /0 AAG 2016-2026 01)1"1.0%(O.2)!~'()(0.2)% EXISTING RESOURCES In 2007 PacifiCorp owns, or has interest in, resources with a system peak capacity of 12 131 megawatts. Table 4.10 provides anticipated system peak capacity ratings by resource category as of July 2007. Table 4.10 - Capacity Ratings of Existing Resources ResotlrceT Pulverized Coal Purchases Gas-CCCT MW* Percent097 50.836 15.1 %698 14. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment MW*Percerit .385 3.556 12.233 1.173 1.4%153 1.3% Total 12 131 100% * Represents the capacity available at the time of system peak. ** Purchases constitute contracts that do not fall into other categories such as hydroelectric, renewables, and natural gas. *** Renewables capacity reflects the capacity contribution at the time of peak load. ResourceT e Gas-SCCT droelectric Interru tible Renewable *** Class 1 DSM Thermal Plants In June 2006, the company converted the Currant Creek facility from a single cycle combustion turbine to a combined cycle combustion turbine, which increased the capability of the plant by 231 megawatts. The Lake Side combined cycle combustion turbine is expected to begin com- mercial operation in June 2007, adding 535 megawatts of additional capacity to the system. The lease for the West Valley plant expires in May 2008, reducing the company s total thermal plant capacity by 202 megawatts. Appendix A, Table A.12, provides operational characteristics of thermal plants and other generation resources for which PacifiCorp has an ownership interest. Renewables PacifiCorp is committed to renewable energy resources as a viable, economic and environmen- tally prudent means of generating electricity. PacifiCorp s renewable resources, presented by resource type, are described below. Wind PacifiCorp acquires wind power from PacifiCorp-owned wind plants and various purchase agreements. For the year ended December 31 , 2006, PacifiCorp received 118 610 megawatt- hours from an owned wind project. In the same period, 394 973 megawatt-hours were purchased from other wind projects. Since the 2004 Integrated Resource Plan, PacifiCorp has acquired large wind resources at Lean- ing Juniper 1 in Oregon (100.5 megawatts) and Marengo (140.4 megawatts) in Washington. Leaning Juniper was acquired in November 2006, while Marengo is expected to come on line in 2007. The company also entered into a 20-year power purchase agreement for the total output at the Wolverine Creek plant in Idaho (64.5 megawatts). PacifiCorp also has wind integration, storage and return agreements with Bonneville Power Ad- ministration, Eugene Water and Electric Board, Public Service Company of Colorado, and Seat- tle City Light. For the year ended December 31 , 2006, electricity under these agreements totaled 552 835 megawatt-hours in addition to the wind energy generated or purchased for PacifiCorp own use. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Geothermal PacifiCorp owns and operates the Blundell Geothermal Plant in Utah, which uses naturally cre- ated steam to generate electricity. The plant has a net generation capacity of 23 megawatts. Blundell is a fully renewable, zero-discharge facility. The bottoming cycle, which will increase the output by 11 megawatts, is currently under construction and is expected to be in service by the end of 2007. Biomass Since the 2004 IRP, PacifiCorp has acquired power through power purchase agreements, as well as from several small biomass facilities under Qualifying Facility Agreements, Examples include the 20 megawatt Roseburg Lumber power purchase agreement and the 10 megawatt Freres Lum- ber power purchase agreement. Solar PacifiCorp has invested in Solar II, the world's largest solar energy plant, located in the Mojave Desert, and continues to assess the economic viability of such solar resources. At present, absent state-specific incentives, central-station solar resources continue to appear uneconomic when compared to other renewable resource alternatives. However, advances in solar technology can reasonably be expected to continue, and state-specific incentives may result in economic projects for consideration. Regarding distributed photovoltaic (PV) applications, the company has installed panels of photo- voltaic (PY) cells in its service area, including The High Desert Museum in Bend Oregon PacifiCorp office in Moab, Utah, an elementary school in Green River, Wyoming, and has worked with Jackson County Fairgrounds and the Salt Palace in Salt Lake City, Utah on photo- voltaic solar panels. Other locations in the service territory with solar include a 60 unit apartment in Salt Lake City, Utah and the North Wasco School district at Mosier, Oregon. Currently, there are 410 net meters throughout the company, mostly residential, and most have solar technology followed by wind and hydroelectric. Hydroelectric Generation PacifiCorp owns or purchases 1 556 megawatts of hydroelectric generation. These resources account for approximately 13 percent of PacifiCorp s total generating capability, in addition to providing operational benefits such as flexible generation, spinning reserves and voltage control. Hydroelectric plants are located in California, Idaho, Montana, Oregon, Washington, Wyoming, and Utah. The amount of electricity PacifiCorp is able to generate from its hydroelectric plants is depend- ent upon a number of factors, including the water content of snow pack accumulations in the mountains upstream of its hydroelectric facilities and the amount of precipitation that falls in its watershed. When these conditions result in above average runoff, PacifiCorp is able to generate a higher than average amount of electricity using its hydroelectric 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. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment PacifiCorp has added approximately 10 megawatts of additional capacity to its hydroelectric portfolio since the release of the 2004 IRP. This additional capacity is the result of turbine up- grades at its lC. Boyle hydroelectric plant. Demand-side Mana2ement Demand-side management programs vary in their dispatchability, reliability of results, term of load reduction benefit and persistence over time. Each has its value and place in effectively man- aging utility investments, resource costs and system operations. Those that have greater persis- tence and firmness (can count on them to be delivered) can be relied upon as base resources for planning purposes; those that do not are well-suited as system reliability tools only. 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. These programs are divided into four general classes. Class 1 DSM: Fully dispatchable or scheduled firm - Class 1 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 programs, 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 dis- patchable in nature and irrigation load management and interruptible or curtailment programs (scheduled firm). Class 2 DSM: Non-dispatchable, firm energy efficiency programs - Class 2 programs are those for which energy and capacity savings are achieved through facilitation of technologi- cal advancements in equipment, appliances, lighting and structures. These types of programs provide an incentive to customers to replace existing customer owned facilities (or to up- grade in new construction) to more efficient lighting, motors, air conditioners, insulation lev- els, windows, etc. Savings will endure over the life of the improvement (firm). Program ex- amples include air conditioning efficiency programs ("Cool Cash"), comprehensive commer- cial and industrial new and retrofit energy efficiency programs ("Energy FinAnswer ) and re- frigerator recycling programs ("See ya later refrigerator Class 3 DSM: Price responsive programs - Class 3 DSM programs seek to achieve short- duration (hour by hour) energy and capacity savings from actions taken by customers volun- tarily, based on a financial incentive or penalty. Savings are measured at a customer-by- customer level (via metering), and customers are compensated or charged in accordance with a program s pricing parameters. As a result of their voluntary nature, savings are less predict- able, making them less suitable to incorporate into resource planning exercises, at least until such time that their size and customer behavior profile provide sufficient information to con- struct a diversity factor suitable for modeling purposes. Savings endure only for the duration of the incentive offering 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: Energy efficiency education and non-incentive based voluntary curtail- ment programs - These programs represent energy and capacity reductions achieved PacifiCorp 2007 lRP Chapter 4 - Resource Needs Assessment through behavioral actions by customers in response to their desire to reduce their energy demands and costs, or voluntary compliance with a company request to conserve or shift their usage to off peak hours. Program savings are difficult to measure and aren t actively tracked in most cases. As a result, they can t be relied upon for planning purposes. The value of Class 4 DSM is longer-term in nature. Class 4 programs help foster an understanding and appreciation as to why utilities seek customer participation in Class 1-3 programs. Program examples include Utah's PowerForward program, company brochures with energy savings tips, customer news, letters focusing on energy efficiency, case studies of customer energy ef- ficiency projects, and public education and awareness programs such as "Do the bright thing. " PacifiCorp has been operating successful DSM programs since the late 1980s. While the com- pany s DSM focus has remained strong over this time, 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 pursued (Classes 1-4) and resource planning considerations. Company investments have increased four times (from $50 million to $200 million) over the last five years (2002-2006) compared to the preceding five years (1997-2001) as the company has expanded DSM activity in the states of Utah, Washington and Idaho and transitioned existing DSM activi- ties in Oregon over to the Energy Trust of Oregon. The company is currently working with the state of Wyoming on a DSM application which seeks to expand company investments in Wyoming and which was filed in December 2006 and, is pending Commission approval by May 2007. Additionally, the company is working to expand DSM programs in California and is preparing a DSM application with expanded program offer- ings for filing with the California Public Utilities Commission in May 2007. In addition, the company has recently introduced new programs such as the Home Energy Savers program in Idaho, Washington, Utah and soon Wyoming and California, as well as expanding the Idaho irri- gation load management program into Utah for the 2007 summer season. The following repre- sents a brief summary of the existing resources by class. Appendix A provides a detailed list of existing DSM programs available and resource targets for Classes 1 through 3. Class 1 Demand-side Management There are currently three types of Class 1 programs in operation. Utah's "Cool Keeper" residen- tial and small commercial air conditioner load control program provided nearly 80 megawatts of dispatchable load control (at the generator) during the summer of 2006 and is expected to deliver the anticipated 90 megawatts by summer 2007. Idaho s irrigation load management program achieved 55 megawatts of "scheduled" relief during the summer of 2006 and has recently added a "dispatchable" event option to compliment the "scheduled" options in an effort to increase that amount in 2007. As noted above, the company has expanded the "schedule" option to Utah be- ginning in 2007. First-year participation is expected to be modest; however, the company hopes to grow the program overtime to 15 megawatts. In addition to these two programs, the company has 233 megawatts of firm curtailable resources under contract with a select set of large indus- trial customers. Contracted curtailable loads are expected to increase to 308 megawatts by 2009. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Class 2 Demand-side Management The cumulative historical energy and capacity savings (1992-2006) associated with Class 2 DSM resource acquisitions are over 300 average megawatts of energy and 390 megawatts respectively (at the generator). The company projects that through the 2016 planning period, existing Class 2 programs will yield, on average, an additional 23 MWa and 30 megawatts each year in energy and capacity reductions , respectively. The company is actively seeking new Class 2 programs and improvements to existing programs in an effort to nearly double this amount, provided those resources can be acquired cost-effectively. Class 3 Demand-side Management The company has numerous Class 3 programs currently available. They include metered time-of- day and time-of-use pricing plans (in all states, availability varies by customer class), a seasonal inverted rate program (Utah), year-around inverted rate programs (Oregon, Washington and California) and Energy Exchange programs (Oregon, Utah and Washington). Savings associated with these programs are captured within the company s load forecast, with the exception of the Energy Exchange program. The impacts of these programs are thus captured in the integrated resource planning framework. Future savings associated with new programs, or added savings of existing programs, are relied upon as reliability resources as opposed to base resources. Current system-wide participation in metered time-of-day and time-of-use programs exceeds 23 000 cus- tomers, up from 15 000 in 2004. Approximately 1.25 million residential customers-89% of the company s residential customer base-are currently subject to inverted rate plans either season- ally or year-around. PacifiCorp continues to evaluate Class 3 programs for applicability to long-term resource plan- ning. As discussed in subsequent chapters, a variety of these programs were included as resource options in scenario modeling. Class 4 Demand-side Management Educating customers regarding energy efficiency and load management opportunities is an im- portant component of the Company s long-term resource acquisition plan. A variety of channels are used to educate customers including television, radio, newspapers, bill inserts, bill messages newsletters, school education programs, and personal contact. Specific firm load reductions due to education will show up in other Class 4 DSM program results and changes in the load forecast over time. Table 4.11 summarizes the existing DSM programs, and describes how they are accounted for as a planned resource. Table 4.11 - Existing DSM Summary, 2007-2016 Descri tion Residential/small commer- cial air conditioner load control Irrigation load mana ement Interru tible contracts Energy Savings or Capacity at Generator 100 MW summer peak .InCluded as Base Resources for 2007 -2016 ,Period Yes 55 MW summer peak Yes 233 MW buildin to 308 MW Yes PacifiCorp 2007 IRP :fJlfogram, , ' !'Class. : " Company and Energy Trust of Ore on ro rams Historic acquisitions to- wards 450 MWa (2004- 2006 onl Energy Exchange 65 MW 95 MWa and 123 MW Time-based pricing MWa/MW unavailable 000 customers MW a/MW unavailable 25 million residential 0- 78 MW summer peak Inverted rate pricing PowerForward Energy Education MW a/MW unavailable Chapter 4 - Resource Needs Assessment " :, Included'asBaseResources'~(h'~ . 2007,;2016.Pel'iod . ' , captured as decrement to future load forecast No, accounted for in load forecast- Ing , leveraged as economic and reliability resource dependent on market rices/s stem loads , historical behavior captured in load forecast , historical behavior captured in load forecast , leveraged as economic and reliability resource dependent on market rices/s stem loads , captured in load forecast over time and other Class 1 and Class 2 ro ram results Contracts PacifiCorp obtains the remainder of its energy requirements, including any changes from expec- tations, through 10ng-tenn firm contracts, short-term firm contracts, and spot market purchases. Listed below are the major contract expirations occurring within the next 10 years. The 202 megawatt West Valley lease expires in May 2008 The 400 megawatt power purchase agreement with TransAlta Energy Marketing expires in June 2007 The 575 megawatt BP A peaking contract expires in August 2011 Figure 4.1 presents the contract capacity in place for 2007 through 2016 as of April 2006. As shown, major capacity reductions in purchases and hydro contracts occur. (For planning pur- poses, PacifiCorp assumes that current Qualifying Facility and interruptible load contracts are extended to the end of the IRP study period.) Note that renewable wind contracts are shown at their capacity contribution levels. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Figure 4.1 - Contract Capacity in the 2007 Load and Resource Balance 000 m Purchase 0 Hydro 500 0 Interruptible .OF 500 m Renewable 000 ~ 1 500 000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Figure 4.2 shows the year-to-year changes in contract capacity. Early year fluctuations are due to changes in short-term balancing contracts of one year or less, and expiration of the contracts cited above. Figure 4.2 - Changes in Contract Capacity in the Load and Resource Balance 400 200 iii Purchase (200) (400) (600)0 Hydro 0 Interruptible .aF(800) 000)iii Renewable 200) 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment LdAj),,~D;,RESO URC:EBAL~C~ Capacity and Ener!!v Balance Overview The purpose of the load and resource balance is to compare the annual obligations for the first ten years of the study period with the annual capability ofPacifiCorp s existing resources, absent new resource additions. This is done with respect to two views of the system, the capacity bal- ance and energy balance. The capacity balance compares generating capability to expected peak load at time of system peak load hours. It is a key part of the load and resource balance because it provides guidance as to the timing and severity of future resource deficits. It was developed by first determining the system coincident peak load hour for each of the first ten years (2007-2016) of the planning hori- zon. The peak load and the firm sales were added together for each of the annual system peak hours to compute the annual peak-hour obligation. Then the annual firm-capacity availability of the existing resources was determined for each of these annual system peak hours. The annual resource deficit (surplus) was then computed by multiplying the obligation by the planning re- serve margin, and then subtracting the result from the existing resources. The energy balance shows the average monthly on-peak and off-peak surplus (deficit) of energy over the first ten years of the planning horizon (2007-2016). 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 type of resource will 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 are addressed with the studies and results of those studies described in Chapters 6 and 7 respectively. 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, obliga- tion, reserves, position, and reserve margin. This section provides a description of these various components. Existing Resources The firm capacities of the existing resources by resource category are summed to show the total available existing resource capacity for the east, west and for the PacifiCorp system. A descrip- tion of each of the resource categories follows: Thermal - This includes all thermal plants that are wholly-owned or partially-owned by PacifiCorp. The capacity balance counts them at maximum dependable capability at time of system peak. The energy balance also counts them at maximum dependable capability, but derates them for forced outages and maintenance. This includes the existing fleet of 11 coal- fired plants, four natural gas-fired plants, and two co-generation units. These thermal re- PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment sources account for roughly two-thirds of the firm capacity available in the PacifiCorp sys- tem. Hydro - This includes all hydroelectric generation resources operated in the PacifiCorp sys- tem as well as a number of contracts providing capacity and energy from various counterpar- ties. The capacity balance counts these resources by the maximum capability that is sustain- able for one hour at time of system peak. The energy associated with critical level stream flow is estimated and shaped by the hydroelectric dispatch from the Vista Decision Support System model. Over 90 percent of the hydroelectric capacity is situated on the west side of the PacifiCorp system. Demand-side Management (DSM) - There are about 160 megawatts of Class 1 demand- side management programs included as existing resources. Both the capacity balance and the energy balance count DSM programs by program capacity. DSM resources directly curtail load and thus planning reserves are not held for them. Renewable - This category contains two geothermal plants (the existing Blundell plant with the bottoming-cycle upgrade, and the Cove Fort project), eight existing wind projects and three planned wind projects from the MEHC commitments. The capacity balance counts the geothermal plants 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 determined in a wind capacity planning contribution study (Appen- dix J). Wind energy is counted according to hourly generation data used to model the pro- jects. Purchase - This includes all ofthe major contracts for purchases of firm capacity and energy in the PacifiCorp system. The capacity balance counts these by the maximum contract avail- ability at time of system peak. The energy balance counts the optimum model dispatch. Pur- chases are considered firm and thus planning reserves are not held for them. Qualifying Facilities (QF) - All Qualifying Facilities that provide capacity and energy are included in this category, Like other power purchases, the capacity balance counts them at maximum system peak availability and the energy balance counts them by optimum model dispatch. It is assumed that all Qualifying Facility agreements will stay in place for the entire duration of the 20-year planning period. It should be noted that three of the Qualifying Facil- ity resources (Kennecott, Tesoro and US Magnesium) are considered non-firm and thus do not contribute to capacity planning. Interruptible - There are three east-side load curtailment contracts in this category. These agreements with Monsanto, MagCorp and Nucor provide about 300 megawatts of load inter- ruption capability at time of system peak. Both the capacity balance and energy balance count these resources at the level of full load interruption on the executed hours. Interruptible resources directly curtail load and thus planning reserves are not held for them. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Obligation The obligation is the total electricity 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 loads of the load forecast. De- scribed in the beginning of this chapter the load forecast is an hourly description of electric loads in the PacifiCorp system for the 20-year IRP study period (2007-2026). The capacity balance counts the load (MW) at the hour of system coincident peak load. The energy bal- ance counts the load as an average of monthly time-of-day energy (MWa). Sales - This component 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 for the capacity balance. Note that for the 2007 IRP there was a reporting change for the delivery portion of exchange contracts. Exchange contract deliveries are no longer reported in the Purchase and Renewable components as was done for the 2004 IRP and 2004 IRP Update. These delivery amounts now appear in the Sales component. Reserves The reserves are the total megawatts of planning and non-owned reserves that must be held for this load and resource balance, A description of the two types of reserves follows: Planning reserves - This is the total reserves that must be held to provide the planning re- serve margin?8 It is the net firm obligation multiplied by the planning reserve margin as in the following equation: Planning reserves (Obligation Purchase DSM Interruptible) x PRM Non-owned reserves - There are a number of counterparties that operate in the PacifiCorp control areas that purchase operating reserves. This amounts to an annual reserve obligation of about 7 megawatts and 71 megawatts on the west and east-sides, respectively. Position The position is the resource surplus (deficit) resulting from subtracting the existing resources from the obligation. 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 will be presented in their respective sections. Reserve Margin The reserve margin is the ratio of existing resources to the obligation. A positive reserve margin indicates that existing resources exceeds obligation. Conversely, a negative reserve margin indi- 28 PacifiCorp models operating reserve requirements, which are based on minimum WECC Operating Reserves that cover Contingency Reserves and Regulating Reserves. PacifiCorp also includes incremental reserves for supporting wind, which is documented in Appendix 1. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment cates that existing resources do not meet obligation. If existing resources equals the obligation then the reserve margin is zero percent. It should be pointed out that the reserve margin can be negative when the corresponding position is non-negative. This is because the reserve margin is measured relative to the obligation, while the position is measured relative to the obligation plus reserves. Cauacitv 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 planning horizon. Then the annual firm-capacity availability of the existing resources is determined for each of these annual system peak hours and summed as follows: Existing Resources Thermal Hydro DSM Renewable Purchase 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 must then be calculated. This is done by first removing the firm purchase and load curtailment components of the existing resources from the obligation. This resulting net obligation 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 Purchase DSM Interruptible) x PRM Non-owned reserves Finally, the annual capacity position is then computed by adding the computed reserves to the obligation and then subtracting the existing resources as in the following formula: Capacity Position Existing Resources Obligation Reserves Load and Resource Balance Assumptions The assumptions underlying the current load and resource balance are generally the same as those from the 2004 IRP Update with a few exceptions. The following is a summary of these assumption changes. Front Office Transactions - For the 2007 IRP, front office transactions were taken out of the existing load and resource balance in order to treat them as potential resources that the Capacity Expansion Module can pick from. This was done in order to treat the front office transactions on a comparable basis to other supply-side resources. . Wind Commitment - In the 2004 IRP Update, 1 400 megawatts of wind were included as planned resources in the initial load and resource balance. For the 2007 IRP, 400 megawatts of the overall 1,400-megawatt commitment are included in the initial load and resource bal- PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment ance. The remaining 1 000 megawatts are treated as part of the overall wind resource poten-tial evaluated in portfolio modeling. Clark County Load Service Contract - In the 2004 IRP Update, the Clark County load service contract including the River Road combined-cycle gas resource was modeled. This contract ends in 2007 and affects little of the 20-year planning horizon. Also, the energy from the component resources and load obligation balances out. Thus, this contract is not part of this load and resource balance. Planning Reserve Calculation for Firm Transactions and Load Curtailment Contracts - In the 2007 IRP, the company represents front office transactions as firm purchases. Consis- tent with current market practices, the seller, rather than the company as the purchaser, car- ries the operating reserve obligation.29 Load curtailment contracts and DSM programs di- rectly reduce firm load. Thus, the planning reserve margin is not applied to firm purchases DSM programs and interruptible resources. This was not done in the 2004 IRP Update. Non-owned Reserves - The 2007 IRP includes the modeling of capacity obligation resulting from the holding of reserves for counterparties within the PacifiCorp control areas. This was not done in the 2004 IRP Update. Planning Reserve Margin - The planning reserve margin is the generating capability that exceeds the expected peak load for each year. The 2004 IRP and 2004 IRP Update assumed a 15 percent planning reserve margin. However, the 2007 IRP considers resource portfolios at 12 and 15 percent levels. PacifiCorp views this percentage range as a prudent and reasonable range for planning purposes when considering both supply reliability and economic impact to customers. Capacity Balance Results Table 4.12 shows the annual capacity balances and component line items using a planning re- serve margin of 12 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 dis- patched on a system basis.) For comparison purposes, Table 4.13 shows the system-level capac- ity balance assuming a 15 percent planning reserve margin. Figures 4.3 through 4.5 display the annual capacity positions (resource surplus or deficits) for the system, west control area, and east control area, respectively. The associated obligation with both 12 and 15 percent planning reserve margins are shown. The decrease in resources in 2008 is caused by the expected expiration of the West Valley lease agreement. The slight increase in 29 Recently, there have been proposals made to the Western Electricity Coordinating Council board of directors to change the current market practice that would require the operating reserve obligation to be calculated based on the load serving entity s load, and the obligation would be independent of purchases or sales. If this change is adopted the company will need to modify its assumptions in future integrated resource plans to calculate the operating re- serve obligation based on its load.30 To provide context, note that the IRP Benchmarking Study in Appendix C of the 2004 IRP Update identified numerous planning reserve margins used by utilities that range from 11 to 20 percent. Also, the Pacific Northwest Resource Adequacy Forum recently developed a regional pilot capacity adequacy standard that included a 19 per- cent planning reserve margin for summer peak planning for the Pacific Northwest. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment 2009 is due to executed front office transactions and an increase in the curtailment portion of the Monsanto contract. The large decrease in 2012 is primarily due to the expiration of the BP peaking contract in August 2011. Additionally, Figure 4.4 highlights a decrease in obligation in the west starting in 2014. This is due to the expiration of the Sacramento Municipal Utility Dis- trict and City of Redding power sales contracts. Table 4.12 - Capacity Load and Resource Balance (12% Planning Reserve Margin) Calendar Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 East Thermal 134 941 941 941 941 941 941 941 941 941 Hydro 135 135 135 135 135 135 135 135 135 135 DSM 153 163 163 163 163 163 163 163 163 163 Renewable 109 109 109 109 109 109 109 105 105 Purchase 904 679 778 548 543 343 343 343 343 322 106 106 106 106 106 106 106 106 106 106 Interruptible 233 233 308 308 308 308 308 308 308 308 East Existing Resources 730 366 540 310 305 105 105 105 101 080 Load 321 515 657 137 289 595 738 895 026 366 Sale 849 811 702 666 631 595 595 595 595 595 East Obligation 170 326 359 803 920 190 333 8,490 621 961 Planning reserves 706 750 733 814 829 885 902 921 937 980 Non-owned reserves East Reserves 776 821 804 885 899 956 973 992 007 051 East Obligation + Reserves 946 147 163 688 819 146 306 9,482 628 012 East Position (217)(781)(623):378)514)041)(2.20'(2.:377)(2.528)(2.932) East Reserve Margin 13%14%16%17%21% West Thermal 046 046 046 046 046 046 046 046 046 046 Hydro 1,421 1,421 1,414 328 357 225 249 243 244 242 DSM Renewable 108 108 108 108 108 Purchase 786 800 800 799 749 112 141 107 107 107 West Existing Resources 4,401 4,415 4,408 321 300 506 558 519 519 518 Load 922 924 095 124 199 240 251 262 271 252 Sale 299 299 299 290 290 258 258 258 158 108 West Obligation 221 223 394 3,414 3,489 3,498 509 520 3,429 360 Planning reserves 292 291 311 314 329 406 404 409 399 390 Non-owned reserves West Reserves 299 297 318 320 335 413 411 416 405 397 West Obligation + Reserves 520 520 712 734 824 911 920 936 834 757 West Position 881 895 696 587 476 (405)(362)(417)(3'14)(239) West Reserve Margin 39%40%33%29%26% System Total Resources 12,131 780 948 631 605 10,611 10,663 624 10,620 10,598 Obligation 10,391 549 753 217 11,409 688 842 12,010 12,050 321 Reserves 075 118 122 205 234 369 384 1 ,408 1,412 1,447 Obligation + Reserves 11,466 667 874 12,421 643 057 226 13,417 13,462 768 System Position 665 113 (791)(1,033)(2,446)563)(2794)(2842)(3,171) Reserve Margin 18%13%13%10%11%12%14% PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Table 4.13 - System Capacity Load and Resource (15% Planning Reserve Margin) Calendar Year 2010 2011 2012 2013 2014 2015 2016 $yst~m. " Total Resources 11,948 631 605 10,624 10,620 10,598 Obligation 391 10,549 10,753 217 11,409 688 11,842 010 12,050 12,321 Reserves 324 378 383 1 ,487 524 691 710 740 746 790 Obligation + Reserves 715 927 136 703 12,932 380 552 13,750 13,796 111 System Position 415 (147)(188)073)327)(2,768)890)(3,126)(3,176)513) Reserve Margin 19%14%13%11%11%14% Figure 4.3 - System Coincident Peak Capacity Chart 000 Obligation + Reserves (15%) 12,000 ObHgation + Reserves (12%) 000 000 000 000 Existing Resources 000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Resources 131 780 948 11 ,631 605 611 663 624 10,620 598 Obligation +Reserves 11,466 667 874 421 643 057 226 417 462 13,768 12% PRM Obligation +Reserves 715 927 136 703 932 380 552 750 796 111 15%PRM 12% System 665 113 (7() I)038)(2.446)(2,563)(2,794)(2,1\42)(3,171) Position 15% System 415 (147)(188)(l,on)(1327)(2,768)890)(3,126)(3,176)513) Position PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Figure 4.4 West Coincident Peak Capacity Chart 14,000 12,000 10,000 000 000 000 000 West Obligation + Reserves (i 5%) West Obligation + Reserves (12%) Existing Resources 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Resources 401 415 4,408 321 300 506 558 519 519 518 Obligation + Reserves 520 520 712 734 824 911 920 936 834 757 12% PRM Obligation +Reserves 593 593 789 812 906 013 021 038 933 854 15% PRM 12% PRM 881 895 696 587 476 (405)(362)(417)(314)(239)Position 15%PRM 808 822 618 509 394 (506\(463)1519)(414)(336)Position PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Figure 4.5 - East Coincident Peak Capacity Chart 000 12,000 10,000 000 ::E 000 000 East Obligation + Reserves (15%) East Obligation + Reserves (12%) Existing Resources 000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Resources 730 366 540 310 305 105 105 105 101 080 Obligation + Reserves 946 147 163 688 819 146 306 482 628 012 12% PRM Obligation + Reserves 123 334 346 891 027 367 531 712 863 257 15%PRM 12%PRM (217)(78!)(623i (j , :r7K)(1,514)(2.041)(2,201)37'7)(2.528)(2,932)Position 15%PRM (3'13)(969)(806)(1.58 J)(un)262)(2A27)(2/)07)(2,762)(3.177)Position PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Enen!v Balance Determination Methodology The energy balance shows the average monthly on-peak and off-peak surplus (deficit) of energy. The on-peak hours are weekdays and Saturdays from hour-ending 7:00 am to 10:00 pm; off-peak hours are all other hours. The existing resource availability is computed for each month and daily time block without regard to economic considerations. 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 DSM Renewable Purchase QF Interruptible The average obligation is computed using the following 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 (I2% PRM) Enen!v Balance Results Figures 4.6 through 4.8 show the energy balances for the system, west control area, and east con- trol area, respectively. They show the energy balance on a monthly average basis across all hours, and also indicate the average annual energy position. The cross-over point, where the sys- tem becomes energy deficient on an average annual basis, is 2009, absent any economic consid- erations. PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Figure 4.Average Monthly and Annual System Energy Balances 000 500 000 500 :;: (500) (1.000) 500) (2,000) (2,500) (3/100) 500) Annual Balance -Monthly Balance ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 000 0 ~ ~ ~ ~.~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 Figure 4.Average Monthly and Annual West Energy Balances 000 500 000 500 :;: (SOD) i1,OOO) 500) (2000) (~'.500) (3,000) 500) to., ~ ~ ~ ~~ ~~ ~ ~ ~ooo o~ ~ ~ ~~~~~~ ~~~ ~ ~ ~ ~~~~~~ ~~ 0 0 0 0 0 0 0 0 0 0 0 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ a ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 PacifiCorp 2007 IRP Chapter 4 - Resource Needs Assessment Figure 4.8 - Average Monthly and Annual East Energy Balances 000 500 000 500 :;: (500) 000) (1,51)0) (2.01:'0) (2.500) (3.fJOO) 500) Annual Balance Monthly Balance ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ a a a a ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ a a a a a a a a a a a a ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ .. ~ .. ..~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 Load and Resource Balance Conclusions The company projects a summer peak resource deficit for the PacifiCorp system beginning in 2008 to 2010, depending on the planning reserve margin assumed. The PacifiCorp deficits prior to 2011 to 2012 will be met by additional renewables, demand side programs, and market pur- chases. The company will consider other options during this time frame if they are cost-effective and provide other system benefits. This could include acceleration of a natural gas plant to com- plement the accelerated and expanded acquisition of renewable wind facilities. Then beginning in 2011 to 2012, base load, intermediate load, or both types of resource additions will be neces- sary to cover the widening capacity and annual energy deficits. The capacity balance at a 12 per- cent planning reserve margin indicates the start of a deficit beginning in 201 O-the system is short by 791 megawatts. This capacity deficit increases to 2 400 megawatts in 2012 and then to almost 3 200 megawatts in 2016. On an annual basis, and disregarding economic considerations the company becomes deficit with respect to energy by 2009. PacifiCorp 2007 IRP Chapter 5 - Resource Options 5. RESOURCE OPTIONS ~ ".. , , , .Foruseinportfolibin()deling,PacifiCorPpev~lqped coS dper.formanceprofil~$fQf supply--side ,reSoU1'ccs,detnand,"side;.Ihan~geIl1~tlt progr~s , ' JI'allsmission ej(pansion ~ pmjects andmarket purchases(fr(:)~t\offjgetr~m~ 'ons) , ~ ~" . ghlights , , , '" , ," ,.. ~~ '", PacifiCorpused4heE lect1ic;,.I?Qw..~t"B-~sea;I'c4.In$tltutc~~irechnica.l". A~sess11lenf;~uic.l~ , (TAG(ID) ,along. with,reQen t.;pr()j~ct;..c~pAri ent:~:~..~P;c()i1stiltagtstudies ' , to"d~ v~!OP its , supply-:side' resource options. 'The.lisJ:()I )l1\GiJJ.foimatiqri,jsnewt(:)J?acifiCorp s j~te- grated resource plamiingprocess. ,~ / ' ~" ~~ ~ Also new to the "colllpa1).Y's ,, int~gratedplanningproce$~.~:i.s,the"e~tit11ation.andllse~o:f capital cost ranges foreac;hsuppJy..side"qptiog.)J)l1esecost, rallgesreflect c()stuncer- ta.in ty ,and 'their use, ill thi~pl*g~qk11p~1 edge:$.the.sigrtifi9 atl~.Qon~tructiqli ,q()s(iIl:: creases taking place. ~ , ~~ ~' ",, "' ,~ , ' The company cominissioIledQll'\.1:1;tegIQijp .toc()p$tructpr()~ysllPply, curves forQl~ss 1 (fullydi~patchable " sc~edllle.dr1flIi)..;agd qJ~ss3' , (pp., c;e-responsive)' deiI1€1,IlP-side mana,gementprograms, , ~ ~, ' ~ The 'companydevelqpedtraIlsTI1issio1il'esoufc;es t&~upport' new ,genetation"oI)tt()ns" 10 enhal1ce transfer 'capabilityalldreliabilij:yacrqss::&~2ifiCorp , s ;;' systelp,andto):,oost im port! export' capabilitywith~,espeCt toe~tema.lmafkets;Thesetransfuissi()nfesources were entered as optionsinPacifiCorp scapacij:y,eJCpansioii optimizati()rftool and, were thus ,allowed to 'compete directly with othefresotircesfot inclusi6n in portfolios. INTRODUCTION This chapter provides background information on the various resources considered in the IRP for meeting future capacity and energy needs. Organized by major category, these resources consist of supply-side generation, demand-side management programs, transmission expansion projects and market purchases. For each resource category, the chapter discusses the criteria for resource selection, presents the options and associated attributes, and describes the technologies. In addi- tion, for supply-side resources, the chapter describes how PacifiCorp addressed long-term cost trends and uncertainty in deriving cost figures. The chapter concludes with a discussion on the use and impact of physical and financial hedging strategies. PacifiCorp 2007 IRP Chapter 5 - Resource Options SUPPLY.,SID ERESO URCES Resource Selection Criteria The list of supply-side resource options has been reduced in relation to previous IRP resource lists to reflect the realities evidenced through previous studies and to help efficiently manage the computer processing time involved in developing detailed portfolios. For instance, subcritical pulverized coal resources are not included since it is felt than any new, large (greater than 500 megawatts) pulverized coal plant will utilize a supercritical boiler based on the increased effi- ciency and superior environmental performance of the supercritical designs. Similarly, natural gas based options based on smaller, less efficient combustion turbines have not been included since previous IRP exercises have demonstrated that the superior heat rate and cost performance of larger combustion turbines will cause the larger machines to be selected over the smaller op-tions. Derivation of Resource Attributes The supply-side resource options were developed from a combination of resources. The process began with the list of major electrical generating resources from the 2004 IRP Update. This re- source list was reviewed and, in some cases, simplified. Once the basic list of resources was de- termined the cost and performance attributes for each resource was estimated. A number of in- formation sources were used to identify parameters needed to model these resources. PacifiCorp has conducted a number of engineering studies to understand the cost of coal and gas resources in recent years. Recent experience with the construction ofthe 2x1 combined cycle plants at Cur- rant Creek and Lake Side as well as other recent simple cycle projects at Gadsby and West Val- ley has provided PacifiCorp with insight into the current cost of new power generating facilities. For newer technologies (integrated gasification combined cycle (IGCC) plants and supercritical pulverized coal plants) a study performed by WorleyParsons was used along with internal studies to review the cost estimates of these resources. In order to refresh the modeling data used in the 2004 IRP Update, PacifiCorp purchased a li- cense to utilize the Electric Power Research Institute (EPRI) new resource data base called the Technical Assessment Guide(ID (TAG). The TAG contains information on capital cost, heat rate availability, and fixed and variable operating and maintenance cost estimates. The data in the TAG must be customized for each application by adjusting basic financial parameters as well as physical parameters for each potential site, such as coal quality, water availability, and elevation. The 2006 TAG data were used to develop a cost and performance profile for each potential re- source. The results of the TAG runs were compared to the actual cost data from recent projects as well as internal PacifiCorp studies of site specific generation options. The TAG results were customized to give results approximately in agreement to these recent studies. The customization was primarily done for capital costs, and reflects market conditions as of late spring of 2006. particular concern with the capital costs contained in the TAG database was the apparent lag in the TAG results in recognizing the recent trend of increases in capital costs for power generating equipment. It was apparent from numerous discussions with engineering and construction com- panies in the power industry that construction costs have increased substantially in the last two to three years. These increases, on the order of 25 to 35 percent with respect to the costs reported in the 2004 IRP Update, are due to increased construction activity stemming from shortages of PacifiCorp 2007 IRP Chapter 5 - Resource Options equipment, material, and skilled construction labor. The TAG numbers, in general, did not ad- dress this recent capital cost trend. The TAG methodology does allow for customization to ac- count for this increase. Therefore, costs were adjusted in the TAG to be consistent with other studies. Heat rate, availability, and operating and maintenance costs were, in general, calculated by the TAG. TAG runs were created for all technologies in the supply-side resource table except as noted be- low for combined heat and power plants. Handlin!! of Technolo!!v Improvement Trends and Cost Uncertainty As mentioned above, the capital cost uncertainty for many of the proposed projects is increasing. Additionally, some technologies, such as IGCC , have a greater uncertainty because only a few demonstration units have been built and operated. A range of estimated capital costs is displayed in the supply-side resource options table. This range of capital cost was adjusted by factors re- flecting the potential cost of various technologies as compared to a combined cycle natural gas plant. The combined cycle natural gas plant is the easiest technology to predict capital costs for since there is less field labor and PacifiCorp has recent (Currant Creek) and on-going (Lake Side) experience with this kind of project. The cost factors used to reflect technology risk in the uncertainty range for various resource op- tions were taken from a U.S Energy Information Administration paper "Assumptions to the An- nual Energy Outlook 2006, DOE/EIA-0554(2006), March 2006". In addition to the technology factors the TAG capital cost estimates were adjusted by 5 percent on the low end and 10 percent on the high end to give an overall range. There is a potential for future relative cost decreases for certain technologies such as IGCC. As the technology matures and more plants are built and operated the costs of such new technolo- gies may decrease relative to more mature options such as pulverized coal. The supply-side op- tions table does 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 are not expected to be available until after 2020 and future IRPs will be able to incorporate the benefit of such future cost reductions. Resource Options and Associated Attributes Tables 5.1 and 5.2 present cost and performance attributes for supply-side resource options des- ignated for PacifiCorp s east and west control areas, respectively. Tables 5.3 and 5.4 present the total resource cost attributes for supply-side resource options, and are based on estimates of the first-year reallevelized cost per megawatt-hour of resources, stated in June 2006 dollars. Options included in PacifiCorp s IRP models are highlighted. As mentioned above, the attributes were mainly derived from the EPRI TAG database with certain technologies adjusted to be more in line with PacifiCorp s recent cost studies and project experience. Cost and performance values reflect analysis concluded by July 2006. Additional explanatory notes for the tables are as fol- lows: The second 600-megawatt Utah supercritical pulverized coal resource is modeled as a 340- megawatt share to emulate the Intermountain Power Project acquisition opportunity. PacifiCorp 2007 IRP Chapter 5 - Resource Options Capital costs are intended to be all-inclusive, and account for Allowance for Funds Used During Construction (AFUDC), land, EPC (Engineering, Procurement, and Construction) cost premiums, owner s costs, etc. Capital costs in Tables 5.1 and 5.2 reflect mid-2006 cur- rent dollars, and do not include escalation from the current year to the year of commercial operation. Wind sites are modeled with differing peak load carrying capability levels. These levels are reported for each wind site in the Wind Capacity Planning Contribution section of Appendix For customer-owned standby generators, the 40 megawatts of capacity is the assumed aggre- gate availability of dispatchable megawatts rather than an average capacity per plant. The capital cost listed includes interconnection and emission control upgrade costs. The variable operations and maintenance (O&M) cost reflects the cost of #2 fuel oil, which is based on an average forecasted monthly fuel price of$13.9/MMBtu for the 2007 to 2026 period. Certain resource names are listed as acronyms. These include: PC - pulverized coal IGCC - integrated gasification combined cycle SCCT - simple cycle combustion turbine CCCT - combined cycle combustion turbine CHP - combined heat and power (cogeneration) For the CHP resources, a steam credit is applied against the variable O&M cost, or, in the case of the west-side topping cycle combustion turbine, against the heat rate. The costs presented do not include any investment tax credits. The heat rate for the solar trough resource with CCCT backup (11 750 Btu/kWh) reflects gas operation only, and comes directly from the EPRI TAG database. Gas backup for solar is less efficient than for a standalone CCCT. For the nuclear option, costs do not include fuel disposal. The capital cost columns in Tables 5.3 and 5.4 reports averages of the low and high capital cost estimates presented in Tables 5.1 and 5.2. Pa c i f i C o r p 20 0 7 I R P Ch a p t e r 5 - Re s o u r c e O p t i o n s Ta b l e 5 . 1 - E a s t S i d e S u p p l y - Si d e R e s o u r c e O p t i o n s 20 0 6 D o l l a r s ) Lo e a t i o n / T i m i n . Pla n t D e t a i l s Ou l a . e l n f o r m a t i o n Co s t s Em i s s i o n s Ea r l i e s t I n , Av e r a g e Av e . A n o u a l Ma i n ! . Eq u i v a l e n t Lo w E s t i m a t e Hig h E s t i m a t e In s t a H a t i o n S e r v i c e Da t e C a p o c i t y De s i g n P l a n t He a t R a t e Ou t a g e Fo r c e d O u t a g e Ca p i t a l C o s t Ca p i t a l C o s t Va r . O& M Fi x e d O & M S0 2 NO x CO , De s . r i n t i o n Lo c a l i o n ' M i d - Ye a r ' IM W \ Lif e i n Y e a r s I B t U l k W h Ra t e Ra t e IE F O R ) i$ / k W ) ($ / k W ) $/ M W h '$ / k W , lb s / M M B T U I b s I M M B T U lb s l f b t u Ib s I M M B T U Ea s l S i d e O p t i o n s ( 4 5 0 0 ' Co a l , U t a h P C S u n e r c r i t i i ; a j l f O O O M \ V ) ;, , Ut a h , , 2 0 1 2 60 0 40 " 9; 1 6 9 4% . : 94 0 , , , 2; 2 6 6 iA ! $ " 35 , ;0 , 0'6 2 07 0 60 0 20 5 , Uta h p c S u o e t c r i t i c a l 2 ; 1 6 0 0 M W ) " " ,; ' Ut a h " " 20 1 2 60 0 9,1 6 9 4% ' $ , 1. 9 4 0 24 1 ' 3 5 : 6 5 06 2 om o 60 0 ' 2 0 5 . , u i i h n k c i M i i i " ca i b o n l ' i i o / L e v e l I t C o n t r o l s ) Ut a h 20 1 4 , 5 0 8 73 2 6% " , 26 9 $ - 2; 6 9 0 1J O $ ' 8 \ : 3 1 01 4 0: O l 4 , 0 , 30 0 ' 20 5 : 3 5 ut a h r G C c : f 1 i A i I L C a r b O h P r e n / L e v e 1 J l - , s p a i e . . s , Ut a h 20 1 4 "' " 5 0 8 ' 4 0 &, 7 3 2 10 % ll % , 14 1 ' $ 53 8 1.1 0 76 : 1 1 01 4 01 4 30 0 20 5 : 3 5 , , " , Uta h I G C C w i t h c i . r b c i n C a c i i t i e & . S e q U e s t r a t i o n ut a h 20 1 4 47 0 91 7 90 1 3. 4 3 9 6: 2 8 11 4 . 5 0 01 4 01 4 , 0:3 . 0 0 20 . wv o m in l ! P C : S t i n e r c i i t l c i a l 1 7 5 0 M W ) Wv o i n i n . ! , 20 1 4 75 0 40 : 9; 4 2 7 - 5 % $ - - 1 . 9 3 0 2; 2 5 6 2: 0 8 $ , 41 . 0 6 0: 0 6 2 0:0 7 0 '0 . 60 0 20 5 3 5 " W y o m i n g l G C C ( M i r i : C a r b o r i ; l ' r e p / L e v e I I l C o n t r o l s ) Wy o m i n g 20 1 4 49 7 40 " . ' 91 5 2,4 7 1 92 9 L0 8 8t . 3 2 , " , 0: 0 1 3 ' 0;0 1 3 , .0 3 0 0 20 5 , 3 5 Na t u r a l G a s Mi c r o t u r b i n e Ut a h 20 0 7 88 5 92 9 07 6 20 0 , 00 1 10 1 25 5 11 8 , , , 's m a l l N o n - C T C H I ' ' , Ut a h 20 0 9 15 6 10 % 82 4 94 5 " 2 9 4 9 0; 0 0 1 08 0 25 5 : 1 ' 1 8 , Sm a l l I n d u s t r i a l C H P Ut a h 20 0 8 25 , 12 , 59 0 1. 4 5 4 $' 1 , 66 9 10 . 32 ) 0. 0 0 1 13 8 0. 2 5 5 . l l 8 . Sm a l l C o m m e r c i a l C H I ' Ut a h 20 0 8 03 5 16 7 33 9 (0 , 03 ) $ 1.3 5 00 1 22 0 25 5 11 8 . Fu e l C e l l . . S m a l l ( S o l i d O x i d e ) Ut a h 20 0 8 82 0 57 7 91 3 00 1 00 3 25 5 11 8 , Fu e l C e l l - L a r g e ( S o l i d O x i d e ) Ut a h 20 1 2 25 0 11 7 35 5 8.4 0 00 1 00 3 25 5 11 8 , SC C T A e r o Ul a h 20 0 9 74 4 10 % 70 1 80 4 20 , 00 1 01 1 25 5 11 8 , In t e r c o o l e d ' A c r e S C C T Ut a h 20 0 9 , 9 ; 4 3 6 3% : ' 2% ' 69 8 $' " 8 0 1 $ , 2 5 8 29 , 0.0 0 1 '" 0 . 0 1 1 0: 2 5 5 :l i 8 . In t e r n a l C o m b u s t i o n E n g i n e s Ut a h 20 0 9 15 3 39 0 82 4 94 6 12 , 00 1 01 7 25 5 11 8 , SC c T F r a m e f 2 E r a m e Ut a h 20 0 9 " 3 0 2 35 ' 11 , 50 9 iO % ~; , 4 6 5 53 4 10 , 86 $ 5;7 8 00 1 ' 0: 0 5 0 25 5 1'1 8 , 00 ' CC C T ( W e t " F" I x l ) Ut a h 20 1 0 22 2 22 3 83 4 95 7 16 . 4 2 00 1 01 1 25 5 11 8 , CC C T D u c t F i r i n . ( W e t " F" I x l ) Ul a h 20 1 0 86 8 27 7 31 8 00 1 01 1 25 5 11 8 . ' " CC C T ( W e t " 2x l ) Ut a h 20 1 0 44 8 16 4 75 9 87 0 $, 2; 6 0 00 1 01 1 25 5 li 8 , CC C T D u c t F m ~ ~ l W e t " ; 2 x l ) Ut a h , 20 1 0 10 0 86 8 5% . . , .. $ 25 5 $ , 29 2 $ ' 00 1 01 1 (). 25 5 I 11 8 : 0 0 CC C T , ( W e t " lx J ) ' Uta h 20 1 0 29 7 07 5 7% , ;" 5 % " 78 9 90 5 $, . 2 , 12 . 4 2 00 1 O. o I I ' 0 . 25 5 11 8 ; 0 0 CC C T D u c t F i r i n g ( W e t " lx l ) - Uta h 20 1 0 35 , - . 86 8 29 2 $ , . " . 33 5 00 1 01 l 25 5 : 1 1 ' 8 , Oth e r - R e n e w a b l e s SW W v o m i i I g W i n d Wv o m i n g 20 0 8 nl a nl a nl a 55 6 91 9 $' 29 , ::, ;- ' . " ' " , ld a h o W i n d Ut a h 20 0 8 "" 2 0 nl a nl a '" , nl a " 55 6 29 . " - Ge o t h e n n a l . D u a l F l a s h Ut a h 20 0 9 nl a 10 1 59 1 5.5 0 22 , Ba t t e r v S t o r a o e Ut a h 20 0 9 00 0 29 8 50 3 10 , 1. 0 0 10 0 0. 4 0 0 00 0 20 5 , Pu m D e d S t o r a g e Ne v a d a 20 1 7 35 0 13 , 00 0 10 4 27 8 10 0 0. 4 0 0 00 0 20 5 . Co m o 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 ) Wv o m i n . 20 1 0 35 0 67 0 10 % 69 8 80 8 5.5 0 00 1 01 1 25 5 11 8 , Nu c l e a r . P a s s i v e S a f e t v Uta h 20 2 2 60 0 71 0 38 2 88 9 0.3 8 10 9 , So l a r T h e n n a l T r o u g h w i t h N a t u r a l G a s B a c k u p Uta h 20 1 0 20 0 11 , 7 5 0 n/ a nl a 54 1 33 7 26 , Pa c i f i C o r p 20 0 7 I R P Ta b l e 5 . 2 - W e s t S i d e S u p p l y - Si d e R e s o u r c e O p t i o n s 20 0 6 D o l l a r s ) De s c r i n t i o n We s t S i d e O p t i o n . ( 1 5 0 0 ' Na t u r a l G a . Mic r o t u r b i n e .." Fu e l C e l l - S m a l l ( S n l i d O x i d e ) SC C T A e r o In t e r c o o l e d A c t o S C C T In t e r n a l C o m b u s t i o n E n ~ i n e s SC C T F r a m e , ( 2 F r a r i i e " F " CC C T ( W e t " F" I x l ) CC C T D u c t F i r i n e l W e t " F" I x ! ) CC C J ' ~ .. , CC C T D u c t ~ : 2 i r j ) , CC C r l W e t ' ~m l x J ) , , ' CC C ' t . 1, ) u c t F i n n i ! ( W e L ' ;m l i r l j . " , ,.. . " Ot h e r - R e n e w a h l e s "" ' , 6 r e e o n W i n d ' Oe o t h e n n a l , D u a l F l a s b Co m p r e s s e d A i r E n e r g y S t o r a g e ( C A B S ) We . t S i d e O p t i o n . ( S e a L e v e l ) Co a l Wa s h i n g t o n 1 0 C C ( M i n , C a r b o n P r e p l L e v e l I I C o n t r o l s ) Na t u r a l G a . Mic r o t u r b i n e La r e e C H P I " . " "" " " ' Stn a I I N r i n - C T C H P . , " S i r i a l U n d u s t r i a I C H P Sm a l l C o m m e r c i a l C H P Fu e l C e l l - S m a l l ( S o l i d O x i d e ) SC C T A e r o !n t e r c o o l e d A e r o S C C T In t e r n a l C o m b u s t i o n E n ~ i n e s SC C T F r a m e ( 2 F r a m e " CC C T I W e t " F" I x l ) CC C T D u c t F i r i n ~ ( W e t " lx l ) CC C T ( W e t " F" 2 x l ) CC C T D u c t F i r i n . ( W e t " F" 2 x l ) CC C T IW e t 0" I x ! ) CC C T D u c t F i r i n g ( W e t " 0" I x l ) Oth e r - R e n e w a b l e . Ot e i ! o I l W i h d : " '. . Bio m a s ;! . l o s e d l o o n ) Nu c l e a r , P a s s i v e S a f e t v Co m n r e s s e d A i r E n e r e v S t o r a ~ e ( C A B S ) " .'. ' " , ' C u s t o m e r O W n e d S t a n d b y G e n e r a t i o n Ch a p t e r 5 - Re s o u r c e O p t i o n s Lo c a t i o n / T i m i n . Pl a n t D e t a i l . Ou t a . e I n f o r m a t i o n Co s t s Em i s s i o n s Ea r l i e s t I n , Av e r a g e Av e , A n n u a l Ma i n ! . Eq u i v a l e n t L o w E s t i m a t e H i g h Es t i m a t e In s t a l l a t i o n Se r v i c e D a t e C a p a c i t y De s i g n P l a n l He a t R a t e Ou t a g e F o r c e d O u t a g e C a p i t a l Co s t Ca p i t a l C o s t Va r , O & M Fi x e d O & M S0 2 NO x Lo c a t i o n I M i d , Ye a r 1 IM W \ Lir e i n Y e a r s IB t U l k W h Ra t e Ra t e E F O R 1 $/ k W \ ($ / k W ) 1$ / M W h ) ($ / k W . " , ) Ib s l M M B T U I b s l M M B T U l b s r r b t u No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e S t No r t h w e s t No r t h w e s t No , t h w e s t No r t h w e s t No r t h w e s t ' No r t h w e s t 20 0 7 20 0 8 20 0 9 20 0 9 20 0 9 20 0 9 , , 20 1 0 20 1 0 20 1 0 20 1 0 20 1 0 20 1 0 03 22 5 87 86 " " 2 5 16 8 33 2 24 4 55 49 2 ." l l O J2 6 " 66 , IN o , t b . " ' e ' t I 2 0 0 8 ~;o I . ' No r t h w e s t 1 20 0 9 I 35 No r t h w e s t I 20 1 0 I 38 5 I , , , No r t h w e s t I 20 1 4 I No r t h w e s t No r t h w e s t No r t h w e s t . No r l h w ~ s j , No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t No r t h w e s t 20 0 7 20 0 9 20 0 9 20 0 8 20 0 8 20 0 8 20 0 9 20 0 9 20 0 9 20 0 9 20 1 0 20 1 0 20 1 0 20 1 0 20 1 0 20 1 0 20 0 8 20 1 0 20 2 2 20 1 0 20 0 8 60 0 I 03 12 0 cc : - 2 5 ' 2 5 "" , 5 91 90 17 7 35 0 25 7 58 51 8 11 6 34 3 69 10 0 60 0 40 5 88 5 82 0 10 , 74 4 9, 4 3 6 39 0 50 9 22 3 86 8 16 4 88 6 8 , . 7 , ' r J 7 5 86 8 88 5 65 5 , 5 15 6 , ' ' ' 12 , 59 0 03 5 82 0 10 , 74 4 43 6 39 0 11 , 50 9 22 3 86 8 16 4 86 8 07 5 86 8 7% , , 7 % .. , :7 % , . 7 " ;'; il i a , I , Dl a + wa I 3% 11 , 67 0 I 7% I 73 2 I 5% I 97 9 71 0 67 0 10 , 50 0 1% 2% 10 % 2% . 1% 10 % 5% 5% %" " $ 5% .:. 5% " " $ 5% . . : , : " , , 5% ' 1% 10 % 5o y ; , 1% 5% 10 % " " ' '" $ 2% 1% 2% 10 % 2% 1% 10 % 5% 5% 5% 5% 5% 5% wo . ' ri / o . 5% ' 10 %wi l . 84 5 $ 43 3 $ 63 7 $ , 6 3 5 $ 74 9 $ "" ' 2 3 $ " 75 8 $ 25 2 $ 69 0 $ ", , " 2 3 2 $ 71 7 $ , M6 $ 55 i H $ , 10 I T $ 63 5 1 $ 26 9 I $ 80 3 $ 75 6 $ 78 2 $ 1; 2 6 5 $ 16 7 $ 36 2 $ 60 5 $ 60 3 $ 71 2 $ 40 2 $ 72 0 $ 24 0 $ 65 5 $ 22 0 $ 68 1 $ 25 2 $ $ ' 55 6 $ ' $ 2 21 3 $ $ 2 , 38 2 $ 60 3 $ $ , 17 0 $ 97 8 $ 1. 8 2 $ 18 1 . 8 2 73 9 $ 0 , 03 $ 8 . 73 1 $ 6. 4 4 $ 1 9 , 72 8 $ , 35 $ , 26 . 86 0 $ 5 , 20 $ 1 2 , 48 5 $, 9 . 87 . $ , 5 , 87 0 $ 2 . 36 $ 1 4 . 28 9 $ 0 . 10 $ 79 1 $ 2 . 36 $ 9;0 7 26 6 $ 10 $ , 8 2 2 $ . ' 23 2 $ 11 . 30 5 $" O . JO $ , - 19 1 9 1 $ 59 1 $ 73 5 $ , ' .. . ( , $ . . 2 ~ / 7 8 5. 5 0 I $ 2 2 , 60 I 00 I $ 3. 4 5 I 69 0 $ 1.1 0 I $ 00 1 0 . 10 1 00 1 0 . 00 3 00 1 0 , 01 1 0. 0 0 1 0 . 01 1 00 1 0 , 01 7 , 0 : 0 0 1 1 05 0 00 1 0 . 01 1 00 1 0 , 01 1 00 1 0, 0 1 1 00 1 O . OJ 1 Q, ( ) O l 0 . 01 l , 0 . 90 1 ' " O; O U 00 1 1 81 . 3 1 I 01 4 1 92 9 $ 1. 7 3 $ 17 2 . 7 3 0 , 00 1 82 4 $ ( 1 7 , 75 ) $ 1 4 , 22 0 , 00 1 89 8 $ , : 0 . 17 $ " :2 9 ; 4 9 " (J i O P l lA 5 J $ : " ;( i t 2 8 ' $:' : 7 8 1 5 ' " O ; O O l 33 9 $ ( 0 . 02 ) $ 1. 1 7 0 , 00 1 65 2 $ 0 . 03 $ 8 . 82 0 , 00 1 69 4 $ 6 , 13 $ 1 8 , 06 0 . 00 1 69 2 $ 2 . 23 $ 2 5 , 06 0 . 00 1 81 7 $ 5 . 20 $ 1 2 . 80 0 , 00 1 46 1 $ 9. 4 0 $ 5 . 00 0 , 00 1 82 6 $ 2 , 25 $ 1 4 , 22 0 . 00 1 27 5 $ 0 , 10 $ 0 , 00 1 75 2 $ 2 , 25 $ 8 . 64 0 , 00 1 25 2 $ 0 . 10 $ - 0 , 00 1 78 1 $ 2 , 21 $ 1 0 , 75 0 , 00 1 29 0 $ 0 , 10 $ 0 , 00 1 CO , Ib s l M M B T U 25 5 1 1 8 , 25 5 1 1 8 , 25 5 1 1 8 , 25 5 1 1 8 . 25 5 1 1 8 , 25 5 ' 11 8 ; 0 0 25 5 1 1 8 , 25 5 1 1 8 , , 0 . 25 5 ' 1 I 8 . 25 5 , l l K O O 0; 2 5 5 1 : . U8 . 0; 2 5 5 . . . , 11 8 . 01 1 01 4 I 0 . 30 0 I 10 1 0 . 25 5 1 0 . 25 5 : 0 , 08 0 0. 1 3 8 22 0 0 , 25 5 00 3 0.2 5 5 01 1 0 , 25 5 01 1 0 , 25 5 OJ 7 0 , 25 5 05 0 0 , 25 5 01 1 0 , 25 5 01 1 0 , 25 5 01 1 0 . 25 5 01 1 0 . 25 5 01 1 0 . 25 5 01 1 0 . 25 5 25 5 I 11 8 . 20 5 , 11 8 , 11 8 , " I l B : O I ! TI B : O O 11 8 , 11 8 , 11 8 . 11 8 , 11 8 , 11 8 , 11 8 . 11 8 , 11 8 , 11 8 , 11 8 , 11 8 , 1. 9 1 9 $ 56 3 $ 88 9 $ 69 8 $ 17 0 $ , ' 1. 9 1 $ 38 $ 76 $ 14 6 , 00 $ 29 , 78 , : , :: : " 12 0 . 06 2 0. 3 5 0 0 , 60 0 2 0 5 . 10 9 , 72 28 0 , 00 1 0 , 01 1 0 , 25 5 1 1 8 . 50 , , 0 ; 0 5 8 ' 0; 2 3 1 n l a I" 19 0 , 0 0 Pa c i f i C o r p 20 0 7 I R P Ch a p t e r 5 - Re s o u r c e O p t i o n s Ta b l e 5 . 3 - 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 - Si d e R e s o u r c e O p t i o n s 20 0 6 Do l l a r s ) Ca n i t a l C o s l S / k W Fi x e d C o s t Co n , e r l t o J l i l l s Va r i a b l e C o s t s A" " " " I I fix e d O & M IS k W , Le v e ; ; " , 1 F o e l mi l l s / k W h To t a l R e s o u r c e To " , l PO " " " " P,w m e ' " T" , " l h " , 1 (" ' P O O " y Tn , " l F i x e d Co s t De s c r i n t i o n ('" " , t , l ( ' o " F" " " r kW , Yr ' 0& \ 1 O,h e r To t a l HW . Fa c t o r Mil ' s l k W h l /lm m B t u Mil l s ' k W h O& M To t a l Ta x C r e d i t s Eo v i r o n m e o t a l (M i l l s l k W h \ Ea s l S i d e O p t i o n s ( 4 $ 0 0 ' Co a l I, Ut a h , P C S u o o i c r i t i c a l l ( 6 0 0 M i l ' ) , 10 3 10 % 17 0 A 3 35 . 41 . 6 5 $ 2 1 2 : 0 8 91 % 26 A 9 18 7 0 2 0 17 - . .1 6 2A 1 5:3 9 51 A 6 : " 0 " Uta h P G s u \ , e n , r i t i c a I 2 1 6 O O M \ v j ' " 10 3 10 % 17 0 A 3 35 . 41 : 6 5 $ , 21 2 . 91 % 26 . 49 , 18 7 . J7 , 2; 4 1 ~i ' 5.3 9 51 A 6 , U t a h I G C C f M i n , Ca r b ( , " P r e n ! L e v e l I T c n n t r o l s ) , 47 9 82 % $J 9 3 ; 8 6 81 . 3 1 $\ , ;8 7 . 3 1 28 L l 7 78 9 % 36 : 0 6 18 7 . 1'6 : 3 5 1. 1 0 58 . 3 5 ut a h I G C C . l M i i k C a r b a n P r e n ! L e v d I T - . n o s n a r e e a s . 33 9 82 % 18 2 . 76 . 82 . $.2 6 5 : 6 2 79 % 38 . 3 8 18 7 , 16 . 3 S 1. 1 0 60 . Uta h Id c c wit b C a r h o n C a n t u r e & ; Se o u e s t r a t i o l 1 17 0 82 % $ . 2 4 7 . $ , 11 4 . 6; 0 0 12 0 . 5 0 36 8 . 3 7 89 % 4n S 18 7 , 18 : 5 6 60 2 8 0. 6 4 72 ; 7 4 ;" " " " Wv o m i f t e JiC S u t i i m : r i t i c a l ( 7 5 0 M W ) $ ' 2; 0 9 3 10 % 16 9 , 41 . 0 6 47 . $ , 21 6 . 91 % 27 , 10 3 : 6 7 5: 5 4 44 . 4 6 wy o t ) l i n g 1 G ( ; C ( M i n . Ga r b o n P r e p l L e v e l l I C o n t r o l s ) 70 0 82 % .2 1 1 . 1 1 $, 8 1 . 3 2 87 , 29 8 . 4 3 89 % 38 . 10 3 . 92 4 1.0 8 4: 9 3 53 . Na l o r a l G a s Mi c r o t u r b i n e 00 3 11 . 2 1 % 11 2 , $ 2 0 0 , 20 0 . 31 2 , 98 % 36 . 4 5 69 3 , 89 , 4.4 5 13 9 , ' S m a l l N o o . CT C H P 88 4 84 % 87 . 29 . 4 9 0. 5 0 29 . 11 7 . 85 % 15 , 69 3 . 35 . 1. 7 5 56 . Sm a l i l o d u s t r i a l C H P 56 1 84 % 15 3 . 0. 5 0 16 2 . 3 6 90 % 20 . 69 3 . 87 . 10 . 4.4 9 11 9 , Sm a l l C o m m e r c i a l C H P 25 3 84 % 12 3 , 1.3 5 1. 8 5 12 5 , 90 % 15 , 69 3 , 69 , 10 , 03 ) 94 . Fu e l C e l l , S m a l l ( S o l i d O x i d e ) 74 5 8.5 0 % 14 8 , 10 , 15 8 . 4 3 97 % 18 , 69 3 . 54 , 2.4 6 79 , Fu e l C e l l - L a r o e ( S o l i d O x i d e ) 23 6 50 % 10 5 , 8.4 0 0. 5 0 11 3 , 95 % 13 , 69 3 , 43 , 1. 9 7 62 . 4 8 SC C T A e r o 75 2 51 % 71 . 5 3 20 , 21 . 4 1 92 . 21 % 50 , 69 3 , 74 , 3.4 1 13 9 . 4 0 In l e r c o o l o o A e r o S C C T 75 0 51 % 71 . 2 7 29 . 29 , 10 0 ; 7 9 21 % ;'5 4 ; 7 9 69 3 . 65 . 4 6 12 9 . In t e r n a l C o m b u s t i o n E n g i n e s 88 5 51 % 84 . 12 . 13 . 3 0 97 , 94 % 11 . 8 3 69 3 , 58 , 82 , SC C T F r a m e ( 2 F r a m e " 49 9 8.3 3 % 41 . 6 1 47 , 21 % 26 . 69 3 . 7 0 79 , 10 , 12 4 . CC C T ( W e t " F" I x 1 ) 89 5 62 % 77 . 1 6 16 . 4 2 16 , 94 , 56 % 19 , 69 3 , 50 , 77 . 9 0 CC C T D u c t F i r i n . ( W e t " F" 1 x l ) 29 8 62 % 25 , 26 , 16 % 18 , 69 3 . 61 . 5 2 86 , CC C f ( W e t " 2x l ) 81 5 62 % 70 . 10 . 4 8 $ , 80 . 56 % 16 . 4 5 69 3 . 49 . 2; 6 0 74 . 7 1 CC C T D l I c iF i r i n n W e t " F" 2 x l ) 27 3 62 % 23 5 6 05 0 24 , 16 % 17 , 69 3 , 61 . 5 2 85 . 1 9 Cc ; c n W e " G" I x l ) 84 7 62 % 72 , 12 . 4 2 12 . 9 2 85 . 56 % , " 11 , 69 3 : 7 0 '" 4 9 . -.. ; - c 75 ; 0 3 ' cC C T D u c ' F l r i n g ( W ~ t " G " hl ) ' , " , ' " " 31 4 62 % .2 . 7 ; 0 5 0:5 0 50 n5 5 16 % 69 3 ' , 61 : 5 2 rT ~ ; : ' 2: 8 1 87 ; 6 8 Olh e r - R e n e w a b l e s SW W y o m i n g W i n c l 01 1 9.4 8 % $ 1 9 0 : 7 0 29 . 0:5 0 30 , $, 2 2 0 , 35 % ' " 72 . 4 9 "; ~ rT i z O . 55 , 13 . ;' ' Id a h o . W i n d 1; 7 2 9 9.4 8 % $.1 6 3 , 29 . 30 : 2 8 $1 9 k 2 4 3. % 68 ; 2 3 (2 0 . 50 . Ge o t h e m J a L , D u a l F l a s h 34 6 7. 4 6 % $ 2 4 9 , 22 , 23 , 27 2 . 6 5 96 % 32 . 3 2 21 . 1 3 (2 0 , 65 ) 38 . 3 0 Ba t t e r v S t o r a p e 1, 4 0 0 51 % 11 9 , 1. 0 0 1.5 0 12 0 , 21 % 65 , 69 3 , 83 , 10 , 16 7 . 4 5 Pu m p e d S t o r a g e 19 1 86 % 93 . 1. 3 5 99 . 2 7 20 % 56 , 69 3 . 90 . 34 0 16 0 . 4 8 Co m p r e s s e d A i r E n e r g y S t o r a g e ( C A B S ) 75 3 69 % 65 . 4 5 1.3 5 70 , 25 % 32 , 69 3 , 80 . 70 4 12 2 . 4 0 Nu c l e a r , P a s s i v e S a f e t y 63 5 01 % $ 2 1 0 . 10 9 , 11 5 , 32 6 , 85 % 43 , 50 . So l a r T h e n n a l T r o u g h w i t h N a t u r a l G a s B a c k u p 93 9 87 % $ 3 1 0 . 26 , 32 , 34 2 , 21 % 18 6 . 18 9 , Pa c i f i C o r p 20 0 7 I R P Ta b l e 5 . 4 - T o t a l R e s o u r c e C o s t f o r W e s t S i d e S u p p l y - Si d e R e s o u r c e O p t i o n s (2 0 0 6 D o l l a r s ) De s c r i n t i o n We s t S i d e O p t i o n s ( 1 5 0 0 ' Na t u r a l G a s Mi c r o t u r b i n e Fu e l C e l l , S m a l l ( S o l i d O x i d e ) SC C T A e r o lr i t e i c o o \ e d A e r o S C C T lo t e r n a l C o m b u s t i o o E o g i o e s St t t f m r i 1 e ( 2 ' F ' rli m ~ " F " ) " CC C T ( W e t " lx l ) CC C T D u c t F i r i n g ( W e t " F" I x l ) CC C r f W e t " j o i i 2x l f ' " ' C C t T D i i c t F i r i n ! i , ( W " t "f ' i 2x b :; , ::" : ' tt c t ( W e t "G " j ~ l ) ' CC C r ' p u c t F i r i n g ( W t t "G " l x I ) , ' Ot b e r - R e n e w a b l e s , d r o g o n wi i i d " Ge o t h e r m a l . D u a l F l a s h Co m p 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 ) We s t S i d e O p t i o n s ( S e a L e v e l ) Co a l Wa s h i n g t o n ! G C C ( M i n , C a r b o n P r e p l L e v e l l I C o n t r o l s ) Na t u r a l G a s , : Mic r o t u r b i n e La r g e C H P Sm a U N o n - C T C H P Su i a i l l i l d u s m , i C H I ' Sm a l l C o m m e r c i a l C H P Fu e l C e l l . S m a l l ( S o l i d O x i d e ) SC C T A e r o In t e r c o o l e d A c r o S C C T In t e r n a l C o m b u s t i o n E n g i n e s SC C T F r a m e ( 2 F r a m e " CC C T ( W e t " lx l ) CC C T D u c t F i r i n g ( W e t " lx l ) CC C T ( W e t " F" 2 x l ) CC C T D u e l F i r i n g ( W e t " F" 2 x l ) CC C T ( W e t " lx l ) CC C T D u c t F i l i n g ( W e t " lx l ) Ot h e r - R e n e w a b l e s Or e g o n W i n d " ' Bi o m a s s ( c l o s e d 1 0 0 0 ) Nu c l e a r . P a s s i v e S a r e t Y Co m o r e s s e d A i r E o e r g y S t o r a g e ( C A E S ) , : C u s t o i n e t O W n e d S t 8 J 1 d b y G e n c r a t i o n " " Ch a p t e r 5 - Re s o u r c e O p t i o n s Ca p i t a l C o s t $ / k W Fi x e d C o s t An n u a I Fi x e d O & M $ i k W . To t a l Pa y m e n t pa y m e n t Ca i t a l C o s t Fa c t o r 1$ / k W . Yr\ O& M Ot h e r To t a l Co n v e r t t o M i l l s Le v e l i z e d F u e l To t a l F i x e d Ca p a c i t y T o t a l Fix e d l$ i k W . Yr \ Fa c t o r I IM i l l s i k W h 1 t l m m B t u M i l l s i k W h Va r i a b l e C o s t s mi l l s l k W h To t a l R e s o u r c e Co s t O& M To t a l I T a x C r e d i t s I E n v i r o n m e o t a l IM i l l s i k W h \ 91 2 $ 1 58 6 68 4 68 2 80 5 45 4 81 4 27 1 74 1 24 9 77 0 28 5 ,,: ; 1 $ un I I $ 3 34 6 I I $ 68 5 1 1 $ 2 , 47 9 I 11 . 2 1 % 50 % 51 % 95 1 % 51 % 33 % 62 % 62 % 62 % 62 % 62 % 62 % $ 1 0 2 , $ 1 3 4 , $ 6 5 , $6 4 ; 7 9 76 . 4 9 $ 3 7 . $ 7 0 . $ 2 3 , 63 : 8 2 $ : 9 , 21 . 4 2 " " - $' 6 6 . 33 $ ' 11 . 29 ' 24 ; 5 9 $ \ 8 1 . 8 2 $ $ 8 , 82 $ $ 1 9 , 01 $ $2 6 3 8 $ $ 1 2 . 80 $ $ " ' 5 : 25 $ ' $ 1 4 , 93 $ $ ' 50 $ 50 $ 50 $ 50 $ 0. 5 0 $ 05 0 50 $ 50 $ 05 0 $ 05 0 , $ , 50 $ 50 $ 18 2 , 32 $ 28 4 . 4 8 98 % 32 $ 1 4 4 , 08 97 % 19 , 51 $ 84 . 5 3 21 % 26 . 88 $ 9\ ; 6 8 : 2 1 % 13 . 3 0 $ 8 9 , 79 94 % 5~ 7 5 $ . . 43 : 5 8 21 % 15 . 4 3 $ 8 5 5 7 56 % 50 $ 2 3 , 84 16 % 95 7 $ 13 . 56 % O~ 5 0 $ . . 2M 2 ' 16 % ' 11 . 7 9 $ 78 : 1 2 56 % 11 , 50 t 25 J ) 9 16 % 48 % 1 $ 1 6 4 , 15 h $ " 2 9 : 1 8 1 $ 7. 4 6 % 1 $ 2 4 9 , 55 I $ 2 2 , 60 I $ 69 % 1 $ 5 9 , 50 I $ 3. 4 5 I $ 22 : 2 2 1 $ ' 52 , OO I $ 2 f 6 . 7 5 I " . ' 34 % 50 I $ 2 3 , 10 I $ 2 7 2 . 6 5 I 96 % 1. 3 5 1 $ 4 , 80 I $ 6 4 . 31 I 25 % 82 % 1 $ 1 9 3 , 86 1 $ 81 . 3 I T $ 86 6 11 . 2 1 % 79 0 9 , 84 % 84 0 " , 9 . 84 % $ 1 , 35 8 9 , 84 % $ 1 25 3 9 , 84 % $ 1 50 7 8 , 50 % 65 0 9 , 51 % 64 7 9 , 51 % 76 4 9 , 51 % 43 \ 8 . 33 % 77 3 8 . 62 % 25 7 8 , 62 % 70 3 8 . 62 % 23 6 8 , 62 % 73 1 8 , 62 % 27 1 8 . 62 % $ 1 , 72 9 ' $ 2 38 8 $ 2 . 63 5 65 1 17 0 $ 9 7 , 77 . 7 5 $ 8 2 . $ 1 3 3 . $ 1 2 3 , $ 1 2 8 , 61 . 7 7 61 . 5 5 $ 7 2 , $ 3 5 , $ 6 6 . $ 2 2 , $ 6 0 . 63 $ $ 2 0 . $ 6 3 , $ 2 3 , 9. 4 8 % $ 1 6 3 , 7. 4 6 % $ 1 7 8 , 01 % $ 2 1 0 , 69 % $ 5 6 , 11 . 0 0 % $ 1 8 . 00 1 $ $ 0 , 50 $ $ 0 , 50 $ , ' 50 $ $ 0 , 50 $ $ 0 , 50 $ $ 0 , 50 $ 0. 5 0 $ $ 0 , 50 $ $ 0 . 50 $ $ 0 , 50 $ 05 0 $ 0. 5 0 $ 64 $ 0 , 50 $ 0. 5 0 $ $ 1 0 , 75 $ 0 , 50 $ $ 0 , 50 $ $ 1 7 2 . 7 3 $ 1 4 , $ 2 9 . $ 7 . 1. 1 7 $ 8 , $ 1 8 , $ 2 5 , $ 1 2 , $ 5 , $ 1 4 , $ 2 9 , 78 $ $ 4 , 12 $ $ 1 0 9 , 72 $ $ 3 , 28 $ 3: 5 0 $ 22 . 22 $ 50 $ 00 $ 1. 3 5 $ 0. 5 0 $ 87 , 31 1 $ 2 8 1 . 1 7 1 17 3 , 23 $ 2 7 0 , 14 . 72 $ 92 . 4 6 29 . 99 $ 1 1 2 . 7: 6 5 $ 14 1 : 2 5 1. 6 7 $ 1 2 4 , 93 2 $ 13 7 . 3 4 18 . 56 $ 80 . 3 3 25 . 56 $ 8 7 , 13 . 3 0 $ 8 5 , 50 $ 41 . 4 4 14 , 72 $ 81 . 3 6 50 $ 2 2 . 14 $ 6 9 . 50 $ 2 0 , 11 . 2 5 $ 7 4 , 50 $ 2 3 , 52 . 00 $ 2 1 5 . 62 $ 1 8 2 . 11 5 , 72 $ 3 2 6 , 63 $ 61 . 1 6 00 $ 22 ; 7 0 98 % 31 . 4 8 89 % 11 . 9 3 85 % J5 : 1 3 ' 9 0 % :. , 1 7 . 90 % 1 5 . 97 % 1 6 . 21 % 4 3 , 21 % 4 7 , 94 % 1 0 , 21 % 2 2 , 56 % 1 6 , 16 % 1 6 , 56 % 1 4 , 16 % J 4 , 56 % 1 5 , 16 % 1 7 . 89 %34 % 1 . . ' 72 . 91 % 2 2 , 85 % 4 3 , 25 % 2 7 , 25 % ' " 1 0 , 1. 8 2 - 03 - 44 - 2: 3 5 ' 1 ' : ' 9: 8 7 . 36 - 2; 3 6 , " :': " "., . 2 ~ 3 2 16 . 1 . : I , ;: , 4. 4 5 $ 1 3 6 , 2. 4 6 $ 78 . 5 1 3. 4 1 $ 1 3 4 , 2: 9 9 $ 12 " : 3 2 68 $ 82 . \ 5 3: 7 9 $ ' 12 1 ; 5 4 , 29 $ 7 6 , 81 $ 85 . 3 7 . 2 ; 2 7 ' $ 7 3 , , : \ " , ; : ' 81 $ , ' 84 : 0 0 , : ' 2 . 25 ' : 1 : ~ ' 73 ' 33 , 16 , 45 , 49 ; 8 3 10 . :2 3 , 6 9 17 , 17 , \4 : 9 6 "'1 5 : 6 4 ' 15 : 9 2 J7 . 69 9 , 25 90 , J O $ 69 9 , 25 5 4 , 68 $ 69 9 . 25 7 5 , 13 $ 69 9 . 25 1 . 65 : 9 8 ' 69 9 , 25 5 8 , 67 $ 69 9 ; 80 : 4 8 $ 69 9 , 25 5 0 . 51 $ 69 9 , 25 6 2 , 01 $ 69 9 . 25 ' 50 ; 0 9 $ '6 9 9 , 25 , 62 . 01 $ , 69 9 . 25 .4 9 : 4 7 $ '6 9 9 : 2 5 , . '6 2 . 01 $ .. 7 2 ; 3 5 1 , :" . " , ' . " : , ,;" .'C I - i1 " 1i0 ~ 6 5 ) I " "" ' , ,, 32 , 32 1 21 . 1 3 I $ 5 , 50 I ( 2 0 , 65 ) 1 29 , 36 1 6 9 9 , 25 81 . 6 0 1 $ 5 , oo T I 3 , 70 1 $ 36 , 06 I 1 5 0 , 1. l 0 T 13 , 10 $ 69 9 , 25 9 0 , 69 9 , 25 81 . 5 0 69 9 ; 2 5 3 6 . 69 9 . 25 ' " 88 , 69 9 , 25 7 0 , 69 9 , 25 5 4 , 69 9 , 25 7 5 , 69 9 , 25 6 5 , 69 9 , 25 5 8 , 69 9 , 25 80 . 4 8 69 9 , 25 5 0 . 69 9 . 25 6 2 , 69 9 . 25 5 0 . 69 9 . 25 6 2 , 69 9 . 25 49 . 4 7 69 9 , 25 6 2 , 4.4 5 I i i ' ; 1 . 7 5 , ' " " ' 4:4 9 2.4 6 3.4 1 2. 2 9 1.7 3 $ 1 1 7 , 75 ) - 0; 1 7 - $ ( 0 , (0 , 02 ) $ 0 . $ 6 , 13 - $ 2 , $ 5 , 9.4 0 $ 2 , 25 - $ 0 , 10 - $ 2 , 25 - $ 0 , $ 2 , 21 - $ 0 , 30 0 . , - 32 , 94 $ 35 $ 81 . 6 0 $ - " " $ 1. 9 1 14 6 . , 1 (2 0 . 65 ) (2 0 , 65 ) 69 9 , - ' .. 5 4 . 38 , 11 9 . 83 $ 55 , $ 1 3 4 , $ 8 6 , $ 5 5 . 11 7 . 95 . 4 6 77 . 7 1 13 1 . 9 3 12 1 . 7 3 81 . 6 8 $ 1 1 9 , 75 . 3 9 $ 8 4 . 72 . 5 6 $ 8 3 , $ 7 2 , $ 8 5 . 7. 4 2 $ 70 $ 22 $ 55 ; 1 5 44 , 50 , 11 7 , 16 2 : 5 9 PacifiCorp 2007 IRP Chapter 5 - Resource Options Resource Descriptions Coal Potential coal resources are shown in the supply-side resource options tables as supercritical pul- verized coal boilers in Utah31 and Wyoming, and IGCC facilities in Utah, Wyoming, and West Main. Supercritical technology was chosen over sub critical technology for pulverized coal for a number of reasons. Increasing coal costs are making 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 subcritical boilers. Increasingly, large boiler manufacturers only offer supercritical boilers in the 500+ megawatt sizes. Due to the in- creased efficiency of supercritical boilers, overall emission quantities are smaller than for a simi- larly sized sub critical unit. Compared to subcritical boilers, supercritical boilers can follow loads better, ramp to full load faster, use less water, and require less steel for construction. The smaller steel requirements have also leveled the construction cost estimates for the two coal technolo- gies. The costs for a supercritical pulverized coal facility reflect the cost of adding a new unit 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. Carbon dioxide capture and sequestration technology represents a potential cost for new and ex- isting coal plants if future regulations require it. Research projects are underway to develop more cost-effective methods of capturing carbon dioxide from the flue gas of conventional boilers. One such concept involves the use of ammonia and chilling the flue gas. ALSTOM, a major sup- plier of utility boilers, gas-fired and steam turbine-generators, and air quality control equipment for power generation applications, has licensed a chilled ammonia process for the capture of CO2 from the flue gas from pulverized coal and natural gas-fired combined-cycle plants. The process is expected to have application for both new generating units and retrofit applications. This tech- nology holds the promise that the cost of energy from a pulverized coal plant with CO2 capture will be competitive with the cost of energy from an integrated gasification combined cycle plant with CO2 capture. ALSTOM is currently working on a 5 megawatt (thermal) demonstration scale facility along with the Electric Power Research Institute and We Energies that is to be constructed at We Ener- gies' Pleasant Prairie Plant. PacifiCorp is participating through EPRI in this CO2 Pilot Capture study; this participation will provide the company with access to summary analysis, perform- ance, and cost projections of the technology. Startup of the project is expected in mid-2007 with extensive testing for at least one year. American Electric Power (AEP) recently announced plans 31 Although the Supply-side Resource Options table shows the two Utah supercritical coal resources at 600 MW each, for modeling purposes, the company assumed that the second Utah resource would be acquired as a 57% share of 600 MW, or 340 MW. 32 The chilled ammonia process entails the use of ammonia in place of amine-based processes. Most studies done to date on CO2 capture from combustion gases have been based on the use of amine-based systems. Reagent costs are expected to be lower since ammonia is a reasonably low-cost commodity chemical. The use of ammonia instead of amine-based systems is expected to minimize the steam requirement associated with regenerating the solvent. This reduced steam requirement mitigates the impact on the net capability of the unit. Chilling the flue gas to low tem- peratures greatly reduces the volume of flue gas that has to be treated, thereby reducing equipment and process costs. The regeneration part of the process also operates at high pressure which reduces the electrical load associated with compression of the recovered CO2. PacifiCorp 2007 IRP Chapter 5 - Resource Options to install a 30 megawatt (thermal) demonstration in 2009 and a 200 megawatt equivalent demon- stration by 2011. Such large demonstrations will verify the commercial status of this process. is expected that the chilled ammonia system will be able to remove approximately 90% of the CO2 in the flue gas. PacifiCorp and its parent company MEHC are monitoring CO2 capture technologies for possible retrofit opportunities 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 necessary in the future. An alternative to supercritical pulverized-coal technology for coal-based generation would be the use of IGCC technology. A significant advantage for IGCC when compared to conventional pul- verized coal with amine-based carbon capture is the reduced cost of capturing carbon dioxide from the process. Gasification plants have been built and demonstrated around the world, primar- ily as a means of producing chemicals from coal. Only a limited number of IGCC plants have been constructed specifically for power generation. In the United States, these facilities have been demonstration projects and cost significantly more than conventional coal plants in both capital and operating costs. These projects have been constructed with significant funding from the federal government. A number of IGCC technology suppliers have teamed up with large con- structor to form consortia who are now offering to build IGCC plants. A few years ago, these consortia were willing to provide IGCC plants on a lump-sum, turn-key basis. However, in to- day s market, the willingness of these consortia to design and construct IGCC plants on lump- sum turn key basis is in question. An extensive and costly front-end engineering design (FEED) study is required to obtain reasonably accurate estimates of the cost of building an IGCC plant. In 2005-2006, PacifiCorp contracted with Worley Parsons to study the cost of an IGCC located either in Utah or Wyoming. The costs presented in the supply-side resource options tables reflect the general results of that study effort. An IGCC plant can be installed with a number of different configurations. Three different con- figurations are presented in the supply-side resource options table for an IGCC installed at a Utah location. One configuration involves installation of Level II emission controls with a spare gasifier and space provisions for future installation of carbon capture equipment. Level II emis- sion controls would include a selective catalytic reduction (SCR) system for enhanced NOx con- trol. A Level II emission control system would achieve emission levels close to those of a natu- ral gas-fired combined cycle plant. Installation of a spare gasifier would enable availability and capacity factors close to a conventional pulverized-coal plant. Another IGCC configuration pre- sented in the supply-side resource options table is for a plant without the spare gasifier. The third configuration presented is for an IGCC plant with carbon capture. The carbon capture case as- sumes a cost of $5/MWh for carbon dioxide sequestration; this cost includes the transportation injection, storage, and monitoring of the carbon dioxide in a local geological formation. PacifiCorp is involved in a number of potential IGCC projects that are in various stages of de- velopment. Major project development efforts are the Energy Northwest Pacific Mountain En- ergy Center (PMEC) and the Wyoming Infrastructure Authority (EPAct Section 413) project. PacifiCorp 2007 IRP Chapter 5 - Resource Options In March 2006, PacifiCorp responded with an expression of interest to Energy Northwest's invi- tation to participate in the PMEC project. Energy Northwest is currently in active negotiations with the two major technology consortia for the next stage of engineering and commercial efforts (Conoco-Phillips/Fluor/Siemens and General Electric/Bechtel), and the project is now going through the Energy Facility Site Evaluation Council (EFSEC) review process. The state of Washington recently passed Senate Bill 6001-climate change legislation that, among other pro- visions, implements a generation CO2 emission standard of 1 100 lbs of CO2 per MWh (or less) or permanent sequestration which meets the same level. Energy Northwest is currently evaluat- ing options that would allow the PMEC clean coal project to satisfy these emissions levels. PacifiCorp was recently selected by the Wyoming Infrastructure Authority (WIA) to participate in joint project development activities for an IGCC facility in Wyoming. The ultimate goal is to develop a Section 413 project under the EPact. PacifiCorp will commission and manage feasibil- ity studies with one or more technology suppliers/consortia for an IGCC facility at its Jim Bridger plant with some level of carbon capture. Alternate Wyoming sites may be considered. During this feasibility study stage, WIA will seek federal funding to support the next stage of development, which would include a detailed Front End Engineering Design (FEED) study. In addition to the PMEC and Wyoming IGCC projects, PacifiCorp has also been in discussions with a number of other proposed IGCC projects. These include Summit Power s IGCC project at Clatskanie, Oregon, Mission s IGCC project at Wallula, Washington, and Xcel's IGCC project in Colorado. Finally, PacifiCorp actively participates in the Electric Power Research Institute s CoalFleet pro- gram. CoalFleet is a major utility and technology supplier-sponsored initiative to accelerate de- velopment, demonstration, and deployment of IGCc. PacifiCorp is a member of the Gasification User s Association. In addition, PacifiCorp communicates regularly with the primary gasification technology suppliers, constructors, and other utilities. Natural Gas Natural gas generation options are numerous and a limited number of representative technologies are included in the supply-side resource options table. Simple cycle and combined cycle combus- tion turbines are included as well as distributed generation and CHP systems which are discussed below. Combustion turbine options include both simple cycle and combined cycle configurations. The simple cycle options include traditional frame machines as well as aero-derivative combustion turbines. Two aero-derivative machine options were chosen. The General Electric LM6000 ma- chines are flexible, high efficiency machines and can be installed with high temperature SCR systems , which allow them to be located in areas with air emissions concerns. These types of gas turbines are identical to those recently installed at Gadsby and West Valley. LM6000 gas tur- bines have quick-start capability (less than 10 minutes to full load) and higher heating value heat rates near 10 000 Btu/kWh. Also selected for the supply-side resource options table is General Electric s new LMS-lOO gas turbine. This machine was recently installed for the first time in a commercial venture. It is a cross between a simple-cycle aero-derivative gas turbine and a frame machine with significant amount of compressor intercooling to improve efficiency. The ma- PacifiCorp 2007 IRP Chapter 5 - Resource Options chines have higher heating value heat rates ofless than 9 500 Btu/kWh and similar starting capa- bilities as the LM6000 with significant load following capability (up to 50 megawatt per minute). Frame simple cycle machines are represented by the "F" class technology. These machines are about 150 megawatts at western elevations, and can deliver good simple cycle efficiencies. Other natural 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 megawatts. These machines are spark-ignited and have the advantages of a relatively attrac- tive heat rate, a low emissions profile, and a high level of availability and reliability due to the large number of machines. At present, fuel cells hold less promise due to high capital cost, partly attributable 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 2012. Combined cycle power plants options have been limited to 1x1 and 2x1 applications of "F" style combustion turbines and a "G" 1x1 facility. The "F" style machine options would allow an ex- pansion of the Lake Side facility. Both the Ix 1 and 2x 1 configurations 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 turbines. The "G" machine is only presented as a 1x1 option to keep the size of the facility reasonable for selection as a portfo- lio option. These natural gas technologies are considered mature and installation lead times and capital costs are well known. The capital cost pressure currently being observed with construct- ing large coal-based generation plants is also being experienced with natural gas-fired plants. The increased cost of natural gas has slowed the building of natural gas power plants in recent years. Over the past year, natural-gas-based resources have not seen the same level of cost in- creases as coal-based generation resources, However, this is expected to change; the same mar- ket forces that are affecting the cost of large coal-based projects also impacts the demand for major equipment, commodities, specialty steels, shop space, and craft labor needed for the con- struction of natural gas based resources, Wind Wind power has experienced rapid development in the U., as well as the Northwest. The re- newal of the investment tax credit with the Energy Policy Act of 2005 has made the availability of wind turbines an increasingly critical issue. The cost for wind turbines has increased signifi- cantly in recent months due to the demand for these machines. The overall strategy for wind project representation was to develop a set of proxy wind sites composed of 100 nameplate megawatt blocks that could be selected as distinct resource options in the Capacity Expansion Module. (Note that the 1O0-megawattsize reflects a suitable average size for modeling purposes, and does not imply that acquisitions are of this size.) Figure 5. shows the general regions in which wind resources were assumed to be available and the quan- tity limits available to CEM for selection. 100 PacifiCorp 2007 IRP Chapter 5 - Resource Options Figure 5.1- Proxy Wind Sites and Maximum Capacity Availabilities !'Fp%;PQrtAoglOle~ ~;#,\\ " SeattlE " " Washingt fI.'1ontana r.",liif"........i.., For other wind resource attributes, the company used multiple sources to derive attributes. PacifiCorp has been very active in purchasing wind projects in the last year. This has given the company considerable market knowledge of the current cost of wind development. Conse- quently, wind resources were developed primarily from PacifiCorp experiences with wind devel- opers and from responses to the 2003 renewable resource request for proposals. The EPRI TAG database was also used for certain cost figures, such as operation and maintenance costs. These costs were adjusted for current market conditions. For modeling purposes, it was deemed advantageous to represent wind projects as realistically possible by capturing the fluctuation of wind generation on an hourly basis, capturing the system costs and effects of the variability, seasonality, and diurnal shape of wind generation. These at- tributes and the methodologies used to derive them are discussed in Appendix J. 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 financial attributes of these renew- able options are based on the TAG database and have been adjusted based on PacifiCorp s recent construction and study experience. The geothermal resource is a dual flash design with a wet cooling tower. This concept would be similar to an expansion of the Blundell Plant. 33 Speculative risks associated with steam field de- velopment, as well as recent escalation in drilling costs, are not captured in the geothermal cost characterization. Note that at the time that PacifiCorp was deciding how to address renewable 33 A single flash expansion study was performed for Blundell unit 3 and filed with the state commissions in March 2007. The report is available on the Utah Public Service Commissions web site at: http:!!W\v'W . psc.state. ut. us! eJec/O 5docs/0 5 03 5 54/3 -20-07 Exhi b it%2 OB.doc 101 PacifiCorp 2007 IRP Chapter 5 - Resource Options resources in the IRP models, the renewable production tax credit was in effect only through the end of 2007, and the company did not include the credit in its geothermal project economic analyses. This treatment reflects the view that year-to-year tax credit extensions do not benefit projects with long development periods typical of a new geothermal plant. The biomass project would involve the combustion of whole trees that would be grown in a plan- tation setting, presumably in the Pacific Northwest. The TAG database used a western Washing- tqn site. The solar resource available in the TAG database is a solar thermal system using para- bolic trough technology with natural gas backup. Such systems have been installed in the south- ern California desert for many years. Cost and performance of these trough systems are well known. Combined Heat and Power and Other Distributed Generation Alternatives A number of different CHP applications were developed. These options were not derived from the EPRI TAG since the license purchased from EPRI was for larger power generation applica- tions. Costs for the CHP options listed come from a 2003 paper from the National Renewable Energy Laboratory (NREL) entitled "Gas-fired Distributed Energy Resource Technology Char- acterizations , and were adjusted for recent construction cost increases. CHP options include small (one megawatt or less) internal combustion engines with water jacket heat recovery, small (five megawatts or less) combustion turbines with exhaust gas heat recovery, non-combustion turbine based steam turbines (topping turbine cycle) systems to utilize process steam in industrial applications, and larger (40 to 120 megawatts) combustion turbines with significant steam based heat recovery from the flue gas. A large CHP concept has not been included in PacifiCorp eastern service territory due to a lack oflarge potential industrial applications. These CHP oppor- tunities are site-specific, and the generic options presented in the supply-side resource options table are not intended to represent any particular project or opportunity. In order to derive an estimate of potential CHP capacity availability within PacifiCorp s service territory for modeling purposes, PacifiCorp surveyed its Customer Account Managers for project opportunities and reviewed existing customer account data. A list of strong CHP prospects was developed. Based on the generic CHP resource capacities used in the supply-side resource op- tions tables, PacifiCorp determined the number of CHP resources to include as options for selec- tion by the Capacity Expansion Module. Table 5.5 profiles these CHP options by east and west- side location. Table 5.5 - CHP Potential Prospects StrongProspects CHP 25 MW Unit 3 units 2 units CHP 5MWUnit 5 units 2 units TotalCHP Capacity: Modeled Location East West 103 100 Energy Storage The storage of energy is represented in the supply-side resource options table with three systems. The three systems are advanced battery applications, pumped hydro and compressed air energy 102 PacifiCorp 2007 IRP Chapter 5 - Resource Options storage. These technologies convert off-peak capacity to on-peak energy and thereby reduce the quantity of required overall capacity installed for peaking needs. The concepts use TAG data and have been adjusted to account for current construction market conditions. Battery applications are typically smaller systems (less than 10 megawatts) which can have the most benefit in smaller local area. Pumped hydro is dependant on a good site combined with the ability to permit the facility, a process that can take many years to accomplish. PacifiCorp does not have any spe- cific pumped hydro projects under development. Compressed air energy storage (CAES) can be an attractive means of utilizing intermittent energy. In a CAES plant, off-peak energy is used to pressurize an underground cavern, The pressurized air would then feed the power turbine portion of a combustion turbine saving the energy normally used in combustion turbine to compress air. CAES plants operate on a simple cycle basis and therefore displace peaking resources. A CAES plant could be built in conjunction with wind resources to level the production for such an inter- mittent resource. A CAES plant, whether associated with wind or not, would have to stand on its own for cost-effectiveness. Nuclear An emissions-free nuclear plant has been included in the supply-side resource options table. This option is based on the TAG database as well as information from a paper prepared by the Ura- nium Information Centre Ltd. , " The Economics of Nuclear Power " April 2006. A 600 megawatt plant is characterized, utilizing advanced nuclear plant designs. Nuclear power is considered a viable option in the PacifiCorp service territory on or after 2018. DEMAND..SIDE RESOURCES Resource Selection Criteria For the 2007 IRP, PacifiCorp evaluated and handled each class ofDSM based on its characteris- tics and current availability. The company presented its proposed DSM resource representation and modeling methodology at a DSM technical workshop held on February 10, 2006, and con- sidered public feedback in developing its final scheme. The following is a summary, by DSM class, of how the DSM options were selected for evaluation in the IRP. Class 1 Demand-side Management To address Class 1 programs (fully dispatchable or scheduled firm), the company commissioned Quantec LLC to construct proxy supply curves. (See Appendix B for the entire Quantec DSM supply curve report.) The supply curves targeted PacifiCorp s existing program expansion oppor- tunities (e., air conditioning load control and irrigation load management) and new program opportunities identified as achievable. For modeling purposes, the Class 1 DSM opportunities were combined into the following five subcategories: Subcategory 1 - Fully dispatchable winter programs, such as space heating Subcategory 2 - Fully dispatchable summer programs, such as air conditioning, water heat- ing, and pool pumps Subcategory 3 - Fully dispatchable, large commercial and industrial, with a focus on ad- justment of the heating, ventilation, and air conditioning (HV AC) equipment during the top summer hours Subcategory 4 - Scheduled firm - irrigation 103 PacifiCorp 2007 IRP Chapter 5 - Resource Options Subcategory 5 - Thermal energy storage, small commercial and industrial, with a focus on cooling systems for summer hours Class 2 Demand-side Management For Class 2 programs (non-dispatchable, firm energy efficiency programs), PacifiCorp updated and added new sample load shapes to reflect energy efficiency program opportunities in the mar- ket as identified by recent studies such as the Northwest Power Planning Council's 5th Power Plan. For example, based on its review, the company determined that residential lighting load shapes for the west and east control areas should be added. Table 5.6 lists the load shapes adopted for the 2007 IRP. Chapter 6 discusses how these sample load shapes were used to de- velop cost-effectiveness values of additional Class 2 resources. Note that Class 2 DSM was not included as a resource option in portfolio modeling. The com- pany is working to complete 'a more comprehensive system-wide demand-side management po- tential study scheduled to be completed by June 2007. This study will be used to develop mod- eled resource options for Classes 1 2 and 3 for the next IRP. Class 3 Demand-side Management For Class 3 DSM (price responsive programs), PacifiCorp commissioned Quantec to develop proxy supply curves for three Class 3 program concepts: curtailable rates, critical peak pricing, and demand buyback/bidding (DBB) products (See Appendix B). As with the Class 1 DSM re- sources, the company obtained and considered public feedback from its February 2006 DSM workshop in selecting these Class 3 DSM resources for the IRP. Class 4 Demand-side Management Class 4 resources are sought by the company. However, these resources are not currently taken into consideration within the 2007 IRP because they cannot be relied upon for planning purposes or cannot be easily quantified. Over time, most Class 4 DSM savings manifest themselves within the company s loads and load forecasts. Resource Options and Attributes Class 1 Demand-side Management Tables 5.7 and 5.8 summarize the key attributes for the five DSM Class 1 program subcategories listed above for the west and east control areas respectively. Appendix B provides more informa- tion on how the attributes were derived. Attributes are provided for three scenarios: low, base 104 PacifiCorp 2007 IRP Chapter 5 - Resource Options and high achievable potential. These scenarios reflect PacifiCorp assumed on-peak electricity market prices of $40/MWh, $60/MWh, and $100/MWh respectively, as well as incrementally higher PacifiCorp marketing efforts, program costs, and customer participation levels. As already noted, Quantec developed these attributes for creation ofPacifiCorp DSM resources for portfolio modeling?4 The sources for the DSM attributes are Figures B.20 and B.21 in Appendix B, re- flecting the "no metering" cost assumptions (Also see the "Treatment of Metering Cost" section in Appendix B. Table 5.7 - Class 1 DSM Program Attributes, West Control Area .Fully Dis~ :FullyDis-" FtJlIyDjspatch.. ' Scheduled Thermali patchable- 'patchable ~ ' , !lbl~ ::.i:.;arge '!:Firm- Irri- 'Energy " Winter Sunlm:er "(3&1, " " 2ation "'Stotalie - $- $- $- $ Attributes Variable Costs ($/MWh) Demand Reduction Period (Hours) Start YearBASE , Total Achievable Potential Maximum (MW) Resource Costs ($/kW/vr) LOW " "" , Total Achievable Potential - Maximum (MW) Resource Costs ($/kW/vr)IDGH " , , Total Achievable Potential- Maximum (MW) Resource Costs ($/kW/yr) Hours Available by Month ,' d " ' 2009 2009 !!"' "!""'."",, ".!,,.. 2009 !" ".", 2009 2009 !"",, '! , ,",!"!!,., " 21 32 $ 75 $ 57 $ 89 $ 28 $ 119 .i" "!!,j(." """"!.' 11 $ 57 $ 60 $ 185 $ 29 .' "" ", "" ", "'; .' ",, ,. !." $ 116 Januarv February March Avril Mav $ 83 ' '' ." 10 38 $ 69 $ 104 $ 37 $ 121 . ,:' "!, ,' ,, " 240 186 180 186 186 180 279 June July Au!!:ust September October November December 34 Quantec s DSM resource attributes were considered interim information needed to complete the 2007 IRP while the company works to complete a more comprehensive system-wide demand-side management potential study scheduled to be completed by June 2007. 105 PacifiCorp 2007 IRP Chapter 5 - Resource Options Table 5.8 - Class 1 DSM Program Attributes, East Control Area ., """ , FullY:Ois..., i Yi;, ' ." patchabl~ , , " Winter Variable Costs ($/MWh) $ - Demand Reduction Period (Hours) Start Year BASE ,, ' ', , ",;,;, Total Achievable Potential Maximum (MW) Resource Costs ($lkW/yr) LOW ";i" ;, " Total Achievable Potential -Maximum (MW) Resource Costs ($/kW/yr) $ 57 $ 52 HIGH ' ", ", " Total Achievable Potential - Maximum (MW) Resource Costs ($/kW/vr) Hours Av:dIablebvMonth , January February March April May I ~, ' " Fully Dis;.Fully"Disp~~ch- ,Scheduled' p~tc~able -, abfe-I:argt\ , 'Fifiri':nH- ' Summer 'C&I 2ation ' - $- $ Therina.l i" En.ergYi , Stora.2c , $ - 2009 2009 2009 2009 2009 " ',, '" " $ 75 i",i' ' " $ 58 $ 82 " " $ 27 , ' $ 117 ) i $ 159 $ 28 $ 115 ', "' "':,.' "" ';;', '" . , $ 83 $ 71 28 $101 $36 $118 .. "" ', ."' ";", ". '" . i"i , , 240 186 180 186 186 180 279 June July Au!!:ust September October November December Class 2 Demand-side Management Figures 5.2 and 5.3 show the hourly end use shapes used for the Class 2 DSM decrement analy- sis. Figure 5.2 plots the hourly end use shapes for the peak day use for each of the 10 end uses. Figure 5.3 illustrates the seasonality of the end uses by plotting peak demand for each week. The east residential cooling shape was derived from an in-house metering study. All other shapes are composites of end use patterns from the Northwest Power Planning and Conservation Council. The megawatt scale ,on the y-axis of Figures 5.2 and 5.3 is for illustration purposes only and does not represent the market potential or planning estimates of any particular program for a given end use. For example, the commercial cooling shape was created from system specific weighting of hospital, school, office, lodging, and service cooling end use shapes. 106 PacifiCorp 2007 IRP Chapter 5 - Resource Options East and West Commercial Cooling Peak Day End Use Shape -16% LF Figure 5.2 - DSM Decrement, Daily End Use Shape (megawatts) Residential Heating Peak Day End Use Shape - 28% LF , , , . , 6 , , 9 " " " " " " " " " " " " " " " East and West Commercial Lighting Peak Day End Use Shape 49% LF , , , . , . , . 9 " " " " " " " " " " . " " a " East Residential Cooling Peak Day End Use Shape -12% LF --_._----_.__.._---~- , , , . , . , , 9 " " " " " " " " " " " " " " " East Residential Whole House Peak Day End Use Shape - 46% LF , , , . , . , . " " " " " " " " " " " . " " a " , , , . , 6 , . 9 " " " " " " " " " '" " " " " West Residential Whole House Peak Day End Use Shape - 35% LF , , , . , 6 , , , " " " " " " " " " '" " " " " " Residential Lighting Peak Day End Use Shape - 60% LF , , , . , 6 , , , " " " " " " " " " '" . " " " " West Residential Cooling Peak Day End Use Shape - 20% LF ' , . , 6 , , 9 " " " " " " " " " '" . " " " " 107 PacifiCorp 2007 lRP Chapter 5 - Resource Options East and West Commercial Cooling Weekly Peaks Decrement Figure 5.3 - DSM Decrement, Weekly Peaks (megawatts) Residential Heating Weekly Peaks Decrement East and West Commercial Lighting Weekly Peaks Decrement '00 -----~:-..., ooi- ... ... -,..... East Residential Cooling Weekly Peaks Decrement , " , , , " " " H " " " " " " " " " " " " " " " .. " East Residential Whole House Weekly Peaks Decrement r"" '00 -, , A A00 i " " IV ~/ ' ~v ----", - ,...... n"nH."""""M."".~""""" West Residenllal Whole House Weekly Peaks Decrement "'"nH."""""M""""~""""" West Residential Cooling Weekly Peaks Decrement ,...,""nH""""""M""".~".""" 35 Weekly residential lighting peaks are constant throughout the year, though the daily timing of the peak can vary with the season. 108 PacifiCorp 2007 IRP Chapter 5 - Resource Options Class 3 Demand-side Management Tables 5.9 and 5.10 summarize the key attributes for three DSM Class 3 program subcategories (curtailable rates, critical peak pricing and demand buyback) for the west and east control area respectively. Attributes are provided for three scenarios: low, base, and high achievable poten- tial. These scenarios reflect PacifiCorp assumed on-peak electricity market prices of $40/MWh $60/MWh, and $100/MWh respectively, as well as incrementally higher marketing efforts, pro- gram costs, and customer participation levels. Appendix B provides more information on how the Class 3 DSM attributes were derived. Table 5.9 - Class 3 DSM Program Attributes, West Control Area ....,' ......... ' . ClIdaiiable CriticalPeak Demand Attributes . . . Rates Priciril!.,Buyback Variable Costs ($/MWh)Market Prices Demand Reduction Period (Hours) Start Year 2009 2009 2009 BASE. . . " .) . Total Achievable Potential -- Maximum (MW) Resource Costs ($/kW/vr)$ 50 $ 56 $ 14 ' "' . LOW \ .., .. . Total Achievable Potential -- Maximum (MW) Resource Costs ($/kW/yr)$ 39 $ 136 $ 14 ffiGH ...... .. . Total Achievable Potential -- Maximum (MW) Resource Costs ($/kW/yr)$ 86 $ 48 $ 19 Hours Availablebv1\1'ontl1 ' , . -c- . .. .. Januarv February March April Mav June July 129 Auj!ust Seotember October November December 109 PacifiCorp 2007 IRP Chapter 5 - Resource Options Table 5.10 - Class 3 DSM Program Attributes, East Control Area $ 14 129 October November December Resource Descriptions Class 1 Demand-side Management Class 1 programs are divided into two types: fully-dispatchable and scheduled-firm. Often re- ferred to as direct load control (DLC), fully-dispatchable programs are designed to reduce the demand during peak periods by turning off equipment or limiting the "cycle" time (i., fre- quency and duration of periods when the equipment is in operation) during system peak. The offerings for the residential sector are seasonally divided, while the potential with large commer- cial and industrial customers typically focus on summer cooling loads only, PacifiCorp s fully- dispatchable resource options are as follows: Winter - Direct load control of water and space heating during winter are the program op- tions considered in this class. This program would be dispatched during the morning and evening peak hours. The largest potential for such a program will be in the west control area because of the higher saturation of electric space and water heating. Incentives are generally 110 PacifiCorp 2007 IRP Chapter 5 - Resource Options paid on a monthly basis. Although there are no large scale DLC programs in the Northwest Portland General Electric (PGE) and Puget Sound Energy (PSE) have both studied imple- mentation through pilot programs, Nationally, there are many utilities with space and/or wa- ter heating controls, including Duke Power, Wisconsin Power and Light, Great River Energy, and Alliant Energy. . Summer - The main demand reduction (DR) product in this group is direct load control air-conditioning units, which are typically dispatched during the hottest summer days, and are common place due to the relatively high summer loads in warm climates. PacifiCorp cur- rently pays monthly incentives to residential and small commercial participants in Utah' Cool Keeper AC Load Control program. There is approximately 130 megawatts of connected load for this program, which is expected to increase to 180 megawatt by summer 2007. Using a 50% cycling dispatch strategy, approximately half can be expected during an event. In ad- dition to those utilities listed above, Nevada Power, Florida Power and Light, Alliant Energy, MidAmerican Energy and the major utilities in California run air conditioner direct load con- trol programs (e., Sacramento Municipal Utility District and San Diego Gas and Electric). Large Commercial and Industrial - Direct control of large commercial and industrial (C&I) customers requires coordination with the existing energy management systems (EMS). The focus of this program type is adjustment of the HV AC equipment during the top summer hours. Incentives are generally paid on a per-kW or per-ton (of cooling equipment) basis. Some utilities running comparable programs include Florida Light & Power, Hawaiian Elec- tric, and Southern California Edison. Scheduled- firm program strategies are those that provide consistent reductions during pre- specified hours, and target customers with usage patterns and technology that allow scheduled shifting of consumption from peak to off-peak periods. These program strategies include the following: Irrigation Pumping - Irrigation load control is a candidate for summer DR due to the rela- tively low load factor (approximately 30%) of pumping equipment and the coincidence of these loads with system summer peak. Through PacifiCorp' s irrigation load control program customers subscribe in advance for specific days and hours when their irrigation systems will be turned off. Load curtailment is executed automatically based on a pre-determined sched- ule through a timer device. Although a total of 100 megawatts is contracted with this pro- gram, only half is available due to the alternating schedules of program participants. In the Northwest, Bonneville Power Authority (BPA) has run a pilot irrigation program (on a dis- patch, rather than scheduled, basis) and Idaho Power has a program similar to that of Pacifi- Corp. Thermal Energy Storage - For small commercial and industrial customers, it is possible to have thermal energy storage (TES) cooling systems that produce ice during off-peak periods which is then used during the on-peak period to cool the building. The system is programmed to use ice-cooling during pre-specified times (typically six hours per day, from April to Oc- tober) and participants are given incentives on a per-kW or per-ton-of-cooling basis. 111 PacifiCorp 2007 IRP Chapter 5 - Resource Options Class 2 Demand-side Management Class 2 DSM programs are not modeled in the 2007 IRP as resource options; rather, these are handled as a decrement to the load forecast. Appendix A provides descriptions of PacifiCorp current Class 2 programs. Class 3 Demand-side Management Curtailable rate options have been offered by many utilities in the United States for many years. These programs are designed to ease system peak by requiring that customers shed load by a set amount or to a set level (such as by turning off equipment or relying more heavily on on-site generation) when requested by the utility. Participants are either provided with a fixed rate dis- count or variable incentives, depending on load reduction; penalties are often levied for partici- pants who do not respond to curtailment events. Large commercial and industrial customers are the target market for those programs that address PacifiCorp s summer system peak. Many utili- ties provide a broad range of program options, including Duke Power, Georgia Power, Dominion Virginia Power, Pacific Gas and Electric, Consolidated Edison, Southern California Edison MidAmerican Energy Company, and Wisconsin Power and Light. Critical peak pricing (CPP) rates only take effect a limited number of times during the year. In times of emergency or high market prices, the utility can invoke a critical peak event, where cus- tomers are notified and rates become much higher than normal, encouraging customers to shed or shift load. Typically, the CPP rate is bundled with a time-of-use rate schedule, whereby cus- tomers are given a lower off-peak rate as an incentive to participate in the program. Customers in all customer classes (residential, commercial, and industrial) may choose to participate in a CPP program, although there are certain segments in the commercial sector that are less able to react to critical peak pricing signals. Currently, there are no CPP programs being offered by Northwest utilities. Peak pricing is, however, being offered through experimental pilots or full-scale pro- grams by several organizations in the United States, notably Southern Company (Georgia Power), Gulf Power, Niagara Mohawk, California utilities (SCE, PG&E, SDG&E), PJM Inter- connection, and New York ISO (NYISO). Adoption of CPP has not been as widespread in the Western states as they have in the East. In the Pacific Northwest, this may be partly explained by the generally milder climate and the fact that, due mainly to large hydroelectric resources, en- ergy, rather than capacity, tends to be the constraining factor. Demand buyback/bidding (DBB) products are designed to encourage customers to curtail loads during system emergencies or high price periods. Unlike curtailment programs, customers have the option to curtail power requirements on an event-by-event basis. Incentives are paid to par- ticipants for the energy reduced during each event, based primarily on the difference between market prices and the utility rates. Since 2001 , all major investor-owned utilities in the North- west and Bonneville Power Administration have offered variants of this option. PacifiCorp current program, Energy Exchange, was used extensively during 2001 and resulted in maximum reduction of slightly over 40 megawatts in that period. Demand reductions from PacifiCorp current program are approximately 1 megawatt. Demand buyback products are common in the United States and are being offered by many major utilities. The use of DBB offerings as a means of mitigating price volatility in power markets is especially common among independent system operators including CAISO, NYISO, PJM, and ISO-NE. However, DBB options are not currently being exercised regularly due to relatively low power prices. 112 PacifiCorp 2007 IRP Chapter 5 - Resource Options TRANSMISSI ONRESO DR CES Resource Selection Criteria PacifiCorp developed its transmission resource options to support new generation options in- cluded in the IRP models, to enhance transfer capacity and reliability across PacifiCorp s system and to boost import/export capability with respect to external markets. These options included transmission projects targeted for investigation as part of the MEHC acquisition commitments. (See Chapter 2 , " MidAmerican Energy Holdings Company IRP Commitments. Resource Options and Attributes Transmission options developed for portfolio analysis are shown in Table 5.11.36 The column labeled "Point A" indicates one end of the transmission path, and "Point B" the other end. The maximum capacity associated with moving generation from one end to the other is shown in the subsequent columns. For resource optimization modeling, the CEM was allowed to phase in transmission purchases in 500 megawatts blocks as needed for four of the transmission paths: Bridger East-Ben Lomond (4); Mona-Utah North (5); Wyoming-Bridger East (8); and Utah North-West Main (9). Included in all portfolios is the MidAmerican Energy Holdings Company commitment (34a) for the 300 megawatt Path C upgrade assumed to be available in 2010. The transmission options as represented in the model topology are shown in Figure 5.4. Table 5.11 - Transmission Options AtoBCa-:QtoAc:apal; pacity ity. . FirsfYear Number of No.. Point A ,.. Point B (MW) (MW).Availablti.. Additions Walla Walla Yakima A 630 2010 Walla Walla Yakima B 400 400 2010 West Main Walla Walla 630 2010 Jim Bridger East Ben Lomond 500 2012 Mona Utah North 500 2012 Path C - South Utah North 600 2011 Yellowtail Jim Bridger 400 2011 Wyoming Jim Bridger East 500 500 2012 Utah North West Main 500 500 2012 Utah South Desert Southwest (in-600 600 2012 eludes Mona-Oquirrh) Base Transmission Assumptions--For All Portfolios ....--- Path C - South Utah North 300 2010 Craig-Hayden Park City 176 2010 36 The 2007 integrated resource plan used proxy transmission additions for portfolio planning purposes. The timing and cost of these proxy additions are based on high level planning estimates which are subject to change as more infonnation becomes available. The company may address specific transmission needs by entering into new wheel- ing contracts, building additional facilities, or participating in joint transmission projects. 113 PacifiCorp 2007 IRP Chapter 5 - Resource Options Transmission requirements associated specifically with wind resources located in southwest Wyoming, southeast Wyoming, and eastern Nevada were not modeled as transmission paths within the CEM. The transmission costs associated with those resources were included in the capital costs of the wind resources themselves, with the generation modeled as occurring (as de- livered) in Utah North for the southwest Wyoming wind; Jim Bridger East for the southeastern Wyoming wind; and Utah South for the eastern Nevada wind. In addition to these resource options, PacifiCorp also modeled a regional transmission project for sensitivity analysis using the Capacity Expansion Module. This resource serves as a proxy for projects like the proposed Frontier Project that links generation in Wyoming with load centers in Utah, Nevada and California. See Chapter 6 , " Scenario and Sensitivity Study Development", for more details on how this regional transmission resource was modeled. Figure 5.4 - Transmission Options Topology MARKET. PURCHASES Resource Selection Criteria PacifiCorp and other utilities engage in purchases and sales of electricity on an ongoing basis to balance the system and maximize the economic efficiency of power system operations. In addi- tion to reflecting spot market purchase activity and existing long-term purchase contracts in the 114 PacifiCorp 2007 IRP Chapter 5 - Resource Options IRP portfolio analysis, PacifiCorp modeled front office transactions (FOT), Front office transac- tions are proxy resources, assumed to be firm, that represent procurement activity expected to be made on an annual forward basis to help the company cover short positions. For this IRP, PacifiCorp tested portfolios that included a limit of 1 200 megawatts of front office transactions beyond 2011. Table 5.12 shows the maximum capacity available for the four market hubs in cases where front office transactions limits were applied. Table 5.12 - Maximum Available Front Office Transaction Quantities by Market Hub . Maximum Available , (Japacity 250 250 500 200 200 Marketllub West Main Mid Columbia F our Corners Mona TOTAL 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. Resource Options and Attributes Two front office transaction types were included for portfolio analysis: a west-side annual flat product, and an east-side heavy load hour (HLH) 3rd quarter product. The west-side transaction reflects purchases of flat annual energy-a constant delivery rate over all the hours of a year- delivered to the West Main bubble,37 The east-side transactions are represented as heavy load hour (16 hours per day, 6 days per week) purchases from July through September available for delivery at both the Mona and Four Corners market hubs. Because these products are assumed to be firm for this IRP, the capacity contribution of front office transactions is grossed up for pur- poses of meeting the planning reserve margin. For example, a 100 megawatt front office trans- action is treated as a 112 megawatt contribution to meeting a 12 percent planning reserve margin with the selling counterparty holding the reserves necessary to make the product firm. Prices for front office transaction purchases are associated with specific market hubs-Mid- Columbia (Mid-C), Mona, and Four Corners-and are set to the relevant forward market prices for the relevant time period and location. 37 A bubble refers to a distinct area of a system model's network topology encompassing one or a combination of the following attributes: load, generation, markets (purchases and sales), and transmission facilities. A bubble is also referred to as a transmission area. 115 PacifiCorp 2007 IRP Chapter 5 - Resource Options Resource Description As proxy resources, front office transactions represent a range of purchase transaction types. 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 "strike" price) and typically rely on standard enabling agreements as a contracting vehicle. Front office transaction prices are determined at the time of the transaction, usually via a third party broker and based on the view of each respective party regarding the then-current forward market price for power. An optimal mix of these purchases would include a range in terms for these transactions. Solicitations for front office transactions can be made years, quarters or months in advance. An- nual transactions can be available up to as much as three or more years in advance. Seasonal transactions are typically delivered during quarters and can be available from one to three years or more in advance. The terms, points of delivery, and products will all vary by individual mar- ket point. Proposed Use and Impact of Physical and Financial Hed!!in2 The company proposes to continue to hedge the price risk inherently carried due to volume mis- matches between sales obligations and economic resources by purchasing or selling fixed-price energy in the forward market. The purpose of these transactions is to mitigate the company financial exposure to the short term markets, which historically have much greater price volatil- ity than the longer term markets. Specifically, purchasing to cover a short position in the for- ward market reduces the company s financial exposure to increasing prices, albeit these transac- tions also reduce the company s financial opportunity if prices decrease. Selling to cover a long position has a similar effect. The company proposes to continue to hedge its electricity and natural gas fixed-price exposure using both physical products and financial products. Both products are effective in hedging this exposure. 116 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach 6. MODELING AND RISK ANALYSIS APPROACH ThelRPJllodelingeffort seeks to detertniiiet4ecomp~ative~ost;fis supply ity,ande.missionsattributes ofresourceponfollps: ' . ", .. , 1'l1eZO07IRPmodelingeffort 'consistedoftqreepha.se.s:( l)resol.1rce scteeiiirig using the".. c om p any s ' .' capacity" e-xp aDS ion ,0 p tiIliii~tioij:t661(tl1e . qapa9ityExpaIlsion ',1\'1 od ul e , orCI3Mj, ,(2) fisk analysis 'portf olioaey~l opIlieJit;arid (3) deta.il~a Pl"obabilistic (sto'- chastic)prpduction cost simulation aiidl'esoW-Cehska~a1Ysi~: ' ,, '' , . For resource 'screening, PacifiCorp de:fine9' It)~itett1ative fut:Ure)scenaposandassoci': atedsenSitivi ty sfudi es. with the assis tailceofp1ihlIcsllikeholdets :tliesea1ternative fu'- turestestwide variations in potentialC()2 regilHltoIycosts naMalgas prices; whole- sale electricity prices, retail load. growth, andtl1escqpe o:fxetiewable,portfoli O'stan-dards. " " ' ' ", . Inadditioii, the company defl11edfutures,toe.vah.late the a.vaila.billtyof repewablepro- ductiontaxcreditsandthe ,level ofachieyahlemarketpot~ntialfof l(jad control, and demand--response programs. ' , PacifiCorp next defined ' risk,analysis,portfo1i(jsforstochasticsimulation.The CEM was used to helpbllild fixedresource.investmel1fschedules for'wiJ).d,anddistributedte- sources, and to optimize the selectionof()therr~~oUrceoptionsaccordingtospecific re- source strategies. ' ', ,, ' PacifiCorp devoted considerable effort to modeLthe effect ofQKhemissioncompliance strategies. 'AILrisk analysis portfolios were simulated with fiveCO~ adder levels- $O/ton, $8/ton, $ 15/ton, $38/ton, and $61/ton (in 2008 dollars)a.ndassociatedforward gas/electricity ,price forecasts. The companYlIlodeled botha,capLand4rade andemis- sionstax compliance strategy, and expanded its'reporting,ofCQ2e.missionsimpacts. Portfolio perfonnance was assessed with the following measures: (1) stochastic mean cost (Present , V alueof Revenue Requirements ),(2) customer rate ' impact, measured as thelevelizedhet present value of the change in the system averagecu!)tomer price due to new resources for 2008 through 2026, (3)emissionsextemalitycost, (4) capital cost (5) risk exposure, (6) CO2 and other emissions, (7) and supply reliability statistics. 117 PacifiCorp 2007 IRP ... ... INTRODIJCTIO N Chapter 6 - Modeling and Risk Analysis Approach The IRP modeling effort seeks to determine the comparative cost, risk, reliability, and pollutant emissions attributes of resource portfolios. These portfolio attributes form the basis of an overall portfolio performance evaluation. This chapter describes the modeling and risk analysis process that supported portfolio performance evaluation, The information drawn from this process summarized in Chapter 7, was used to help determine PacifiCorp s preferred portfolio. The 2007 IRP modeling effort consists of three phases: (1) resource screening, (2) risk analysis portfolio development, and (3) detailed production cost and stochastic risk analysis. The Capac- ity Expansion Module (CEM) supports resource screening and development of risk analysis port- folios. Detailed production cost simulation and associated stochastic analysis, which attempts to quantify the most significant sources of portfolio risk, are supported by the Planning and Risk (PaR) Module. Figure 6.1 characterizes the three phases in flow chart form, showing the main steps involved and how these phases are linked with the preferred portfolio selection phase (far right on the chart). This chapter covers each of these steps. Figure 6.1- Modeling and Risk Analysis Process Resource Screening and Risk AnalysisPortfolio Development (Capacity Expansion Module)r - - - - :~~ : - : - - -- - - - ~ : I . Scenario development: i: I "altel1lative future~'and sensitivity studies '" ~I '" 1 :; 1 ,CottductCEM . ~ 1 optimization hmsforeachscenario ex: . '______--- -------- .RESO URGE SCREEN IN G Detailed Stochastic Production Cost Simulation and Risk Analysis (Planning and Risk Module) Preferred Portfolio Selection Poitf'olio perfOlinanee . measures For resource screening, PacifiCorp evaluated generation, demand-side management, market pur- chase, and transmission resources on a comparable basis using the Capacity Expansion Module. The CEM performs a deterministic least-cost optimization with these resources over the twenty- year study horizon. To support resource screening, the company developed a set of "alternative future" scenarios to study. These scenarios consist of combinations of input variables represent- 118 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach ing the primary sources of portfolio cost uncertainty. Additional sensitivity analysis scenarios were also developed to investigate the individual effects of certain planning and resource- specific assumptions. The main objectives of this screening effort include the following: Determine and study resource selection choices given different assumptions about the future Determine the range of resource quantities selected for alternative future scenarios designed to favor one or more resource types over others. Identify the frequency of resources selected across the alternative futures modeled. Determine acquisition patterns (quantities and timing) for smaller-scale resource types- front office transactions, wind, DSM programs, and Combined Heat and Power facilities- be incorporated into the risk analysis portfolios based on an aggregate view of the alternative future modeling results. Alternative Future Scenarios The alternative future scenarios consist of cases to test the impact of variations in load growth as well as combinations of several variable values that simulate conditions variously favorable and unfavorable to the major resource types (coal, gas, renewables, and DSM). The input variables chosen to represent the alternative futures consist of the following: Incremental coal cost, consisting of new CO2 regulatory costs (via a dollar-per-ton CO2 ad- der) and alternative commodity price trends driven by assumptions on coal production and transportation costs. Natural gas and wholesale electricity prices, based on PacifiCorp s forward price curves Retail load growth The level of renewable electricity generation requirements stemming from renewable portfo- lio standard (RPS) regulations The availability of renewable energy Production Tax Credits (PTCs) after 2007 The potential for demand-side management programs, defined as a program s achievable market potential adjusted to account for competition with existing programs PacifiCorp developed low, medium, and high values for each of these input variables to ensure that a reasonably wide range in potential outcomes is captured. The one exception is for renew- able PTC availability, which was structured as a yes-or-no outcome. Table 6.1 profiles the 16 alternative future scenarios developed, indicating the assigned variable value levels for each of the six input variables. Note that alternative future scenarios are labeled with the acronym "CAF", which stands for CEM alternative future. The CAF studies include a business-as-usual case reflecting no new regulatory requirements (CAFOO) and a medium case based on the company s official load forecast and forward price curves (CAFl1 , " medium load growth"). All CAF scenarios assume a 15-percent planning reserve margin. 119 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Table 6.1 - Alternative Future Scenarios ~F I ~wn. fi' .' C~o~~~M ~I~c I ~ iIIII~ft~ Business As Usual NonelMedium Medium Medium Low Yes Medium Low Cost Coal/High Cost Gas None/Low High Medium Medium Yes Medium with Low Load Growth None/Low High Low Medium Yes Medium with High Load Growth None/Low High High Medium Yes Medium High Cost Coal/Low Cost Gas HighlHigh Low Medium Medium Yes Medium with Low Load Growth High/High Low Low Medium Yes Medium with High Load Growth High/High Low High Medium Yes Medium Favorable Wind Environment High/Medium High Medium High Yes Medium Unfavorable Wind Environment NonelMedium Low Medium Low No Medium High DSM Potential High/Medium High Medium Medium Yes High 10 Low DSM Potential NonelMedium Low Medium Medium Yes LowII Medium Load Growth MediumlMedium Medium Medium Medium Yes Medium 12 Low Load Growth MediumlMedium Medium Low Medium Yes Medium 13 High Load Growth MediumlMedium Medium High Medium Yes Medium 14 Low Cost Portfolio Bookend None/Low Low Low Medium Yes Medium 15 High Cost Portfolio Bookend High/High High High Medium No Medium ~ariable Value Frequency Counts (Excluding "Business As Usual" Scenario) High" Count 6/4 N/A Medium" Count 3/7 N/A Low" and "None" Count 6/4 N/A IrOT ALS 15/15 N/A In developing these scenarios as well as other CEM studies, PacifiCorp relied heavily on feed- back from public stakeholders. An important design criterion was to ensure that the scenarios, in aggregate, were not biased towards certain resource outcomes. As indicated at the bottom of Ta- ble 6., the number of scenarios with low and high values for an input variable is the same. An- other design criterion was to construct them so as to enable straightforward comparisons with respect to changes in variables, particularly load growth. Table 6.2 summarizes the values and data sources for the input variables with low, medium, and high values. Additional details for each input variable follow. 120 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Table 6.2 - Scenario Input Variable Values and Sources Input Variable co2 Cost Adder Coal Commodity Prices for New Resources Natural Gas Prices Wholesale Electricity Prices Retail Load Growth Renewable Portfolio Standards Class 1 and Class 3 DSM Achievable Potential 12% lower than the Pacifi- Corp Fuels Marketing & Supply Group price forecast b 2026 32% lower than the Pacifi- Corp official forward prices (dated August 3 2006), on an average annual basis for 2007 through 2016 14% lower than the Pacifi- Corp official forward prices, dated August 31 2006, on an average annual basis for 2007 through 2016; low values reflect a $O/ton CO2 adder and the PIRA low Gas price fore- cast case Average annual system- wide load growth of 0. for 2007 through 2026 3% of system-wide retail load by 2020 Starting in 2009: . 69 MW of Class 1 pro- grams . 40 MW of Class 3 pro- rams MediUm Value $8/ton in 2008 dollars, beginning in 2010 with costs phased in at 50%, escalating to 75% in 2011 and 100% in 2012 PacifiCorp Fuels Marketing & Supply Dept. price fore- cast PacifiCorp official forward prices, dated August 31 2006; Incorporates PIRA Energy s August 3, 2006 probabilistic-weighted long-tenn gas forecast PacifiCorp official forward prices, dated August 31 2006 Average annual system- wide load growth of 2. for 2007 through 2026 (PacifiCorp long tenn load forecast, Ma 1 , 2006) 6% of system-wide retail load by 2020 (Assumes California, Washington and Oregon RPS targets in lace StartIng in 2009: . 153 MW of Class programs . 106 MW of Class 3 ro rams . Hi h Value $37.9/ton in 2008 dollars ($25/ton in 1990 dollars), beginning in 2010 with costs phased in at 50%, escalating to 75% in 2011 and 100% in 2012 20% higher than the PacifiCorp Fuels Marketing & Supply Group price forecasts b 2026 86% higher than the PacifiCorp official forward prices (dated August 3 2006), on an average annual basis for 2007 through 2016 25% higher than the PacifiCorp official forward prices, dated August 31 2006, on an average annual basis for 2007 through 2016; high values reflect a $37.7/ton CO2 adder and the PIRA high gas price forecast case Average annual system- wide load growth of3. for 2007 through 2026 15% of system-wide retail load by 2020 (Assumes RPS targets in place in all states) Starting in 2009: . 219 MW of Class 1 programs . 166 MW of Class 3 ro rams Carbon Dioxide Regulation Cost For the CO2 regulation cost, PacifiCorp sought public comments and recommendations on a suit- able cost adder for its high scenario value. At the IRP public meeting held on June 7, 2006 PacifiCorp proposed $25/ton and $40/ton adders (in 1990 dollars). Meeting participants accepted the $25/ton level ($38/ton in 2008 dollars) as appropriate for reflecting the threshold at which a significant shift in resource selection would occur based on regulatory costs. 121 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Commodity Coal Cost Percentages for the low and high coal commodity cost values are based on the U.S. Energy In- formation Administration s low and high delivered coal price sensitivity forecast cases reported in the 2006 Annual Energy Outlook.38 PacifiCorp assumed one-half of the difference between the sensitivity and reference cases to account for the fact that transportation costs, a main com- ponent of the cost forecast, are a relatively smaller portion of the delivered fuel cost in the Rocky Mountain region than for the u.s. as a whole. Natural Gas and Electricity Prices Due to the strong correlation between natural gas and wholesale electricity prices, these variables were linked together as low, medium, or high values for a scenario. The low and high gas price forecasts were based on PIRA Energy s Henry Hub low and high prices cases, and come from PIRA Energy s long-term gas forecast update, dated June 15 2006. Figure 6.2 shows the system average annual low, medium, and high natural gas prices. Figure 6.3 shows the system annual average low, medium, and high electricity prices by Heavy Load Hour and Light Load Hour pe- riods. Figure 6.2 - System Average Annual Natural Gas Prices: Low, M~dium, and High Scenario Values 20, 18, 16. 14, 12, :E 10. 8.00 00 ' 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 ...... System-Medium -II- System-High -+- System-Low 38 u.S. Energy Infonnation Administration Annual Energy Outlook 2006 with Projections to 2030 DOE/EIA- 0383(2006), December 2005.39 Heavy Load Hours constitute the period from 6 a.m. to 10 p., Monday through Saturday. Light Load Hours are 10 p.m. to 6 a., Monday through Saturday, and all of Sunday and holidays. 122 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Figure 6.3 - System Average Annual Electricity Prices for Heavy and Light Load Hour Natural Gas Prices: Low, Medium, and High Scenario Values $180 $60 _.- .~.... . e. . '. =': . $40 .. . ... . .. . ..... . .... . e' . ' e." e. $160 $140 $120 $100 tii $80 ...........+.............. $20 - 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 ---#--. HLH-High ... LLH-High -.&- HLH-Medium .... LLH-Medium -+- HLH-Low . + . LLH-Low Retail Load Growth The low and high load growth forecasts were determined by using the 5th and 95th percentile average load values from 100 stochastic iterations of the PaR model for 2026. Annual growth factors were applied to the medium load forecast. For the low forecast, the growth factor is the ratio of the average loads for the 5th percentile stochastic values to the load for the medium value in 2026. For the high forecast, the growth factor is the ratio of the average loads for the 95th percentile stochastic values to the load for the medium load value in 2026. Renewable Portfolio Standards For modeling the impact of renewable portfolio standards across the company s six-state service territory, PacifiCorp determined a system-wide annual generation requirement based on an as- sessment of state RPS requirements in California and Washington, and the contribution of each state to system retail sales. The system renewables generation requirement is translated into an incremental requirement by deducting renewables generation expected for 2007. Class 1 and Class 3 DSM Potential The development oflow, medium, and high potentials for Class 1 and Class 3 demand-side man- agement programs is described in detail in Chapter 5 and Appendix B. The Class 1 DSM pro- grams included in the alternative future scenarios consist of dispatchable load control, scheduled irrigation, and thermal energy storage. The Class 3 programs consist of curtailable rates, critical peak pricing, and demand buyback. While the alternative future scenario studies included both Class 1 and Class 3 programs as resource options, only Class 1 resources were considered for risk analysis portfolio development. This decision was based on the need to conduct further re- 123 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach search on the reliability of Class 3 DSM resources to address peak load demand issues, and to improve the modeling representation of the programs based on the DSM potentials study. Sensitivity Analvsis Scenarios for the Capacity Expansion Module The Capacity Expansion Module sensitivity analysis scenarios-designated with the acronym SAS and totaling 16 in number-are intended to supplement the alternative future analysis.4o The focus of these scenarios is to determine optimal portfolios resulting from changes to secondary variables and other resource selection factors, with the results to be compared to those for a ref- erence scenario. These sensitivity scenarios are defined with the primary variable values speci- fied for the "Medium Load Growth" scenario (CAFll) except where noted below. The CEM sensitivity scenarios, which are listed in Table 6.3, test the following conditions: Alternative capacity Planning Reserve Margin levels -low (12%) and high (18%) values. Deferred carbon dioxide adder implementation - CO2 costs start accruing in 2016 as opposed to 2012, which is the assumed year of a fully phased-in CO2 adder. The impact of a regional transmission project - The regional transmission option consists of a new 1 500-megawatt line from Wyoming to the SP15 transmission zone in southern Cali- fornia, and a new 1 500-megawatt line from Utah to the NP15 transmission zone in northern California. (The CEM was not allowed to choose this resource; rather, it was fixed in order to determine the economic benefits assuming that it is built and PacifiCorp acquires an owner- ship share or transmission rights. Determination of the carbon dioxide adder threshold value that affects resource selection; specifically, run the CEM with incrementally higher CO2 adders to determine at what point major changes in resource selection are made. Low and high wind project capital costs (see Table 6.4) Low and high coal commodity prices Low and high IGCC plant capital costs (see Table 6.4) Integrated Gasification Combined Cycle technology configurations - constrain the Capacity Expansion Module to select an IGCC plant if not chosen as a resource given expected values for the primary variables (i., the "Medium Load Growth", CAFll). The IGCC plant is tested with three configurations: minimum carbon capture provisions, one gasifier, and car- bon sequestration included. The scenarios are used to determine the incremental cost impact relative to an unconstrained resource choice. An alternative approach for determining the peak system obligation Impact of renewable Production Tax Credit expiration combined with other regulatory de- velopments favorable for wind projects, namely CO2 regulation and widely-adopted renew- able portfolio standards. This scenario uses variable values defined for the "favorable wind environment" alternative future scenario (CAF07). 40 A sensitivity scenario for testing the impact of replacing Klamath Falls hydro units with alternative resources was excluded from the list, as it was detennined that such analysis was not appropriate for the IRP setting given ongoing litigation and settlement discussions. 41 In its 2004 IRP Acknowledgement Order, the Oregon Public Utility Commission directed PacifiCorp to "evaluate alternatives for detennining the expected annual peak demand for detennining the planning margin-for example planning to the average of the eight-hour super-peak period." (Order No. 06-029, January 23 , 2006. 124 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Table 6.3 - Sensitivity Scenarios SAS# Name Table 6.4 - CEM Sensitivity Scenario Capital Cost Values Input Variable IGCC Capital Cost Wind Capital Cost Plan to 12% planning reserve margin Basis . Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario # Medium Load Growth" Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario # ;Medium Load Growth" Alternative Futures Scenario # Medium Load Growth" Plan to 18% planning reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: test $15 , $20, $25 per ton adders (approximately $10, $15 , and $20 in 1990 dollars) Low wind capital cost Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario # Medium Load Growth" Alternative Futures Scenario # Medium Load Growth" Alternative Futures Scenario # II Medium Load Growth" High wind capital cost Low coal price High coal price Low IGCC capital cost High IGCC capital cost Add a carbon-capture-ready IGCC to the portfolio (base case for SAS13 and SASI4 Replace the IGCC resource in the SASI2 portfolio with a single- asifier version Replace the IGCC resource in the SASI2 portfolio with one that includes carbon se uestration SAS #12 SAS #12 Plan to "average of super-peak" load Favorable Wind Environment" scenario assuming perma- nent ex iration of the renewab1es PTC be innin in 2008 Alternative Futures Scenario #11 Medium Load Growth" Alternative Futures Scenario #07 Favorable Wind Environment" Low Value 5% lower than the PacifiCorp Resource Development and Construction Dept. cost esti- mates Medium V alue Based on a configuration with mini- mum carbon capture preparation and Level II emission controls. PacifiCorp Resource Development and Construc- tion De 1. cost estimates Based on PacifiCorp Resource Devel- opment and Construction Dept. cost estimates Hih Value 12.5% higher than the PacifiCorp Resource Devel- opment and Construction Dept. cost estimates 10% lower than the PacifiCorp Resource Development and Construction Dept. cost esti- mates 11 % higher than the Pacifi- Corp Resource Development and Construction Dept. cost estimates 125 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Sensitivity Analysis Scenarios for the Plannin!! and Risk Module A number of stochastic simulations were performed for sensitivity analysis purposes. Several of the scenarios were designed to address specific risk analysis requirements identified in the Ore- gon Public Utility Commission s Integrated Resource Planning guidelines and 2004 IRP ac- knowledgement order. The Planning and Risk Module sensitivity scenarios test the following conditions: Plan to a 12% planning reserve margin, and include a sufficient amount of Class 3 demand- side management program capacity to eliminate Energy Not Served (ENS).42 This study addresses an Oregon Public Utility Commission acknowledgement order requirement. Plan to an 18% planning reserve margin - use the same portfolio resources selected by the Capacity Expansion Module for Sensitivity Analysis Scenario #2 ("Plan to 18% capacity reserve margin Using one of the risk analysis portfolios as the basis, replace a new base load resource with an equivalent amount of front office transactions to determine the incremental cost and risk impacts. Using one of the risk analysis portfolios as the basis, replace a base load pulverized coal resource with an IGCC plant that has minimum carbon capture provisions. Also include suf- ficient shorter-term resources to maintain the planning reserve margin until an IGCC plant can be placed into service. Using one of the risk analysis portfolios as the basis, replace a new resource with Combined Heat & Power (CHP) and aggregated dispatchable customer-owned standby generators to de- termine the incremental cost and risk impacts.43 This sensitivity addresses an analysis re- quirement in the Oregon Public Utility Commission s 2004 Integrated Resource Plan ac- knowledgement order. Capacity Expansion Module Optimization Runs The Capacity Expansion Module is executed for each alternative future and sensitivity scenario generating an optimized investment plan and associated real levelized present value of revenue requirements (PVRR) for 2007 through 2026. To avoid bunching of coal-fired resources at the end of the 10-year investment period when higher variable cost CCCT growth stations become available, a two-year investment extension period is added to enable the model to select all re- source options through 2018. 42 Energy Not Served is a condition due to physical or market constraints where insufficient energy is available to meet load obligations.43 Large industrial sector CRP was included as a resource option in the CEM scenarios. For this sensitivity scenario, proxy resources representing small-to-medium sized industrial CRP plants (5 and 25 MW) were included along with a resource representing aggregate standby generators. For standby generators, PacifiCorp used Portland General Electric Company s standby generator program as the basis for detennining resource characteristics. Due to air quality issues in Utah, standby generators were only modeled as a west-side resource. 44 Growth stations are included as a generic resource choice beginning in 2019 to address load growth, plant retire- ments, and contract expirations during the out-years of the study period. Optimizing with a single resource for part of the study period is a necessary compromise for maintaining acceptable model run-times. 126 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach The CEM 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 planning reserve margin for the 24-zone model topology). To accomplish these optimization objectives, the model performs a time-of-day least-cost dispatch for existing and potential planned generation contract, demand-side management, and trans- mission resources. The dispatch is based on a representative-week method. Time-of-day hourly blocks are simulated according to a user- specified day-type 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 elec- tricity 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 am- ortized capital costs for planned resources. Modeling Front Office Transactions Front office transactions, described in Chapter , 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, the CEM engages in market pur- chase acquisition-both front office transac- tions and spot market purchases-to the extent it is economic given other available resources. The model can select virtually any quantity of FOT generation up to limits imposed for each scenario, in any study year, independently of choices in other years. However, once a ftont office transaction resource is selected, it is treated as a must-run resource for the duration of the transaction. In addition, ftont office transactions are only available through 2018. After 2018, the purchases are set to zero, at which point the model can'select "growth sta- tions. " The transactions modeled in the Planning and Risk Module generally have the same charac- teristics as those modeled in the CEM, except that transaction prices reflect wholesale for- ward electric market prices that are "shocked" according to a stochastic modeling process prior to simulation execution, For capital cost derivation, the CEM uses annual capital recovery factors to address end-effects issues associated with capital-intensive invest- ments of different durations and in-service dates. PacifiCorp used the real-Ievelized capital costs produced by the CEM for PVRR reporting by both the CEM and Planning and Risk module. RISK ANAL YSISPORTFOLIO DEVELOPMENT Risk analysis portfolios refer to portfolio solutions, obtained from one or more CEM runs, which are subjected to stochastic production cost simulation using the Planning and Risk module. To develop the risk analysis portfolios, PacifiCorp relied on the CEM to build fixed resource in- . vestment schedules for wind and distributed resources, and to optimize the selection of other resource options according to specific resource strategies defined as constraints on the model solution. For example, a resource strategy may entail restricting the range of resource choices placing constraints on when resources can be selected, or implementing upper limits on resource quantities. The impact of evolving state regulatory policies was considered in developing re- source constraints. 127 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach Determination of Fixed Resource Investment Schedules PacifiCorp used the CEM to determine fixed resource investment schedules for certain smaller- scale resource types-wind, demand-side management programs and CHP facilities-in order to limit resource variability for subsequent CEM optimization studies and in the risk analysis port- folios themselves. (Restricting the number of resources is important for managing portfolio analysis complexity and model run-times.) These investment schedules constitute set resource quantities, locations, and in-service dates that are included in all risk analysis portfolios. In the case of the proxy wind resources, PacifiCorp developed multiple fixed investment schedules for portfolio testing. For DSM and CHP a single investment schedule was developed and used in the risk analysis portfolios. The company determined most of the fixed resource investment schedules by assessing the CEM's resource selection behavior across the range of alternative future scenarios described above. The next chapter describes the investment schedules derived from the alternative future scenario analysis. Alternative Resource Stratel!ies PacifiCorp s resource strategies fall into two categories: (1) those intended to evaluate the im- pacts of incremental resource changes, and (2) those intended to evaluate a specific resource in- vestment policy. Strategies that fall into the first category typically involve specifying model constraints around a single resource, such as forcing selection for a certain year or removing it altogether as an option. The second category encompasses strategies that broadly tackle certain portfolio risks. Such risks include CO2 regulatory costs, escalation and volatility of wholesale electricity and natural gas prices, and potential state restrictions and standards for resource acqui- sition (e., renewable portfolio standards). Examples of such resource strategies include elimi- nating or deferring an entire resource type such as coal, gas, or market purchases. Optimization Runs for Risk Analysis Portfolio Development The CEM is ready for execution once the fixed resource investment schedules and resource strategies have been defined and input into the model. All CEM runs are configured as "Mixed Integer Programming" problems. This means that expansion choices can be represented as either build/not-build binary variables or continuous variables that enable the model to select fractional resource amounts. The mixed integer solution better characterizes investments where large fixed capital costs are involved. In certain cases, a single CEM run completely defines the portfolio that is to be simulated using PaR. In other cases, a group of CEM runs are used to test multiple resource strategies or assump- tions. For this later situation, PacifiCorp manually selects the resource investment schedule based on observations across the set of CEM runs. This approach is typically used to determine the model's selection behavior for a specific resource when other resources are constrained in differ- 45 A limitation of this modeling strategy is that variable amounts of DSM and CHP resources were not subjected to risk analysis using the PaR model. PacifiCorp will continue to refine its approach to modeling distributed resources in concert with the scheduled June 2007 receipt of DSM and CHP supply curve data from the multi-state DSM po- tentials study. 128 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach ent ways. A resource that is routinely selected or chosen for a certain year indicates a robust re- source under the set of simulated resource strategies. The CEM is then executed a second time with this fixed set of generation resources. The purpose of this additional run is to have the CEM optimize the selection of remaining available resource options, thereby ensuring that the final portfolio meets the model's planning reserve margin constraints. This two-step process is sum- marized in Figure 6.4. Figure 6.4 - Two-Stage Risk Analysis Portfolio Development Process Phase 1: Resource Screening Stochastic simulation with the Planning and Risk Module STOCHASTICSIMULA TION OF RISK ANALYSIS PORTFOLIOS Stochastic Risk Analysis PacifiCorp next simulates each risk analysis portfolio, along with existing system resources, us- ing the Planning and Risk model in stochastics mode. The PaR simulation produces a dispatch solution that accounts for chronological commitment and dispatch constraints. The PaR simula- tion also incorporates stochastic risk in its production cost estimates by using Monte Carlo ran- dom sampling of five stochastic variables: loads, commodity natural gas prices, wholesale power prices, hydro energy availability, and thermal unit availability. 46 Although wind resource generation was not varied in the same way as the other stochastic variables, the hour-to- hour generation did vary throughout the year, but the pattern was repeated identically for all study years (2007- 2026) and iterations (1-100). 129 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach A stochastic model in PaR guides the random sampling process. The stochastic model accounts for both short-term and long-term variable volatility as well as correlation effects among the variables. (Appendix E describes PacifiCorp s stochastic modeling methodology.) The output of the stochastic model consists of stochastic parameters-multipliers that represent the stochastic shocks" applied to the expected value forecasts for each variable. The PaR model is configured to conduct 100 Monte Carlo simulations for the 20-year study pe- riod, 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 runs (itera- tions) reflecting a wide range of alternative futures. PacifiCorp derives expected values for the Monte Carlo simulation by averaging run results across all 100 iterations. The company also looks at subsets of the 100 iterations that signify particularly adverse cost conditions, and derives associated cost measures as indicators of high-end portfolio risk, or "risk exposure." The company uses scatter plots of portfolio cost versus risk exposure to help assess how each portfolio performs with respect to balancing cost and risk, as well as showing the cost- risk tradeoff for specific resource strategies. Scenario Risk Analysis In addition to modeling portfolio stochastic risks (the base stochastic simulation step in Figure 1), stochastic simulations were also conducted with various CO2 emission cost adders to cap- ture the risks associated with potential CO2 emission compliance regulations. Since the probabil- ity of realizing a specific CO2 emissions cost cannot be determined with a reasonable degree accuracy, potential CO2 emission costs were treated as a scenario risk in this IRP. PacifiCorp defines a scenario risk as an externally-driven fundamental and persistent change to the expected value of some parameter that is expected to significantly impact portfolio costs. This risk cate- gory is intended to embrace abrupt changes to risk factors that are not amenable to stochastic analysis. The practice of combining stochastic simulation with CO2 cost adder scenario analysis represents advancement with respect to the modeling approach used for PacifiCorp s 2004 IRP. Previously, the company simulated CO2 scenario risks using several separate deterministic production cost runs. Another scenario risk investigated in this IRP is potential widespread enactment of California greenhouse gas emissions performance standard. (See Chapter 3 , " California Greenhouse Gas Emissions Policies , for background information.) PacifiCorp used the CEM and PaR models to develop a portfolio that (1) excludes all new resources-generation and purchase contracts-that fail the emission performance threshold and (2) meets system-wide Renewable Portfolio Stan- dard generation requirements stemming from assumed RPS enactment in all of PacifiCorp' s west-side jurisdictions. Stochastic simulation of this portfolio yielded cost, risk, and CO2 emis- sion measures for comparison against other risk analysis portfolios. The results of this analysis are reported as the conclusion to Chapter 7. 130 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach tPOR TFOLIO'PERFORl\lANCE MEASURES Stochastic simulation results for the risk analysis portfolios were summarized and compared to determine which portfolios perform best according to a set of performance measures. These measures, grouped by category, include the following: Cost Stochastic mean cost (Present Value of Revenue Requirements, or PVRR) Customer rate impact Environmental (emissions) externality cost Capital cost Risk Risk exposure Production cost variability Emissions Carbon dioxide emissions Reliability Average annual Energy Not Served (ENS) Loss of Load Probability (LOLP) The following sections describe in detail each of the performance measures listed above. Stochastic Mean Cost The stochastic mean cost for each risk analysis portfolio is the average of the portfolio s net vari- able operating costs for 100 iterations of the PaR model in stochastic mode, combined with the capital cost additions of new resources determined by the CEM for that portfolio. 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. 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 com- ponents included in the stochastic mean PVRR include the value of renewable energy credits (green tags), renewable production tax credits, emission allowance costs and credits, and the cost assigned to Energy Not Served,. Emission allowance costs or credits are determined outside the CEM and PaR models and added to the PVRR as one of the final calculation steps. 47 The cost of Energy Not Served is set to $400/MWh, which is the FERC wholesale electricity price cap now in effect for the California Independent System Operator. Note that PacifiCorp added this cost to its stochastic PVRR calculations subsequent to the distribution of early risk analysis portfolio results to public stakeholders in October 2006. 131 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach The PVRR measure captures the total resource cost for each portfolio. Total resource cost in- cludes 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. In addition, the PVRR accounts for emissions adders used for costing environmental externalities. Customer Rate Impact In addition to PVRR measures, PacifiCorp calculates the per-megawatt-hour customer rate im- pact associated with each of the risk analysis portfolios. The rate impact measure is the change in the customer dollar-per-megawatt-hour price for the period 2012 through 2026, expressed on a levelized net present value basis. This approach differs from the one used for the 2004 IRP in two respects. First, the rates represent stochastic mean values from the Monte Carlo simulations rather than deterministic values. Second, the rate is a single summary change measure. In contrast, the 2004 IRP reported just the year-to-year im- pacts. The dollars in the rate numerator consist of the stochastic mean system operating cost (fuel cost cap-and-trade environmental cost, and variable O&M costs of all resources), combined with the fixed O&M and capital costs of the new supply-side and transmission resources.48 The rate de- nominator is the retail load. The present value calculations use a 7.1 % discount rate. It should be noted that this measure provides an indication of the comparative rate impacts across risk analysis portfolios, but is not intended to accurately capture projected total system revenue requirements. For example, planned upgrades for current stations such as pollution controls added under PacifiCorp s Clean Air Initiative, as well as hydro relicensing costs, are not in- cluded in the calculations. Likewise, the IRP impacts assume immediate ratemaking treatment and make no distinction between current or proposed multi-jurisdictional allocation methodolo- gIes. Environmental Externality Cost For this IRP, PacifiCorp quantified environmental externalities by using externality cost adders for air emissions impacts-an approach that is consistent with prior company IRPs. The quantifi- cation of air emissions impacts through cost adders is generally recognized as the least ambiguous and least subjective approach to assessing externalities. A full range of other potential impacts, such as those on water supplies, traffic and land use patterns, and visual or aesthetic qualities, critically depend on the specifics of any particular project. The DSM potentials study to be completed in June 2007 addresses environmental externalities not currently included in this IRP. 48 New IRP resource capital costs are represented in 2006 dollars and grow with inflation, and start in the year the resource added. This method is used so resources having different lives can be evaluated on a comparable basis. The customer rate impacts will be lower in the early years and higher in the later years when compared to customer rate impacts computed under a rate-making formula. 132 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach The externality cost adder is treated as a variable cost in both the CEM and PaR models, and therefore is accounted for in each model's dispatch solution. Cost adders are included for CO2, SO2, NOx, and mercury (Hg) emissions. See Chapter A of the Technical Appendix for informa- tion on pollutant allowance prices used in the IRP models.Modeling the Impact of CO2 Externality Costs on Forward Electricity Prices PacifiCorp currently uses an inflation-adjusted CO2 allowance price of $8/ton (2008$) in its calculation of official forward electricity price curves. These official price curves serve as the wholesale electricity price inputs to both the CEM and PaR models, For alternative CO2 cost adders, new price curves are estimated using the Company s market price forecasting model, MIDAS. The forward price curves need to account for the effect of a CO2 allowance market on fore- casted natural gas, SO2 allowance, and NOx allowance prices. PacifiCorp contracted with ICF Consulting to estimate these interaction effects for use in developing the forward elec- tricity prices needed for the CO2 cost adder scenarIOs. ICF us cd their national power market simula- tion tool, IPM(jD, to develop natural gas, SO2 allowancc, and NOx allowance prices taking into account the CO2 allowance prices pro- vidcd by PacifiCorp. The IPM(jD simulations used ICF's "expected case" model run as the starting point for forecast development. Allowance trading markets for NOx and SO2 currently exist, while a market for mercury is slated to start in 2010. Carbon emissions are currently not regulated except in California. To simulate the impacts of allowance trading, al- lowance costs and credits are estimated outside of the CEM and PaR models using a spread- sheet model. The allowance trading calculations use baseline annual emissions caps along with the PaR model's annual emission quantities for a portfolio simulation. (For a stochastic simula- tion, the calculations use the average emissions across the 100 iterations.) Annual emissions above a cap are multiplied by the per-ton annual allowance price (or in the case of mercury, a per-pound price), while emissions below the cap are assigned a cost credit equal to the difference between the cap and the actual emissions multi- plied by the allowance price. Note that as a sim- plifying assumption, all allowances are traded in the year accrued. The resulting net present value of the 20-year stream of annual allowance balances is included in the PVRR. PacifiCorp modeled future carbon regulation scenarios assuming that CO2 ,emissions are capped to 2000 levels, and that a CO2 allowance trading market begins in 2010. In recognition of the timing uncertainty, 2010 CO2 costs are probability-weighted by a factor of 0.50. Likewise 20 II costs are weighted by a factor of 0.75. By 2012, the full inflation-adjusted CO2 allowance cost is imposed, growing at inflation thereafter. The CO2 adder scenario simulations were performed with five adder levels: $0, $8 , $15 , $38, and $61 per ton (in 2008 dollars). For the $61/ton cost adder, the cap-and-trade program is assumed to start in 2010, but is not fully phased in until 2016. As a key performance measure, PacifiCorp reports the emissions externality cost as the increase in stochastic mean PVRR relative to the $0 adder case at each successively higher CO2 adder level. For the set of risk analysis portfolio finalists, the externality cost is calculated as a tax 49 To avoid double counting, the emission adder cost is backed out of the PaR model's total production cost. 133 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach (emission quantity multiplied by the emissions cost adders) as well as a net allowance cost bal- ance under a cap-and-trade regime for all pollutants. Risk Exposure Risk exposure is the stochastic upper-tail mean PVRR minus the stochastic mean PVRR. The upper-tail mean PVRR is a measure of high-end stochastic risk, and is calculated as the average of the five stochastic simulation iterations with the highest net variable cost. Risk exposure is somewhat analogous to Value at Risk (VaR) measures. The fifth and ninety-fifth percentile PVRRs are also reported. These PVRR values correspond to the iteration out of the 100 that represents the fifth and ninety-fifth percentiles, respectively. These measures represent snapshot indicators of low-risk and high-risk stochastic outcomes. Capital Cost The total capital cost measure is the sum of the capital costs for generation resources and trans- mission, expressed as a net present value. Production Cost Variabilitv To capture production cost volatility risk, PacifiCorp uses the standard 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 annual costs for 2007 through 2026. Carbon Dioxide Emissions Carbon dioxide emissions are reported for two time periods: 2007-2016 and 2007-2026. The 10- year view excludes the emissions impact of growth stations-generic combined cycle units that serve primarily to meet load growth beyond the 10-year investment window. For risk analysis portfolios considered as finalists for preferred portfolio selection, CO2 emis- sions are reported for both generation sources (direct emissions) as well as combined with the net effect of wholesale market activity. The emission contribution assigned to market purchases (in- direct emissions, net of emission credits from wholesale sales). The indirect CO2 emissions re- lated to purchases are calculated by multiplying net purchased power generation by an average emissions factor of 0.565 tons/MWh which is offset by emissions deemed to go with wholesale sales at the average system emission rate. This factor is based on actual 2005 purchases, and is applied through the 20-year forecast. The total system emissions footprint (generation only) for sulfur dioxide, nitrogen oxides, mercury is also reported for the period 2007-2026. Supply Reliabilitv Energy Not Served Energy Not Served is a condition where there is insufficient generation available to meet load because of physical constraints or market conditions. Certain iterations of a PaR stochastic simu- lation will have "Energy Not Served" or ENS. This occurs when an 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. For example, a large load shock in a transmission- constrained topology bubble would yield a relatively large amount of ENS. Running the PaR 134 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach model in stochastic mode without including the stochastic variability of load yields virtually no ENS over the planning horizon. Similarly, deterministic PaR simulations do not experience ENS because there is no random behavior of model parameters; loads increase in a smooth fashion over time. The stochastic ENS results, averaged across all 100 iterations, are used to compare the reliability among portfolios when stressed. Consequently, stochastic ENS results are indicative of relative differences in portfolio reliability given extreme modeled conditions with low probability of oc- currence, and are not intended to represent indicators of expected system reliability under normal conditions. It is noteworthy that in actual practice PacifiCorp has not needed to shed retail load other than the curtailment contract customers, due to a resource shortage. For reporting of the ENS statistics, PacifiCorp calculates an average annual value for 2007 through 2016 in gigawatt-hours, as well as the upper-tail ENS (average of the five iterations with the highest ENS). Simulations using the $8/ton CO2 cost adder are reported, as the adder level does not have a material influence on ENS results. Loss of Load Probability The new IRP guidelines issued in January 2007 by OPUC (Order 07-002) state: Loss of load probability, expected planning reserve margin, and expected and worst-case unserved energy should be determined by year for top-performing port- folios. To meet the LOLP guideline, PacifiCorp developed a metric and applied it to the risk analysis portfolios simulated with the Planning and Risk model. Loss of Load Probability is a term used to describe the probability that the combinations of online and available energy resources cannot supply sufficient generation to serve the load peak during a given interval of time. Mathematically, LOLP is a simple concept: LOLP = PreS S L) where is a random variable representing the available power supply, and L is the daily load peak where the peak load is regarded as known, Traditionally LOLP was calculated for each hour of the year, converted to a measure of statisti- cally expected outage times or number of outage events (depending on the model), and summed for the year. The annual measure estimates the generating system s reliability. A high LOLP gen- erally indicates a resource shortage, which can be due to generator outages, insufficient installed capacity, or both. Target values for annual system LOLP depend on the utilities' degree of risk aversion, but a level equivalent of one day per ten years is typical. Loss of load probability is considered a limited measure of reliability, and does not account for numerous risk factors, util- ity agreements, and other considerations that govern the operation of the utility network. 135 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach For reporting LOLP, PacifiCorp calculates the probability of Energy Not Served events, where the magnitude of the ENS exceeds given threshold levels. PacifiCorp is strongly interconnected with the 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 7, the proportion of iterations with ENS events in July exceeding selected threshold levels are reported for each risk analysis portfolio simulated with the PaR module. The LOLP is reported as a study average as well as year-by-year results for an example threshold level of 25 000 Megawatt-hours. This threshold methodology follows the lead of the Pacific Northwest Resource Adequacy Forum, which re- ports the probability of a "significant event" occurring during the winter season. PREFERRED PORTFOLIO SELECTION The preferred portfolio is selected from among the risk analysis portfolios primarily on the basis of relative cost-effectiveness, customer rate impact, and the balance between cost and risk expo- sure. Also important is the robustness of the portfolios with respect to their cost and risk per- formance under successively higher CO2 adder scenarios; the portfolios that consistently rank the highest regardless of the assumed CO2 adder are strong contenders for selection as the prefelTed portfolio. Supply reliability risk and CO2 emissions are also important, but playa lesser role in selecting the preferred portfolio because differences among portfolios with respect to these measures are relatively small. These primary selection criteria are in line with state IRP guidelines that dictate that the pre- ferred portfolio be least-cost after accounting for uncertainty, risk, and the long-run public inter- est. CLASS 2 DEMAND-SIDE.MANAGEMENT PROGRAM. ANALYSIS Decrement Analvsis For the Class 2 demand-side management decrement analysis, the preferred portfolio was used to calculate the reduced system operating costs (or decrement value) of various types of Class 2 programs. PacifiCorp will use these decrements values when evaluating the cost-effectiveness current programs and potential new DSM programs between IRP cycles. The process used for this IRP is to model Class 2 DSM program types as contracts that supply energy according to hourly load shapes provided by PacifiCorp s DSM department. These con- tracts serve as surrogates for direct load reductions attributable to energy efficiency programs. The Planning and Risk Module is then run in stochastics mode with and without the Class 2 DSM resources to establish the change in system cost (reduction in the stochastic mean PVRR for 100 simulations) from lower market purchases or resource re-optimization due to the addition of the Class 2 DSM. This approach differs from that used in the 2004 IRP. For the 2004 IRP, the load decrements were modeled as reductions in the load forecasts, with system cost differences determined by deterministic PaR runs. The new approach simplifies the data set-up process and accounts for stochastic risk in the cost estimates. 136 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach To detennine the Class 2 DSM decrements, 12 shaped planning decrements, each at 100 mega- watts at peak, were modeled starting in 2010 throughout the 20-year IRP study period. The dec- rements are shaped to each of the following loads for both the east and west control areas. Table 5 below provides an overview of the planning decrement design, showing the load size (load factor) and end-use hourly load shape. Table 6.5 - Planning Decrement Design Decrement ~ast~yst~mLoad W e~t~ystem.L.oadSize .cCenter Center100 MW 7% Load Factor 20% Load Factor100 MW 60% Load Factor 60% Load Factor 100 MW 46% Load Factor nla 100 MW 16% Load Factor 16% Load Factor100 MW 49% Load Factor 49% Load Factor 100 MW nla 28% Load Factor 100 MW East load shape West load shape (approx. 65% Load (approx. 67% LoadFactor) Factor The company will evaluate additional DSM program opportunities by replacing the forward- market-price avoided cost used in the traditional DSM cost effectiveness tests with the shaped decrement values. For such evaluations , the decrement values will be pro-rated to match the load shape of new DSM proposals. Once new programs are implemented, their contributions to load reductions will be incorporated directly into the load forecast used for the next IRP. Public Utility Commission Guidelines for Conservation Pro2ram Analvsis in the IRP During the 2007 integrated resource planning process and development of the company s Class 2 energy efficiency resource assessment, there were questions raised as to whether PacifiCorp had sufficient information available, absent the completion of a system-wide demand-side resource assessment study, to arrive at a fair representation of the energy efficiency resource potential available over the planning period. While having additional data from such a study would likely have provided additional clarity around this assessment, the company had several other reliable sources of information from which to arrive at a forecast of achievable resource potential as rep- resented within the 2007 IRP. These sources have been used for prior planning exercises and continue to be used to identify significant resource opportunities. Additionally, these sources have proven reliable in the past in helping the company achieve verifiable results. Class 2 energy efficiency resources comprise a significant portion of the overall demand-side management investments and resource targets within the 2007 IRP. There are approximately 250 MWa of Class 2 energy efficiency resources accounted for within the 2007 preferred portfo- lio, These resources were identified through a composite of resource assessment exercises con- ducted over the last five years. These assessments, coupled with the performance of the com- pany s existing demand-side resource portfolio and associated lessons-learned, aided PacifiCorp in the development of the 2007 Class 2 energy efficiency plan contributions. The studies and infonnation sources relied upon included market-specific as well as measure-specific characteri- 137 PacifiCorp 2007 IRP Chapter 6 - Modeling and Risk Analysis Approach zation studies/work, third-party program process and impact evaluations, regional assessments such as the Northwest Power Planning Council's 5th Power Plan, the Energy Trust of Oregon forecast, demand-side management advisory groups, and others. These sources represent the most relevant information available from which to draw assumptions regarding resource poten- tial. The company s confidence in this information is reflected in their use for adjusting the 2007 plan s load forecast, indicating they will be acquired within cost-effective parameters. To avoid foreclosing opportunities to exceed the 250 MWa target already established for the IRP until a new target can be defined using the results of the multi-state DSM potentials study, the company intends to use the Class 2 DSM decrement analysis described above to establish values at various load shapes, of 200 MWa of incremental resource acquisitions (beyond the 250 MWa in the 2007 IRP) that might present themselves between planning cycles. However, since the amounts and shapes, availability, timing and acquisition costs are less certain than the resources from existing programs and assessments, they were not placed within the company s 2007 load and resource balance. As these resources are identified and determined to be cost-effective based on the decrement values, they will be incorporated into the next integrated resource plan update. Modeling of demand-side resources in the 2007 integrated resource planning process is robust and treats them as functionally equivalent to supply-side resources, even without the utilization of specific supply curves. Forecasted loads are reduced by the known and certain demand-side management resources in much the same manner that a supply-side resource would offset the load. In regards to additional assessment work, PacifiCorp will complete a comprehensive system- wide demand-side resource market assessment by late June, 2007. At that time, the company will begin incorporating the results of that assessment, in addition to the sources identified above and used during this IRP planning cycle, into the planning assumptions and forecasts going forward. Once the system-wide demand-side resource assessment information is available, both the in- cremental 200 MWa amount as well as the Class 2 DSM modeling methodology will be re- visited to assure that the planning process places the appropriate dependence on demand-side resources commensurate with their availability. In summary, while the potential study and supply curves will refine the company s approach to assessing and modeling demand-side management resources, the current practices and ap- proaches do not arbitrarily limit the amount, the value or potential acquisition of cost-effective energy efficiency resources within the current plan. 138 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results 7. MODELING AND PORTFOLIO SELECTION RESULTS , , , C~apt~rHigblights PacifiCorp assessed 16a1ternativ~'ft:rtlJ.fescenariOst()detepriine resollfcesanddrpaCity , quantities suitableforinc1usioll iIl.r!ska.nalysispbItfoJids. 'Base40n the QapacityExpan.. ' sion Modllle.s ,optimizedinvestmeptplaIls thecornpanyselectedwind (a proxy for all renewables) ,comQinepheatandpd'wei sbpercnti c~npulveri:z;ed' "coal(SCPC~.;.col11Qined ' cycle combustion,1;cirbine ,.( CGCT~,ingle-cyc1ecol11bustion tutbine,($ GCT),iritegrated gas ifi cati 0 nmcombin~(:t'cyc le (IGQC),i load.()ontrolpf(u~ra.ms ,~md' sh ort- tepri ,market 'pur- chases (front officetra.Ilsactions) in,subse:quentpoItfoliostudi~s; , " , The analysis of the original 12 portfolios informed the development of the ,second set of portfolios; theseportfdlios focusedonthetimiIlgofSQPC ' plants, the:mixofgas..;fired plants and market purchases toaddresseast-sideloadgtowth, the ti:m!Ilg,a.ndtypeofre- sources needed to :make lIP for the lossofth~ BPApeakingcontraCt in, 201 1 ,and the planning reserVeIIlilrginlevel. " ., The company initiililystlldi~g ,i2.pgI't.fqlios\ls!ngitsstopl1asticprodl.l(;tioncOst simula- tion model. ThesepoI'tfolios tested.a.",arie:tyqfresource strategies , disttrig-uisp,edby the planning reserve ma.rgirrandthequantityof'Wlnci,pulverized coal , ' frot1foffiee transac- tions, and IGCCresoUrce:s included." " ,. " , , , ,,;; The stochastic 'modeling "result$ fqr the 12Pdrtf9liqs indicate "that . the:~e:ststra.tegy " .' fot achieving alow-cqst~tisk- info~edJ10rtfoliois to' iIJplude sltpercriticalpulverized coal along with additionalwindand naturalgasresOlrrcesto mitigate,GO2costlisk , .. , PacifiCorp evaluat~cla second,set offiv~.pOItfolioS toaccduntfor(l)newande:volving state resourcepQlicie~/t1:Iafpla.ceconstraints .on the ,company's iesourcechoices atid(2) new Wyoming load growth inf()rma.tiori. AIL of theseportfoliosin.cluded600 megawatts of addi ti onalwind(lncre:me:rltalto 'theorigina.1 1;400- megawattre:newab lescol111TIitment), 100 megawattsofCHP and95 megawatts of new 10adcoIltrblprograms. Based on superiorpeifonnance withrespecttostochastic cost, customer rate impact, cost vs. risk balance, and supply reliability, a portfolio with the following characteristics was chosen as the preferredpbrtfolio: - A total of 2 000 megawatts of renew ab1es by 2013 - A west..;side GCCT in 2011 - High-capaCity-factorbaseload resources in the east in2012and 2014 East -side CCCTs, in 2012 ,and2016 Balance of system need fulfilled byfront office transactions beginning in 2010 139 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results INTROI)HCTION ' This chapter presents modeling results for the portfolio analysis, as well as chronicles the devel- opment of the portfolios, the associated decision process that guided their formulation, and the selection of a preferred portfolio. Discussion of the portfolio analysis results falls into the following six sections. Alternative Future and Sensitivity Scenario Results - This section presents the Capacity Expansion Module s optimized resource investment plans and PVRRs for the alternative fu- ture and sensitivity scenarios. These results constitute the outcome of the resource screening phase of the IRP modeling effort. Risk Analysis Portfolio Development and Stochastic Simulation Results - This section describes the derivation and resource specifications for the risk analysis portfolios, and then provides a comparative assessment based on the performance measures described in Chapter 6. Creation of fixed investment schedules for wind, demand-side management programs, and combined heat and power resources, is covered first, followed by a description of the portfo- lio design goals and alternative resource strategies used to formulate them. The section also presents findings on a cost-versus-risk exposure tradeoff analysis of the resource strategies. (As discussed in Chapter 6, risk exposure is defined as the upper-tail mean PVRR minus the overall stochastic mean PVRR. Selection of the Preferred Portfolio - This section provides a consolidated view of the port- folio evaluation results to indicate which portfolio is the most desirable after cost, risk, reli- ability, CO2 emissions, and state resource policy evolution are considered. Fuel Diversity Planning - This section describes how fuel source diversity is addressed in the 2007 Integrated Resource Plan. Forecasted Fossil Fuel Generator Heat Rate Trend - This section reports the system- average fossil fuel generator heat rate trend for the preferred portfolio. This information ad- dresses a new Utah Commission IRP reporting requirement to support the PURP A Fuel Sources Standard. Class 2 Demand-side Management Decrement Analysis - This section presents the dec- rement values for Class 2 program evaluations using the preferred portfolio to calculate the system benefit. , , AL TERNA TIVEFUTORE. AND SENSITIVITY SCENARIO RESULTS Alternative Future Scenario Results This section presents the modeling results and findings for the CEM alternative future studies. As a refresher, Table 7.1 repeats the alternative future specifications outlined in Chapter 6. 140 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.1- Alternative Future Scenarios " " ii Coal (:()st: , ' "."", ' CO2Adder/Coal Ga~l ". d CoJrlJrl()dity ".Elecfric' "Load , "' ",.".." Price Price ,.. Growth None/Medium Medium Medium None/Low High Medium None/Low High Low None/Low High High High/High Low Medium High/High Low Low High/High Low High HighlMedium High Medium NonelMedium Low Medium HighlMedium High Medium None/Medium Low Medium MediumlMedium Medium Medium MediumlMedium Medium Low MediumlMedium Medium High None/Low Low Low ,," CAF # N ailie .., 00 Business As Usual 01 Low Cost Coal/High Cost Gas02 With Low Load Growth03 With High Load Growth 04 High Cost Coal/Low Cost Gas05 With Low Load Growth06 With High Load Growth 07 Favorable Wind Environment 08 Unfavorable Wind Environment 09 High DSM Potential 10 Low DSM PotentialII Medium Load Growth 12 Low Load Growth 13 High Load Growth 14 Low Cost Portfolio Bookend 15 High Cost Portfolio Bookend High HighHigh/High RenewablePTC DSM A vaihlbility Potentbd.Yes MediumYes MediumYes MediumYes MediumYes Medium Renewable Sales Perc~ntage due to RPS Low Medium Medium Medium Medium Medium Medium High Low Medium Medium Medium Medium Medium Medium Medium Yes Yes Yes Yes Yes Yes Yes Yes Yes Medium Medium Medium Medium High Low Medium Medium Medium Medium Medium Table 7.2 reports the PVRR and total cumulative additions (2007-2018) by resource type for the 16 alternative future studies. The wind capacity contribution and average annual front office transactions acquired for 2007 through 2018 are also shown. Table 7.2 - Alternative Future Scenario PVRR and Cumulative Additions for 2007-2018 !~~l~hh~t! /; h~I/ ' '" Oil Oil ....., ;;~ ;;:;;: I; .$, "ifIf! If! ... ;:: ;:::... \,; \,; :: 'i ,Ii! ffo" :::: :::: ...,!!; ,!!; f! \,; \,; \,; ... 1:5 t::; ...;; iiJ ~~!fiit 7' 7' , ~,' & f!j ';' ':' "i- f!s ::; ;;;;;! ! 'I J J .. .. I; eg I!! ...... Study PVRR oJ oJ ;l! ifU r:;' ~ CAFOO $ 19,619 15%103 150 125 125 500 440 500 134 715 966 111 CAFOI $ 18,071 15%103 151 002 2.440 1.100 217 718 669 769 CAF02 $ 11.022 15%" 78 500 440 600 125 618 406 467 CAF03 $ 30 159 15%169 602 602 125 634 1.361 510 2.440 100 514 580 748 860 CAF04 $ 30 504 15%698 698 125 823 200 354 101 961 105 CAF05 $ 23 920 15%52 '125 2.100 317 2324 796 916 CAF06 $ 40 002 15%82" 169 1.498 300 798 125 923 2.400 409 6.492 071 232 CAF07 $ 33.339 15%100 100 500 2.440 600 568 698 753 866 CAF08 $ 18858 15%129 150 150 125 275 750 154 958 102 CAF09 $ 33213 15%100 '100 500 2.440 100 514 6204 733 843 CAFIO $ 19002 15%150 150 225 750 700 148 2743 929 068 CAFll $ 24606 15%105 106 211 125 634 759 500 2440 1.800 342 ' 5,710 876 007 CAF12 $ 17 689 15%103 150 100 100 500 1.500 900 184 3150 602 693 CAF13 $ 35024 15%127 106 233 392 602 994 125 634 753 002 440 700 467 128 000 150 CAFI4 $ 13 689 15%103 150 750 500 122 1425 622 716 CAFl5 $ 49 234 15%103 198 784 784 125 302 1,211 510 2.440 100 514 9459 913 049 CAF Avera 1 $ 26,122 I 929 202 63 76 135 891 250 454 103 551 978 893 329 139 I 1 813 9351 Figure 7.1 provides a composite view of cumulative additions by resource type over time, aver- aged for all 16 alternative future investment plans. Annual front office transactions acquired are also shown. 141 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 1- Cumulative Resource Additions by Year for Alternative Future Studies Average Additions for the 16 Alternative Future Studies 000 500 Line indicates the awrage amount of front office transactions acquired per year 500 000 500 ~ 2 000 500 000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Ii':IIJIJ SCPC _IGCC = Gas-CCCT Wind (Capacity Contribution) OJIIIIII Gas-SCCT CHP DSM --Front Office Transactions --- Demand-side Management Program Selection Patterns The CEM chose, on average, 135 megawatts of DSM resources across the alternative future stud- ies-63 megawatts of Class 1 resources and 76 megawatts of Class 3 resources. The CEM se- lected Class 1 programs under all scenarios except one: the high DSM potential scenario. This result is covered under the DSM potential scenario discussion later in this section. The highest individual amount selected for a scenario was 233 megawatts; this was for CAF13 the high load growth study. In contrast, the lowest amount was 58 megawatts under CAF07, the favorable wind environment scenario. It is apparent that conditions that support aggressive wind investment for the model have a dampening effect on the amount of DSM selected. Table 7.3 shows the CEM's DSM additions for scenarios that included (1) low and high load growth assumptions, (2) low and high coal costs (based principally on the CO2 adder level), and (3) low and high gas/electricity prices. The megawatt additions are reported as averages for the group of portfolios. 50 so A complicating factor for interpreting the model's resource selection behavior is the impact of resource size. The model may find it advantageous to select a small resource to minimally meet the planning reserve margin constraint for a particular year, rather than invest in a larger yet less costly resource. 142 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.3 - DSM Resource Selection by Alternative Future Type . J.\iIegawattAverage Class IDSM .Class 3 DSM47 89 Low Gas/Electricity Prices High Gas/Electricity Prices 165 III 116 120 Low Coal Cost High Coal Cost DSM Potential Scenarios The two DSM potential scenarios, CAF09 and CAFlO, are intended to determine how other re- source costs affect the CEM's choice of DSM resources at higher and lower levels of program participation. The High DSM potential scenario tests whether high fuel and market prices com- pensate for the higher DSM resource cost that accompanies greater program participation. The low DSM potential" scenario tests the opposite set of conditions. Note that as the market poten- tial increases, the resource cost ($/kW/yr) for most of the DSM programs is higher as wel1.51 The higher cost reflects a greater level of incentive and administrative expenditures needed to main- tain program savings at an elevated level. As mentioned above, the CEM did not choose any Class 1 DSM programs under the high poten- tial scenario, even with a high CO2 adder and high gas and electricity prices in place. (On the other hand, the CEM selected 3 100 megawatts of wind.) The only DSM resources selected were the east and west demand buyback programs. For the low potential scenario, CAF 1 0, both Class 1 and Class 2 programs are selected. How- ever, the combined amounts are only 4 megawatts greater than the DSM total und~r the high potential scenario. Load Growth Scenarios The alternative future scenarios CAFIO, CAFll , and CAF12 test the CEM's resource prefer- ences under a wide load growth range, holding other scenario variables constant. Table 7.4 pro- files the resource additions for each of these load growth scenarios. Table 7.4 - Resource Additions for Load Growth Scenarios Coal-SCPC Coal-IGCC Gas Cumulative Build Amounts (MW): 2001,.2018500 500 1002,440 500 759 2,440 2 002 1 753 900 800 700 51 Critical Peak Pricing is the only program type for which unit resource costs decrease as the market potential in- creases. 143 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results The most interesting model behavior relates to the type of gas resource selected under each load growth scenario. For the low load growth scenario (CAF12), the model selects no central-station gas resources; instead, it relies mostly on coal builds. Under the medium load growth scenario (CAFll), the model then turns to SCCT frames and additional pulverized coal to address the higher loads, but no CCCT capacity was added to the investment plan at this point. (Wind name- plate capacity also doubled from 900 to 1 800 megawatts.) Under the high load growth scenario (CAF13), the next incremental resources selected were IGCC and CCCT, with the model having already selected all SCPC resources available to it under medium load growth conditions. Tables 7., 7.6 and 7.7 show the CEM's resource additions for all scenarios that include the low medium, and high load growth assumptions, respectively. The model tends to add pulverized coal first to meet incremental load growth, and then add significantly more gas and wind re- sources under the higher load growth scenarios. For all scenarios that include high load growth the model chooses every SCPC resource available to it. Table 7.5 - Resource Additions for Scenarios with Low Load Growth CAF02 CAF05 CAF12 CAF14. Average 150 150 119 Coal..iIGCC .Gas (;1lllIlulatiV~Buila Amounts (MW):2907 -201s440 500 500 750 173 500 125 100 600 100 900 500 600 Table 7.6 - Resource Additions for Scenarios with Medium Load Growth Scenario CAFOO CAPO 1 CAP04 CAPO? CAPO8 CAF09 CAP 10 CAPll Average 500 Coal..SCPC'. Coa(.;.IGCC Gas CumulativeBllilaAmounts(MW):2007 -2018 ..2,440 500 125 2,440 2 002 823 100 275 100 225 759 679 2,440 750 440 750 440 957 500 100 700 800 625 Table 7.7 - Resource Additions for Scenarios with High Load Growth 500 500 SOO . , ... . . Coal..SCPC .CoaI4GCC Gas Cumulative.Buila Amounts (MW):2007-201S440 2 510 1 361 923 753440002 100 2,400 700 144 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Coal-SCPC ,CoaI4GCC CumUlative. Build.AmountslMW):2007,.201S. .440 2 510 1 211440 1 207 1,030 Gas/Electricity Price Scenarios Tables 7.8 and 7.9 show the CEM resource additions for the six scenarios that include the low and high gas/electricity price assumptions, respectively. With low prices, the model chose coal for only three of the six scenarios. Those three scenarios (CAF08 CAF10, CAF14), assumed no CO2 adder, and only one coal plant was selected. The model selected wind for nearly all low-price scenarios, the exception being the "unfavorable wind environment" scenario CAF08. Scenarios that also included the low coal cost assumption (CAFlO CAF14) had a relatively small amount of wind investment at 400 megawatts. For the scenario with a high coal cost and load growth (CAF06), the fossil fuel investment plant con- sisted of only CCCT resources at 3 798 megawatts. Table 7.8 - Resource Additions for Scenarios with Low Gas/Electricity Prices CAF04 CAF05 CAF06 . CAF08 CAFIO CAF14 Average 169 129 150 116 750 750 750 375 700 500 317 With high gas and electricity prices, the model invested heavily in both supercritical pulverized coal and wind, except for the scenario with low load growth, For all scenarios, every SCPC op- tion was chosen (2,440 megawatts). Gas resources (CCCT and SCCT frame) were selected only for the two scenarios that also had high load growth (CAF03 CAF15). The model selected west IGCC resources in all scenarios, and added all the IGCC units available to it under the high price/high load growth scenario (CAF03). Table 7.9 - Resource Additions for Scenarios with High Gas/Electricity Prices Scenario CAF01 CAF02 CAF03 CAF07 CAF09 CAFI5 361 100 100 211 100 600 100 600 100 100 145 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results -- , Goal.:$CmC CoaI-IGCC , :Gtifi1tIlativ~ B uildAmoun ts(MW) :'2 1)07.,20.18 .120 2 440 1 420 466 Carbon Dioxide Adder/Coal Cost Scenarios Tables 7.10 and 7.11 show the CEM's resource additions for scenarios that have the low and high coal cost assumptions, respectively. The CEM added 1 716 megawatts of supercritical pulverized coal capacity, on average, for the scenarios with low coal cost assumptions. As expected, the CEM built the most coal capacity when high gas/electricity prices and high load growth are included as assumptions (CAF1 and CAF3). Table 7.10 - Resource Additions for Scenarios with Low CO2 Adder/Coal Costs CAPOO ' CAPO! ' CAF02 CAP03 CAP08 CAPI0 CAP14 150 151 169 129 150 124 - ' Coal:'SCPC Coal-IGCC ' Gas :CulDulative BuilllAmounts,(MW): 2007,,20.182,440 500 125 2,440 2 002 2,440 500440 2 510 750 750 750 716 500 100 600 100 700 500 929787 361 275 225 577 With high coal costs (Table 7.11), the model did not add any coal resources unless the scenario was accompanied by high gas/electricity prices. Base load gas was added in only three of the six portfolios. Substantial wind capacity was added in all scenarios, with an average of 2 750 mega- watts (a 446-megawatt capacity contribution). Table 7.11- Resource Additions for Scenarios with High CO2 Adder/Coal Costs Coal-SCPC Coal-IGCC Gas Scenario Cumulative Build Amounts (MW):2007-20J8 CAPO4 823 200 CAPO5 125 100 CAP06'169 923 400 CAPO?440 500 100 600 CAP09, '2,440 500 100 100 CAF15 198 2,440 510 211 100 Average 111 220 585 214 750 146 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Sensitivitv Analysis Results This section presents the modeling results for the CEM sensitivity analysis studies. As a re- fresher, Table 7.12 repeats the sensitivity scenario specifications outlined in Chapter 6. Table 7.12 - Sensitivity Analysis Scenarios SAS#Name . "... i;\" '.'. .. ":... Basis . . .:. .. ..;",. . Plan to 12% capacity reserve margIn Alternative Futures Scenario #11 Medium Load Growth" Plan to 18% capacity reserve margin Alternative Futures Scenario #11 Medium Load Growth" CO2 adder implementation in 2016 Alternative Futures Scenario # 11 Medium Load Growth" Regional transmission project Alternative Futures Scenario # 11 Medium Load Growth" CO2 adder impact on resource selection: test $15 , $20, $25 per ton Alternative Futures Scenario # 11 adders (approximately $10, $15, and $20 in 1990 dollars)Medium Load Growth" Low wind capital cost Alternative Futures Scenario # 11 Medium Load Growth" High wind capital cost Alternative Futures Scenario # 11 Medium Load Growth" Low coal price Alternative Futures Scenario # 11 Medium Load Growth" High coal price Alternative Futures Scenario #11 ("Medium Load Growth" Low IGCC capital cost Alternative Futures Scenario # 11 Medium Load Growth" High IGCC capital cost Alternative Futures Scenario #11 Medium Load Growth" Add a carbon-capture-ready IGCC to the portfolio (base case for Alternative Futures Scenario # SAS13 and SAS14)Medium Load Growth" Replace the lGCC resource in the SAS12 portfolio with a single SAS #12gasifier version Replace the IGCC resource in the SASl2 portfolio with one tha SAS #12includes carbon sequestration Plan to "average of super-peak" load Alternative Futures Scenario # 11 Medium Load Growth" Favorable Wind Environment" scenarIO assumIng permanent ex Alternative Futures Scenario #07 piration of the renewables PTC beginning in 2008 Favorable Wind Environment" Table 7.13 reports the PVRR and total cumulative additions (2007-2018) by resource type for the 16 sensitivity studies. The wind capacity contribution and average annual front office trans- actions acquired for 2007 through 2018 are also shown. The study results are summarized below. 147 PacijiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.13 - Sensitivity Analysis Scenario PVRR and Cumulative Additions, 2007-2018 l~h W ~h~t/~iiV /, iff . ~ :Ii if fIE ,.:.,.:. fo, . ~ '" 1/ ~ J If !i!'!fj"'I: "'I:ii; '. ,.; ,..; Studv PVRR ii; ~ (j (j c3 c3 c3 J - " ~ ;; Ii j.;m f: SASOI $ 24400 12%106 161 125 125 500 2,440 100 223 326 865 969 SAS02 $ 24,983 18%106 161 100 634 734 500 2440 1700 326 5535 936 1104 SAS03 $ 22673 15%106 153 125 302 427 500 2440 1500 291 5;020 942 083 SASO4 $ 24 182 15%113 106 219 125 125 997 2440 2,400 409 6181 896 031 SAS05-$ 28 551 15%103 106 209 602 602 125 634 1;361 500 1840 500 406 .641D 872 1003 SAS05,$ 32 390 15%127 106 233 602 602 125 634 1,361 500 090 3 100 514 6284 935 075 SAS05,$ 36073 15%143 106 249 I 150 150 125 720 1995 750 100 514 - '6094 906 042 SAS06 $ 24282 15%106 161 125 634 759 500 440 600 422 6460 806 927 SAS07 $ 24836 15%129 100 634 734 997 2,440 700 163 ' 5000 897 1031 SAS08 $ 24,401 15%103 198 125 302 427 500 440 300 253 ~ 4865 920 058 SAS09 $ 24980 15%103 150 125 302 427 500 2440 500 300 5;017 890 1023 SASIO $ 24559 15%103 .150 125 332 457 997 2,440 1100 223 5144 889 023 SASll $ 24660 15%103 106 209 125 634 759 500 440 1800 334 708 922 1.060 SASI2 $ 24976 15%103 106 209 100 332 432 250 2440 1.000 196 ; 5 31 915 1052 SAS13 $ 24980 15%106 - 153 100 302 402 1250 2440 800 165 5045 828 953 SASI4 $ 25521 15%106 201 100 332 432 250 440 000 196 -5323 848 975 SAS15 $ 24412 15%105 106 211 125 332 457 500 2440 700 323 5308 803 924 SAS16 $ 35049 15%26". 73 75 . 75 500 440 500 580 - 6,St8 649 727 Alternative planning reserve margins (SASO 1 and SAS02) Allowing the CEM to optimize to alternative planning reserve margins, 12% and 18%, had the following impacts: The PVRR was lowest for the 15% PRM base case portfolio (CAFll); the cost difference between the 15% PRM portfolio and 18% PRM was $6.9 billion, while the difference be- tween the 12% PRM portfolio and the 15% PRM portfolio was $6.3 billion. There was no difference in the amount of supercritical pulverized coal or IGCC capacity among the portfolios None of the portfolios included CCCT capacity; SCCT capacity was added for 15% and 18% PRM portfolios (both at 634 megawatts) The 12% PRM portfolio had no base load gas resources, but included CHP Relative to the 12% PRM portfolio, the 15% PRM portfolio had more wind (700 megawatts) and more front office transactions Relative to the 15% PRM portfolio, the 18% PRM portfolio had more front office transac- tions and slightly less wind and DSM CO7- adder implementation in 2016. compared to 2012 for the base case portfolio Moving back the start of CO2 regulation from 2012 to 2016 had the following impacts on the base case portfolio: The PVRR decreased by $1.9 billion The resulting portfolio had less Class 1 DSM, less SCCT capacity, less wind, and more front office transactions Inclusion of the regional transmission proiect The project resulted in a $424 million decrease in PVRR relative to the base case portfolio 52 The project consisted of new 1 500 MW capacity lines from Wyoming to the SP 15 transmission zone in Califor- nia, and from Utah to NP15. 148 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Changes to the resource mix included elimination of all SCCT capacity, the addition of an IGCC unit, more wind, and a small increase in front office transactions Resource mix impact of increasing the CO? adder Increasing the CO2 adder in a step-wise fashion for the base case portfolios had the following impacts: From $8 to $15: The CEM removed the Utah SCPC resource (600 megawatts), and added a CCCT and 700 megawatts of additional wind; PVRR increased by $3.9 billion From $15 to $20: The CEM removed a Wyoming SCPC (750 megawatts), and added 600 megawatts of additional wind, 24 megawatts of Class 3 DSM, and additional front office transactions (63 average annual megawatts); PVRR increased by another $3.8 billion From $20 to $25: The CEM removed the small Utah SCPC and the west IGCC (500 mega- watts), and added another east CCCT as well as an intercooled aero SCCT; in addition, the model added 16 megawatts of Class 1 DSM, but decreased front office transactions by aver- age annual 29 megawatts; PVRR increased by another $3.7 billion Low and high wind capital cost Lowering the wind capital cost by 10% had the following effects relative to the base case portfo- lio: The CEM added 800 megawatts of wind The PVRR decreased by $800 million Class 1 DSM is reduced by 50 megawatts Front office transactions are reduced by an average annual 70 megawatts Increasing the wind capital cost by 11 % had the following effects relative to the base case portfo- lio: The CEM removed 1 100 megawatts of wind capacity An east IGCC resource was added (497 megawatts) The PVRR increases by $231 million Front office transactions increased by an average annual 21 megawatts Class 1 DSM is reduced by 50 megawatts, apparently displaced by the other resource addi- tions Low and high commodity coal prices Lowering the coal price for new coal resources had the following effects relative to the base case portfolio: The PVRR decreases by $204 million The CEM removed the west SCCT (332 megawatts) and 500 megawatts of wind (90 mega- watts capacity contribution) Front office transaction were increased by an average annual 44 megawatts, while DSM de- creases by 13 megawatts Raising the coal price for new coal resources has the following effects relative to the base case portfolio: 149 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results The Wyoming SCPC plants were moved up a year, and the large and small Utah SCPCs switched places: the large 600-megawatt unit moved from 2018 to 2012, while the small 340- megawatt unit moved from 2012 to 2018. (The coal price change adversely affected the eco- nomics of the small Utah SCPC unit to a greater degree than for the large Utah SCPC unit). The timing change of the coal plants resulted in removal of a west SCCT (332 megawatts) and 300 megawatts of wind (42-megawatt capacity contribution) The PVRR increased by $375 million Front office transaction increased by an average annual 44 megawatts, while DSM decreases by 61 megawatts Low and high IGCC capital cost Lowering the IGCC capital cost had the following effects relative to the base case portfolio: The CEM added an east IGCC (497 megawatts), and moved up the 200-megawatt west IGCC from 2017 to 2016 The CEM removed 700 megawatts of wind (119-megawatt capacity contribution), and a SCCT (302 megawatts) The PVRR decreased by $46 million Front office transactions increased by an average annual 13 megawatts Raising the IGCC capital cost had the following effects relative to the base case portfolio: The west IGCC is deferred from 2017 to 2018, which increases front office transactions by an average annual 46 megawatts and raises PVRR by $54 million Impact of switching from an IGCC with a spare gasifier to one with a single gasifier This change reduced PVRR by $4 million. Resource impacts included switching the location of a SCCT from the west location to the east location in 2012, reducing wind by 200 megawatts (32- megawatt capacity contribution), and reducing front office transactions by an average annual 87 megawatts. Cost impact of building an IGCC with carbon sequestration Replacing a carbon-capture-ready IGCC with one that has carbon sequestration increased PVRR by $541 million. The IGCC replacement resulted in minor resource selection impacts; namely, Class 1 DSM increased by 48 megawatts, and front office transactions increased by an average annual 19 megawatts. Plan to the average of the eight-hour super-peak period Relative to the base case portfolio, CAF11 , planning to the average of the eight-hour super-peak period decreases PVRR by $194 million. The resource impacts include: removal of a SCCT (302 megawatts), a decrease in wind capacity by 100 megawatts, and a reduction in front office trans- actions (103 megawatts on an average annual basis). DSM was unaffected. Favorable wind development environment combined with expiration ofthe renewable production tax credit (PTC) Comparing the portfolio PVRR for CAF07 and SAS 16 indicates the impact of not renewing the PTC after 2008. The impact was found to be an additional $1.7 billion. Removing the PTC also 150 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results significantly changed the wind investment schedule. Figure 7.2 compares the cumulative annual nameplate megawatt wind additions for CAF07 and SAS16. With no PTC in place (SAS16), the model chose to add wind in a smooth pattern until 2017, and then add 1 400 megawatts in 2018. This large capacity addition is an artifact of the timing of the generic growth stations, which start in 2019. With the PTC in place (CAF07), the wind addition schedule was lumpier, with signifi- cant additions in 2007 2013 , and 2015. Figure 7.2 - Cumulative Wind Additions for CAFO7 and SAS16 000 500 000 500 000 ::2: 500 000 500 -+- CAFO? ---4-- SAS 16 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Resource Selection Conclusions Based on the CEM modeling results, a number of general observations can be reached regarding the model's resource preferences , and what specific resources constitute robust selections to in- clude in the risk analysis portfolios, First, supercritical pulverized coal was part of the resource stack in all the CEM portfolio solutions except for the three scenarios with high coal costs and low gas and electricity prices (CAF04, CAF05, and CAF06). Given that a high CO2 adder is ex- pected to put upward pressure on gas prices due to greater demand for cleaner power supplies, a scenario more in line with the "favorable wind environment" future (CAF07)-or the version of this scenario without renewable production tax credits (SAS16)-is a more realistic future. For these two scenarios, the model still selected supercritical pulverized coal and added it early in the study period. A second observation concerns the model's selection frequency of the resources across the alter- native future studies. Only two resources appeared in the majority of the studies: the large Wyo- 151 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results ming and small Utah supercritical pulverized coal units. With few exceptions, the CEM added these coal units as soon as they were available for selection. Based on this result, PacifiCorp judged these coal resources to be robust options under the set of alternative futures evaluated. Figure 7.3 shows the selection frequency for all fossil fuel resources. Regarding gas resource selection, CCCTs came into play only under scenarios that included low gas/electricity prices or high load growth. Selection of single-cycle combustion turbine frames appears to be sensitive to the level of load growth assumed; these resources were added for two scenarios with high load growth, as well as the medium load growth scenario. Given these selec- tion patterns, gas plants are not judged to be robust resources under deterministic modeling con- ditions. However, it should be noted that the CEM deterministic runs do not capture the optional- ity value of gas resources; consequently, testing them in a stochastic modeling environment is necessary to estimate their full value in a diversified portfolio. Figure 7.3 - CEM Fossil Fuel Resource Selection Frequency --- 14 - ~ 10 8 - C1I ; '0 ;'ii; .s:::.s:::.s::: ro :t:l:N....-N N;:::t:I:~ I- ;:: ;:::t:I: (,) Q) )-Q) I-Q) ....-~ ~(,) -5 s ~:J ;:.:J (,)~ - 'S - (,) CL ~CL ~ ....- f!!CL -L.L. (,) L.L.CL -f!! (,) Q) ro 'i6 (,)Q) (,) (,) Q) ro L.L.L.L. (,) OJ 0 e:'OJ 0 ~ (,)(,)(,)~ (,)(,)(,)(,)(,) ...J (/) ...J (,)(,) ...J (,)(,)(,)(,)(/)(,)(/) Coal Coal Coal Gas Coal Gas Coal Gas Gas Gas Coal Coal Coal Fossil Fuel Resources 152 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Wind appeared in 15 out of the 16 alternative future studies. While this resource is considered robust as far as inclusion in the CEM's investment plans is concerned, unlike the pulverized coal resources, a robust quantity can t be determined due to the wide variance in selected wind ca- pacities among the alternative future studies. Consequently, the company used measures of cen- tral tendency to determine an initial wind investment schedule for inclusion in the risk analysis portfolios. The development of the wind investment schedule is described in the next section. The CEM chose IGCC for 10 out of the 16 alternative futures, with the west IGCC units (total of 500 megawatts) selected in seven futures and the east IGCC units selected in four futures. The model's selection of east-side IGCC resources was predicated on the high load growth assump- tion, and these resources were generally added beyond the 10-year investment horizon (2007- 2016). , , RISK ANAL YSISPORTFOLIODEVELOPMENT .2GROtJPl" To develop the first risk analysis portfolio, PacifiCorp first combined the fixed wind, DSM, and CHP investment schedules described below, along with the other resource options. The CEM was then executed with this set of resources using the medium-case assumptions adopted for the alternative future studies. The resulting CEM investment plan, labeled as RA 1 , thus parallels the plan that resulted from the "medium case" alternative future (CAF11) run. To derive subsequent risk analysis portfolios, PacifiCorp applied one or a combination of alternative resource strate- gies to RA1 or other variants ofRAI prior to CEM execution. Twelve portfolios were initially developed with input received from public stakeholders during the fall of 2006. PacifiCorp used the associated portfolio simulation results and the analysis sup- porting the 10-year Business Plan to formulate a "base case" resource proposal that was shared with regulators. The feedback received on the resource proposal, as well as recent external events53 and an as- sessment of state resource policy directions, prompted the company to investigate portfolio alter- natives that recognize existing and expected state resource acquisition constraints. A new set of risk analysis portfolios was consequently created to address these constraints while still adhering to system planning principles and the states' IRP development guidelines. (The new risk analysis portfolios also account for the revised load forecast.) This second portfolio group constitutes the "finalists" from which the preferred was selected. The original set of 12 risk analysis portfolios informed the construction of these new portfolios. This chapter documents both sets of portfolios, which are referenced as "Group 1" and "Group 53 These events, cited in Chapter 3 , include the Oregon PUC rejection of the 2012 RFP for base load resources and issuance of new IRP guidelines (January 2006), adoption of renewable portfolio standards in Washington, Califor- nia s adoption of a green house gas emissions performance standard, and introduction of climate change legislation in both Oregon and Washington. 153 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Fixed Resource Additions for Risk Analysis Portfolios Renewables A fixed wind resource investment schedule was included in all risk analysis portfolios. Pacifi- Corp developed an initial wind investment schedule based on a composite view of the resource addition patterns for the 16 alternative future scenarios covering the period 2007 through 2016. This initial wind investment schedule was modified as appropriate to support the testing of alter- native resource strategies. The CEM selected a wide range of wind resource capacities across the alternative future scenar- ios, from zero capacity for CAF08 ("unfavorable wind environment") to 3 100 megawatts of nameplate capacity for two scenarios (CAF07 , " favorable wind environment" and CAF09 , " high DSM potential"). The average nameplate amount for the 16 scenarios was 1 213 megawatts (for a capacity contribution of 235 megawatts), while the median amount was 950 megawatts. The amount selected for the medium case scenario was 700 megawatts. The most frequently occur- ring amount was 400 megawatts for four scenarios. Figure 7.4 shows the amount of wind capacity that the CEM selected for each of the alternative future scenarios. Both nameplate capacity and capacity contribution are shown. Figure 7.4 - Wind Capacity Preferences for Alternative Future Scenarios I/) 3500 3000 2500 2000 1500 1000 500 CAFOO CAF01 CAF02 CAF03 CAF04 CAF05 CAF06 CAF07 CAF08 CAF09 CAF10 CAF11 CAF12 CAF13 CAF14 CAF15 Ave. iii Wind Capacity Contribution 82 196 60 277 259 215 354 514 0 514 85 148 95 222 99 410 235 . Renew abies Narreplate 300 1 000 400 1,400 1,400 1,400 2 200 3,100 - 3 100 400 700 400 900 400 2.300 1213 111 Wind Capacity Contribution. Renewables Nameplate Figure 7.5 profiles the CEM's location preferences for wind resources across the alternative fu- ture portfolios. It shows the number of scenarios in which wind was selected by location, and the average number of 100 megawatt project sites selected for each location four sites-Southeast Idaho, Southwest Wyoming, North Central Oregon, and East Central Nevada-appeared in the majority of the scenarios. The southeast Wyoming location (SE WY) had the largest number of sited added. 154 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.5 - Wind Location Preferences for Alternative Future Scenarios I:J Number of altemati-.e future scenarios (out of 16) in which wind was chosen for the location . A-.erage number of 100 MW sites added to the location SE 10 SW WY NC OR EC NV SE WA SE WY SC MT WC Location Given these model results, a total nameplate capacity of 1 000 megawatts (capacity contribution of 217 megawatts) was added to each of the risk analysis portfolios and distributed among the sites favored by the model. Note that this capacity amount is in addition to the 400 megawatts considered a planned resource for 2007 and reflected in PacifiCorp s load and resource balance, Table 7.14 shows the resource addition schedule for 2008 through 2016 adopted for the risk analysis portfolios, Table 7.14 - Wind Resource Additions Schedule for Risk Analysis Portfolios Year 2008 2009 2010 2011 2012 2013 Annual Additions Nameplate Capacity 200 200 100 Location North Central Ore on; Southeast Idaho North Central Ore on; Southeast Idaho Southeast Idaho 300 200 Class 1 Demand-side Management Programs A fixed megawatt amount of certain Class 1 demand-side management programs were included in all risk analysis portfolios based on a review of DSM addition patterns covering the 2017- 2016 investment horizon for the alternative future scenarios. In order to be selected for risk 155 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results analysis portfolio inclusion, programs needed to have been chosen in the medium case scenario (CAFl1) or a majority of the other alternative future scenarios, as well as have a capacity that exceeds 10 megawatts when selected. This combination of criteria is meant to strike a balance between a relatively aggressive DSM implementation pattern for the risk analysis portfolios (ac- counting for the fact that not all potential system benefits can be readily quantified and captured in the CEM solution) and constraining the entire set of CEM options to a reasonable number. For the medium case scenario, the CEM chose the following programs, megawatt quantities (as measured at the customer meter), and installation years: East-side summer direct load control- 48 megawatts in 2013 West-side summer direct load control- 8 megawatts in 2013 East-side commercial/industrial direct load control- 2 megawatts in 2013 East-side scheduled irrigation - 15 megawatts in 2012 West-side scheduled irrigation - 32 megawatts in 2012 The only resources that the CEM selected for the majority of alternative future scenarios were the east-side and west-side scheduled irrigation programs. The CEM selected the east-side pro- gram in 11 out of 16 scenarios, while the west-side program was selected in 10 out of 16 scenar- ios. Figures 7.6 and 7,7 show the number of scenarios in which program types were selected by the CEM and the average megawatts for all scenarios, respectively. Regarding the CEM's selection of program installation dates, 2012 and 2013 were the most common across the alternative future scenarios. Only under the high-cost bookend scenario (CAF15) are programs selected for implementation earlier than 2010. For this scenario, several programs are added in 2008 , such as east-side scheduled irrigation and the three east-side direct load control programs (summer, winter, and commercial/industrial). Figure 7.6 - Class 1 DSM Selection Frequency for Alternative Future Scenarios, 2007-2016 ;:! J: 4 East Sch. West Sch, East DLC East DLC East DLC West DLC East West DLC West DLC West Irrigation Irrigation Sunnner C&I Winter Sunnner Thennal Summer C&I ThennalStorage Storage 156 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.7 - Class 1 DSM Average Megawatts for Alternative Future Scenarios, 2007-2016 E 20 p... 15 p... ::E 10 OJ) 0 , EastSch. WestSch, EastDLC EastDLC EastDLC WestDLC East WestDLC WestDLC West Irrigation Irrigation Sunnner C&I Winter Sumner Thennal Summer C&I ThennalStorage Storage Based on these CEM results, and assuming a generic two or three-year phase-in period, Table 15 shows the Class 1 DSM resource addition schedule for each of the risk analysis portfolios. Table 7.15 - Class 1 DSM Cumulative Resource Additions for Candidate Portfolios Annual.CumulativeMegawatt Additions at the customer meter2011 201216 21 East East West Summer Direct Load Control Irri ation Control lrri ation Control Combined Heat and Power Resources A fixed megawatt amount of combined heat and power (CHP) resources were included in all risk analysis portfolios based on a review of CHP addition patterns for the alternative future scenar- ios. Figure 7.8 shows the megawatts selected in each of the scenarios by location. (Note that the CHP resource included in the CEM was the 25-megawatt gas-fired topping cycle unit.) The most common resource selection pattern was 125 megawatts (100 megawatts installed in the west side and 25 megawatts installed in the east side), which occurred for seven of the 16 scenar- ios. The average quantity selected for all scenarios was 90 megawatts. For 11 out of the 16 sce- narios, the CHP capacity was added in 2012. Based on these results, PacifiCorp chose a CHP resource investment schedule consisting of three 25-megawatt CHP units in the west in 2012 and one 25-megawatt CHP facility in the east control area in 2012. 54 Selection of DSM programs or any other resource type for the candidate portfolios should not be construed as meaning that PacifiCorp is limiting program procurement in any way. Similarly, the resource additions schedule including the phase-in period, is not indicative of the pace of actual program implementation once PacifiCorp identi- fies cost-effective programs through its procurement process. 157 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.8 - CHP Quantities Selected for Each Alternative Future Scenario, 2007-2016 1/1 110 100 IIJ West . East Cij CJ):::J CJ)CJ) gj,s gj,s gj,s gj,su;:.c: ~ .c: e .c: ~ ;: ~ !;1' (9 .!;1' (9 ,!;1' (9 0 (9;!;"C ;!;"C ;!;"C S"C Cij '" Cij '" Cij '" '" '" ..J u..J u ..J u..J ~-g ~;: ~-a, in-g8:; 8.3 8I 8:; ..J ..J ..J gj,s gj,sU;: U ~;: e ;: ~~ ~ ~ ~'" '" '" '" 0 0 0 0U..J u..J gj~ gj~ ..J U J:.c: .c:OJ u.. :::J Cij (l. .c: .c: ..J ...J .c: .c: (l.(l. .c: Ii;Ii;Ii;Ii;Ii;Ii; CAFOO CAFO1 CAFO2 CAFO3 CAF04 CAFO5 CAFO6 CAFO7 CAFO8 CAFO9 CAF10 CAF11 CAF12 CAF13 CAF14 CAF15 Alternative Resource Strates!ies The original 12 risk analysis portfolios were developed according to five resource strategies. These portfolios are distinguished by the planning reserve margin level and the quantity and tim- ing of wind, front office transactions , pulverized coal, and IGCC resources included. The five resource strategies are summarized below. Reduce CO2 cost risk by deferring coal plants until low CO2-emitting coal options with car- bon sequestration are commercially proven (such as IGCC or pulverized coal with chill am- monia CO2 removal)55, or eliminating them as a resource option altogether. Reduce electricity market price risk by eliminating long-term reliance on front office transac- tions after 2011 , the year that PacifiCorp s system becomes significantly capacity-short. Acquire additional wind resources above the amount contained in the initial wind investment schedule described above. Plan to a 12 percent planning reserve margin to reduce the risk of having excess generation capacity in the event that expected load growth does not materialize. Acquire base load coal resources in the near term to hedge against high gas and electricity prices and price volatility. 55 This strategy is what the Oregon PUC calls a "coal plant delay scenario . It relies primarily on gas resources and market purchases to address any resource gaps until IGCC is available. (See OPUC IRP Acknowledgement Order LC-, Order No. 06-029, p. 51.) 158 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.16 outlines the specifications for the 12 risk analysis portfolios (labeled RA1 through RA12), and presents the design rationale for each. The CEM scenario definitions for the risk analysis portfolios include the "medium" forecast val- ues for CO2 costs, gas/electricity prices, load growth, RPS generation requirements, production tax credit availability, and DSM potential. Nevertheless, the risk analysis portfolios emulate many of the other scenario conditions modeled for the alternative future studies. For example RA6, which entails removal of pulverized coal as an option, is representative of the coal resource outcome of the three alternative future scenarios based on high coal costs and low gas costs (CAF04, CAF05 , and CAF06). Table 7.16 - Risk Analysis Portfolio Descriptions (Group 1)ID Descri tion Desi nRatiomtle RAI Medium" alternative future portfolio, with wind, By virtue of having the fewest constraints on re- DSM, and CRP at fixed levels and front office source choice, it serves as a perfonnance bench- transactions capped at quantities assumed for the mark and starting point for development of the2004 IRP other 11 ortfolios. RAI with front office transactions removed as a Tests the strategy of eliminating the use of short- resource option from 2012 onward (long-tenn tenn market purchases (front office transactions) asset-based portfolio) to meet long-tenn resource needs, and thereby reduce ex osure to electrici market rice risk. Tests the strategy of using incremental amounts of wind to reduce CO2, fuel, and market rice risks. Represents a variant of the "long-tenn asset- based" portfolio (RA2), but with the lower plan- ning reserve margin to detennine the associated cost/risk tradeoff. Tests the relative economics and risk of building coal early as a hedge against gas and electricity market price risk; the IGCC plant replaces an east- side gas plant. Tests the strategy of reducing CO2 cost risks, as well as testing the risk impact of relying on higher variable cost, shorter lead-time resources until IGCC is commercially ready (i., gas-fired gen- eration and market urchases. Tests additional wind in combination with the construction pattern resulting from limiting front office transactions. RA9 with a 15% planning reserve margin Tests the medium alternative future portfolio (RAl) with the lower 12% planning reserve mar- Ill. Tests an IGCC-intensive portfolio at the lower planning reserve margin level, assuming that the technology is commercially mature enough to ac uire b 2013. Creates a version ofRA9 that parallels others with the higher 15% planning reserve margin. Recom- mended by an IRP public stakeholder at the Octo- ber 31, IRP ublic meetin . RA8 with the model restricted to select Wyoming IGCC plants in 2013 and 2016 159 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Descritiol1 RA3 (600 MW additional wind and front office transactions included) with the model restricted to select gas resources in 2012 and 2013 and an IGCC resource in 2014 DesinRatiol1a1e Tests the strategy of reducing CO2 cost risks with additional wind and restrictions on pulverized coal builds, as well as testing the risk impact of relying on gas resources and front office transactions to address resource deficits until an IGCC resource is ac uired in 2014. Creates a version of RA II that parallels others with the lower 12% planning reserve margin. See the revious footnote. RAIl with a 12% planning reserve margin The CEM was allowed to optimize the timing of all resources, subject to the following condi- tions. First, the earliest in-service dates for resources reported in Chapter 5 (Table 5., East Side Supply-Side Resource Options) were observed with the exception of the Wyoming supercritical pulverized coal (SCPC) plant. Based on a more recent assessment of the acquisition time line for this resource, the earliest in-service date was changed from 2013 to 2014 in the model. (Also note that the first Utah SCPC resource was modeled at 340 megawatts rather than the 600 mega- watts reported in the Supply-Side Resource Options table to reflect a project scale similar to the Intermountain Power Project Unit 3 (IPP 3). This unit is thus referenced as the "small Utah SCPC resource. ") Second, the timing of wind, class 1 DSM, and CHP was fixed according to the pre-defined investment schedules described earlier in the chapter. Running the CEM for each of the 12 risk analysis portfolios resulted in a unique set of generat- ing and transmission resources and timing patterns. Resource selections for 2012-2014 are pro- filed below. 2012 resources The small Utah SCPC resource was selected in 10 of the 12 portfolios, or 9 of the 11 for which pulverized coal was not excluded as a model option The east single-cycle combustion turbine (SCCT) frame was selected in 9 of the 12 port- folios The east combined cycle combustion turbine (CCCT) was selected in 5 of the 12 portfo- lios The west SCCT frame was selected in 10 of the 12 portfolios The west CCCT was selected in 4 of the 12 portfolios 2013 and 2014 resources The first Wyoming SCPC resource was selected in 6 of the 12 portfolios (replaced by IGCC in one and not allowed in another) Only one gas resource was selected for 2013; all others were selected for 2012 Table 7.17 shows generation (coal and gas) and transmission resource additions for each of the risk analysis portfolios by general location and year. 56 This portfolio, requested for study by OPUC staff, addresses the OPUC's 2004 IRP acknowledgement order man- date to "fully explore whether delaying a commitment to coal until IGCC technology is further commercialized is a reasonable course of action." (Order No. 06-029, p. 51) 160 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.17 - Generation and Transmission Resource Additions , '. . . Resource RAt RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 RAlO RAl1 RAt2 Coal Small Utah SCPC (340 MW)2012 2012 2012 2012 2012 2012 2012 2012 2012 2018 Large Utah SCPC (600 MW)2017 2018 2018 2018 2013 2018 2017 2018 2018 2018 2018 Wyoming SCPC 1 (750 MW)2013 2013 2015 2013 2013 2014 2014 2017 2017 2015 2016 Wyoming SCPC 2 (750 MW)2018 2018 2018 2018 2018 2018 2018 2018 2018 West IGCC (200 MW)2016 2017 2017 2016 2018 2016 2017 2018 2018 2018 2018 2018 West IGCC (300 MW)2018 2017 2018 2017 2018 2018 2017 2018 2018 2018 2018 2018 Wyoming IGCC 1 (497 MW)2014 2016 2013 2013 2014 2014 Wyoming IGCC 2 (497 MW)2017 2016 2016 Utah IGCC I (497 MW)2018 Utah IGCC 2 (497 MW)2018 Gas West SCCT Frame (332 MW)2012 2012 2012 2012 2012 2013 2012 2012 2012 2012 West CCCT F 2x1 w/DF (602 MW)2012 2012 2012 West CCCT G Ixl w/DF (392 MW)2012 East SCCT Frame (302 MW)2012 2012 2012 2012 2012 2012 2012 2012 2012 East CCCT F 2x1 w/DF (548 MW)2012 2012 2012 2012 East CCCT G 1x1 w/DF (357 MW)2012 Front Office Transactions 063 005 024 000 115 097 009 863Ave Annual MW, 2012-2016 PlannIng Reserve Margin 15%15%15%12%15%15%15%12%12%15%15%12% Transmission Project RAI RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9.RAIO RAIl RA12 West Main-Walla Walla 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012(630 MW) Walla Walla-Yakima B 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012(400 MW) Mona-Utah North 2012 2018 2012 2018 2018 2018 2018 2018 2018 2012 (500 MW increments) Jim Bridger-Ben Lomond 2015 2016 2016 2016 2014 2014 2014 2016 2015 2016 2015 2016 (500 MW increments) Utah North-West Main 2018 2018 2018 2018 2014 2018 2018 2018 2017 2017 2018 2018 (500 MW increments) Wyoming-Bridger 2018 2018 2018 2015 2018 2018 (500 MW increments) Path-C Upgrade B57 2018(600MW) STOCHASTIC SIMULA TIONRESUL TS - GROUP 1 PORTFOLIOS The 12 risk analysis portfolios were run in stochastic simulation mode with varying loads, ther- mal outages, hydro availability, and electricity and natural gas wholesale prices across 100 itera- 57 The original Path C upgrade and the Craig Hayden - Utah North transmission projects were treated as fixed as- sumptions in the CEM. 161 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results tions. The sections below show how the portfolios compare to one another on the basis of the stochastic cost, risk, reliability, and emissions measures. The section concludes with a summary portfolio performance assessment, as well as resource selection conclusions that informed the development of the second group of risk analysis portfolios. Stochastic Mean Cost Table 7.18 reports the stochastic mean PVRR for each of the portfolios by CO2 adder cases, and shows the portfolio rankings based on the PVRR average across the five adder cases. Portfolio RA1 has the lowest average PVRR, followed by RA7 and RA3. In contrast, RA5 and RA6 have the highest average PVRRs. Table 7.18 - Portfolio Cost by CO2 Adder Case ' "';, StochastkMean ,PVRR (Million ~;~' :, 1)) ..';.;;" $O..Adder $8.Adder $15.Adder $38 Adder $61.Adder (2008$)(2008$)"l2()O8$)(2008$)(2008$)" ,'Averal!e'Rank RAI 016 346 614 865 706 509 RA2 183 514 758 893 601 590 RA3 269 515 740 827 21,482 567 RA4 140 21,489 753 975 789 629 RA5 921 238 22,496 583 225 292 RA6 042 313 548 658 411 394 RA7 414 642 829 732 200 563 RA8 140 472 758 072 018 692 RA9 663 964 242 510 423 160 RAlO 573 882 158 392 244 050 RAIl 529 769 019 139 827 857 RA12 505 754 999 143 881 856 Figure 7.9 shows the progression of each portfolio s stochastic cost as the CO2 adder increases. For most of the portfolios, the cost peaks at the $38 adder level, and then declines at the $61 ad- der level. This cost behavior is driven by the influence of CO2 allowance trading activity in the studies' out-years, where a significant amount of allowance credits are realized. 162 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.9 - Stochastic Mean Cost by CO2 Adder Case ~ 22 500 a: 22 000 0.. I: 21 500 III :!!: ~ 21 000 II)III .s::. ~ 20 500 23,000 I-- L,- !!ill $0 Adder III $8 Adder 0 $15 Adder 0 $38 Adder III $61 Adder 20,000 t:f:' .J!? ~ d.~ d.'i9 d.~ d..;t' d.J. \:) J. " J. '("" " ' c " ~' ~' It is noteworthy that the CEM's deterministic portfolio solution without resource restrictions- Portfolio RA 1-also has the lowest stochastic cost. Table 7.19 summarizes the cost impact of constraining CEM-selected resources in the reference portfolio according to the resource strate- gies defined for the other portfolios. The average PVRRs for the five CO2 adder cases is used as the cost impact measure. Table 7.19 - Cost Impact of Portfolio Resource Strategies RAI RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 RAID RAIl RAI2 Cost Impact Relative to Portfolio RAt Ave. Stochastic Mean PYRRfor CO2 adder cases Million $Resource strategy Modeled in the CEM Reference Case: no resource constraints (FOT ca Remove FOT as a resource 0 tion after 20 II Additional wind Plan to a 12% PRM and remove FOT after 2011 Earl SCPC and force IGCC in 2014 Remove SCPC as a resource 0 tion Additional wind and remove FOT after 20 II Plan to a 12% PRM Force IGCC in 2013 and 2016 Force IGCC in 2013 and 2016; Ian to 12% PRM Additional wind; exclude SCPC for 2012-13 and force IGCC in 2014 Same as RAIl but Ian to a 12% PRM 120 783 885 183 651 540 348 347 163 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results As shown in the table, constraining the coal resources has the largest impact. Removing super- critical pulverized coal increases portfolio cost by $885 million relative to the RA1 portfolio. Portfolios with a 15 percent planning reserve margin that involved restricting the CEM to select IGCC in certain years (RA5, RAlO, and RAll) averaged $557 million higher. The average cost increase for all the portfolios relative to RA 1 was $368 million. Other observations concerning the relationship between portfolio cost and resource mix and tim- ing include the following. Building coal resources earlier or later than recommended by the CEM increases stochasticcost. Lowering the planning reserve margin increases stochastic PVRR due to the costs associated with higher Energy Not Served, Rather than reducing investment in base load plants to meet the lower load obligation, the CEM chooses to defer them. Acquiring the additional 600 megawatts of wind increases stochastic cost, although the amount is smaller than for the other resource strategies. Removing front office transactions after 2011 increases stochastic cost. Customer Rate Impact Figure 7.10 shows the customer rate impact of each portfolio. 58 The rate impact measure is the change in the customer dollar-per-megawatt-hour price from 2008 through 2026 due to the port- folio resources, expressed on a levelized net present value basis. As indicated, RA 1 has the smallest rate change at $3.08/MWh. RA6, which has no pulverized coal plants, has the highest at $3.31/MWh. Figure 7.10 - Customer Rate Impact Stochastic mean price change from 2008 through 2026, Levelized Net Present Value basis $3. $3, $2. $3, ..c:: ~ $3. tit $2. RA1 RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 RA10 RA11 RA12 58 The revenue requirement calculated by the CEM uses a reall(;welized capital charge. 164 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Emissions Externality Cost PacifiCorp calculates the emissions externality cost as the increase in stochastic mean PVRR relative to the $0 adder case for each CO2 adder level. This externality cost measure captures (1) the increased variable operating costs for fossil fuel generation, (2) the system re-dispatch impact attributable to the cost adders , and (2) the net present value of the sum of the annual CO2 allow- ance trading balances for 2007-2026. The externality costs are reported in Table 7.20 along with portfolio rankings based on the average of the incremental costs for the four adder levels. These cost estimates assume a cap-and-trade compliance strategy. Portfolio RA 7 performs the best with an average externality cost of $187 million. RA8 had the highest cost at $690 million. All the portfolios that included the extra wind-RA3, RA7, RAll and RA12-had the lowest costs. In contrast, portfolios built according to the lower 12-percent planning reserve margin had the highest externality costs (RA8 and RA9). The lower reserve margin results in higher coal resource utilization to keep the system balanced. Table 7.20 - Portfolio Emissions Externality Cost by CO2 Adder Level . .,,... ." .. '. .. .. ......,. . lncremen:tal~tochasticMean PVRR by COzAdder(MilIion$) ..'..........'........ COz Adder Level (2008$) ... . $0(.'$8 $15 $38 $61'Average Rank RA1 330 598 849 690 617 RA2 331 575 710 417 508 RA3 246 471 558 213 372 RA4 349 613 835 649 612 RA5 317 575 662 304 465 RA6 271 506 616 369 441 RA7 228 415 318 214 187 RA8 332 618 932 878 690 RA9 301 579 847 760 622 RA1O 309 585 819 672 596 RAIl 240 490 610 298 410 RA12 249 494 638 375 439 Capital Cost Figure 7.11 shows the total capital cost for each portfolio, expressed on a net present value of the sum of all capital costs accrued for 2007-2026. As expected, RA5 with its relatively larger coal plant investment schedule and earlier in-service dates exceeds all others at $6.78 billion. In con- trast RA6-with no coal resources until 2016-has the lowest capital cost at $5.08 billion. The average capital for all portfolios is $5.83 billion. 165 PacifiCorp 2007 IRP Chapter 7 - Modeling and Porifolio Selection Results Figure 7.11- Total Capital Cost by Portfolio Generation and Transmission Capital Cost, Net Present Value r:::~ 5. RA1 RA4 RA7 RA11 RA12RA8RAgRA10RA5RA6RA2RA3 Stochastic Risk Measures Tables 7.21 and 7.22 report the stochastic risk results for each of the 12 risk analysis portfolios. Table 7.21 shows risk exposure and standard deviation (production cost) averaged across the five CO2 adder cases, as well as the portfolio rankings for these two measures. Table 7.22 shows the detailed statistics for each CO2 adder case, and also includes fifth-percentile PVRR and ninety- fifth-percentile PVRR results. Table 7.21- Average Risk Exposure and Standard Deviation for CO2 Adder Cases RAI RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 166 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.22 - Risk Measure Results by CO2 Adder Case (Million $) Risk Standard '.'... Sth 95th.Upper::'fail Exuosure Deviation Percentile Percentile Mean . ... $0 CO2 Adder (2008$), "77. RA1 879 837 258 111 894 RA2 096 608 504 989 279 RA3 654 753 553 34,404 923 RA4 063 886 355 358 203 RA5 837 544 819 286 758 RA6 971 060 221 155 013 RA7 900 313 968 007 315 RA8 192 154 014 725 332 RA9 783 097 699 608 57,445 RAlO 210 939 862 075 783 RAIl 101 9,411 . 14 988 596 630 RA12 860.130 588 370 366 $8 CO2 Adder (2008$) . .,.. . RA1 651 690 770 895 997 RA2 36,957 484 974 812 471 RA3 419 602 900 099 934 RA4 923 761 691 176 412 RA5 538 377 987 148 776 RA6 026 992 892 837 339 RA7 683 166 061 730 326 RA8 949 008 824 481 420 RA9 38,493 936 501 326 60,457 RAlO 974 787 313 817 856 RAIl 759 236 264 279 258 RA12 638 984 001 029 391 . . $ISCO2 Added2008$) ,.'". ," .,. .. .. RA1 39,161 006 185 049 775 RA2 38,449 12,737 340 953 207 RA3 920 899 328 208 660 RA4 39,432 053 232 327 186 RA5 33,965 628 575 329 461 RA6 615 14,400 701 930 163 RA7 149 394 688 822 978 167 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results /;' .;ii 7i;RiSk :c, ' Standafd'5th 95th Upper;;Tiil ; ';;, Percentile ..' IV,Deviation Percentile" "Mean, RA8 469 332 361 624 62,226 RA9 980 270 990 470 221 RAlO 479 13,103 800 967 637 RA11 215 541 953 37,428 59,234 RA12 127 340 544 142 126 , " c:,' , ..'$38CO2Add~r(2008$). " " RAI 344 106 304 944 209 RA2 675 873 218 799 568 RA3 113 004 315 962 940 RA4 45,733 202 249 207 67,708 RA5 037 728 554 967 620 RA6 296 633 933 604 953 RA7 247 487 371 40,489 979 RA8 741 455 211 521 813 RA9 206 369 878 278 716 RAlO 674 193 975 781 066 RA11 311 616 019 334 451 RA12 418 465 586 935 561 , ,;:, :~Ol(JO2 Adde.. (2008$) / , RAI 604 593 398 741 310 RA2 911 372 453 526 511 RA3 345 17,487 203 627 73,826 RA4 076 720 267 987 865 RA5 152 176 941 024 69,377 RA6 029 245 505 249 440 RA7 298 931 105 972 498 RA8 084 956 452 323 102 RA9 53,459 843 121 995 883 RAlO 896 663 112 514 141 RA11 365 052 989 086 193 RA12 53,717 963 559 628 597 Portfolio RA5 has the smallest average risk exposure due to the early addition of coal capacity. Other resource strategies that lower risk exposure include (1) increasing wind capacity, (2) eliminating or reducing reliance on market purchases, and (3) planning to a 15% reserve margin rather than 12%. For example, by comparing RA3 with RA1 , the 600 megawatts of additional wind is shown to reduce risk exposure by an average of $238 million across the five CO2 adder scenarios. The risk reduction benefit increases at successfully higher CO2 adder levels ($224 million under the $0 adder to $260 million under the $61 adder). The benefit ofreducing reliance on frontoffice transactions after 2011 is evident from comparing portfolio RA2 with RAL The average risk exposure decreases by an average of $711 million. Combining both extra wind and eliminating front office transactions after 2011 (RA 7) decreases average risk exposure by $2. 168 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results billion. Changing the planning reserve margin strategy (RA8) has a large impact on risk expo- sure: going from a 12% to 15% margin reduces average risk exposure by $1.4 billion. In contrast to the risk exposure reduction strategies, removing pulverized coal as a resource op- tion eRA5) increases average risk exposure by $5.7 billion, At the $61 CO2 adder level, the risk exposure for RA6 reaches a high of $6.4 billion. Cost/Risk Tradeoff Analysis The three figures below are scatter plots of portfolio cost (PVRR) and risk exposure, and illus- trate the tradeoff between the two performance measures. Figure 7.12 plots the average PVRR and risk exposure across the CO2 adder cases. Figure 7.13 shows the cost-risk relationship for the $0 CO2 adder case, while Figure 7.14 shows the relationship for the $61 CO2 adder case (repre- senting the CO2 scenario risk bookends). The figures show that when considering exposure to potential high-cost outcomes , RA5 has the lowest portfolio risk regardless of the CO2 adder level. However, when considering the balance between risk and cost, RA 7 and RA 1-and RA2 and RA3 right behind-perform the best among this portfolio set. Under the high CO2 adder case, portfolio RA 7 dominates the others by a sig- nificant amount. Figure 7.12 - Average Stochastic Cost versus Risk Exposure 50. .------... I------. RA6 RA8 RA12 RAg RA4 III (,) RA1 111 RA2 RA11 RA10 RA7 RA5 Average Across All CO2 Adder Cases ($0, $8, $15, $38, $61/ton) iiO r:: 'tj,g 47.co ::.r:: a:I ,,- .s D:: ~ ~ 45. co 11. I-;' r:: ... ., ., 8: ~ 42.::I 1a ~ ~ ~ ~ 40. Co ::. )( r::W.- ... E!!! r:: 37.D:: m 35. 21.4 21.21.22.22.22.4 Stochastic Mean PVRR (Billion $) 169 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.13 - Stochastic Cost versus Risk Exposure for the $0 CO2 Adder Case 41. ,g 5!(! ~ 39..r: mu - oS II:: ~ g; 37.01 no I-, c: :; :R g; :i: 35. ? ~ I!! GI ;: ~ 33.II)Co :J ~ . .II: E!!! c: 31. II:: :R :i: 29. 20. $0 CO2 Adder Case .....,..m... ...............................,..,....., .........m....................... RA6 ~12- RA8 RA4 () RA1n + R '\9 "" I ill RA2 " r,RA11 RA7 ... RA5 21.21.22.21.21.21. Stochastic Mean PVRR (Billion $) Figure 7.14 - Stochastic Cost versus Risk Exposure for the $61 CO2 Adder Case 60. 58.:i: ,;;u c::;::: 0II) :=01 =56..r: mu - ~ ~=;:. 54.01 no I-, c: ... CD CD g;:i:52. :J 'i6 f! ;50.II) 0II)Co :J )( c:w.-48..II: EII) it: 46. 21. $61 CO2 Adder Case RA6 RA8 RA4 RA10 RA3 RA1 RA1 RA9 RA2 RA11 RA7 ... RA5 21.22.22.21.21.21.22. Stochastic Mean PVRR (Billion $) As far the resource strategies go, increasing wind capacity and reducing reliance on market pur- chases promotes a better balance of portfolio cost and risk. In contrast, eliminating pulverized coal yields the worst cost-risk balance in all cases; this strategy yields a portfolio with both higher-risk and higher-cost resources. 170 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Resource Strate2V Risk Reduction As described above, adding constraints to the reference portfolio results in a higher stochastic cost. Nevertheless, it can be desirable to choose portfolios or resource strategies that may be sub- optimal on the basis of expected stochastic cost, but that reduce risk exposure. Several risk analysis portfolios were developed to evaluate the cost versus risk exposure implica- tions of specific resource strategies. These resource strategies and the associated test portfolios are summarized in Table 7.23. Table 7.23 - Resource Strategies and Test Portfolios for Cost-Risk Exposure Test Portfolio RA2 RA3 RA8 RA6 At issue is whether the resource strategies increase or decrease risk exposure relative to the ref- erence portfolio, and by how much. If an extra dollar of PVRR spent on the resource strategy translates into more than a dollar in risk exposure reduction, then the extra portfolio cost could be considered a worthwhile insurance investment for customers. Comparing the PVRR and risk exposure at the $61 CO2 adder level in these terms yields the following conclusions: Eliminate market purchases after 2012 (RA2) - this resource strategy lowers total risk exposure; the relative reduction is $4.15 for every additional PVRR dollar spent Include an additional 600 megawatts of wind (RA3) - this resource strategy lowers total risk exposure marginally; the relative reduction is $1.03 for every additional PVRR dollar spent Lower the planning reserve margin from 15% to 12% (RA8) - this resource strategy raises total risk exposure; the relative increase is $11.93 for every additional PVRR dollar spent Remove pulverized coal plants as a resource option (RA6) - this resource strategy raises total risk exposure; the relative increase is $6.26 for every additional PVRR dollar spent Carbon Dioxide and Other Emissions The following tables and figures profile the CO2 emissions footprint for the risk analysis portfo- lios, as well as for SO2, NOx, and mercury (Hg). For CO2 emissions, results are shown by CO2 adder level and for two periods, 2007-2016 and 2007-2026. The tables also report the separate CO2 contributions from generators and market purchases (existing long term purchases, front office transactions and spot purchases). Figures 7.15 and 7.16 show how the cumulative CO2 emission for each portfolio decline as the cost adder is increased. The resource strategies had the following effect on generator CO2 emissions relative to the refer- ence portfolio, RA1: 171 PacifiCorp 2007 IRP Chapter 7 - Modeling and Porifolio Selection Results Removing all pulverized coal plants had the highest emission reduction benefit, lowering the generator CO2 footprint by 12 million tons for 2007-2016 and 29 million tons for 2007-2026 on average Reducing front office transactions had a negligible impact on generator emissions for the first ten years; for 2007-2026, there was a decrease of 7 million tons The additional 600 megawatts of wind decreased emissions by 8 million tons for 2007-2016 and 22 million tons for 2007-2026 Reducing the planning reserve margin from 15% to 12% decreased emissions by 2.5 million tons for 2007-2016, but the overall reduction for 2007-2026 was only 259 000 tons The IGCC bridging strategy (RA11) reduced emissions by 9 million tons for 2007-2016 and 14 million tons for 2007-2026 Table 7.24 - Cumulative CO2 Emissions by Cost Adder Level, 2007-2016 ..' GeneratorCO2 Emissions2007~2016(l00OT()l1s) " .. ,/i ,' . ' $8,Adder .$15 Adder :'$38 Adder $61AdderA'Avera~~(. ",,:' $OAdder ' RAI 520 275 498 032 494 673 488,422 483 805 497 041 RA2 522 525 498 785 495 141 488,330 483 052 497 567 RA3 511 ,893 490 290 486 868 480 446 475 651 489 030 RA4 523 785 500 658 497 114 490 322 485 150 499 406 RA5 526 226 501 006 497 079 488 500 481 903 498 943 RA6 507 235 486 289 482 912 476 713 472 093 485 048 RA7 515 681 492 030 488 377 481 337 475 995 490 684 RA8 516 988 495 680 492 322 486 088 481,439 494 503 RA9 515 118 493 741 490 461 484 494 480 148 492 792 RAlO 517 046 495 287 491 936 485 756 481 329 494 271 RAIl 511 198 489,590 486 177 479 694 474 732 488 278 RA12 509 825 488 734 485 389 479 087 474 398 487 487 CO2 Emissions from Market Purchases, 2007-20 16 (lOOOTpns ' ,", .. .:, '. ID $0 Adder $8 Adder $15 Adder $38 Adder '$61Adder Avera2 Rank RAI 798 510 358 255 87,488 882 RA2 301 831 758 742 068 73,140 RA3 243 374 85,408 215 527 353 RA4 133 603 517 581 909 949 RA5 245 124 144 453 374 668 RA6 586 870 673 468 673 254 RA7 771 229 117 110 75,468 539 RA8 715 342 195 136 605 799 RA9 715 458 88,341 244 623 676 RAlO 001 86,627 511 348 88,461 990 RAIl 166 727 578 636 069 235 RA12 470 904 761 768 233 427 172 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.25 - Cumulative CO2 Emissions by Cost Adder Level, 2007-2026 " ,' .' ' m ' ..." iGenerat()rC()~Emissi~l1s.2007-2026Jl(lOO'f()ns)' ' ,' ",.,. '. , )$OAdder $8 Adder $15 Adder' $38 Adder $6iAdder Averal!e RA1 1 121 716 071 110 1 051 661 1 005 991 983 131 046 722 RA2 118 600 1 065 377 1 044 783 996 976 972 473 039 642 RA3 1 100 779 050 767 1 030 985 983 391 959 728 025 130 RA4 1 122 432 070 823 1 050 931 1 004 604 980 942 1 045 947 RA5 1 122 352 066 931 1 045 768 993 546 966 702 1 039,060 RA6 092,590 1 043 019 1 023 626 977 283 954 462 018,196 RA7 098 664 1 045,400 1 024 659 976 320 951 671 019 343 RA8 1 119 654 070 775 1 051 835 007 310 985 331 046 981 RA9 1 117 852 068 445 1 049 168 1 004 509 983 189 044 632 RAlO 1 120 216 070 065 1 050,497 1 004 820 982 764 045 672 RAIl 1 109 142 058 370 1 038 568 990 992 967 452 032 905 RA12 1 104 925 055 091 1 035 617 989 230 966 425 030 258 " """ , ' " CQiEritissh)Jisf..~niMark~tPurchases,2007-2026d.OOOJ'ons , " $OAdd.~r..$8Adder "$lS1\dder $38Adder $6fAdd.~t Averaj!e RA1 146 689 164 207 170 810 180 598 182 578 168 976 RA2 134 276 153 061 160 118 170 663 173 411 158 306 RA3 147 303 175 981 171 287 182 115 184 159 172 169 RA4 136 267 154 743 161 760 172 140 174 792 159 940 RA5 133 685 153 044 160 597 172 336 175 981 159 129 RA6 152 525 169 071 175 514 184 348 187,453 173 782 RA7 131 307 149 820 156 751 167 235 170 350 155 093 RA8 149 653 166 984 173 528 182 981 185 322 171 694 RA9 149 653 165 141 171 773 182 117 185 321 170 801 RAlO 145 724 162 544 169 099 179 515 182 473 167 871 RAIl 145 021 162 764 169 618 180 874 183 689 168 393 RA12 145 335 163 064 170 005 181 359 183 821 168 717 Rank. 1 , Rank 173 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.15 - Generator CO2 Emissions by Cost Adder Level, Cumulative for 2007-2016 Total Cumulative CO2 Emissions from 2007 through 2016 540,000 530,000 520 000 510,000 460 000 1m $0 Adder . $8 Adder 0 $15 Adder 0 $38 Adder . $61 Adder (II 500 000 s:: I- 490,000 .... 480 000 470 000 440 000 450 000 RA1 RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 RA10 RA11 RA12 Figure 7.16 - Generator CO2 Emissions by Cost Adder Level, Cumulative for 2007-2026 Total Cumulative CO2 Emissions from 2007 through 2026 150,000 100,000 050 000 f--- ~ ~' -"' (IIs:: ~ 1 000 000 ....~, f--e.-. , - f--- 1m $0 Adder . $8 Adder 0$15 Adder 0 $38 Adder . $61 Adder 950,000 900,000 L~' '-r L, RA8 RA9 RA10 RA11 RA12RA1RA2RA3RA4RA5RA6 RA7 174 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.26 - System Generator Emissions Footprint, Cumulative Amount for 2007-2026 ;' , , ~;.(i i:.NOx" ,.. HI!:CO~SCk cNOx III! ""."'.. " 1000 Tons ;1000 Tons Pounds 1000Tons 1000Tons 1000 Tons . , Pounds 1000Tons ,. . .;... ..;.. $0 Adder (2008$) . .. . . $8 Added2008$) // .;..' ,. RAI 822 161 340 121 716 781 099 560 071 110 RA2 814 149 330 118 600 771 082 860 065 377 RA3 817 1,156 228 100 779 775 093 060 050 767 RA4 821 160 354 122,432 779 095 040 070 823 RA5 796 122 293 122 352 749 049 953 066 931 RA6 792 132 825 092 590 751 068 560 043 019 RA7 805 135 228 098 664 762 068 985 045,400 RA8 827 170 332 119 654 787 109 936 070 775 RA9 805 138 130 117 852 764 075 860 068 445 RAW 804 138 140 120 216 763 074 867 070 065 RAIl 805 135 186 109 142 763 071 909 058 370 RA12 808 143 152 104 925 767 080 880 055 091 S02 . ,;;. . NOx.,', HI!:CO2 S02 NOx HI!:'CO2 :: Pounds .1000Tons 1000 Tons Pounds 1000 Tons 1000Tons 1000 Tons 1000 Tons . . " $l5Adder(2008$) , . '. . $38Adder (20()8$) , .. '. " RAI 769 079 962 051 661 725 011 712 005 991 RA2 758 061 938 044 783 712 990 674 996 976 RA3 761 072 853 030 985 711 998 593 983 391 RA4 766 075 976 050 931 722 005 717 004 604 RA5 735 027 890 045 768 680 944 610 993 546 RA6 738 047 469 023 626 693 976 195 977 ,283 RA7 749 047 834 024 659 703 975 567 976 320 RA8 775 089 967 051 835 731 021 604 007 310 RA9 752 056 766 049 168 711 990 506 004 509 RAW 751 055 880 050 497 708 987 880 004 820 RAIl 750 052 812 038 568 701 979 549 990 992 RA12 753 060 785 035 617 707 991 523 989 230 S02 NOx HI!:CO2 1000Tons 1000 Tons Pounds 1000 Tons $61 Adder 2008$) RAI 705 975 598 983 131 RA2 690 952 546 972 473 RA3 688 961 7,475 959 728 RA4 701 968 593 980 942 RA5 655 901 7,472 966 702 RA6 673 942 056 954,462 RA7 681 938 438 951 671 RA8 711 987 604 985 331 RA9 692 958 387 983 189 175 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results '~O2 Af" jiOOOTon.s: 982 764 967 452 966 425 Supply Reliability Energy Not Served Figures 7.17 and 7.18 below show, respectively, the average annual amount of Energy Not Served (ENS) and the upper-tail mean Energy Not Served for the $8 CO2 adder case, a measure of high-end supply reliability risk. It is clear that the system reliability is generally reduced under a 12% planning reserve margin. Asset-based portfolios tended to have higher reliability than portfolios that allowed short-term market purchases to meet firm requirements. RA6, which had no pulverized coal resources, also had a somewhat reduced level of reliability likely due to the combination of including front office transactions and a higher number of less reliable IGCC units in the portfolio. From a reliability basis, measured by energy not served, Portfolio RA5 has the highest reliability. Figure 7.17 - Stochastic Average Annual Energy Not Served Energy Not Served, $8 CO2 Adder Case Average Annual Gigawatt-hours for 2007-2026 240 220 200 180 160 -'= 140 120 100 218 RA1 RA2 RA5 RA6 RA7 RA8 RA9 RA10 RA11 RA12 (12% (12% (12% PRM) PRM) PRM) RA3 RA4 (12% PRM) IE! West. East 176 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.18 - Upper-Tail Stochastic Mean Energy Not Served Upper-Tail Mean Energy Not Served, $8 CO2 Adder Case Average Annual Gigawatt-hours for 2007-2026 000 750 500 250 000 750 500 250 820 RA1 RA2 RA3 RA4 RA5 RA6 RA7 RA8 RAg RA10 RA11 RA12 Loss of Load Probability As discussed in Chapter 6, the Loss of Load Probability (LOLP) parameter is best represented by the probability of an occurrence of Energy Not Served (ENS). Table 7.27 displays the average Loss of Load Probability for each of the risk analysis portfolios modeled using the $8 CO2 adder case. The first block of data is the average LOLP for the first ten years of the study period. The second block of data shows the same information calculated for the entire 20 years. The LOLP values in the second block are significantly higher than the first because the variability of the random draws for the stochastic variable draws increases over time, causing greater extremes in the out-years of the study period. The data is summarized against multiple levels of lost load which shows the likelihood of losing various amounts of load in a single event. Table 7.27 - Average Loss of Load Probability During Summer Peak .. . Avera e for operatin2,years20()7throu2h2016i Event Size ..,...".'"... . (MWh)RAI RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 RAIO RAll RAI2 37%34%36%35%34%37%34%37%39%37%36%38% ~1,000 30%26%29%27%26%30%26%30%32%30%29%31% ;; 10,000 17%13%17%14%12%17%13%17%18%17%17%18% ~ 25000 13%10%13%11%13%10%13%14%13%12%14% ~50,000 10%10%10%11%10%10% :;::.100,000 :;::. 500,000 :;::. 1 000,000 177 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results . /. "...,,,., Avera efot"operatine"ears2007tbroueh 2026. "7~' " ' " EventSize "',.,';;"~""';" RAt RA2;RA3 RA4 RA5 RA6 RA7 RA8 RA9 RA10 RAIl RA12 "', 53%52%39%54%39%52%52%54%57%55%41%43%;:.u,. :;-.;1;000 ' ..' 44%44%33%45%33%44%43%46%49%47%35%37% ,.,, ".,,.., ~to~ooo 25%24%22%26%20%26%23%27%29%27%24%26% ... 20%21%~25.000'20%18%18%15%20%18%21%23%22%19% 50~()00,16%14%15%15%11%16%14%17%19%18%15%17% " , ;;':100,000 12%10%11%11%12%10%13%14%12%11%13% ;;500,000 ;:'1,000,000" Table 7.28 displays the year-by-year results for the threshold value of 25 000 MWh. (As men- tioned in Chapter 6, the 25 000 MWh case was selected as an example to show the annual LOLP as required in the Oregon Commission s 2004 IRP acknowledgement order.) For each year, the LOLP value represents the proportion of the 100 iterations where the July ENS was greater than 000 MWhs. This is the equivalent of 2 500 megawatts for 10 hours. Table 7.28 - Year-by-Year Loss of Load Probability Probability of ENS Event? 25 000 MWh in Jul Year RA1 RA2 RA3 RA4 RA5 RA6 RA7 RA8 RA9 RA10 RAIl RAn 2007 " ,'.' " 2008 2009. ,15%15%15%15%15%15%15%15%15%15%15%15% 2010 "13%13%13%15%13%13%13%15%15%13%13%15% 2011 17%17%17%17%17%17%17%17%17%17%17%17% 2012 10%12%11% 2013 13%13%13%10%15%15%14%14%17% 2014 '14%17%17%14%15%16%15%15% 2015 , ", " 22%14%18%16%23%11%19%23%24%18%22% 2016 19%13%16%14%19%13%19%21%18%16%17% 2017 24%23%23%22%12%29%22%23%21%21%24%25% 2018 22%17%19%19%17%21%17%22%22%23%19%19% , 2019""16%19%13%19%19%13%19%15%15%15%20%21% 2020 23%22%18%23%21%15%22%22%23%23%22%23% 2021 27%23%20%26%20%23%23%26%27%27%23%25% 2022 35%37%33%38%31%39%37%39%40%39%36%39% 2023 24%23%23%28%19%27%23%30%30%31%23%24% 2024 40%39%31%41%26%40%39%42%43%42%30%38% 2025 ,33%30%31%45%29%35%30%46%47%43%30%33% 2026/31%31%31%30%28%33%31%32%48%48%28%36% 178 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Portfolio Resource Conclusions Based on the stochastic simulation results, the best strategy for achieving a low-cost, risk- informed portfolio for PacifiCorp s customers is to include supercritical pulverized coal along with additional wind and natural gas to mitigate CO2 cost risk. Although eliminating front office transactions after 2011 was found to be beneficial for reducing risk exposure, it also increased portfolio cost. On balance, PacifiCorp judges this resource type to be beneficial because it in- creases planning flexibility and resource diversity. Consequently, subsequent risk analysis port- folio development assumes that front office transactions will be available as a model option after 2011. . . RISK ANAL YSIS .PORTFOLIODEVELOPMENT ~GROUP As mentioned above, PacifiCorp developed the Group 2 risk analysis portfolios to account for current and expected resource policies in several of its state jurisdictions, and to address the new load forecast (See Chapter 4). Similar to the process used to derive the Group 1 portfolios, the CEM was allowed to optimize investment plans subject to certain resource constraints and strategies. The CEM optimization process for the Group 2 portfolio was conducted in two phases. The first phase consisted of a screening test to determine general resource selection patterns under a vari- ety of planning assumptions, including the new March 2007 load forecast. Model runs for this phase were based on medium-case scenario conditions, and subject to the following resource assumptions. Coal Resources At least two supercritical pulverized coal resources were included in all of the new portfolios. This decision reflects the following findings from the previous portfolio evaluation work: For Group 1 risk analysis portfolio development, the CEM chose the small Utah resource and the Wyoming resource for 2012-2014 in all portfolios for which the CEM was al- lowed to optimize their selection and timing. The stochastic simulations indicated that removing or deferring these coal resources raised both portfolio cost and risk, even under the higher CO2 adder cases. The Wyoming supercritical pulverized coal resources were resized from 750 megawatts each to 527 megawatts. This size change is intended to mitigate the customer rate and carbon footprint impacts of new coal resources. Also, the large Utah SCPC resource was changed from 600 to 575 megawatts. These changes are consistent with the resource sizes assumed for PacifiCorp ' s 10-year Business Plan. The second Utah and Wyoming supercritical pulverized coal units were removed as resource options for all portfolios. 59 Other resource assumption changes made to confonn to the PacifiCorp Business Plan included (1) removing the 100 MW Desert Power QF from the load and resource balance due to the project s owner declaring bankruptcy, and (2) excluding the Blundell expansion project. (PacifiCorp s economic evaluation of the Blundell project found it to not be cost-effective. This report was filed in all six states in March 2007 to comply with a PacifiCorp-MEHC ac- quisition commitment.) 179 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results The west IGCC resources were removed as options for all portfolios. These IGCC units were patterned after the planned Pacific Mountain Energy Center IGCC project in Kalama Washington, Reasons for exclusion included (1) regulatory uncertainties regarding siting coal-based generation in Washington, (2) commercial uncertainties regarding capital costs and (3) the unique project-specific characteristics (such as a proposed fuel supply that includes imported petroleum coke) that make it unsuitable as a generic IGCC resource. Wind Resources PacifiCorp developed and applied a new fixed wind investment schedule for all Group 2 portfolios except for RA13 , consisting of a total of 1 600 megawatts of wind resources be- yond the 400 megawatts already reflected in the load and resource balance. This schedule is based on acquiring the 1 400 megawatts of wind by 2010 (reflecting an accelerated time table relative to the initial investment schedule developed for risk analysis portfolios) and the addi- tional 600 megawatts tested as a resource strategy in the Group 1 analysis. Table 7.29 shows this new wind investment schedule for the 1 600 megawatts of wind, including the associated cumulative capacity contributions. Table 7.29 - Wind Resource Additions Schedule for Risk Analysis Portfolios ';\nnual Additions; , NalDcplate;c, Capacity ' " W ' 300 300 100 300 200 100 300 c, Culriuhdive W:ind~~~jiJpl~te C:.(V~~jty 300 600 700 000 200 300 600 Cumulative Wind :g~~kpapacitj ' Colltributioll ' , " (M 119 127 146 207 The capacity factor for southeast Wyoming wind resources was increased from 32% to 40% to reflect updated operational expectations for these wind sites. Gas Resources For initial CEM resource screening analysis, there were no restrictions placed on the type and timing of gas resources. Front Office Transactions The model is able to select front office transactions after 2011. Transmission Resources PacifiCorp incorporated the following set of transmission resources in all the Group 2 portfo- lios: 60 The capacity contribution of this new investment schedule is smaller than the contribution for the previous sched- ule, even though there is more nameplate capacity added. This is due to the relocation of wind projects to areas for which incremental additions have less peak-hour load carrying capability. 180 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Path C Upgrade: Borah to Path-C South to Utah North Utah - Desert Southwest (Includes Mona - Oquirrh)61 Mona - Utah North - Craig-Hayden to Park City Miners - Jim Bridger - Terminal Jim Bridger - Terminal Walla Walla - Yakima West Main - Walla Walla These resources are supported by previous portfolio analysis, and are consistent with both the PacifiCorp 10-year Business Plan and MEHC transmission commitments, Additionally, as mentioned in Chapter 2, these transmission resources represent proxies for future transmis- sion requirements rather than specific projects. Planning Reserve Margin Test portfolios with both a 12% and 15% planning reserve margin. The second CEM portfolio optimization phase consisted of the development of the risk analysis portfolios to be simulated with the PaR module, The results of the CEM screening runs were used to inform the selection and timing of resources. Based on the resulting fixed generation resource investment schedule for each portfolio, a CEM run determined the front office transac- tions needed to meet the planning reserve margin. (See Figure 6.4 in Chapter 6 for a generic de- scription of this two-stage CEM optimization process. Alternative Resource Strate2ies Having already determined a new wind investment schedule and the coal resources to include in the Group 2 portfolios, PacifiCorp considered a relatively small set of alternative resource strate- gies to be evaluated. These strategies focus on the timing of the two supercritical coal resources and the mix of gas resources. Specifically, the strategies test (1) whether the new resource as- sumptions alter the CEM's optimal timing for the two supercritical coal plants, (2) reliance on only combined cycle combustion turbines versus a combination ofCCCTs and non-base-Ioad gas resources to meet the latest load growth projections, (3) the timing and type of resources needed to make up for the loss of the BP A peaking contract in August 2011 (i., determine the resource selection impact of removing the contract in 2011 rather than 2012 to ensure that new resources are selected to meet load by August 2011), and (4) alternative planning reserve margins-12% and 15%. For the pulverized coal resources, the CEM was allowed to select the small Utah unit for 2012 or 2013 only, while the Wyoming resource could be acquired in any year after 2013. The major conclusions obtained from the associated CEM screening runs include the following. Coal resource timing - The Utah small supercritical coal resource was always selected in 2012, while the Wyoming supercritical coal resource (527 megawatts) was always selected in 2014. Gas resource mix - When the CEM was allowed to optimize the selection and timing of gas resources, it chose a combination of CCCTs and SCCT frames; the west CCCT was always 61 This resource was included in the 10-year PacifiCorp Business Plan. 181 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results selected in 2012. Restricting the model to choose only CCCTs resulted in just one east CCCT selected in 2012. (This is in addition to the west CCCT selected in 2012. Timing of resource acquisition to address expiration of the BP A peak contract - Re- moving the BPA contract in 2011 (as opposed to 2012) had no effect on the timing of the west CCCT assuming unlimited availability of front office transactions in 2011. Alternative planning reserve margins - Under a 12% planning reserve margin, allowing the model to choose its own gas resources resulted in two SCCT frames selected in 2012 - one in the east and one in the west; this is in addition to the west CCCT selected in 2012. Under a 15% planning reserve margin with no gas resource option restrictions, the CEM portfolio solution included about 200 megawatts of additional gas resources by 2016; east SCCT frames were selected in 2010 and 2012 in addition to an east CCCT in 2012. Based on these results, PacifiCorp developed five portfolios for stochastic simulation. These portfolios are intended to compare CCCTs against reliance on the market to meet new forecasted loads under alternative planning reserve margin targets (12% and 15%). Combined cycle plants were chosen as the proxy gas-fired resource type for two reasons. First, the PaR stochastic simu- lation captures extrinsic (or optionality) value of a resource, while the CEM does not. A CCCT is expected to have a lower PVRR impact than a non-base-Ioad gas resource with all else held con- stant. Second, the larger CCCT minimizes the number of gas resources added in a single year. In addition, all five risk analysis portfolios have a west CCCT added in 2011 to ensure that a resource is available to meet west-side load by August 2011. Finally, the amount of annual front office transactions needed to balance the system is detennined by CEM; no caps are placed on the resources. Table 7.30 outlines the specifications for the five risk analysis portfolios (labeled RA13 through RA 1 7), and presents the design rationale and common features for each. Table 7.30 - Risk Analysis Portfolio Descriptions (Group 2)ID Descri non Desi .nRationale Features RA13 An updated "Base Case This portfolio serves as the . Based on the revised load forecast resource proposal that mirrors reference portfolio for (March 2007)the original PacifiCorp comparison with the other . Wind investment schedule assumed Business Plan s base load risk analysis portfolios. It for original Business Plan resources. This portfolio, based reflects a coal- and . All portfolios use the same on a 12% planning reserve market- intensive resource transmission investment schedule margin, includes four strategy. supercritical pulverized coal resources: the small Utah SCPC (2012), the Wyoming SCPC (2014), the large Utah SCPC (2017), and the second W oming SCPC (2018). 182 PacifiCorp 2007 IRP Descri ., tion This portfolio addresses the higher east load forecast by adding two east CCCTs: one in 2012 (2xl F type) and one in 2016 (Ixl G type). This portfolio addresses the revised east load forecast by adding just one east CCCT in 2012. A 12% planning reserve margin is met with front office transactions. RA14 based on a 15% planning reserve margin; the higher reserve margin is met with CCCT capacity and front office transactions This portfolio addresses the revised load forecast by relying on front office transactions onl . Chapter 7 - Modeling and Portfolio Selection Results Desi nRationale Tests the strategy of meeting east load growth with CCCTs as opposed to the market. Features . Based on the revised load forecast (March 2007) . Small Utah SCPC plant acquired in 2012 . Wyoming SCPC acquired in 2014 . West CCCT acquired in 2011 . Revised wind investment schedule (I,400 MW by 2010; 600 MW by 2013 - Total of2 000 MW by 2013) . All portfolios use the same transmission investment schedule . 12% Planning reserve margin except RA16 Tests the strategy of meeting east load growth with a mix of CCCT capacity and the market. Tests the consequences of meeting the higher planning reserve margin with market resources. Tests the strategy of using market purchases to meet the increased forecasted load. Tables 7.31 through 7.35 present the detailed supply- and demand-side investment schedules for each portfolio. Table 7.36 provides the common transmission investment schedule for all the Group 2 portfolios, Table 7.31- Resource Investment Schedule for Portfolio RA13 Namellate Caoacitl. MW. . '' , .." Resource Type . .,.. 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Utah pulverized coal Supercritical 340 Wyoming pulverized coal Supercritical 527 Utah pulverized coal Supercritical 575 Wyoming pulverized coal Supercritical 527 Combined cycle CT 2xl F class with duct firing Combined cycle CT 1 xl G class with duct firing Combined Heat and Power Generic east-wide Renewable Wind, Wyoming and Idaho 100 200 100 200 100 100 Class 1 DSM*Load control, Sch. irrigation Front office transactions Heavy Load Hour, 3rd Qtr 451 550 281 281 911 054 209 121 811 Combined cycle CT 2xl F Type with duct firing Combined Heat and Power Generic west-wide Renewable Wind, SE Washington Renewable Wind, NC Oregon 200 Class 1 DSM*Sch. irrigation Front office transactions Flat annual product 134 222 300 350 513 413 551 663 840 . .. .. .. AnnuaJAdditions;Long Tenn'Resources 300 200 112 237 577 118;527 ~.; I d . ~ 575 527. Annual Additions, Short Tenn Resources 585 772 581 631 424 467 760 784 651 .. .." . Total Annual Additions 300 200 697 1 ,009 158 749 1;951 467'760 359 178 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. 183 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.32 - Resource Investment Schedule for Portfolio RAt4 NamellateCauaci I1 MW, "":' " Resource " ;,, ;:X :;,:: " 1;.v,pe, " ",,:..,"" 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 East Utah pulverized coal Supercritical 340 Wyoming pulverized coal Supercritical 527 Combined cycle CT 2xl F class with duct firing 548 Combined cycle CT Ixl G class with duct firing 357 Combined Heat and Power Generic east-wide Renewable Wind, Wyoming 200 200 200 300 Class I DSM*Load control, Sch. irrigation Front office transactions HeavY Load Hour, 3rd Qtr 393 272 149 192 165 West CCCT 2x I F Type with duct firing 602 Combined Heat and Power Generic west-wide Renewable Wind, SE Washington 300 100 Renewable Wind, NC Oregon 100 100 100 Class DSM*Load control, Sch. irrigation Front office transactions Flat annual product 219 555 657 247 246 249 Annua.lAdditions, LongTerniReSources 300 300"100 :312 839 125 1:318 527 I... "'357 ; ", ,'" ,, ,, , ;,;, ' 612 336 652 '660 396 438 414AnnuaIAddttH)tls ShortTenn Resouh::es : TotalAnhualAdditiolls 300 300 100 924 1~175 1;777 978 923 438 771 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. Table 7.33 - Resource Investment Schedule for Portfolio RAtS NameplateCapacity, Resource Tvue " , ,::'' , 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 East Utah pulverized coal Supercritical 340 Wyoming pulverized coal Supercritical 527 Combined cycle CT 2x I F class with duct firing 548 Combined cycle CT lxl G class with duct firing Combined Heat and Power Generic east-wide Renewable Wind, Wyoming 200 200 200 300 Class I DSM*Load control, Sch. irrigation Front office transactions Heavy Load Hour, 3rd Qtr 393 272 149 192 349 West Combined cycle CT 2xl F Type with duct firing 602 Combined Heat and Power Generic west-wide Renewable Wind, SE Washington 300 100 Renewable Wind, NC Oregon 100 100 100 Class I DSM*Load control, Sch. irrigation Front office transactions Flat annual product 219 555 657 247 246 384 Annua.lAdditiol1s ,Lon gOT enn Resources 300 300 100 312 839"125 318 527 1;- Annl1al AdditioIlS"Short TellI1 Resmirces ' "~;:. 612 336 652 660 396 438 733 c,:..T utal Arttiual Additions 300 300 100 924 175 777 '978 923 438 733 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. 184 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.34 - Resource Investment Schedule for Portfolio RA16 , " NameD)atetJaDacitv:~:MW ::' Resource "'." Tvpe 2007 2008 2009 2010 2011 2012 2013.2014 2015 2016 East Utah pulvenzed coal Suuercritical 340 Wyoming uulverized coal Suuercritical 527 Combined cycle CT 2xl F class with duct firin!!548 Combined cycle CT 2xl F class with duct firing 548 , Combined cycle CT Ixl G class with duct firing Combined Heat and Power Generic east-wide Renewable Wind, Wyoming 200 200 200 300 Class I DSM*Load control, Sch. irri!!ation Front office transactions Heavy Load Hour, 3rd Qtr 108 111 553 103 272 West Combined cvcle CT 2xl F Tyue with duct firing 602 Combined Heat and Power Generic west-wide Renewable Wind, SE Washin!!ton 300 100 Renewable Wind, NC Oregon 100 100 100 Class I DSM*Load control, Sch. irrigation ,. Front office transactions Flat annual oroduct 289 366 533 261 260 263 .:"..:" Anm.iaIAdditions, Lon!! Tenn Resources 300 300 100 312 1;387 1,125 $18 527 ::.. Annual Additions, Short Term Resources 108 111 842 103 439 533,261 260 535 Total Annual Additions 300 408 211 1;154 1,490 564 851 788 260 535 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. Table 7.35 - Resource Investment Schedule for Portfolio RA17 Name IllaiteCanacitv :MW: , '... Resource 'Type 2007 2008 2009 2010 2011 2012 2013.2014 2015 2016 East Utah uulverized coal Supercritical 340 Wyoming pulverized coal Supercritical 527 Combined cvcle CT 2xl F class with duct firing Combined cvcle CT Ixl G class with duct firin!! Combined Heat and Power Generic east-wide Renewable Wind, Wyoming 200 200 200 300 Class I DSM*Load control, Sch. irrigation Front office transactions Heavy Load Hour, 3rd Qtr 393 272 281 255 394 616 706 West Combined cycle CT 2xl F Tvue with duct firin!!602 Combined Heat and Power Generic west-wide Renewable Wind, SE Washington 300 100 Renewable Wind, NC Oregon 100 100 100 Class I DSM*Load control, Sch. irrigation Front office transactions Flat annual oroduct 219 861 894 492 312 517 Annual Additions, Long Term Resources 300 300 100 312 839.577 318 527 AnnualAdditions, Short Term Resources "'" 612 336 1142 149 886 928 223 .. T ota! Annual Additions 300 300 100'924 la75 719 467 413 928 223 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. 185 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.36 - Transmission Resource Investment Schedule for All Group 2 Portfolios 20072008 200920102011 2012 2013 201420152016 300 600 400 176 600 500 400 , TotalAnnualAdditions 630 700 630 1,776 -500 . . STOCHASTIC. SIMULATION RESULTS The five Group 2 risk analysis portfolios were run in stochastic simulation mode to determine cost, risk, reliability, and emission performance results. The tables and charts below show how the portfolios compare to one another on the basis of these results. Stochastic Mean Cost Table 7.37 compares the stochastic mean PVRR for each portfolio across the CO2 adder cas , as well as by CO2 compliance strategy (per-ton CO2 tax and cap-and-trade). Portfolio RA14 (two east CCCTs) has the lowest stochastic cost at each adder level. RA17 (no east CCCTs) has the highest cost under the $0, $8, $15 , and $38 adder levels, while RA13 has the highest cost under the $61 adder. The average cost deviation among the portfolios is about $200 million for the $0 adder case, and increases to over $600 million at the $61 adder level. Table 7.37 - Stochastic Mean PVRR by CO2 Adder Case RA13 RA14 RA15 RA16 RA17 257 21,401 507 433 685 186 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Customer Rate Impact The portfolio customer rate impact results for each CO2 cost adder level are reported in Figure , and are based on a CO2 cap-and-trade compliance strategy. Portfolio RA14 has the smallest impact across all the CO2 adder levels. The difference between the lowest and highest impact (RAB) under the $0 adder case is $0.12/MWh, and increases to $0.40/MWh for the $61 adder case. Figure 7.19 - Customer Rate Impact Incremental Customer Rate Impact for new Resource Additions Levelized Net Present Value from 2008 to 2026 $3. $2. $3. J: $3. $3. $2. RA13 RA14 RA15 RA16 RA17 8$OCO2 0$8 CO2 O$15CO2 8$38 CO2 1i!I$61 CO2 Emissions Externalitv Cost For the Group 2 portfolios, PacifiCorp estimated the emissions externality cost given two regula- tory strategies: cap-and-trade and a per-ton tax. For the tax strategy, each ton of emissions (pounds in the case of mercury) is assessed an emissions tax equivalent to the cost adder value. Table 7.38 shows the externality cost for each portfolio by CO2 adder level and regulation type. Note that the portfolio rankings, based on the average externality cost across the CO2 adder cases, did not change from one regulatory strategy to other. Portfolio RA16 had the lowest externality cost, followed closely by RA14. In contrast, RA13 had the highest externality cost due to the tWo additional coal plants not included in the other portfo- lios. Nevertheless, the externality cost for RA13 under the tax basis is only six percent higher than that for the best-performing portfolio, RA16. Of' note is that under the cap-and-trade scheme, RA14 and RA16 have a negative externality cost under the $61 adder. This result is a 187 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results consequence of large positive annual allowance balances that have accrued for part of the study period as a result of the cap-and-trade modeling assumptions. Future modeling work is expected to focus on alternative specifications for CO2 compliance strategies. Table 7.38 - Portfolio Emissions Externality Cost by CO2 Adder Level and Regulation Type Average 10,948 310 366 255 457 Rank , - and Tnide,$trategy),iaVliIUon$ , Capital Cost Figure 7.20 shows the total capital cost for eachportfulio expressed on a net present value of the sum of all capital costs accrued for 2007-2026. Portfolios RA14 and RA16 have the highest capital cost on account of the three CCCT resources acquired in the 2012-2016 timeframe. RA13 has the lowest capital cost-despite four coal plants-because of the lack of the east CCCT in 2011 and the accelerated wind investment schedule, as well as the cost discount impact of two coal resources acquired beyond 2016. 188 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Portfolio Construction Cost Risk PacifiCorp calculated a measure of portfolio construction cost risk using its "high case" per-kilowatt capital cost values. (These values are reported in Chapter 5, Tables 5.1 and 5.) The high capital cost ($/kW) estimates are comprised of a standard project construction cost contingency (10%), as well as technology-specific contingen- cies and "optimism" factors for first-of-a-kind technologies that account for the established tendency to underes- timate actual costs (applicable to IGCC). The source for the technology cost contingency and optimism factors is the U.S. Energy Information Administration (Assumptions to the Annual Energy Outlook 2006, DOE/EIA- 0554(2006), March 2006). The risk value for each portfolio is the difference between the PVRR calculated with the high per-kW capital cost and the PVRR calculated with the average per-kW capital cost. The table shows the results for the 17 risk analysis portfolios. Portfolio RA9 had the lowest construction cost risk, while RA5 had the highest. Although RA9 includes the more expensive IGCC plants (on a per-kW basis), the smaller capacity sizes of these units combined with deferral and removal of the supercritical pulverized coal plants, results in a lower overall capital cost. Construction Cost Risk Based on "high case" per-kW Resource Capital Cost 600 500 400c:: 300 :e 200 100 ~ ~ ~~ ~~ ~~ ~~ ~~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ f--f--f-- f-- f--f--f--1--f--f-- f--0 f--f--l--f-- Figure 7.20 - Total Capital Cost by Portfolio Generation and Transmission Capital Cost, Net Present Value $5, $5, $4, $5.40 $5, ~ $5, .Q . iij $4, $4.40 $4. $4. RA13 RA14 RA15 RA16 (15% PRM)RA17 189 PacifiCorp 2007IRP Chapter 7 - Modeling and Portfolio Selection Results Stochastic Risk Measures Table 7.39 reports the portfolio stochastic risk results for each of the CO2 adder cases. Risk ex- posure, production cost standard deviation, fifth-percentile PVRR, ninety-fifth-percentile PVRR and upper-tail PVRR are presented for the cap-and-trade compliance strategy. (Note that relative risk measure railings are the same under both CO2 emissions compliance strategies. Portfolio RA13, with four pulverized coal plants, performed the best overall on the risk meas- ures, followed by RA16 with its two east CCCT resources and 15% planning reserve margin. As expected, RA17 has the highest risk due to its heavy reliance on the market. Interestingly, RA14 performed the best on the basis of the 5th percentile measure, indicating that it could be a good performer under a confluence of low-cost conditions. Table 7.39 - Stochastic Risk Results I.i. ,., ' ...,. RiskExposure ..... i." ........ (Upper-TailPVRR minusMeanPVRR) . ' ...' I . ' .,..' ' Standard ..... 95th iD pp~r;- . Million $,Rank Deviation fe.rcentile TaillVlean $0 Adder (2008$) . ..."...".,';',' i"' '/' RA13 703 020 628 692 309 RA14 056 094 584 315 316 RA15 718 296 518 918 040 RA16 638 987 732 196 974 RA17 339 460 464 198 766 . .,. . $8 Adder (2()08$)..'i " . RA13 984 016 846 652 994 RA14 523 13,134 620 066 082 RA15 198 339 576 665 830 RA16 128 034 693 970 753 RA17 812 501 661 935 562 $15 Adder(2008$). . .' "' '' , . RA13 668 556 987 736 950 RA14 49,195 666 725 038 977 RA15 863 868 695 629 626 RA16 775 560 840 933 510 RAI7 501 036 903 907 398 $38 Adder (2008$) ,'.. RA13 855 852 908 993 993 RA14 258 927 226 426 41,426 RA15 971 136 223 019 019 RA16 835 827 264 311 311 RA17 704 322 357 326 326 S61'Adder(2008S) ..... . RA13 344 544 740 48,252 060 RA14 614 584 562 875 596 RA15 396 805 728 468 564 RA16 159 18,482 481 719 093 190 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results RAl3 911 598 622 465 168 RA14 329 681 743 344 730 RA15 029 889 748 940 537 RA16 907 578 802 226 340 RA17 719 066 999 247 75,403 Cost/Risk Tradeoff Analysis The three figures below are scatter plots of portfolio cost (PVRR) and risk exposure. Figure 7.21 plots the average PVRR and risk exposure across the CO2 adder cases. Figures 7.22 and 7. show the cost-risk relationship for the $0 CO2 adder case and the $61 CO2 adder case, respec- tively. The figures indicate that RA 14 has the best balance of cost and risk on an average basis across the five CO2 adder cases, as well as for adders greater than $0. Portfolio RA17 fares relatively poorly, having both a higher cost and risk than the other portfolios. Figure 7.21 - Average Stochastic Cost versus Risk Exposure Average Across All CO2 Adder Cases CO2 Cap and Trade Basis 54. 7 II ~15 RA14 DII ... RA16 RA13 :::;; ;;;-:; ,g co ==.r; Inu - B II:: 53. en II:: == :;:. co 11. I-;" c: ., ..~:::;; ~ 'iij ~ ~ 52.~ 0 C. " )( c: ~ ' it:51. 21.21.22.22.4 22.23. Stochastic Mean PVRR (Billion $) 191 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.22 - Stochastic Cost versus Risk Exposure for the $0 CO2 Adder Case :::I :!1 ;;;LI C.. 0 "' :::.. = .c InLI- S 0::II) 0:: = ::- .. GoI-;' c ... .. GI GI 8: :!1::J 1; :;; :::I ;:."' 0 i:E 46. 45. 44. 43. 20. $0 CO2 Adder Case CO2 Cap and Trade Basis RA17 RA15 RA14 Iii RA16 F~13 ... 21.22.22.21.22.4 Stochastic Mean PVRR (Billion $) Figure 7.23 - Stochastic Cost versus Risk Exposure for the $61 CO2 Adder Case :!1 ;;; LI C.. 0 "' :::.. = .c InLI- 0:: II) c:: = ::- .. GoI-;' c ... .. GI GI 8: :!1::J 1; :;; :::I ;:."' 00 "'Q. :::I)( Cw.-... E i:E 67. 66. 65. 64. 20. $61 CO2 Adder Case CO2 Cap and Trade Basis ~--_. RA17 II! RA15 RA14 RA13 RA16 0.. ... 21.21.22.23.22.22.4 Stochastic Mean PVRR (Billion $) 192 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Carbon Dioxide and Other Emissions Table 7.40 reports for the portfolios the total system CO2 emissions for the $8 adder and $61 adder cases. Total emissions are presented as the contribution from direct sources (generators) plus indirect emissions from purchases less emissions attributed to wholesale sales , and are reported for 2007-to-2016 and 2007-to-2026. Portfolio RA16 has the lowest CO2 emissions for both CO2 adder levels, followed closely by RA14. For RA16, the early addition of a CCCT dis- places front office transactions, which have a slightly higher CO2 emission rate than a CCCT. Portfolio RA13 has the highest CO2 emissions because of the additional two coal plants. CO2 Adder Breakeven Analysis for Coal versus Gas Combined Cycle PacifiCorp conducted a study to determine the CO2 adder level that causes the CEM to select a combined cycle combustion turbine over a supercritical pulverized coal plant. The model was executed at various CO2 adders between $8/ton and $40/ton (in 2008 dollars) to converge on the breakeven point. The study was performed on a portfolio that had the 600 megawatts of extra wind and a Wyoming supercritical pulverized coal acquired in 2016. The simulations were designed to hold all influences constant except for the substitution of one coal plant with a CCCT. Study assumptions included the following: The pulverized coal and CCCT test resources were both sized at 575 megawatts The two resources were located in the same topology bubble (Utah South) The CEM was required to select either the coal or CCCT resource in 2016, but not both (mutually exclusive options) Each simulation used a set of forward natural gas and wholesale electricity prices that were adjusted to ac- count for the effect of the CO2 adder level tested The breakeven CO2 adder level was found to be $38/ton; up to this level, the CEM selected the coal plant rather than the CCCT. Over the range of CO2 adders tested, a $l/ton increase in the adder translated into an average $373 million increase in deterministic Present Value of Revenue Requirements. (Note that the CEM treats the cost adder as an emissions tax. Table 7.40 - CO2 Emissions by Adder Case and Time Period (1 000 Tons) Scenario RAl3 RAl4 RAl5 RAl6 RAl7 Direct (Generation onl 493 664 495 099 495 040 493 225 495 186 Total Direct and Net Indirect 523 812 507 807 508 332 503 148 512 737 Rank (fotalDirect and Net Indirect TobtiDirect and Net Indirect 127 571 064 710 068 540 057 885 075 848 62 Emissions imputed to purchases are based on a survey of 2005 PacifiCorp historical purchases, at 0.565 tons CO2 MWh. Emissions imputed to sales are based on a year-by-year system weighted average rate: Thermal plus Pur- chases CO2 (tons)/Total System Generation (MWh). 193 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results ~, " RAl3 RA14 RA15 RA16 RA17 , ' TotatDired and Net Indirect ' 515 380 496 788 497 663 491 563 503 290 , " Rank (Total Direct" ~nd Net" Indirect ' Rank,,(' , " ,JI'()fal' ' ,,".. , /" .~Dir TotlilniieCt. " " ~ndIndil'ect "Indirect" 085 311 016,625 022 002 008 456 031 967 Figures 7.24 and 7.25 show the annual CO2 emissions trend from 2007 through 2026 for the and $61 CO2 adder cases, respectively. The impact of the wind and CCCT additions is evident from the emissions drop from 2011 through 2012 for portfolios RA14, RA15 , and RA16. The increasing annual emissions after this point are attributable to the addition of the Wyoming su- percritical pulverized coal resource in 2014 and an increase in front office transactions. The sig- nificant emissions drop in 2019 for all the portfolios is caused by the addition of CCCT -based growth stations, which replace the acquisition of front office transactions. For the $61 adder case, the large CO2 emission decreases in 2013 through 2015 are due to the phasing in of the adder, which starts in 2010 but ramps up significantly in 2014 and 2015. Figure 7.24 - Annual CO2 Emission Trends, 2007-2026, ($8 CO2 Adder Case) (Generation plus the net indirect effect of wholesale purchases and sales) -Coo Period of New IRP Resources and FOTs Growth Stations Only .. 55,000 $8/Ton CO2 adder has a phase- period from 2010-2012 65.000 60,000 c;- 50,000 45,000 40,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 -RA13 --RA14 ""*""RA15 -RA16 -RA17 194 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.25 - Annual CO2 Emission Trends, 2007-2026, ($61 CO2 Adder Case) (Generation plus the net indirect effect of wholesale purchases and sales) ,,-- Period of New IRP Resources and FOTs Growth Stations Only - 000 $61fTon CO2 adder has a phase- period from 2010-2016 55,000 60,000 III 000 000 40,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 ---RA13 """'RA14 '""*""RA15 --RA16 --RA17 Figures 7.26 through 7.29 show the annual system CO2 emissions trends (generation plus net pur- chases) for 2007 through 2016 by CO2 adder case, as well as the contributions from generators only. Figure 7.26 - Annual CO2 Emissions Trends, 2007-2016 ($8 CO2 Adder Case) (From generation only) 55,000 53,000 000 49,000 47,000 III 45,000 43,000 41,000 39,000 37,000 35,000 2007 2008 $8 CO2 adder starts in 2010 and phases in throu h 2012 2009 2010 2011 2012 2013 2014 2015 2016 ---RRP01 .......RRP06 -#-RRP05 --RRP07 --RRP02 195 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.27 - Annual CO2 Emissions Trends, 2007-2016 ($61 CO2 Adder Case) (From generation only) 55,000 000 51,000 000 000 000 !:.. 43,000 41,000 39,000 000 000 2007 2008 S61 CO2 adder starts In 2010 and phases in throu h 2016 2009 2014 201620152010201120122013 --RRPOI --RRP06 -'0-RRP05 ""*",RRP07 --RRP02 Figure 7.28 - Annual CO2 Emissions Trends, 2007-2016 ($8 CO2 Adder Case) (Generation plus the net indirect effect of wholesale purchases and sales) 60,000 SSlTon cO2 adder has a phase-in period from 2010-2012 000 ~ 50,000 !:.. 000 000 2007 2008 2009 2015 201620102012201320142011 --RA13 --RA14 -*-RA15 ""*",RA16 --RA17 196 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.29 - Annual CO2 Emissions Trends, 2007-2016 ($61 CO2 Adder Case) (Generation plus the net indirect effect of wholesale purchases and sales) 000 $61/Ton CO, adder has a phase~n period from 2010-2016 55,000 :g 50 000 '=- 45,000 000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 L-----RA13 -+-RA14 -0,+-RA15 ~RA16 --RA17 Table 7.41 shows the total portfolio emissions of S02, NOx, mercury, and CO2 from generators only, by CO2 adder case, for 2007 through 2026. Portfolio RA16 performed the best across the emission types for most of the CO2 adder cases. RA2 performed nearly as well, coming in sec- ond place on S02, NOx, and mercury emissions for all CO2 adders except the $61 case. RA13 844 RA14 811 RA15 814 RA16 805 RA17 820 RA13 803 RA14 766 RA15 770 RA16 759 RA17 777 064 261 019,946 021 983 017 187 023,767 197 PacifiCorp 2007 IRP 751 708 712 699 722 RA13 RA14 RA15 RA16 RA17 730 686 691 677 702 Supply Reliabilitv Chapter 7 - Modeling and Portfolio Selection Results . Eml8sionT ' N()~ 1000 Tol1s . Pounds111 7 913063 7 615070 7 623052 7 590081 7 635 $38 COzAdder Case047 7 651999 7 335007 7 347986 7,306020 7 367 $61COz Adder Case011 7 529964 7 195 972 7 210950 7 163987 7 236 10001:0118 . 043,467 998 044 000 419 994 806 002 900 972 566 922 926 926 375 918 006 931 329 Energy Not Served (ENS) Figures 7.30 and 7.31 show the average annual ENS and upper-tail ENS by portfolio for 2007- 2026, respectively. RA16 has the smallest ENS amount at 135 gigawatt hours, followed by RA14. Portfolios RA13 and RA17 have the highest ENS due to the heavier reliance on front of- fice transactions to meet the load obligation. The ENS was also tested for the $O/ton CO2 and $61/ton CO2 and the amount of ENS was the same for each portfolio. Figure 7.30 - Energy Not Served for the $8 CO2 Adder Case Stochastic Mean Energy Not Served, $8 CO2 Average Annual GWh for 2007 - 2026 280 260 240 220 200 1801:. 1603: 140 C) 120 CIS 100 RA13 RA14 RA15 13 West. East RA17RA16 198 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.31- Upper-Tail Mean Energy Not Served for the $8 CO2 Adder Case Upper Tail Mean Energy Not Served, $8 CO2 Adder Case Average Annual Gigawatt-hours for 2007 to 2026 000 697 500 .t: 000 500 549 RA13 RA14 RA15 RA16 RA17 Loss of Load Probability Table 7.42 displays the average Loss of Load Probability for each of the risk analysis portfolios modeled using the $8 CO2 adder case. The first block of data is the average LOLP for the first ten years of the study period. The second block of data shows the same information calculated for the entire 20 years. The data is summarized against multiple levels of lost load, which shows the likelihood of losing various amounts of load in a single event. RAt3 RAt4 RAt5 RAt6 RAt7 29%24%25%23%26% 24%22%22%20%24% 16%14%15%13%17% 12%11%11%13% 10% RA13 RAt4 RA15 RAt6 RAt7 53%38%42%36%44% 47%33%38%32%40% 28%22%25%22%29% 21%18%19%18%24% 199 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results RA13, 16% 11% 15% 11% 16% 12% 14% 11% Table 7.43 displays the year-by-year results for the threshold value of 25 000 megawatt-hours. For each year, the LOLP value represents the proportion of the 100 iterations where the July ENS was greater than 25 000 megawatt-hours. This is the equivalent of 2 500 megawatts for 10 hours. Table 7.43 - Y ear-by- Year Loss of Load Probability Year . , RA13 )RAI4.RAtS.RA16 RA17 2007 2008 2009. ,. 10%10%10%10% 2010 13%12%12%13%12% 2011.16%16%16%10%16% 2012 . . 2013 13%12%12%13% .2014 . . .",. 15%10%10%16% 2015 23%18%18%15%22% 2016.20%16%20%17%26% 2017.23%26%29%25%30% 2018 28%26%30%27%39% 2019 15%18%19%20%30% 2020 22%23%27%25%31% 2021 24%22%25%23%33% 2022 32%29%31%34%38% 2023 28%23%28%22%36% 2024 36%25%27%30%36% 2025 41%28%33%32%32% 2026 49%28%28%29%37% STOCHASTIC SIMULATION SENSITIVITY ANALYSES PacifiCorp performed several stochastic simulation studies to test the stochastic cost, risk, and reliability impacts of planning reserve margin and resource type assumptions against a reference portfolio. Table 7.44 lists the sensitivity analysis studies conducted and the reference portfolios used. The study assumptions and results are summarized below. 200 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.44 - Sensitivity Analysis Scenarios for Detailed Simulation Analysis# Name . Referen(!eCase' , . 1 Plan to a 12% capacity reserve margin, and include Class 3 DSM 8 (Consistent with the portfolio developedsufficient to eliminate ENS for SA SO 1) 2 Plan to 18% capacity reserve margin SAS02 , " Plan to 18% capacity reserve margin 3 Re lace a 2012 base load resource with front office transactions isk Anal sis Portfolio RAI 4 Replace a base load pulverized coal resource with a carbon- ca ture-read IGCC resource Substitute a base load resource with CHP and aggregated dis atchable customer standb eneration sk Analysis Portfolio RAI 12-Percent Plannine: Reserve Mare:in with Class 3 Demand-side Manae:ement Proe:rams For this study, 106 megawatts of Class 3 demand side management programs were added to the RA8 risk analysis portfolio in 2009. This DSM quantity reflects the total available to the model according to the base case proxy supply curve results reported by Quantec LLC, and includes capacity for curtailable rate, critical peak pricing, and demand buyback programs for both the east and west sides of the system. The Class 3 DSM programs were modeled in the PaR module as a "take" component during super-peak hours and a "return" component for all other hours. The impact of the Class 3 DSM on portfolio performance was negligible. Compared to RA8 stochastic mean PVRR increased by $11 million, risk exposure decreased by $9 million, and Energy Not Served decreased by 0.1 percent. Plan to an IS-Percent Plannine: Reserve Mandn PacifiCorp modeled the CEM investment plan that resulted from planning to an 18-percent plan- ning reserve margin (SAS02 study). The SAS02 study reflects the same scenario conditions as RA1 except for the 15-percent planning reserve margin. Relative to RA1 , the SAS02 portfolio resulted in a $69 million increase in stochastic mean PVRR, while risk exposure decreased by $346 million. Energy Not Served also decreased by about 16 percent. The PVRR increase was mainly attributable to the addition of an east SCCT frame resource. Replace a 2012 Base Load Resource with Front Office Transactions Using RA1 as the reference case, PacifiCorp replaced the small Utah pulverized coal resource acquired in 2012 (340 megawatts) with a comparable amount of front office transactions ac- quired at the Mona trading location (6x16 product over 3 month summer season) that continued over the remaining study period. Compared to RA1 , the new portfolio s stochastic mean PVRR was $4 million lower, while the risk exposure increased by $3.4 billion. Energy Not Served increased by nine percent. Based on this sensitivity study, PacifiCorp concluded that replacing a long-term asset outright with market purchases-holding other factors constant-is not a preferred east-side resource strategy given the cost-versus-risk tradeoff. Replace a Base Load Pulverized Coal Resource with a Carbon-Capture-Readv IGCC Starting with portfolio RA1 , PacifiCorp replaced the 750-megawatt Wyoming supercritical pul- verized coal resource with an equivalently sized IGCC plant that has minimum carbon capture 201 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results provisions. The coal resource replacement resulted in a $687 million increase in stochastic mean PVRR and a $411 million increase in risk exposure. The risk exposure increase is due to the two- percent lower availability of the IGCC relative to the Wyoming SCPC resource. Replace a Base Load Resource with CHP and Dispatchable Customer Standby Generation Using portfolio RA1 as the starting point, PacifiCorp replaced the small Utah pulverized coal resource with 280 megawatts of gas-fired CHP resources and 60 megawatts of west-side cus- tomer standby generation. (This sensitivity addresses an analysis requirement in the Oregon Pub- lic Utility Commission s 2004 Integrated Resource Plan acknowledgement order.) Table 7.45 reports the sizes, locations, and number of units used for the study. Table 7.45 - Combined Heat and Power Replacement Resources CHPResource T Lar e industrial- 25 MW Small industrial/commercial- 5 MW Total. Comparing against portfolio RA1 , the new portfolio with CHP and customer standby generation resources had a $168 million higher stochastic mean PVRR. Risk exposure was higher by $2.4 billion, while Energy Not Served was higher by about 7 percent. . . ,. PREFERRED ,PORTFo.LIo. SELECTION ANDJUSTIFI CA TIo.N Based on the stochastic analysis results for the Group 2 risk analysis portfolios, the company has chosen RA14 as the preferred portfolio. Table 7.46 shows the resulting load and resource balance with preferred portfolio resources and east-west transfers included. This portfolio reflects a robust resource strategy that accounts for the major resource risk factors (specifically the form and cost impact of CO2 regulations, and price volatility for natural gas plants and market purchases) as well as evolving state resource policies that are currently not coordinated with respect to PacifiCorp s system-wide integrated resource planning mandate, Portfolio RA14 is viewed as the least-cost and least economically risky proposition for reliably meeting PacifiCorp s load obligation while accommodating different state policies and interests. In assessing the overall merits of this portfolio, PacifiCorp also concentrated on the value of the different resource types for managing portfolio risks in the short term, mid term, and long term. For the short term, the acquisition of renewables, DSM and CHP increases portfolio diversity and lays the groundwork for a resource base that can comply with early RPS and CO2 compli- ance schedules. For the mid term-2012 through 2014, which is a period marked by significant resource need and escalating regulatory risks-the preferred portfolio is constituted with a mix of proxy long-term assets with complementary risk profiles (supercritical pulverized coal and CCCT resources), supplemented by new front office transactions to increase planning flexibility. For the long term, the preferred portfolio includes flexible long-term assets with a small emis- sions footprint and a moderate reliance on front office transactions. This resource mix is most in line with the company strategy to reduce its long-term reliance on the market, which is discussed in more detail later in this chapter. 202 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Plannin!! Reserve Mar!!in Selection While Portfolio RA14 is based on a target planning reserve margin of 12 percent, PacifiCorp is targeting a reserve margin range of 12 to 15 percent to increase planning flexibility given a time of rapid public policy evolution and wide uncertainty over the resulting down-stream cost im- pacts. While the portfolio analysis indicates that lowering the planning reserve margin increases portfolio stochastic risk and reduces reliability, the decision on what margin to adopt is a subjec- tive one that depends on balancing portfolio risk against cost. Given the expected pressure on customer rates due to state resource constraints, as well as the rapid pace of construction cost increases for all resource types, near-term affordability of a resource plan is a consideration guid- ing the planning margin decision. PacifiCorp s choice to adopt a 12 percent planning reserve margin is intended to keep the portfo- lio cost down while retaining the flexibility to adjust the margin upwards and acquire appropriate incremental resources. Market conditions, revised load growth projections, or new regional ade- quacy standards may prompt the company to increase the margin in response. Based on the Group 2 portfolio analysis and the resource outlook developed for this IRP, a higher planning reserve margin would be met with a combination of gas generation and front office transactions as can be seen in Portfolio RA16. An issue raised by public stakeholders is the impact of the planning reserve margin decision on supply reliability. PacifiCorp s view is that supply reliability is not materially impacted by a swing in the margin from 15 to 12 percent. The supply reliability analyses (Energy Not Served and Loss of Load Probability) indicate that, with the exception of "all coal" portfolios such as RA 13 , there are no significant differences among the portfolios with respect to reliability. As additional evidence of this finding, comparing portfolio pairs intended to test the impact of a 15 percent margin against a 12 percent margin (RA1 versus RA8, RAlO versus RA9, RA11 versus RA 12, and RA 16 versus RA 14) yields small differences in average annual ENS of between 1.2 MWa to 3.9 MWa. 203 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.46 - Preferred Portfolio Capacity Load and Resource Balance 2007 2008 2009 2010 2011 2013 2014 2015 2016 \~1 134 941 941 941 941 941 941 Hydro 135 135 135 135 135 135 135 135 135 DSM 153 163 163 163 163 163 163 163 163 Renewable 109 109 109 109 109 109 105 105 Purchase 904 679 778 548 543 343 343 343 322 106 106 106 106 106 106 106 106 106 Interruptible 233 233 308 308 308 308 308 308 308 Transfers 534 797 731 898 162 955 597 701 777 East Existing Resources 264 163 271 208 8,467 060 702 802 857 Wind 109 109 109 109 DSM CHP Front Office Transactions 393 272 149 192 165 Thermal 888 888 1,415 1,415 772 East Planned Resources 433 320 073 088 761 804 134 East Total Resources 264 187 295 641 787 133 304 9,463 606 991 Load 321 515 657 137 289 595 738 895 026 366 Sale 849 811 702 666 631 595 595 595 595 595 East Obligation 170 326 359 803 920 190 333 8,490 621 961 Planning reserves (12%)706 750 733 767 796 872 894 896 906 953 Non-owned reserves East Reserves 776 821 804 837 867 942 965 966 977 023 ;t Obligation + Reserves (12%)946 147 163 641 787 132 298 9,456 598 984 East Position 317 132 East Reserve Margin 16%13%14%12%12%12%12%12%12%12% 046 Hydro 328 357 249 243 244 242 DSM Renewable 108 108 108 Purchase 786 799 749 141 107 107 107 Transfers (542)(907)(1,170)120)(606)(708)(786) West Existing Resources 859 3,414 130 2,438 913 811 732 Wind DSM CHP Front Office Transactions 219 555 657 247 246 249 Thermal 548 548 548 548 548 548 West Planned Resources 298 691 308 1,410 000 999 002 West Total Resources 873 625 718 712 821 850 848 913 810 734 Load 922 924 095 124 199 240 251 262 271 252 Sale 299 299 299 290 290 258 258 258 158 108 West Obligation 221 223 394 3,414 3,489 3,498 509 520 3,429 360 Planning Reserves (12%)292 291 311 287 321 336 322 376 365 357 Non-owned reserves West Reserves 299 297 318 294 328 342 328 383 372 363 West Obligation + Reserves 513 514 705 701 810 834 831 896 794 716 West Position 360 111 West Reserve Margin 23%15%12%12%12%12%12%12%12%12% ~ystem Total Resources 12,137 811 013 13,416 Obligation 10,391 10,549 10,753 12,010 050 321 Reserves 075 118 122 349 348 386 Obligation + Reserves 11,466 11,667 11,874 13,359 398 13,707 System Position 671 144 138 Reserve Margin 18%13%13%12%12%12% 204 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results The Role of Front Office Transactions and Market A vailabilitv Considerations In parallel with the decision on an appropriate planning reserve margin level, the degree to which PacifiCorp relies on firm market transactions is a decision that requires balancing portfolio cost and risk. As demonstrated by comparing risk analysis portfolios with differing front office trans- action assumptions, less reliance on front office transactions tends to reduce market price risk exposure, but can increase or decrease mean stochastic cost depending on the make-up of the portfolio. As mentioned earlier in this chapter, PacifiCorp believes that a limited amount of front office transactions benefit the preferred portfolio by increasing planning flexibility and resource diversity. Nevertheless, the company is concerned about long-term reliance on the market and exposure to market price risk, and therefore seeks to reduce that reliance as part of its overall resource management strategy. This concern stems from two sources of market price risk and uncertainty. The first source is the shifting resource mix outlook in the Western Interconnection driven principally by new or expected state regulatory requirements. Specific trends include ex- tensive expansion of renewable and gas-fired capacity and a counterpart reduction in coal capac- ity development. The second source of risk and uncertainty is the potential tightening of the re- gional capacity balance in the next decade due to planned resources not being built as more utili- ties rely on the market to meet their future needs. This is the time frame when a significant amount of base load capacity is needed by PacifiCorp and other utilities. The preferred portfolio is consistent with this strategic view on market reliance. The system-wide front office transaction amount in the preferred portfolio peaks at 660 megawatts in 2013 , repre- senting just over 55 percent of the transactions amount included as a planned resource in Pacifi- Corp s 2004 IRP (1,200 megawatts). Additionally, the company no longer plans for a fixed an- nual target amount of new firm market purchases in the load and resource balance as was done for the previous IRP; rather, front office transactions are evaluated on a comparable basis with other resources and are subject to the company s stochastic risk analysis. Finally, the reliance on front office transactions drops off significantly after 2013 , declining over one-third by 2016. Regarding market availability to support the level of front office transactions in the preferred portfolio, PacifiCorp points to purchase offer activity in response to recent periodic requests for proposals issued by the company s commercial and trading department. Requests in 2007 for third-quarter products for 2007-2012 delivery yielded over 5 000 megawatts in offers. FUEL DlVERSITYPLANNIN G Pursuant to the Utah Public Service Commission s order on the PURPA Fuel Source Standard (Docket no. 06-999-, issued on March 13 2007), this section describes how fuel source diver- sity is addressed in the 2007 Integrated Resource Plan. The IRP standards and guidelines require PacifiCorp to evaluate all resource options on a consis- tent and comparable basis, which explicitly implies consideration of coal, natural gas, demand- side management, and renewable resources (See Appendix I). In addition, the new Oregon Public 63 As directed by the Utah Commission and agreed to by PacifiCorp, all future IRPs will include a section on fuel source diversity to comply with the new fuel source standard under Title I Subtitle B of PURP A. See Chapter 3 for more details. 205 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Utility Commission IRP guidelines issued in January 2007 require the company to consider "all known resources for meeting the utility's load", as well as compare different fuel types,64 As discussed in Chapter 2, one of PacifiCorp s planning principles is to seek a diversified, low-cost mix of resources that minimizes risks for customers and the company. The company s portfolio optimization studies, using a range of planning scenarios, adhered to this planning principle. This IRP fulfills the PURP A requirement for a fuel diversity plan in the following ways: PacifiCorp considered a comprehensive range of resource options for the IRP, including transmission resources. With the exception of Class 2 DSM, these resources were evaluated on a comparable basis using the CEM model. PacifiCorp conducted alternative future studies to derive optimal resource investment plans under a wide range of conditions. As a result of these deterministic scenario studies, Pacifi- Corp selected a variety of DSM programs, wind, and CHP resources to be included in subse- quent portfolio evaluations and the preferred portfolio. . To account for state resource policies in the areas of renewable generation and climate change, the company evaluated portfolios with an additional 600 megawatts of nameplate wind capacity. Based on the associated stochastic modeling results, PacifiCorp decided to in- clude this additional wind capacity in its preferred portfolio. PacifiCorp validated with its stochastic production cost modeling that a balanced mixture of new wind, gas, and coal resources is optimal from a cost and portfolio risk management standpoint. Although the preferred portfolio includes 867 megawatts of supercritical pulverized coal ca- pacity, the amount of natural gas-fired capacity added exceeds this amount (1,553 mega- watts) as does the nameplate renewables capacity (2 000 megawatts). Figure 7.32 compares the resource energy mix for 2007 and 2016; the latter including preferred portfolio resources. The 2016 results are shown for generation under an $8/ton CO2 adder and the average generation across the five CO2 adders modeled. The comparison highlights the large decrease in coal-fired generation and the offsetting increase in renewable, gas-fired, and front office transaction generation. (Note that only the system balancing purchases are shown; for ex- ample, under the $8/ton CO2 adder case, accounting for system balancing sales results in a net sales amount of 9 843 gigawatt-hours in 2007 and a net purchase amount of 3 518 gigawatt- hours in 2016. Figure 7.33 provides a resource mix comparison on the basis of capacity for the $8/ton CO2 ad- der case. For the renewables category, the capacity contribution of wind resources is used. 64 Public Utility Commission of Oregon , " Investigation Into Integrated Resource Planning" UM 1056, Order No. 07- 002, Appendix A, p. 7. 65 The prefelTed portfolio was also tested to determine the cost and risk impact of removing the 600 MW of wind. Stochastic PVRR increased by $0.9 billion and risk exposure increased by $5.5 billion due to the increase in spot market purchases. 206 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.32 - Current and Projected PacifiCorp Resource Energy Mix 2007 Resource Energy Mix with Preferred Portfolio Resources ($8 CO2 Adder Case) Gas-SCCT Hydroelectric Gas-CHP System Balancing Purchases Existing Purchases 2016 Resource Energy Mix with Preferred Portfolio Resources ($8 CO2 Adder Case) Interru~tible Class 1 DSM1 Yo Renewable =-0, Hydroelectric 8, Gas-CCCT 15. Pulverized Coal 46. System Balancing Purchases 13.1~ont Office Transactions Existing Purchases 207 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results 2016 Resource Energy Mix with Preferred Portfolio Resources (Average for five CO2 Adder Cases) Hydroelectric Pulverized Coal 43, Gas-CCCT 17.4% System Balancing Purchases 14.2% Front Office Transactions Figure 7.33 - Current and Projected PacifiCorp Resource Capacity Mix 2007 Resource Capacity Mix, with Preferred Portfolio Resources ($8 CO2 Adder Case) Renewable 5% Class-1 DSMInterruptible 1. Hydroeiectric 12. Pulverized Coal 50. Gas-CHP Gas-SCCT Gas-CCCT 14, Existing Purchases 15. 208 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results 2016 Resource Capacity Mix, with Preferred Portfolio Resources ($8 CO2 Adder Case) Renewable Gas-CCCT 21, Hydroelectric 10. Gas-CHP Pulverized Coal 50. Existing Purchases Front Office Transactions2% 3. . . FO RECASTED FOSSIL FUEL GENERATORHEA TiRATE TREND. Pursuant to the Utah Public Service Commission s order on the PURP A Fuel Sources Standard (Docket no. 06-999-03), this section reports the forecasted average heat rate trend for the com- pany s fossil fuel generator fleet on an annual basis, accounting for new IRP resources and cur- rent planned retirements of existing resources. The fleet-wide heat rate represents the individual generator heat rates weighted by their annual generation. (Note that system dispatch accounts for an $8/ton CO2 cost adder). For existing fossil fuel resources, four-year average historical heat rate curves are used, whereas new resources use expected heat rates accounting for degradationover time. Figure 7.34 shows the fleet weighted-average fossil fuel generator heat rate trend from 2007 through 2026, indicating the contributions from existing coal resources, existing gas resources new coal resources, and new gas resources (including CHP). The average heat rate declines from 255 to 9 082 Btu/kWh, a compounded average annual decrease of 0.6 percent. As indicated in Figure 7.34, the heat rate contribution of existing coal plants drops significantly, declining from 91 percent of the system total in 2007 to only 53 percent by 2026. Also underlying the trend is increasing reliance on generation from new gas and wind resources, the later displacing genera- tion from existing coal plants. 209 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.34 - Fleet Average Fossil Fuel Heat Rate Annual Trend by Generator Type 000 ~ 10,000 CD 9 000 .2iIII0:: 8 000 III :: 7 000III ~ 6,000 III :ii 5 000 000 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ - Existing Coal III Existing Gas 0 IRP-Gas 0 IRP-coal . . .... . - CI..ASS2 DSM DECREMENTANALYSIS . This section presents the results of the Class 2 demand-side management decrement analysis. For this analysis, the preferred portfolio, RA14, was used to calculate the decrement value of various types of Class 2 programs following the methodology described in Chapter 6. PacifiCorp will use these decrement values when evaluating the cost-effectiveness of potential new programs between IRP cycles. Note that for the next IRP, the company intends to model Class 2 DSM pro- grams as options in the CEM. Modeline Results Tables 7.47 and 7.48 show the nominal results of the 12 decrement cases for each year of the 20- year study period. Although no resources were deferred or eliminated from the portfolio due to the addition of Class 2 decrements, there is value in having to produce less generation to meet a smaller load. Consistent with the results for the 2004 IRP, the residential air conditioning decre- ments produce the highest value for both the east and west locations. The commercial lighting, residential lighting, and system load shapes provide the lowest avoided costs. Much of their end use shapes reduce loads during a greater percentage of off-peak hours than the other shapes and during all seasons, not just the summer. 210 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.47 - Annual Nominal Avoided Costs for Decrements, 2010-2017 , Actu~1 DecremeIJ.tYalues~olBinar$/~nYh) .. ..'.... .. . ' .u u . Load 2011.J" 2012, . '. , " i r ,2015 12016 2017DecremenfNameFa'ctor'2010 ' 21Jl3 2014 EAST Residential Cooling 113.38 108.87.102.93.103.109.125.48 Residential Lighting 60%68.71.73 59.62.59.64.70.79. Residential Whole House 46%70.15 72.59.42 62.60.20 65.45 70.80. Commercial Cooling 16%84.85.69.71.34 67.73.80.92.47 Commercial Lighting 49%68.71.97 58.61.46 58.63.41 69.78. System Load Shape 65%65.18 68.56.59.56.47 61.24 67.75. WEST Residential Cooling 20%53.51.87 46.48.53.61.06 64.71.75 Residential Heating 28%39.51.06 46.41.06 46.49.58.62. Residential Lighting 60%44.34 48.43.42.47.45 52.58.64. Commercial Cooling 16%51.51.53 46.45.39 50.56.61.81 68. Commercial Lighting 49%43.49.44.49 42.47.47 53.59.64. System Load Shape 67%43.30 47.42.40.37 45.50.56.61.72 Table 7.48 - Annual Nominal Avoided Costs for Decrements, 2018-2026 . " . .... ,. C . , ,. c. . .' . c.,.DecrementYalueslNominal$/MWh) .cC,c c .. 1: : '" "'," DecremenfName 2018 2019" 2020 " " 21122 2023 2024 2025\2026 EAST Residential Cooling 159.126.134.143.156.62.162.45 179.163.169. Residential Lighting 89.48 79.84.94.101.92 107.114.109.114.15 Residential Whole House 92.80.86.96.104.109.46 115.110.115. Commercial Cooling 112.94.43 101.17 112.120.127.134.125.130. Commercial Lighting 88.79.84.34 93.102.27 107.34 112.108.113. System Load Shape 85.11 76.81.36 91.08 98.103.109.32 106.14 110. WEST Residential Cooling 82.31 84.81.81 84.88.92.92.101.82 106. Residential Heating 64.74.73.75.77.45 83.83.87.90. Residential Lighting 69.75.74.77.80.83.49 84.90.92. Commercial Cooling 79.81.63 79.82.85.89.89.99.102. Commercial Lighting 69.44 76.45 75.78.81.44 85.47 86.40 91.81 94. System Load Shape 66.73.25 72.75.77.81.97 82.87.90. Figures 7.35 and 7.36 show the decrement costs for each end use along with the average annual forward market price for that location: Palo Verde (PV) for the east and Mid-Columbia (Mid- for the west. 211 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.35 - East Decrement Price Trends 180. 170, 160, 150. 140. 130, 120. .c 110. :!:::;; ... 100. 90, 80, 70, 60. 50, 40, 30. 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 -7% --60% -46%16% --49% --65% . + - Palo Verde - Flat Figure 7.36 - West Decrement Price Trends 110, 105, 100, 95, 90. 85, 80. 75. :!: 70. ::;;... 65. 60, -j. 55. 50, 45, 40. 35, 30, 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 -20% --28% -60%16% --49% --67% . + - Mid Columbia Flat 1 212 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results "". ...,..,... ...m".... ... ....' 'H """'"" ,.... REGUBAOPORYSCEN:ARI(:),,:ro:SK-ANALYSJS.. .~' G REENH OUSE GASEMISSIONS PERFORMANCIt"S;I'ANDARDS Chapter 2 identified CO2 regulation as an important scenario risk facing the company. In addi- tion to the CO2 externality cost scenarios investigated for this IRP, PacifiCorp also conducted a portfolio scenario study using the CEM and PaR models where a generator-based greenhouse gas emissions performance standard, such as the one in place in California, is instituted in all of PacifiCorp s service territory. The purpose of the study was to determine the comparative sto- chastic cost, risk, and CO2 emission impacts of a portfolio that meets performance standard re- quirements as modeled using the CEM. This section first outlines the study approach and then presents comparative results with respect to the preferred portfolio (RA14) and the other Group 2 portfolios. Scenario Study Approach For this study, PacifiCorp first used the CEM to determine a deterministically optimized portfo- lio on the basis of GHG performance standard constraints, and then manually constrained the CEM resources to yield a portfolio with an improved cost and risk profile as determined by sto- chastic PaR model runs. This process is similar to the one used to develop the risk analysis port- folios. The CEM was allowed to optimize resource selection and timing subject to assumptions de- signed to restrict resources to those that can comply with a CO2 emission performance standard (a per-ton emissions amount comparable or less than a CCCT). The specific CEM portfolio as- sumptions for the study are as follows: Resources available for selection by the CEM include CCCT (F and G types with duct firing), IGCC with carbon capture and sequestration (CCS), renewables, DSM (both Class 1 and Class 3), and combined heat and power; pulverized coal was excluded as a resource option. . No constraints were placed on resource amounts, timing, or location, except for earliest available in-service dates. . A total of3 700 megawatts of renew abies was made available for selection. Renewable portfolio standards for California, Oregon, and Washington were assumed to be in place. The RPS requirements were handled as state contributions to a gross percent- age on system retail loads-the same method used for previous RPS portfolio modeling. The percentages were updated based on the March 2007 load forecast. The quantity of front office transactions was limited to 1 200 megawatts after 2011 (700 in the east and 500 megawatts in the west). . A 12 percent planning reserve margin and $8/ton CO2 cost adder were assumed. Table 7.49 shows the cumulative capacity by resource type and simulation period for the result- ing CEM portfolio solution. 213 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Table 7.49 - Capacity Additions for the Initial CEM GHG Emissions Performance Stan- dard Portfolio Gas - CCCT Renewables DSM IGCC with CCS (Jumulative NalDepla!. ~ . aci .b 'Period(MWJ\ 20Q7~2016 2007~20,26);;ii507 6,410900 3 100137 156 As noted above, the CEM was not constrained to select certain resource amounts in certain years or areas. One consequence of this model set-up is that the resulting CEM portfolio does not re- flect an investment schedule that is advantageous from a stochastic cost and risk standpoint. An- other consequence is that the model's wind investment pattern differs significantly from what was identified in PacifiCorp s preferred portfolio. For example, the model did not recognize geographical RPS requirements in placing renewable resources; all wind resources were added in the east side until 2018. Additionally, the CEM included more renewables in 2007 than the pre- ferred portfolio (700 megawatts versus 400 megawatts in the preferred portfolio), which is not practical from a procurement perspective. To address these two issues, PacifiCorp first subjected this portfolio to stochastic simulation to create baseline stochastic results. Then, the CEM was executed again after applying resource constraints to the portfolio. These constraints include (1) limiting renewables to 300 megawatts in 2007 , (2) adding an east-side CCCT in 2011 to replace a portion of front office transactions and (3) fixing the east-side CCCT resource selected in 2011. The resulting CEM portfolio was simulated with the PaR model, and stochastic results compared against those of the original CEM portfolio. These resource constraints reduced stochastic mean PVRR by $144 million, risk exposure by $671 million, and upper-tail risk by $816 million. Table 7.50 shows the resource additions for the final GHG emission performance standard portfolio from 2007 through 2026. As with the other risk analysis portfolios, load growth and capacity reserve requirements are met with CCCT growth stations after 2018. Stochastic Cost and Risk Results Table 7.51 provides the stochastic cost and risk results for the GHG emission performance stan- dard portfolio by CO2 cost adder case. Results are shown for both the CO2 tax and cap-and-trade compliance scenarios. Figures 7.37 through 7.39 show the cost-versus-risk trade-off of the port- folio in relation to the other Group 2 risk analysis portfolios assuming the CO2 cap-and-trade scenario. Figure 7.37 is a scatter plot of the cost and risk measures based on the average of the five CO2 adder cases, while Figures 7.38 and 7.39 show the cost and risk results for the $0 and $61 CO2 adder cases, respectively. 66 The remainder of the renewables investment schedule was not altered in order to minimize manual portfolio changes. 214 Pa c i f i C o r p 20 0 7 I R P Ch a p t e r 7 - Mo d e l i n g a n d P o r t f o l i o S e l e c t i o n R e s u l t s Ta b l e 7 . 50 - R e s o u r c e I n v e s t m e n t S c h e d u l e f o r t h e F i n a l G H G E m i s s i o n s P e r f o r m a n c e St a n d a r d P o r t f o l i o 'e e ' , e , ; e e " " , " " " " Na m e p H i t e C a r i a C i N , ; , ee e ' " ,e e e e ' ,." ';, ." " e , , " Re s o u r c e 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Ea s t CC C T , 2 x 1 F C l a s s 54 8 54 8 54 8 09 6 54 8 54 8 Re n e w a b l e s , S E I D 20 0 20 0 .e ' Re n e w a b l e s , W Y 10 0 70 0 20 0 10 0 20 0 :. . . . . i ; , .. . . . . e Re n e w a b l e s , N V 20 0 20 0 DS M , C l a s s 1 a n d 3 , ' Fr o n t o f f i c e t r a n s a c t i o n s 48 6 55 0 15 8 13 0 56 3 70 0 50 5 55 6 We s t CC C T , 2 x 1 F C l a s s 60 2 60 2 60 2 60 2 CC C T , I x l Cl a s s 39 2 Re n e w a b l e s , S E W A 20 0 Re n e w a b l e s , M T 40 0 Re n e w a b l e s , N C 10 0 30 0 DS M , C l a s s 1 a n d 3 Fr o n t o f f i c e t r a n s a c t i o n s 31 1 40 0 50 0 25 0 25 0 41 6 25 0 25 0 To t a l A n n u a l A d d i t i o n s 30 0 70 0 75 5 1, 4 0 9 81 8 74 0 82 3 04 8 31 6 16 7 77 8 77 0 - I e ;" - 54 8 60 2 60 2 54 8 Ta b l e 7 . 51 - St o c h a s t i c C o s t a n d R i s k R e s u l t s f o r t h e F i n a l G H G E m i s s i o n s P e r f o r m a n c e St a n d a r d P o r t f o l i o St o c b a s t i c R e s u l t s fM i l l i o n $ ) - CO 2 T a x Ba s i s ;. , e" , CO 2 C o s t Ad d e r C a s e St o c h a s t i c M e l ' t D 5t h 95 t b Up p e r ~ T a i i Ri s k St a n d a r d (2 0 0 8 $ ) PV R R Pe r c e n t i l e Pe r c e n t i l e ;' Me a n EX D O S p r e De v i a t i o n 23 0 63 7 38 7 70 , 85 8 62 8 04 6 95 0 24 4 54 7 25 3 30 3 15 2 $1 5 73 1 75 4 15 2 75 6 02 6 69 5 $3 8 95 6 17 2 80 2 42 0 60 , 46 5 06 3 $6 1 22 7 24 , 4 8 4 94 8 11 0 44 5 21 8 19 , 82 3 St o c h a s t i c R e s u l t s f M i l H o n $ , - " C ( ) 2 Ca p an d T r a d e B a s i s ' m , , CO 2 C o s t Ad d e r C a s e St o c h a s t i c M e a n 5t b 95 t h Up p e r . . T a i i Ris k St a n d a r d (2 0 0 8 $ ) PV R R Pe r c e n t i l e Pe r c e n t i l e Me a n Ex p o s u r e De v i ~ t i ( ) r i " 92 2 33 0 36 , 08 0 55 0 62 8 04 6 03 3 32 7 63 0 73 , 33 6 30 3 15 2 $1 5 01 4 03 7 43 5 03 9 02 6 69 5 $3 8 47 0 68 7 31 6 93 5 46 5 06 3 $6 1 57 7 83 4 29 8 79 5 69 , 21 8 82 3 21 5 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results gure 7.37 - Average Stochastic Cost versus Risk Exposure Across All CO2 Adder Cases Average Across All CO2 Adder Cases CO2 Cap and Trade Basis 57.s:: III ::!: n; =I- E II) ::-~c. 0 (;I')- 55.c. (/) s:: ;:) ::I . .. s:: = ~ ' e ~ 54. III s:: ~III ~ C. Q) :;::. .n ::!: Q. 53. .:.:: . III ,- (/)~ ~ 56. 52. 51. 21. GHG Perf.Std. III RA17 Rf15 RA14 RA16 RA13 21.22.4 22.23.22. Stochastic Mean PVRR (Billion $) Figure 7.38 - Stochastic Cost versus Risk Exposure for the $0 CO2 Adder Case ,--- iii ::; 48.III ::- ~ '70(;1')- (/) 5 47.c. ::I .-C. s:: == ? ' e!!!. 46.f! s:: ~ ;;: :g g; 45. ::!: Q. s:: 44.Wiii:g ..'II:: III "'"(/) .s:: 0::: 43.,- u~ 0 L__- $0 CO2 Adder Case CO2 Cap-and-Trade Basis 49. )K G G Perf, Std. !II! R 17 +RA15 RA14 .. RA16 ~. RA13 42. 21.21.22.22.23. Stochastic Mean PVRR (Billion $) 216 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.39 - Stochastic Cost versus Risk Exposure for the $61 CO2 Adder Case "iii ... III IIII-=-~~ 0 ~ en :5 c. ~ == ;:) ,- .- .. E ~f! t: It:::I III It:enlllo:E c..c. u)( .- t:W 1ii III Jo: III III en .t: :E.- uIt: 0 $61 CO2 Adder Case CO2 Cap and Trade Basis 70. 69. 68. 67. 66. 65. 64. 63. 62. 61. 60. 20. .GHG Perf, SIc, II!RA17 . RA15 RA16 .X RA14 )!( RA13 RA19 - 22.23.21.21.22. Stochastic Mean PVRR (Billion $) As can be seen from the figures, the stochastic cost ranking of the GHG emissions performance standard portfolio relative to the Group 2 risk analysis portfolios is sensitive to the CO2 cost ad- der level. Under the $O/ton CO2 adder case, the stochastic PVRR of the GHG emissions per- formance standard portfolio is $662 million higher than that of the preferred portfolio. In con- trast, under the $611ton CO2 adder case, the preferred portfolio stochastic PVRR is $406 million higher. When averaging stochastic PVRR results across the CO2 adder cases, the GHG emissions performance standard portfolio falls within the middle of the pack. The GHG emissions performance standard portfolio has the highest risk among the Group 2 port- folios for all CO2 adder scenarios. In comparison to the preferred portfolio, risk is about $3. billion higher under the $O/ton CO2 adder and $4.6 billion higher under the $611ton CO2 adder. Carbon Dioxide Emissions Results As expected, the GHG emissions performance standard portfolio has a smaller CO2 footprint than the other risk analysis portfolios due to the lack of new coal plants. Relative to the preferred portfolio, the GHG emissions performance standard portfolio emits about 49 million fewer tons of CO2 on a cumulative basis from 2007 through 2026 when averaged across the five CO2 adder cases. The annual CO2 emissions impact of the adder can be seen by comparing Figures 7.40 and 7.41 which show emissions under the $0 and $611ton CO2 adders, respectively. (Annual emission quantities are reported as the contribution from retail sales; that is, net of wholesale sales.) Fig- ure 7.42 shows annual CO2 emission trends as the average of the results for the six portfolios. 217 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.40 - Annual CO2 Emission Trends, 2007-2026 ($0 CO2 Adder Case) !::. "'- Period of New IRP Resources and FOTs Growth Stations Only - 000 000 55,000 000 000 40,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 -RA13 -RA15 -RA17 -GHG Pre!. Std. -RA16--RA14 Figure 7.41- Annual CO2 Emission Trends, 2007-2026 ($61 CO2 Adder Case) !::. "'.. Period o! New IRP Resources and FOTs Growth Stations Only""" 65,000 $61/Ton CO2 adder has a phase- period from 2010-2016 60,000 55,000 50,000 45,000 40,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 --RA13 --RA14 "'"*""'RA15 --RA16 -RA17 -GHG Pre!. Std. 218 PacifiCorp 2007 IRP Chapter 7 - Modeling and Portfolio Selection Results Figure 7.42 - Annual CO2 Emission Trends, 2007-2026 (Average for all CO2 Adder Cases) II) !::- c:- Period of New IRP Resources and FOTs Growth Stations Only""" 65,000 60,000 55,000 000 000 40,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 -RA13 --RA14 -RA15 --RA16 -RA17 -+-GHG Pref. Std. 219 PacifiCorp 2007 IRP Chapter 8 - Action Plan 8. ACTION PLAN Chapter Higl1llghts . The... coIl1paIly,#'mc()~tinu.etorunprogramslo acquire 250iaverage .lllegawattsofcost- . , effectiye..ellergY'e'fficiency,al1d ...anadditiol1a1200 average.l1J.egawatts .if.cost ~effectiy~ initiatives.cari beii(leritified~ . . .. " , ,.. . " . The comp any plal1s Il1ail1tain .aIld.build ,upon..tl1e.existing 150megawatts\ofirrigatibn . andairconditio:niIlglBadcohtrol ihUtah ,and . ~daho, al1dadd 100 .megawatts ()faddi-' tional ipigatio1J.~()acl. cgritrol .'. spli the tween system -Eastalldsystem -:- Wes thegin.riingil1 2010. . ,, . .. . ThecompanYPla#~toacquire 200tol 300megawatts of base loadresouree on the west side ofitssysteIIljl1~O 10 to 2014 through a mix of thermal resollrcesandpurchases. Thecompanyplaris to e2Cpand its transmission system to allow the resources identified in the preferied Portfoho to serVe custol11erloadsiriacost-effective and reliable manner The company Will incorporate the results of the demand-side management potential study into its business and into future integrated resource plans. Thecolllpany Will continue to take ,a leadership role in discussions on, global climate change and will continue to investigate carbon reduction technology ,including1J.uclearpower. . , 221 PacifiCorp 2007 IRP Chapter 8 - Action Plan INTRODUCTION This chapter presents the company s 2007 action plan, which identifies the steps the company will take during the next two years to implement this plan. It is based on the guidance provided by the company s analysis and results described in Chapters 1 through 7 of this document as well as feedback from stakeholders. In large part, the action plan is used to map out the steps required to acquire the resources identified in the preferred portfolio and to identify ways to improve the company s future integrated resource planning. To develop the action plan, the company used the preferred portfolio as shown in Table 8. (Portfolio RA14) along with issues raised by stakeholders during the course of the 2007 inte- grated resource planning process. Table 8.1- Resource Investment Schedule for Portfolio RA14 . ;., . .. .' .. . SlIDDlv and Demand-'sideProxvResources ". ',.,.'" NameDll1t~Ca.Daciv;MW. ' ..... . Resource .Tvve .,. 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 East Utah pulverized coal Supercritical 340 Wyoming pulverized coal Supercritical 527 Combined cycle CT 2xl F class with duct firing 548 Combined cycle CT I xl G class with duct firing 357 Combined Heat and Power Generic east-wide Renewable Wind, Wyoming 200 200 200 300 ...... Class I DSM*Load control, Sch. irrigation Front office transactions Heavy Load Hour, 3rd Otr 393 272 149 192 165 West CCCT 2x I F Type with duct firing 602 Combined Heat and Power Generic west-wide Renewable Wind, SE Washington 300 100 Renewable Wind, NC Oregon 100 100 100 Class I DSM*Load control, Sch. irrigation Front office transactions Flat annual product 219 555 657 247 246 249 AnnualAdditions, Long: T eITnR~sources . . ' 300 300,100 312 839 125 318 527 ..;, 357 ' . .' . .,, " . 336Annual Additions, Short Term Resources 612 652 660 396 438 414 300 100 924 . ., ,' . Total AnnuiilAdditicitis .300 175 1;777 978 923 438 771 * DSM is scaled up by 10% to account for avoided line losses. ** Front office transaction amounts reflect purchases made for the year, and are not additive. ,. . . TransmlssionProxvResources ," . i ;.. frallsfe~CaDabilitv.M--;l!awatts Resource , ,.. . 2007 200S 2009 2010 2011 2012 2013 2014 2015 2016 East Path C Upgrade: Borah to Path-C South to Utah North 300 Utah - Desert Southwest (Includes Mona - Oquirrh)600 Mona - Utah North 400 Craig-Hayden to Park City 176 Miners - Jim Bridger - Terminal 600 Jim Bridger - Terminal 500 West Walla Walla - Yakima 400 West Main - Walla Walla 630 . ,. . Total Annual Additions , ' . ", , "". ... 700 630 776 500 * Transmission resource proxies represent a range of possible procurement strategies, including new wheeling con- tracts or construction of transmission facilities by PacifiCorp or as a joint project with other parties. 222 PacifiCorp 2007 IRP Chapter 8 - Action Plan .. ,.., wee, , ".... 'I'HKINTEGRATED ,RESOURCE PLAN ACTION PLAN The IRP action plan, detailed in Table 8.2, provides the company with a road map for moving forward with new resource acquisitions over the next two years. The IRP action plan is based upon the latest and most accurate information available at the time the integrated resource plan is filed. The resources identified in the plan are proxy resources and act as a guide to resource pro- curement. As resources are acquired, the resource type, timing, size, and location may vary from the proxy resource identified in the plan. Evaluations will be conducted at the time of acquiring any resource to justify such acquisition. 223 Pa c i f i C o r p 20 0 7 I R P Ta b l e 8 . 2 - 2 0 0 7 I R P A c t i o n P l a n Re n e w a b l e s Ne w Re n e w a b l e s 20 0 7 - 2 0 1 3 DS M Ex i s t i n g a n d Ne w C l a s s 2 pr o g r a m s 20 0 7 - 2 0 1 4 DS M Ne w C l a s s pr o g r a m s 20 0 7 - 2 0 1 4 Ch a p t e r 8 - Ac t i o n P l a n Si z e (r b u n d e d t p th ~ n e a : r e s f 50 M W f o t ge n e r a t i o n re s o u r c e s 00 0 Sy s t e m 45 0 M W a Sy s t e m 10 0 Ea s t - 5 0 We s t - Wi n d 10 0 M W d e c r e m e n t s a t va r i o u s l o a d s h a p e s Ea s t a n d W e s t i r r i g a t i o n lo a d c o n t r o l , E a s t s u m m e r lo a d s Ac q u i r e 2 00 0 M W o f r e n e w a b i e s b y 20 1 3 , i n c l u d i n g t h e 1 40 0 M W o u t l i n e d in t h e R e n e w a b l e P l a n , S e e k t o a d d tr a n s m i s s i o n i n f r a s t r u c t u r e a n d f l e x i b l e ge n e r a t i n g r e s o u r c e s , s u c h a s n a t u r a l , t o i n t e g r a t e n e w w i n d r e s o u r c e s . Us e d e c r e m e n t v a l u e s t o a s s e s s c o s t - ef f e c t i v e n e s s o f n e w p r o g r a m pr o p o s a l s , A c q u i r e t h e b a s e D S M (P a c i f i C o r p a n d E T a c o m b i n e d ) o f 2 5 0 MW a a n d u p t o a n a d d i t i o n a l 2 0 0 M W a if c o s t - e f f e c t i v e i n i t i a t i v e s c a n b e id e n t i f i e d . W i l l r e a s s e s s C l a s s 2 ob j e c t i v e s u p o n c o m p l e t i o n o f s y s t e m - wi d e D S M p o t e n t i a l s t u d y t o b e co m p l e t e d b y J u n e 2 0 0 7 . W i l l in c o r p o r a t e p o t e n t i a l s s t u d y f i n d i n g s in t o t h e 2 0 0 7 u p d a t e a n d 2 0 0 8 in t e g r a t e d r e s o u r c e p l a n n i n g p r o c e s s e s . Ta r g e t s w e r e e s t a b l i s h e d t h r o u g h po t e n t i a l s t u d y w o r k p e r f o r m e d f o r t h e 20 0 7 I R P . A n e w p o t e n t i a l s t u d y i s ex p e c t e d t o b e c o m p l e t e d b y J u n e 2 0 0 7 an d a s s o c i a t e d f i n d i n g s w i l l b e in c o r p o r a t e d i n t o t h e 2 0 0 7 u p d a t e a n d th e 2 0 0 8 i n t e g r a t e d r e s o u r c e p l a n n i n g ro c e s s e s . 22 4 Pa c i f i C o r p 20 0 7 I R P Ch a p t e r 8 - Ac t i o n P l a n Si z e (r o u n d e d t o th e n e a r e s t Ca l e n d a r - 50 M W f o r Ac t i o n Ye a r ge n e r a t i o n IR P P r o x y R e s o u r c e It e m Ca t e o r Ac t i o n Ti m i n re s o u r c e s Lo c a t i o n Mo d e l e d Ac t i o n Al t h o u g h n o t c u r r e n t l y i n t h e b a s e Cl a s s 3 : d e m a n d b u y - ba c k re s o u r c e s t a c k , t h e c o m p a n y w i l l s e e k to l e v e r a g e C l a s s 3 a n d 4 r e s o u r c e s t o Ex i s t i n g a n d To b e ho u r l y p r i c i n g , s e a s o n a l im p r o v e s y s t e m r e l i a b i l i t y d u r i n g p e a k DS M Ne w C l a s s 3 20 0 7 - 2 0 1 4 de t e r m i n e d Sy s t e m pr i c i n g , e t c . lo a d h o u r s . W i l l i n c o r p o r a t e p o t e n t i a l pr o g r a m s Cl a s s 4 : s y s t e m m e s s a g i n g st u d y f i n d i n g s i n t o t h e 2 0 0 7 u p d a t e an d e d u c a t i o n an d / o r 2 0 0 8 i n t e g r a t e d r e s o u r c e la n n i n ro c e s s e s . Pu r s u e a t l e a s t 7 5 M W o f C H P ge n e r a t i o n f o r t h e w e s t - s i d e a n d 2 5 MW f o r t h e e a s t - s i d e , t o i n c l u d e Co m b i n e d 25 M W s t e a m t o p p i n g c y c l e pu r c h a s e o f C H P o u t p u t p u r s u a n t t o Di s t r i b u t e d He a t a n d 20 0 7 - 20 1 4 10 0 Sy s t e m CH P ; 5 M W g a s PU R P A r e g u l a t i o n s a n d f r o m s u p p l y - Ge n e r a t i o n Po w e r ( C H P ) co m b u s t i o n t u r b i n e C H P si d e R F P o u t c o m e s . T h e p o t e n t i a l s t u d y re s u l t s w i l l b e i n c o r p o r a t e d i n t o t h e 20 0 7 u p d a t e a n d 2 0 0 8 i n t e g r a t e d re s o u r c e la n n i n ro c e s s e s To b e 60 M W o f d i e s e l e n g i n e Wi l l i n c o r p o r a t e p o t e n t i a l s t u d y Di s t r i b u t e d St a n d b y 20 0 7 - 20 1 4 Sy s t e m fi n d i n g s i n t o t h e 2 0 0 7 u p d a t e a n d 2 0 0 8 Ge n e r a t i o n Ge n e r a t o r s de t e r m i n e d ca p a c i t y o n t h e w e s t s i d e in t e g r a t e d r e s o u r c e p l a n n i n g p r o c e s s e s Pr o c u r e a b a s e l o a d / i n t e r m e d i a t e l o a d Ba s e L o a d / CC C T ( W e t " F" 2 X l ) w i t h re s o u r c e i n t h e e a s t b y t h e s u m m e r o f Su p p l y - Si d e In t e r m e d i a t e 20 1 2 55 0 Ea s t du c t f i r i n g 20 1 2 . T h i s i s p a r t o f t h e r e q u i r e m e n t Lo a d in c l u d e d i n t h e B a s e L o a d R F P Pr o c u r e a b a s e l o a d / i n t e r m e d i a t e l o a d Ba s e L o a d / Su p e r c r i t i c a l p u l v e r i z e d c o a l re s o u r c e i n t h e e a s t b y t h e s u m m e r o f Su p p l y - Si d e In t e r m e d i a t e 20 1 2 35 0 Ea s t (3 4 0 M W U t a h u n i t ) 20 1 2 . T h i s i s p a r t o f t h e r e q u i r e m e n t Lo a d in c l u d e d i n t h e B a s e L o a d R F P Pr o c u r e a b a s e l o a d / i n t e r m e d i a t e l o a d Ba s e L o a d / Su p e r c r i t i c a l p u l v e r i z e d c o a l re s o u r c e i n t h e e a s t b y t h e s u m m e r o f Su p p l y - Si d e In t e r m e d i a t e 20 1 4 55 0 Ea s t (5 2 7 M W W y o m i n g u n i t ) 20 1 4 . T h i s i s p a r t o f t h e r e q u i r e m e n t Lo a d in c l u d e d i n t h e B a s e L o a d R F P 22 5 Pa c i f i C o r p 20 0 7 I R P Ch a p t e r 8 - Ac t i o n P l a n Ac t i o n it t m A~ t i o i l . In v e s t i g a t e a b a s e l o a d / i n t e r m e d i a t e Ba s e L o a d / CC C T ( W e t " G" I X 1 ) w i t h lo a d r e s o u r c e i n t h e e a s t b y t h e s u m m e r Su p p l y - Si d e In t e r m e d i a t e 20 1 6 35 0 Ea s t du c t f i r i n g of 2 0 1 6 , T h i s i s n o t p a r t o f t h e Lo a d re q u i r e m e n t i n c l u d e d i n t h e B a s e L o a d RF P Ba s e L o a d / CC C T ( W e t " F" 2 X l ) w i t h Pr o c u r e a b a s e l o a d / i n t e r m e d i a t e l o a d Su p p l y - Si d e In t e r m e d i a t e 20 1 1 60 0 We s t re s o u r c e i n t h e w e s t b y t h e s u m m e r o f Lo a d du c t f i r i n g 20 1 1 - 2 0 1 2 Ba s e L o a d / Fr o n t o f f i c e t r a n s a c t i o n s : Pr o c u r e b a s e l o a d / i n t e r m e d i a t e l o a d Ea s t / We s t - f l a t a n n u a l p r o d u c t s re s o u r c e b e g i n n i n g i n t h e s u m m e r o f Su p p l y - Si d e In t e r m e d i a t e 20 1 0 - 20 1 4 35 0 - 65 0 We s t Ea s t - 3 r d q u a r t e r p r o d u c t s 20 1 0 , u s e t h e B a s e L o a d R F P a s Lo a d ro r i a t e t o f i l l t h e n e e d i n t h e e a s t Pa t h C U p g r a d e Pu r s u e t h e a d d i t i o n o f t r a n s m i s s i o n Ut a h - D e s e r t S o u t h w e s t fa c i l i t i e s o r w h e e l i n g c o n t r a c t s a s Mo n a - t J t a h N o r t h id e n t i f i e d i n t h e I R P t o c o s t - e f f e c t i v e l y Tr a n s m i s s I O n Tr a n s m i s s I O n 20 1 0 a n d Va r i o u s Sy s t e m Cr a i g H a y d e n - U t a h N o r t h me e t r e t a i l l o a d r e q u i r e m e n t s , i n t e g r a t e be y o n d Mi n e r s - U t a h N o r t h wi n d a n d p r o v i d e s y s t e m r e l i a b i l i t y . Ji m B r i d g e r - U t a h N o r t h Wo r k w i t h o t h e r t r a n s m i s s i o n p r o v i d e r s Wa l l a W a l l a - Y a k i m a to f a c i l i t a t e j o i n t p r o j e c t s w h e r e Wa l l a W a l l a - W e s t M a i n ro r i a t e St r a t e g y a n d No t Co n t i n u e t o h a v e d i a l o g u e w i t h Cl i m a t e C h a n g e Po l i c y On g o i n g ap p l i c a b l e Sy s t e m No t a p p l i c a b l e st a k e h o l d e r s o n G l o b a l C l i m a t e C h a n g e is s u e s Ev a l u a t e t e c h n o l o g i e s t h a t c a n r e d u c e Ca r b o n - th e c a r b o n d i o x i d e e m i s s i o n s o f t h e Re d u c i n g St r a t e g y a n d On g o i n g No t Sy s t e m No t a p p l i c a b l e co m p a n y s r e s o u r c e p o r t f o l i o i n a c o s t - Po l i c y ap p l i c a b l e ef f e c t i v e m a n n e r , i n c l u d i n g b u t n o t Te c h n o l o g y li m i t e d t o , c l e a n c o a l , s e q u e s t r a t i o n an d n u c l e a r ow e r 22 6 Pa c i f i C o r p 20 0 7 I R P Ac t i o n It e m Ca f e 0 Ac t i o n IR P P l a n n i n g Mo d e l i n g a n d 20 0 7 - 20 0 8 An a l y s i s IR P P l a n n i n g IR P Ac k n o w l e d g e m e Mo d e l i n g a n d An a l y s i s Po l i c y a n d c o s t re c o v e r y 20 0 7 - 20 0 8 20 0 7 Si z e (r o u n d e d t o th e n e a r e s t 50 M W f o r ge n e r a t i o n re s o u r c e s No t ap p l i c a b l e No t ap p l i c a b l e No t ap p l i c a b l e Lo c a t i o n Sy s t e m Sy s t e m Sy s t e m Ch a p t e r 8 - Ac t i o n P l a n No t a p p l i c a b l e Ac t i o n Co n t i n u e t o i n v e s t i g a t e i m p l i c a t i o n s o f in t e g r a t i n g a t l e a s t 2 00 0 M W o f w i n d to P a c i f i C o r p s s y s t e m No t a p p l i c a b l e Up d a t e m o d e l i n g t o o l s a n d a s s u m p t i o n s to r e f l e c t p o l i c y c h a n g e s i n t h e a r e a o f 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 s a n d ca r b o n d i o x i d e e m i s s i o n s Wo r k w i t h s t a t e s t o g a i n ac k n o w l e d g e m e n t o r a c c e p t a n c e o f t h e 20 0 7 i n t e g r a t e d r e s o u r c e p l a n a n d ac t i o n p l a n . T o t h e e x t e n t s t a t e p o l i c i e s re s u l t i n d i f f e r e n t a c k n o w l e d g e d p l a n s wo r k w i t h s t a t e s t o a c h i e v e s t a t e p o l i c y go a l s i n a m a n n e r t h a t r e s u l t s i n f u l l co s t r e c o v e r y o f p r u d e n t l y i n c u r r e d co s t s No t a p p l i c a b l e 22 7 PacifiCorp 2007 IRP Chapter 8 - Action Plan RESOURCEUPROCUREMENT Overall Resource Procurement Strate2V To implement resource decisions in the action plan, PacifiCorp intends to use a formal and trans- parent procurement program in accordance with the then-current law, rules, and/or guidelines in each of the states in which PacifiCorp operates. The IRP has determined the need for resources with considerable specificity and identified the desirable portfolio resource characteristics and timing of need. The IRP has not identified specific resources to procure, or even determined a preference between asset ownership versus contracted resources. These decisions will be made subsequently on a case-by-case basis with an evaluation of competing resource options including updated available information on technological, environmental and other external factors such as electric and natural gas price projections. These options will be fully developed using competi- tive bidding with a request for proposal (RFP) process, or other procurement methods as appro- priate. For demand-side resources, 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 project manages the program and contracts out specific tasks (such as the Energy FinAnswer program). A third method is to operate the program completely in-house as was done with the Idaho Irriga- tion Load Control program. The business process used for any given program is based on opera- tional expertise , performance risk and cost-effectiveness. As with supply-side resources, the company may resort to competitive bidding with an RFP process to uncover new program oppor- tunities. Renewable Resources The 2007 integrated resource plan identifies 2 000 megawatts of renewable resources to be ac- quired by 2013. Under this plan, the company seeks to acquire 1 400 megawatts of new renew- able resources by 2010, with an additional 600 megawatts in place by 2013. The 2 000 mega- watts of renewable resources is inclusive of the 1 400 megawatts of cost-effective renewable resources identified in the company s renewable plan. In order to fill this requirement, the com- pany will continue to aggressively pursue the acquisition of these resources through various ap- proaches including new requests for proposals, bi-Iateral negotiations, the Public Utilities Regu- latory Policy Act, and self-development. While the company used wind for modeling purposes in the integrated resource planning process, renewable generation includes other fuel sources such as biomass and landfill gas. In addition, the company will actively seek to add transmission in- frastructure and flexible generating resources, such as natural gas , to integrate new wind re- sources and work to continuously improve its understanding of how to integrate large amounts of wind into its portfolio in a reliable and cost-effective manner. Demand-side Mana2ement The company has a variety of ongoing programs and associations to procure energy efficiency measures (Class 2 demand-side resources) from industrial, commercial and residential custom- ers. These programs will be leveraged, and company-offered programs extended to other states 229 PacifiCorp 2007 IRP Chapter 8 - Action Plan as the means to acquire the majority of the 250 average megawatts of Class 2 demand-side re- sources identified in the 2007 integrated resource plan. The company will continue these pro- grams as long as they are cost-effective, and will seek to add new cost-effective programs in or- der to meet this target. The company will also continue to pursue an additional 200 average megawatts of energy efficiency measures if cost-effective. With regard to load control (Class 1 demand-side resources), the company is actively working to retain the existing customers and continue expanding participation in these programs to achieve and build upon the 150 megawatts currently identified in the 2007 plan as an existing resource. The company will pursue acquisition of an additional 1 00 megawatts of load control identified in the preferred portfolio starting in 2010, The company plans to leverage voluntary load control programs (Class 3 demand-side resources) such as demand buyback, hourly pricing and seasonal pricing, as well as system messaging and education (Class 4 demand-side resources), to improve system reliability during peak load hours. Finally, the company will be completing a demand-side management potential study in June 2007, which will provide updated information on the potential for acquiring cost-effective de- mand-side resources across all major resource types (load management, energy efficiency, de- mand response and system messaging and education). Information learned from the demand-side management potential study will be incorporated in the company s demand-side management programs and in future integrated resource plans. Combined Heat and Power The 2007 integrated resource plan includes 100 megawatts of new combined heat and power in 2012. Combined heat and power facilities are allowed to bid into the company s current east side base load request for proposal, and can become part of the company s resource portfolio as quali- fying facilities under the Public Utilities Regulatory Policy Act. Additional information on the potential for combined heat and power will be available from the demand-side management po- tential study and will be incorporated into the company s future integrated resource plans. Distributed Generation The company investigated the potential of adding distributed generation on the east side of its system and was informed by the Utah Department of Air Quality that it was not feasible to rely on existing standby generators at customer sites due to air quality considerations. On the west side of the system, the company found using sensitivity analysis that replacing a new resource with combined heat and power and aggregated dispatchable customer-owned standby generators marginally increased cost and risk. The company will have additional information on distributed generation potential as part of the demand-side management potential study. Based on this in- formation, the company will determine what further steps to take with regard to distributed gen- eration. Thermal Base Load/Intermediate Load Resources The company has an outstanding request for proposals that is aimed at acquiring up to 1 700 megawatts of cost-effective base load resource by 2014 on the east side of its system. The 2007 integrated resource plan identifies 1 450 megawatts of base load / intermediate load thermal re- 230 PacifiCorp 2007 IRP Chapter 8 - Action Plan sources needed on the east side of the system during this time frame based on a 12 percent plan- ning reserve margin. Another 357 megawatts of base load / intermediate resource are identified in 2016. The 2007 integrated resource plan fully supports the outstanding Base Load Request for Proposal. The 2007 integrated resource plan identified the need for 677 megawatts of base load / interme- diate load thermal resources for the west side. The thermal resources consist of a 602 megawatt combined cycle natural gas plant in 2011 and 75 megawatts of combined heat and power in 2012. These proxy resources identified in the integrated resource plan will be used to guide the procurement of resources for the west side of the system such that the company can meet its deficit in the 2011-to-2012 time frame in a manner that is cost-effective, adjusted for risk. The actual mix and quantity of resources procured by the company to satisfy this need in the west may differ from the proxy resources identified in the integrated resource plan. Consistent with state guidelines for resource procurement, the company will perform updated analyses at the time new resources are acquired. Front Office Transactions The 2007 integrated resource plan identified the annual need for 50 to 650 megawatts of front office transactions on the west side of its system for 2010 to 2014. The front office transactions are modeled as flat annual purchases67 and serve as a proxy for base load / intermediate load re- sources. Acquisition of front office transactions in the west will be considered in the context of the overall base load / intennediate load resource need in the west. On the east side, the integrated resource plan identified the annual need for up to 400 megawatts of front office transactions for the 201O-to-2014 period. The need may be addressed using the Base Load Request for Proposals. Beyond this time frame, the annual need drops to no more than 200 megawatts. Transmission Expansion The 2007 integrated resource plan has identified a need for additional transmission as part of the preferred portfolio. In general, transmission additions reflect the need to meet retail load re- quirements, integrate wind and provide system reliability. Specific enhancements are required to integrate both the Wyoming and southern Utah areas with the Wasatch front, create additional integration with markets in the desert southwest, and integrate new resources and front office transactions with loads on the west side of the company s system. The transmission additions identified in the preferred portfolio are proxy transmission additions. They are included as options that can be selected by the company s integrated resource planning models on a comparable basis with supply-side and demand-side resources. The proxy transmis- sion additions included in the preferred portfolio serve as a guide to the company s transmission planners and may ultimately result in construction of new facilities by the company, partnering in regional transmission projects with others, or the execution of third party wheeling contracts, The timing and size of new transmission facilities may vary from the proxy transmission addi- 67 Market purchases are assumed to be delivered at market hubs, primarily Mid-Columbia, and not at the load. For front office transactions to reach load, additional transmission is required. 231 PacifiCorp 2007 IRP Chapter 8 - Action Plan tions included in the preferred portfolio due to specific siting, permitting and construction issues associated with a given project. ;OTHER ISSUES Global Climate Chan2e As discussed elsewhere in this IRP, one of the most challenging resource planning issues facing the company is how to address risk associated with the regulation of greenhouse gas emissions. As new climate policies and laws are adopted by state legislatures, utility commissions or the federal government to limit the utilization of higher carbon-emitting resources, PacifiCorp will adjust its capacity expansion model to account for those new policies. To address this challenge, PacifiCorp has formed a Global Climate Change Working Group to analyze and discuss utility best practices in managing emissions of greenhouse gases and identify cost-effective opportunities to reduce greenhouse gas emissions within the respective states regulatory framework. The company expects to have filed, with all six commissions, a prelimi- nary Global Climate Change Action Plan by the fourth quarter 2007. PacifiCorp employees will continue to have dialogue with stakeholders on this issue, explaining the various efforts already underway, and with stakeholder partners offering guidance and feed- back on how the company might improve upon the efforts identified within the Global Climate Change Action Plan, Separately, PacifiCorp is engaged in several partnerships, such as the Big Sky Carbon Sequestra- tion Partnership and the Electric Power Research Institute, to explore energy, climate change economic growth and carbon sequestration opportunities. The company also continues to partici- pate in groups organized at state government levels that are designed to develop global climate change policy such as Oregon Docket UM 1302 that is investigating the treatment of carbon di- oxide risk in integrated resource planning. Carbon Reducin2 Technolo2ies Since the second quarter of 2006, the company has sponsored a workgroup to specifically inves- tigate integrated gasification combined cycle technology and carbon dioxide sequestration. As the company moves forward, it will expand its view to all feasible technologies that can poten- tially reduce carbon dioxide emissions in a cost-effective manner, including nuclear power. For example, the Wyoming Infrastructure Authority and PacifiCorp are pursuing joint project devel- opment activities for an IGCC facility in Wyoming. Modelin2 Improvements While the 2007 integrated resource plan addresses renewable portfolio standards and carbon risk it is becoming increasingly important to refine the modeling capabilities in this area. The com- pany will pursue enhancements to the integrated resource planning models to potentially incor- porate more sophisticated methods to address new resource portfolio standards and carbon regu- lations. 232 PacifiCorp 2007 IRP Chapter 8 - Action Plan Cost Assi2nment and Recoverv The preferred portfolio is based on the premise of a single integrated system with rolled-in costs for new resources as prescribed under the Revised Protocol allocation methodology. Acknowl- edgement or acceptance of a single plan is a prerequisite for use of the Revised Protocol when the company is acquiring new resources. To the extent states acknowledge or accept different plans, the company will work with the states to find ways to deliver different plans to different states, while maintaining the highest possible level of system integration benefits and assuring full cost recovery of prudently incurred costs required to serve retail customers. ASSESSMENT OF OWNING..ASSETSYERSUSPURCHASING.POWER As the company acquires new resources, it will need to determine whether it is better to own a resource or purchase power from another party. While the ultimate decision will be made at the time resources are acquired, and will primarily be based on 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 ex- tension improvements, use the site for additional resources in the future, change fueling strate- gies or sources, efficiently address plant modifications that may be required as a result of changes in environmental or other laws and regulations, and utilize the plant at cost as long as the it remains economic. In addition, by owning a plant, the company can hedge itself from the uncertainty of relying on purchasing power from others. On the negative side, owning a facility subjects the company and customers to the risk that the cost of ownership and operation exceeds expectations, the cost of poor performance or early termination, fuel price risk, and the liability of reclamation at the end of the facilities life. Purchasing power from another party can help mitigate the risk of cost overruns during construc- tion and operation of the plant, can provide certainty of cost and performance, and can avoid any liabilities associated with closure of the plant. Short-term purchased power contracts could allow the company to forgo a long term decision for a period of time if it was deemed appropriate to do so. On the negative side, a purchase power contract could terminate prior to the end of the term requiring the company to replace the output of the contract at then current market prices. In addi- tion, 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. RESOURCE ACQUISITION PLANP ATH ANALYSIS The Utah Public Service Commission s IRP standards and guidelines require that PacifiCorp IRP contain a "plan of different resource acquisition paths for different economic circumstances with a decision mechanism to select among and modify these paths as the future unfolds. PacifiCorp s resource acquisition path analysis plan for this IRP consists of the use of the IRP models for the Base Load Request For Proposals issued on April 5, 2007. The modeling plan entails evaluating bid resources on a portfolio basis similar to how portfolios were evaluated in the 2007 IRP. The timing of the RFP, with a consequent refreshing of analysis inputs and inclu- 233 PacifiCorp 2007 IRP Chapter 8 - Action Plan sion of PacifiCorp s benchmark resources, represents a logical and efficient strategy to address this requirement. To formulate and analyze different resource acquisition paths, the RFP modeling process in- cludes two deterministic scenario analysis steps in which bid resources, including PacifiCorp benchmark resources, are evaluated with the Capacity Expansion Module under a range of sce- nario assumptions, The scenarios capture a combination of alternative electricity/gas prices, CO2 cost adders, and planning reserve margins. The first scenario analysis step involves running the CEM with the full set of short-listed bid resources to assist in screening the resources. The second scenario analysis step occurs after sto- chastic simulation has been used to select bid resource finalists. The portfolio of bid resource finalists is subjected to another round of CEM runs using the same scenario set applied to ini- tially screen the bid resources. In contrast to the first scenario analysis step, the bid resources are fixed, and CEM use is limited to just determining the dispatch solution and PVRR under differ- ent economic conditions. This path analysis step is intended to help assure the company that the bid resource finalists are robust with respect to cost and cost variability under alternative eco- nomic and planning assumptions. 234