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Home My WebLink About200906012009 IRP.pdf~~~OUNTAIN n r.i:~~' '~_ i.: ''I ...., ;:'",." May 29, 2009 "ílf\r¡\~AV?Q M'l 9: 39Lutr, l~h., ¡ ~-.,' 201 South Main, Suite 2300 Salt Lake City, Utah 84111 VI OVERNIGHT DELIVERY Idaho Public Utilties Commission 472 West Washigton Boise, ID 83702 PAC-E-09..06 Att: Jean Jewell Commission Secreta Re: PacifiCorp's 2008 Integrated Resource Plan ("2009 IRP") -- Dear Ms. Jewell: Please find enclosed the original and seven (7) copies, along with a compact disk, of PacifiCorp's 2008 Integrated Resource Plan ("2009 IRP")l. Copies of the 2009 IRP are also available electronically on PacifiCorp's website, at ww.pacificorp.com. PacifiCorp submits the 2009 IR filing in compliance with Order No. 22299, Case No. U-1500- 165, dated Janua 1989; whereby the Idaho Public Utilties Commssion (the "Commssion") ordered biennal filings of the electric integrated resoure plan. PacifiCorp submits the 2009 IR to the Commission as the Resource Management Report on the Company's resource plannng statu. Appendix C (pages 223 to 252) to the 2008 IRP, contains tables that outline how PacifiCorp has addressed the Commission's integrated resource planng requiements (see Tables C.1 and C.2 in "Appendix C - IR Reguatory Compliance"). The 2009 IR fuly complies with the resource planng requiements in the Commssion's rues, and the Company respectfully requests tht the Commission acknowledge the 2009 IR in accordance with those rules and fuly support the 2009 IR conclusions, including the proposed action plan. PacifiCorp's submission of the 2009 IR is also in compliance with Order No. 30766, Case No. PAC-E-09-02, dated April 8, 2009, whereby the Commission approved an extension of time for the Company to fie its 2009 IR no later than May 29,2009. It is respectfully requested that all formal correspondence and Sta requests regarding ths filing be provided to the Company in a Microsoft Word document, addressed to the following: 1 Please note that although ths IR is being submitted in calendar year 2009, the document is entitled and is referred to as the "2008 Integrated Resource Plan". Nevereless, ths submission fufills the requiement for the Company to file the 2009 IR in calendar year 2009, as specified in Order No. 30766, Case No. PAC-E-09-02, dated April 8, 2009. . Idaho Public Utilties Commssion May 29, 2009 Page 2 Bye-mail (preferred):/dataeguest(ßpacificorp.com By regular mail:Data Request Response Center PacifiCorp 825 NE Multnomah Suite 2000 Portland, OR 97232 Please direct any inormal inquiries to Pete Waren, Manger Integrated Resource Planng at (503) 813-5518 or Ted Weston, Idaho Reguatory Affairs Manager, at (801) 220-2963. PacifiCorp appreciates the time and effort Idao parcipants have dedicated to helping the Company develop its 2009 IRP. Sincerely,(f~Jeffey K. Laren ~ Vice President, Reguation cc: Terr Carlock, Idaho Public Utilties Commssion (w/out enclosures) Rick Sterling, Idaho Public Utilties Commssion (w/out enclosures) Dave Schune, Idao Public Utilities Commission (w/out enclosures) Rady Lobb, Idao Public Utilties Commssion (w/out enclosures) Jim Yost, State ofIdaho - Governor's Offce (w/out enclosures) Mark Stokes, Idao Power Company (w/out enclosures) Nancy Kelly, Western Resource Advocates (w/out enclosures) Randall Budge, Raine, Olson, Nye, Budge & Bailey (w/out enclosures) ~;¿ ~xiïìt1Æ ¥ 4; . PACIFICORP A MIDAMERICAN ENERGY HOLDINGS COMPANY May 28,2009 Pacific Power I Rocky Mountain Power I PacifiCorp Energy enM ............................................ W ettC" "1 tl,' I",",I¡i,*,,, This 2008 Integrated Resource Plan (IRP) Report is based upon the best available information at the time of preparation. The IRP action plan wil be implemented as described herein, but is sub- ject to change as new information becomes available or as circumstances change. It is Pacifi- Corp's intention to revisit and refresh the IRP action plan no less frequently than annually. Any refreshed IRP action plan wil be submitted to the State Commissions for their information. F or more information, contact: PacifiCorp IRP Resource Planning 825 N .E. Multnomah, Suite 600 Portland, Oregon 97232 (503) 813-5245 IRP(iPacifiCorp.com http://www.PacifiCorp.com This report is printed on recycled paper Cover Photos (Left to Right): Wind: Foot Creek 1 Hydroelectric Generation: Yale Reservoir (Washington) Demand side management: Agricultural Irrigation Thermal-Gas: Currant Creek Power Plant Transmission: South Central Wyoming line ............................................ PacifiCorp - 2008 IRP Table of Contents Table of Contents................. ............................... .............. ...... ........ ........................................... ..... ..... ... i Index of Tables.. ........ ............... ....... ............... ......................... ...................................... ............ ........... vii Index of Figues......................................................... ............................................................................xi 2008 IRP Volume 2 - Listing of Appendices .....................................................................................xiii I.. Executive Summary .............................................................................................................................. i The Integrted Resource Planning Environment..................... ................ ................................... ....... ..... 1 Resource Needs and Portfolio Modeling................................................................................................4 The 2008 IRP Preferred Portfolio...........................................................................................................6 The 2008 IRP Action Plan............... ...... ......... ..... ... .... ........................................ ............. ............ ......... 11 2. Introduction.........................................................................................................................................17 2008 Integrted Resource Plan Components.............. ....... ............................................ ............. .......... 18 The Role ofPacifiCorp's Integrated Resource Planing......................................................................19 Alignent ofPacifiCorp's IRP and Business Planing Processes....................................................... 19 Alignment Strategy Overview... .................. ............... ............................ ............... .................. ........ 19 Planning Process Alignment Challenges.. ................ .......... ................. .................... ........................20 Alignment Strategy Progress.............. .................... ........... .............. ....................................... .........21 Public Process.......................................................................................................................................22 MidAmerican Energy Holdings Company IRP Commitments.. ..... ...... ..... ......... ........................... ......23 3. The Planning Environment ................................................................................................................ 2S Introduction............. ....... ................. ................ .......... .......................... ................ ........... ...... ... ....... ......25 Impact of the 2012 Combined-Cycle Gas Plant Project Termination .................................................. 26 Wholesale Electricity Markets ............................................................................................................. 26 Natual Gas Uncertinty ..................................................................................................................27 Greenhouse Gas Policy Uncertinty ... ........ ............ ............... ............... ...................... ....... ..... ..... ....30 Curently Regulated Emissions ....... ............. .......... ... ....... ................... ............................. ............ ........ 34 Ozone...............................................................................................................................................34 Particulate Matter ...........................................,................................................................................ 35 Regional Haze .................................................................................................................................36 Mercur ...........................................................................................................................................36 Climate Change.......... .... ... ........................ ....................................................... .., ............... ..... ............. 37 Impacts and Sources ........................................................................................................................38 International and Federal Policies ...................................................................................................38 U.S. Environmental Protection Agency's Advance Notice of Public Rulemakng.........................39 Regional State Initiatives....... ......... .... ........... ........................... ........ ..................... ... ......... ... ...........41 Midwestern Regional Greenhouse Gas Accord..........................................................................41 Regional Greenhouse Gas Initiative.. .... ....... ..... ......... ... ................. ...................... ....... ..... ... .......41 Western Climate Initiative .... ............... ........ .................................... ............ ........................ .......41 Individual State Initiatives. ..... .......... ........ ... ............. ............ ............................ ....... ............... ..... ....42 State Economy-wide Greenhouse Gas Emission Reduction Goals ............................................42 State Greenhouse Gas Emission Performance Stadards ........... .................. .............. ............. ...42 Oter Recent State Accomplishments............... ....... ... ................... ............................................42 Corporate Greenhouse Gas Mitigation Strategy ......... .......... ............ ........... ........ ............ .... ....... 44 EPRI analysis of CO2 Prices and Their Potential Impact On the Western U.S. Power Market ...........45 Energy Independence and Securty Act of 2007 ...... ....... .... ........... ..... ................... ...... ...... ..... .............48 Renewable Portfolio Stadards ........ .................. ................ .... .......................... .., ............ ................. ....49 California................... ........ ... ..... ............... ... ..... ............ ..... .... ........ .... ....... ........ ..... ... ....... ..... ..... ...... 50 PacifiCorp - 200BIRP Table of Contents Oregon.............................................................................................................................................51 Uta ................................................................................................................................................. 51 Washington.... ... ............. '" .......... ... .... ....... ..... .......... ......... .... .......... ................... .................. ............ 51 Federal Renewable Portfolio Stadad ............................................................................................52 Renewable Energy Certificates .......................................................................................................52 Hydroelectrc Relicensing .................................................................................................................... 52 Potential Impact...............................................................................................................................53 Treatment in the IRP .... ........................... ...................... ................................... ............................... 54 PacifiCorp's Approach to Hydroelectric Relicensing ..................................................................... 54 Recent Resource Procurement Activities. ... ....................... ........ ....... .................................. ..... ... ......... 54 2012 Request for Proposals for Base Load Resources .................................................................... 54 2008 All-Source Request for Proposals...........................................................................................54 Renewable Request for Proposal (RP 2008R) .............................................................................. 55 Renewable Request for Proposal (RFP 2008R-l) ........................................................................... 55 Demand-side Resources ..................................................................................................................55 4. Transmission Planning ......................................................................................................................... .57 Purose of Trasmission ......................................................................................................................57 Integrated Resource Planning Perspective ...........................................................................................57 Interconnection-Wide Regional Planing ............................................................................................ 58 Sub-regional Planning Groups............... ...... ....... .............. ....... ........................................................ 59 Energy Gateway ..............................................................................................................................60 New Transmission Requirements ....................................................................................................61 Reliability. .... ...... .... ... ... ................ ........................ .... ......... .... ............ ....... .... ........ ... ............ ......... ... 62 Resource Locations ..... '" ...... ..... ...... ............ .................... .............. .......... .... ........ ... ........ ..... ........ ....62 Energy Gateway Priorities..... .............. .......... ..... ...................... .......... ..... .... .... .......... ..... ......... ........ .....64 Phasing of Energy Gateway............. ..................... .......................... ...... .................................. ........ 65 5. Resource Needs Assessment ................................................................................................................67 Introduction ...... ... ... ... .... ... ....... .... ..... ... ............... .......... ............... ....... ..... .... ....... .., ...... ..... ......... ....... ....67 Load Forecast ....................................................................................................................................... 67 Methodology Overview ................................................................................................................... 67 Evolution and changes in Integrted Resource Planning Load Forecasts ....................................... 67 Modeling overview. .......... ....... ... ....... .......... ........................... ....... ......... .... ... ........... ..... ....... ...... .....69 Energy Forecast....... .... ............. ........... ...................... ......................... ........ ...... ........... ....... ..... ........ 71 System-Wide Coincident Peak Load Forecast ................................................................................71 Jursdictional Peak Load Forecast ...................................................................................................73 Existing Resources ...............................................................................................................................74 Thermal Plants.................................................................................................................................74 Renewables......................................................................................................................................75 Wind...........................................................................................................................................75 Geothermal. ....... ..... ...... ..... ... ......... ... .... ..... ....... ........... ........... ... ..... ..... ... ........... ... ..... ..... ... ..... .... 77 Biomass ......................................................................................................................................77 Biogas.........................................................................................................................................77 Solar............................................................................................................................................77 Hydroelectrc Generation ........... ... .... ......... ........ .... ... .... ...... ..... .................. ........ ....... ...... .... ... ..... .... 78 Hydroelectric Relicensing Impacts on Generation ............. .................. ...... ........ ......... ............... 79 Demand-side Management......................... ................... ..................... ................ ..................... ........ 80 Class 1 Demand-side Management...................... ........................ ............. ........ ................. ........ 82 Class 2 Demand-side Management ............................. ............................................... ........ ........ 82 Class 3 Demand-side Management ........ ..... .......... ...... .............. ................................. ...... .......... 82 Class 4 Demand-side Management ..... ................. ....................... ........... ........ .............. .............. 82 ii ............................................ ............................................ PacifìCorp - 2008 IRP Table of Contents Power Puchase Contracts............................. .............. ...................... ..... .......... ......... ...................... 83 Load and Resource Balance........................................................................ ................... .............. ........ 85 Capacity and Energy Balance Overview............................ .................... ........................... .............. 85 Load and Resource Balance Components ......... ....................... ....... .......... ............ .......... ............ .... 86 Existing Resources .......... .... ..... ............. '" ............ ................. .... ... ..... ....... ........ ...... .... ................ 86 Obligation ...................................................................................................................................87 Reserves......................................................................................................................................89 Position ........ ......................... .................... .............. ......... .................. ....... ... ..... ...... ..... ......... ...... 89 Reserve Margin.. ............... ....... .... ....... ...... ....... ....... ........................... ....... ... ..... .......... ............ .... 89 Capacity Balance Determination .................................................................. ................................... 89 Methodology..... ... ................. .... ................ ....... ............ ...................... ...... ....... .... ... ... ....... ........... 89 Load and Resource Balance Assumptions..................................................................................90 Capacity Balance Results.. ... .... .................................................... ......... ......... .... .................... ....90 Energy Balance Determnation.......................................................................................... ..............94 Methodology................................................................................................. .............................. 94 Energy Balance Results...................................... ......... ..... .............. ...... ..... ...... .... .... ... .... ...... ...........94 Load and Resource Balance Conclusions........................................................................................96 6. Resource Options ....................................................................................................................................97 Introduction............. ...... ................. ........ ....... .......... ..................................... ...... .............. .......... .... ......97 Supply-side Resources .........................................................................................................................97 Resource Selection Criteria................................................... ........................... ...............................97 Derivation of Resource Attbutes.......... ...................... ...................................................................97 Handling of Technology Improvement Trends and Cost Uncertainties .......................................... 98 Resource Options and Attbutes......................... ........................ ..................................... ............. 100 Distributed Generation.................................... .............. ....................................... ...... .............. 108 Resource Option Description.........................................................................................................113 Coal...........................................................................................................................................113 Coal Plant Efficiency Improvements....................................,...................................................114 Natual Gas ...............................................................................................................................115 Wind .........................................................................................................................................116 Other Renewable Resources ........... ............... ....................... ................................. .......... ......... 117 Energy Storage....... ................................................... .................. .............. ............ ................... 117 Combined Heat and Power and Other Distributed Generation Alternatives ..... ......... .............. 118 Nuclear...................................................................................................................................... 120 Demand-side Resources .......... ... .................... .................... ..... ......... ......... ......... .............. ...... ............ 121 Resource Options and Attbutes...................................................................................................121 Source of Demand-side Management Resource Data ..............................................................121 Demand-side Management Supply Cures............................................................................... 1 21 Transmission Resources. ................................................................ .................................................... 130 Market Puchases....... ..... ...... ........ ........ ................................................... ..................... ........ ............. 130 Resource Option Selection Criteria ...............................................................................................130 Resource Options and Attributes...................................................................................................132 Resource Description.....................................................................................................................132 7. Modeling and Portolio Evaluation Approach ................................................................................ 135 Introduction ........................................................................................................................................135 General Assumptions and Price Inputs...............................................................................................136 Study Period and Date Conventions..............................................................................................136 Escalation Rates and Other Financial Parameters ......................................................................... 136 Inflation Rates...........................................................................................................................136 Discount Factor.........................................................................................................................136 ii PacifiCorp - 2008 IRP Table of Contents Federal and State Renewable Resource Tax Incentives ........................................................... 136 Asset Lives ...............................................................................................................................137 Transmission System Representation............................................................................................138 Case Definition...................................................................................................................................139 Case Specifications........................................................................................................................140 Carbon Dioxide Compliance Strategy and Costs .....................................................................143 Natual Gas and Electricity Prices............................................................................................145 Retail Load Growth.. .... .......... ............................................... ...... ..... ......... ............................... 145 Renewable Portfolio Stadads.................................................................................................147 Renewables Production Tax Credit Expiration ........................................................................147 Clean Base Load Plant Availability............. ............. ........ .............. .......................................... 147 High Plant Constrction Costs............................ ............. ...................................... ................... 147 Capacity Planning Reserve Margin......... ...... .......... ........... ...... ................. ... ............................ 147 Business Plan Reference Cases ................... ..... ..... ....... ........................... .............. ................... 147 Class 3 Demand-side Management Programs for Peak Load Reductions................................ 148 Scenario Price Forecast Development................................................................................................148 Gas and Electricity Price Forecasts ...............................................................................................150 Price Projections Tied to the High June 2008 Forecast...........................................................150 Price Projections Tied to the High October 2008 Forecast ......................................................152 Prce Projections Tied to the Medium June 2008 Forecast ......................................................153 Price Projections Tied to the Medium October 2008 Forecast................................................155 Price Projections Tied to the Low June 2008 Forecast............................................................156 Emission Price Forecasts...............................................................................................................158 Optimized Portolio Development .............. ....................... ........................ ............. ........................... 160 Representation and Modeling of Renewable Portfolio Stadards ...... ....... .............. ........ .............. 161 Modeling Front Offce Transactions and Growt Resources ......... ....... .......... ........ ............... ....... 161 Modeling Wind Resources .................... .............. ......................... .................... ...................... ....... 162 Modeling Fossil Fuel Effciency Improvements ...........................................................................163 Monte Carlo Production Cost Simulation ............ ................................................ .................. ............ 163 The Stochastic Model... ...... ..... .............. ................................... ....... ......... .......... ..... ...................... 163 Stochastic Model Parmeter Estimation........................................................................................164 Monte Carlo Simulation ............ .................................... ............. .................... ........ ......... .............. 164 Portfolio Performance Measures ....................... .............................. ........... .......................... ...... ........ 169 Mean PVRR................................................................................................................................... 170 Risk-adjusted Mean PVRR............................................................................................................170 Minimum Cost Exposure under Alternative Carbon Dioxide Tax Levels..... ....... ........................ 171 Customer Rate Impact .............. .............. ................ ..... ............ .................... .......... ...... ... ............... 172 Capital Cost.... ....... ................ .......... ... .... ...................... ...... ....................... ............ ..... ....... ..... ....... 172 Risk Measures ........... ............ ................. ........... ........... ................ ............. ............... ........... .......... 173 Upper-Tail Mean PVRR ........................................................................................................... 173 95th and 5th Percentile PVR ...... ...................... ...... ................................... ........ ............... ........ 173 Production Cost Stadard Deviation ................................ ............ .... ..................... ........... ........ 173 Supply Reliability.... ....................... ....... .... ......... ........ ............ ......... ......... .......... ..... ...................... 173 Average and Upper-Tail Energy Not Served.............................. ............... ............................... 173 Loss of Load Probability ..........................................................................................................174 Fuel Source Diversity ....................................................................................................................174 Top-Performing Portfolio Selection...................................................................................................175 Scenaro Risk Assessment..................................................................................................................177 Preferred Portfolio Selection and Acquisition Risk Analysis .... ..... ...................... ............ ..... ............ 178 8. Modeling and Portolio Selection Results ........................................................................................ i 79' iv ............................................ ............................................ PacifiCorp - 2008 IRP Table of Contents Introduction...... ........................................................................................................... ........ ............... 179 Portfolio Development Results........................................................................................................... 180 Wind Resource Selection................................................................................................... ............ 183 Gas Resource Selection.. ......................... ................... .... ..... ....................................... ......... .......... 183 Class 1 Demand-side Management Resource Se1ection................................................................ 183 Class 2 Demand-side Management Resource Selection................................................................ 184 Supercritical Pulverized Coal Resource Selection ........................................................................ 184 Geothermal Resource Selection................................ .................................................. ......... .......... 184 Nuclear Resource Selection...........................................................................................................184 Clean Coal Resource Selection.. ..................................................... ................................... ......... ... 185 Short-term Market Purchase Selection............................ ................................... ................. .......... 185 Distributed Generation Selection...................................... ............ ..... ........... ......... ..... ........... ........ 185 Emerging Technology Resource Selection....................................................................................185 Transmission Option Selection................... .............................................................. ..................... 186 Incremental Resource Selection under Alternative Load Growth Scenaros..... ............. ............... 186 Thermal Resource Utilization........................................................................................................187 Sensitivity Case Results .............................................................................. ........................... ....... 190 C02 Tax Real Cost Escalation and Demand Response............................................................ 190 Early Clean Base-load Resource Availability .......................................................................... 190 High Constrction Costs...........................................................................................................191 Carbon Dioxide Emissions Hard Cap.......................................................................................191 Alternative Renewable Policy Assumptions .. ......... ..... .................... ............... .............. ....... .... 194 Stochastic Simulation Results - Candidate Portolios ....................... ................................ ........... ...... 194 Stochastic Mean PVRR ............ .... .............. .......................... ................. .... ....... ..... ..... ..... .... .......... 194 Risk-adjusted PVRR......................................................................................................................196 Customer Rate Impact.......... .............. .... ...... .............. ............ .......... .... ...... .............. ..... ....... .... .....200 Cost Exposure under Alternative Carbon Dioxide Tax Levels .... ......... .......... .......... ........ ......... ...201 Portfolio Capital Costs ........................... ..... ............... ...... ................. ......................... ............ .......202 Upper-tail Mean PVRR . ..................................... ....................... ... .................... ... ....... ................... 205 Meanpper- Tail Cost Scatter Plots .............................................................................................. 208 Fifth and Ninety-Fifth Percentile PVRR ....................................................................................... 211 Production Cost Stadard Deviation. .............................. ........ ...................... .............. ..................212 Energy Not Served (ENS) .............................................................................................................213 Loss of Load Probability ...............................................................................................................214 Load Growt Impact on Resource Choice ...... ........... ......... ... .... ....... ....... .......... ........... ..... ..... ...........217 Capacity Planning Reserve Margin..................................................... ........ .... ....... ................ ............218 Fuel Source Diversity........... ........ .................... ..... ...... ........... .................... .......................... .... .......... 221 Generator Emissions Footprit...........................................................................................................223 Carbon Dioxide.................. .......................... .......... ......... ............... ........... .... ....... .... ... ..................223 Other Pollutants .............................................................................................................................225 Top-Performing Portfolio Selection...................................................................................................226 Sensitivity of Portfolio Preference Rankngs to Measure Importnce Weights ............................ 228 Case 5 versus Case 8 Portfolio Assessment..... ................. ....... ................ ...... ....... ............ ............230 Scenario Risk Assessment.............................................................................................................232 Risk Scenario Development .....................................................................................................232 Risk Scenario Modeling Results...............................................................................................233 Conclusions............. ..... ............ ..... .... ... ...... ..... ........... ........ ..... ......... ........ ..... ....... .......... ... .... ...234 Portfolio Impact ofthe 2012 Gas Resource Deferral Decision.......................................................... 235 WInd Resource Acquisition Schedule Development ......................................................................... 239 The IRP Preferred Portfolio............... ....... .................... .... ............. ................... ..... ............... ...... ........ 241 Portfolio Impact of PacifiCorp' s February 2009 Load Forecast .................. ...... ................ ........... ..... 250 v PacifiCorp - 2008 IRP Table of Contents 9. Action Plan and Resource Risk Management ..................................................................................253 Introduction ........................................................................................................................................253 The Integrated Resource Plan Action Plan.........................................................................................254 Progress on Previous Action Plan Items ..... ................ ............................. ..................... ......... ............ 260 IRP Action Plan Linkage to Business Planning........ ........... ............. ....... ....... ......... ..... ...... .... ...........263 Resource Procurement Strategy ....................................................................... ................... .... ...........264 Renewable Resources ............................................................................... .............. .......................264 Demand-side Management.................................. ........ ...... .................................... ........................265 Thermal Plants and Power Purchases.............. ........ ..... ..... ....... ............ ..................................... ....265 Distrbuted Generation ....................................................... ......... ......... ...... ............. ....... ....... ........ 266 Assessment of Owning Assets versus Purchasing Power ............... ....... .............. ......... .............. .......266 Acquisition Path Analysis .... ......... .......... ........ ... ... .... ...... .... ............. ............. .............. ......... ....... .......267 Regulatory Events ...... ... ........ ... ..... ... ............. ..... ............ ................ .... ...... ........ ......... .......... ... .......267 Procurement Delays.......................................................................................................................273 Managing carbon Risk for Existing Plants ......................................................................................... 273 Use of Physical and Financial Hedging For Electrcity Price Risk .................................................... 274 Managing Gas Supply Risk................................................................................................................274 Price Risk.......................................................................................................................................274 Availability Risk........ ...................... ............. ............. .................................. ..................................275 Deliverability Risk.........................................................................................................................275 Treatment of Customer and Investor Risks ............... .................... ............ .........................................276 Stochastic Risk Assessment ..........................................................................................................276 Capital Cost Risks .........................................................................................................................276 Scenario Risk Assessment ............................................................................................................. 277 10. Transmission Expansion Action Plan ............................................................................................ 279 Introduction ........................................................................................................................................279 Gateway Segment Action Plans ............ ............... .......... ............ ............ ....... .....................................280 Walla Walla to McNary - Segment A..... ........ ............. ......... ............... ................... ......................280 Populus to Terminal- Segment B ................................................................................................. 280 Mona to Limber to Oquirrh - Segment C...................................................................................... 280 Oquirrh to Termnal.......................................................................................................................280 Windstar to Aeolus to Bridger to Populus - Segment D ........ ................ .......... ........... .......... ........ 28 i Populus to Hemingway - Segment E............ ................ ......... ............ ........... ...... ......... ....... .......... 28 i Aeolus to Mona - Segment F ........................................................................................................ 281 Sigud to Red Butte - Segment G ............. ........ ............... ......................... ............. ............... ........ 28 i vi ............................................ ............................................ PacifiCorp - 2008 IRP Index of Tables Table 2.1 - 2008 IRP Public Meetings ....................................................................................................... 22 Table 3.1 - Sumary of state renewable goals (as applicable to PacifiCorp)............................................ 50 Table 5.1- Forecasted Average Anual Energy Growt Rates for Load................................................... 71 Table 5.2 - Anual Load Growt forecasted (in Megawatt-hours) 2009 though 2018.............................71 Table 5.3 - Forecasted Coincidental Peak Load Growth Rates.................................................................. 72 Table 5.4 - Forecasted Coincidental Peak Load in Megawatts .................................................................. 72 Table 5.5 - Jursdictional Peak Load forecast, 2009 through 2018 (Megawatts)....................................... 73 Table 5.6 - Capacity Ratings of Existing Resources .................................................................................. 74 Table 5.7 - Coal Fired Plants......................................................................................................................74 Table 5.8 - Natual Gas Plants....................................................................................................................75 Table 5.9 - PacifiCorp-owned Wind Resources .........................................................................................76 Table 5.10 - Wind Power Purchase Agreements........................................................................................76 Table 5.11- Existing Biomass resources ...................................................................................................77 Table 5.12 - Existing Biogas resources ......................................................................................................77 Table 5.13 - Hydroelectric additions................................... ............... ........................ ..................... ........... 78 Table 5.14 - Hydroelectric Generation Facilities - Nameplate Capacity as of January 2009.................... 78 Table 5.15 - Estimated Impact ofFERC License Renewals on Hydroelectric Generation........................ 79 Table 5.16 ~ Existing DSM Sumar, 2009-2018..................................................................................... 83 Table 5.17 - Federal Lighting Standard Impact on System Peak loads...................................................... 88 Table 5.18 - System Capacity Loads and Resources (12% Target Reserve Margin)................................. 91 Table 5.19 - System Capacity Loads and Resources (15% Target Reserve Margin) .......... ......... ....... .......92 Table 6.1 - Distributed Generation Installed Cost Reduction .... ...... ... ......... ........ ......... ............... ............ 100 Table 6.2 - East Side Supply-Side Resource Options .............................................................................. 102 Table 6.3 - West Side Supply-Side Resource Options............................................................................. 103 Table 6.4 - Total Resource Cost for East Side Supply-Side Resource Options, $8 CO2 Tax .................. 104 Table 6.5 - Total Resource Cost for West Side Supply-Side Resource Options, $8 CO2 Tax................. 105 Table 6.6 - Total Resource Cost for East Side Supply-Side Resource Options, $45 CO2 Tax ................ 106 Table 6.7 - Total Resource Cost for West Side Supply-Side Resource Options, $45 CO2 Tax............... 107 Table 6.8 - Distributed Generation Resource Options .............................................................................110 Table 6.9 ~ Distrbuted Generation Total Resource Costs, $8 CO2 tax .................................................... 111 Table 6.10 ~ Distributed Generation Total Resource Cost, $45 CO2 Tax ................................................112 Table 6.1 1 - Proxy Wind Sites and Characteristics.. .............. .... ........ ................ ......... .... ..... .......... .......... 1 16 Table 6.12 - Standby Generation Economic Potential and Modeled Capacity ............ ..... ................ ....... 119 Table 6.13 - Distributed CHP Economic Potential (MW) ....................................................................... 120 Table 6.14 - Distrbuted CHP Resources Included as IRP Model Options.............................................. 120 Table 6.15 - Class 1 DSM Program Attributes West Control Area .........................................................123 Table 6.16 - Class 1 DSM Program Attibutes East Control Area........................................................... 124 Table 6.17 - Class 3 DSM Program Attributes West Control area........................................................... 126 Table 6.18 - Class 3 DSM Program Attbutes East Control area............................................................ 126 Table 6.19 - Load Area Energy Distrbution by State.............................................................................. 128 Table 6.20 - Class 2 DSM Cost Bundles and Bundle Prices.................................................................... 128 Table 6.21 - Class 2 DSM Supply Cure Capacities by State.................................................................. 129 Table 6.22 - Maximum Available Front Offce Trasaction Quantity by Market Hub ........................... 131 Table 7.1- Resource Book Lives.............................................................................................................137 Table 7.2 - Core Case Definitions............................................................................................................141 Table 7.3 - Sensitivity and Business Plan Reference Case Definitions.................................................... 142 vii PacifiCorp - 2008 IRP Index of Tables Table 7.4 - CO2 Tax Values .....................................................................................................................143 Table 7.5 - CO2 Pnces for the Business Plan Reference Cases................................................................ 14 5 Table 7.6 - Underlying Henr Hub Pnce Forecast Summar (nominal $/Mtu)................................. 150 Table 7.7 - Reference S02 Allowance Pnce Forecast Sumary (nominal $/ton)....................................158 Table 7.8 - Measure Importce Weights for Portfolio Rang.............................................................175 Table 7.9 - Portfolio Preference Sconng Gnd .........................................................................................176 Table 7.10 - Cases Selected for Determnistic Risk Assessment ............................................................. 177 Table 8.1 - Portfolio Capacity Additions by Resource Type, 2009 - 2018 ............................................. 181 Table 8.2 - Portfolio Capacity Additions by Resource Type, 2009 - 2028.............................................182 Table 8.3 - Average Anual Thermal Resource Capacity Factors by Portfolio....................................... 189 Table 8.4 - Hard Cap CO2 Emission Allowances.....................................................................................191 Table 8.5 - Portfolio Comparison, System Optimizer Total CO2 Emissions by Year.............................. 192 Table 8.6 - Stochastic Mean PVRR by Candidate Portolio ....................................................................195 Table 8.7 - Incremental Mean PVR by CO2 Tax Level........................................................................ 195 Table 8.8 - PVRR Net Power Costs and Fixed Costs by CO2 Tax Level................................................ 196 Table 8.9 - Risk-adjusted PVRR by Portfolio..........................................................................................197 Table 8.10 - Customer Rate Impacts by Portfolio....................................................................................201 Table 8.11 - Portfolio Cost Exposures for Carbon Dioxide Tax Outcomes ............................................. 202 Table 8.12 - Upper-tail Mean PVRR by Portfolio ...................................................................................205 Table 8.13 - 5th and 95th Percentile PVRR by Portfolio ........................................................................... 211 Table 8.14 - Production Cost Stadad Deviation.................................................................................... 212 Table 8.15 - Average Loss of Load Probability by Event Size Dung Sumer Peak............................. 215 Table 8.16 - Year-by-Year Loss of Load Probability...............................................................................216 Table 8.17 - Stochastic Performance Results for Alternative Load Growt Scenano Cases ...................217 Table 8.18 - Cost versus Risk for 12% and 15% Planing Reserve Margin Portfolios ...........................219 Table 8.19 - PVRR Cost Details ($45/ton C02 Tax), 12% and 15% Planning Reserve Margin Portfolios ..........................................................................................................................................................219 Table 8.20 - PVRR Cost Details ($70/ton C02 Tax), 12% and 15% Planing Reserve Margin Portfolios ..........................................................................................................................................................220 Table 8.21 - PVRR Cost Details ($100/ton C02 Tax), 12% and 15% Planing Reserve Margin Portfolios ..........................................................................................................................................................221 Table 8.22 - Generation Shares for New Resources by Fuel Type for 2013............................................222 Table 8.23 - Generation Shares for New Resources by Fuel Type for 2020............................................ 222 Table 8.24 - Generation Shares for New Resources by Fuel Type for 2028............................................223 Table 8.25 - Cumulative Generator Carbon Dioxide Emissions, 2009-2028...........................................224 Table 8.26 - Generator Carbon Dioxide Emissions by CO2 Tax Level................................................... 225 Table 8.27 - Probabilty Weights for Calculating Expected Value CO2 Tax Levels ...............................226 Table 8.28 - Measure Rankngs and Preference Scores, $45/ton Expected-value CO2 Tax .................... 227 Table 8.29 - Portfolio Preference Scores..................................................................................................227 Table 8.30 - Alternate Measure Importnce Weights .............................................................................. 228 Table 8.31 - Measure Rankings and Preference Scores with Alternative Measure Importnce Weights, $45/ton Expected-value CO2 Tax..................................................................................................... 229 Table 8.32 - Short- and Long-term 95th Percentile PVR Comparsons .................................................231 Table 8.33 - Scenano Risk Case Defmitions ........................................................................................... 232 Table 8.34 - Scenaro Risk PVRR Results ............................................................................................... 233 Table 8.35 - Portfolio PVR Rankings....................................................................................................233 Table 8.36 - PVRR Differences, Portfolio Development Case less Risk Scenaro Results ...... ............... 234 Table 8.37 - Additional Portfolios Modeled to Support a 2012 Gas Resource Deferral Strategy ...........236 Table 8.38 - Resource Capacity Compansons, Onginal and B Senes Portfolios ....................................236 Table 8.39 - Stochastic Mean PVR for 2012 Gas Resource Deferrl Strtegy Portfolios..................... 238 vii ............................................ ............................................ PacifiCorp - 2008 IRP Index of Tables Table 8.40 - Measure Rankings and Preference Scores for 2012 Gas Resource Deferral Strategy Portolios, $45/ton Expected-value CO2 Tax ................................................................................... 238 Table 8.41 - Measure Rankings and Preference Scores for 2012 Gas Resource Deferral Strategy Portfolios ..........................................................................................................................................239 Table 8.42 - Revised Wind Resource Acquisition Schedule....................................................................240 Table 8.43 - Resource Differences, 2008 IRP Preferred Portfolio less 2007 IRP Update Preferred .......243 Table 8.44 - Preferred Portfolio, Detail Level........................................................................................245 Table 8.45 - Preferred Portfolio Load and Resource Balance (2009-2018)..............................................246 Table 8.46 - Coincident Peak Load Forecast Comparison ....................................................................... 250 Table 8.47 - Resource Capacity Differences, Februar 2009 Load Forecast Portfolio less Wet-Cooled CCCT Portfolio ................ ............................. .... .......... .... ............... ................. .......... ... ....................251 Table 9.1 - Preferred Portfolio, Sumary Level..................................................................................... 254 Table 9.2 - 2008 IRP Action Plan ............................................................................................................255 Table 9.3 - Resource Acquisition Paths Triggered by Major Regulatory Actions ..... ...... ..... .... ............... 269 ix ............................................ PocifiCorp - 2008 IRP Index of Figures Figue 2.1 - IRP/Business Plan Process Flow ............................................................................................20 Figue 3.1- Henr Hub Day-ahead Natual Gas Price History..................................................................28 Figure 3.2 - U.S. Natual Gas Balance History ..........................................................................................29 Figure 3.3 - Green House Gas Cost Implications for Electric Generators ................................................. 33 Figue 4.1 - Sub-regional Transmission Planning Groups in the WECC................................................... 60 Figure 4.2 - Western States Wind Power Potential Up to 25,000 Megawatts............................................ 63 Figure 5.1 - Contract Capacity in the 2008 Load and Resource Balance ....... .............. ........ ........ .............. 84 Figue 5.2 - Changes in Contract Capacity in the Load and Resource Balance......................................... 85 Figue 5.3 - System Capacity Position Trend.............................................................................................92 Figure 5.4 - West Capacity Position Trend ................................................................................................93 Figure 5.5 - East Capacity Position Trend ................................................................................................. 93 Figure 5.6 - System Average Monthly and Annual Energy Balances........................................................ 95 Figue 5.7 - West Average Monthly and Anual Energy Balances ........................................................... 95 Figue 5.8 - East Average Monthly and Annual Energy Balances............................................................. 96 Figue 6.1 - Nort American and World Carbon Steel Price Trends .........................................................99 Figue 6.2 - Utah Load Shape .................................................................................................................. 130 Figue 7.1 - Modeling and Risk Analysis Process ...................................................................................135 Figure 7.2 - Transmission System Model Topology ................................................................................138 Figure 7.3 - Peak Load Growth Scenarios ...............................................................................................146 Figue 7.4 - Energy Load Growth Scenarios............................................................................................146 Figue 7.5 - Modeling Framework for Commodity Price Forecasts ........................................................149 Figue 7.6 - Henr Hub Natual Gas Prices from the High June 2008 Underlying Forecast..................151 Figue 7.7 - Western Electrcity Prices from the High June 2008 Underlying Gas Price Forecast........151 Figue 7.8 - Henry Hub Natul Gas Prices from the High October 2008 Underlying Forecast .............152 Figue 7.9 - Western Electricity Prices from the High October 2008 Underlying Gas Price Forecast... 153 Figure 7.10 - Henr Hub Natual Gas Prices from the Medium June 2008 Underlying Forecast ...........154 Figure 7.11 - Western Electrcity Prices from the Medium June 2008 Underlying Gas Price Forecast. 154 Figue 7.12 - Henr Hub Natual Gas Prices from the Medium October 2008 Underlying Forecast.....155 Figue 7.13 - Western Electrcity Prices from the Medium June 2008 Underlying Gas Price Forecast. 156 Figue 7.14 - Henr Hub Natual Gas Prices from the Low June 2008 Underlying Forecast.................157 Figure 7.15 - Western Electricity Prices from the Low June 2008 Underlying Gas Price Forecast ........157 Figue 7.16 - S02 Allowance Prices Developed off of the June 2008 Reference Forecast.....................159 Figue 7.17 - S02 Allowance Prices Developed off of the August 2008 Reference Forecast.... ....... ...... 160 Figure 7.18 - Frequency of Western (Mid-Columbia) Electricity Market Prices for 2009 and 2018 ......165 Figue 7.19 - Frequency of Eastern (Palo Verde) Electrcity Market Prices, 2009 and 2018 ..... ............. 165 Figue 7.20 - Frequency of Western Natual Gas Market Prices, 2009 and 2018....................................165 Figue 7.21 - Frequency of Eastern Natual Gas Market Prices, 2009 and 2018..................................... 166 Figue 7.22 - Frequencies for Idaho (Goshen) Loads............................................................................... 16 6 Figue 7.23 - Frequencies for Utah Loads................................................................................................167 Figue 7.24 - Frequencies for Washington Loads ....................................................................................167 Figue 7.25 - Frequencies for West Main (California and Oregon) Loads ..............................................168 Figue 7.26 - Frequencies for Wyoming Loads ........ ................... ....... ............ ........................ ................. 168 Figue 7.27 - Hydroelectric Generation Frequency, 2009 and 2018........................................................169 Figue 8.1- Average Annual Capacity Factors by Resource Type, CO2 Hard Cap Portfolio.................. 193 Figue 8.2 - Risk-adjusted PVRR Range and Wind Nameplate Capacity by Portfolio ........................... 198 Figure 8.3 - Wind Capacity for Portfolios Ranked by Risk-adjusted PVR ...........................................198 xi PacifiCorp - 2008 IRP Index of Figures Figue 8.4 - Energy Effciency Capacity for Portfolios Ranked by Risk-adjusted PVR....................... 199 Figue 8.5 - Annual Average Front Offce Transaction Capacity for Portfolios Raned by Risk-adjusted PVRR ............................................................................................................................................... 199 Figue 8.6 - Clean Base Load Coal Capacity for Portfolios Ranked by Risk-adjusted PVR ................200 Figue 8.7 - IC Aeroderivative SCCT Capacity for Portfolios Ranked by Risk-adjusted PVRR ............ 200 Figue 8.8 - Portfolio Capital Costs, 2009-20 18 ......................................................................................203 Figue 8.9 - Portfolio Capital Costs, 2009-2028 ......................................................................................203 Figue 8.10 - Average Anual Planng Reserve Margins.......................................................................204 Figure 8.11 - Incremental Portfolio Capital Costs (20% increase from Base per-kW values)................. 205 Figue 8.12 - Wind Capacity for Portfolios Raned by Upper-tail Mean PVR.....................................207 Figue 8.13 - Energy Effciency Capacity for Portfolios Raned by Upper-tail Mean PVRR ................207 Figue 8.14- Front Offce Transaction Capacity for Portolios Ranked by Upper-tail Mean PVRR......208 Figure 8.15 - Intercooled Aeroderivative SCCT Capacity for Portfolios Ranked by Upper-tail Mean PVR...............................................................................................................................................208 Figue 8.16 - Stochastic Cost versus Upper-tail Risk, $0 CO2 Tax.......................................................... 209 Figue 8.17 - Stochastic Cost versus Upper-tail Risk, $45 CO2 Tax........................................................ 210 Figue 8.18 - Stochastic Cost versus Upper-tail Risk, $100 CO2 Tax...................................................... 210 Figue 8.19 - Stochastic Cost versus Upper-tail Risk, Average for CO2 Tax Levels...............................211 Figure 8.20 - Average Anual Energy Not Served, 2009-2028 ($45 CO2 Tax) ......................................213 Figure 8.21 - Average Annual Energy Not Served, 2009-2018 ($45 CO2 Tax) ......................................214 Figue 8.22 - Upper-tail Energy Not Served, $45 CO2 Tax ..................................................................... 214 Figue 8.23 - Generator Carbon Dioxide Emissions by CO2 Tax Level.................................................. 225 Figue 8.24 - Portfolio Preference Scores, sorted from Best to Worst....................................................228 Figure 8.25 - Preference Scores by Expected Value CO2 Tax, Top-performng Portfolios..................... 230 Figue 8.26 - Stochastic Cost versus Upper-tail Risk: $0, $45, and $100 CO2 Tax Levels...................... 239 Figue 8.27 - Carbon Dioxide Intensity of the 2008 IRP Preferred Portfolio ..........................................241 Figue 8.28 - Renewable Portolio Stadad Compliance 2008 IRP Preferred Portfolio......................... 242 Figue 8.29 - Curent and Projected PacifiCorp Resource Energy Mix...................................................247 Figue 8.30 - Curent and Projected PacifiCorp Resource Capacity Mix ................................................ 248 Figue 9.1 - Resource Acquisition Paths Tied to Load Growt and Natul Gas Prices..........................272 Figure 10.1- Energy Gateway 2010 Additions........................................................................................283 Figue 10.2 - Energy Gateway 2012 Additions........................................................................................284 Figure 10.3 - Energy Gateway 2014 Additions........................................................................................285 Figue 10.4 - Energy Gateway 2016 Additions........................................................................................286 Figue 10.5 - Energy Gateway 2017 Additions........................................................................................ 287 Figue 10.6 - Westside Plan / Red Butte - Crystal..................................................................................289 xii ............................................ ............................................ Paci~Corp - 2008 IRP Listng of Appendices Appendix A - Detail Capacity Expansion Results Appendix B - Stochastic Production Cost Simulation Results Appendix C - IRP Regulatory Compliance Appendix D - Public Input Process Appendix E - State Load Forecast Appendix F - Wind Integration Cost Update Appendix G - DSM Decrement Analysis Appendix H - Additional Load and Resource Balance Information xii ............................................. PacifiCorp - 2008 IRP Chapter I - Executive Summary 1. EXECUTIVE SUMMARY PacifiCorp's 2008 Integrated Resource Plan (2008 IRP), representing the 10th plan submitted to state regulatory commissions, presents a framework of futue actions to ensure PacifiCorp con- tinues to provide reliable, reasonable-cost service with manageable risk to its customers. It was developed through a collaborative public process with involvement from regulatory staff, advo- cacy groups, and other interested paries. . The key elements of the 2008 IRP include a finding of resource need-focusing on the 10-year period 2009-2018, the preferred portfolio of supply-side and demand-side resources to meet this need, and an action plan that identifies the steps the Company wil take durng the next two to four years to implement the plan. The resources identified in the 2008 IRP preferred portfolio are considered proxy resources that guide procurement efforts, and do not constitute the actual re- sources that would be acquired as part of futue procurement initiatives. Signficant changes reflected in this IRP relative to the 2007 IRP (filed in May 2007) include: ~ A decrease in resource need: the system becomes short on capacity in 2011 rather than 2010 due to lower forecasted loads and new resource additions. ~ Acquisition of the 520 megawatt (MW) Chehalis gas plant and 175 MW of additional wind resources added in 2008. ~ New IRP guidelines issued by the Oregon Public Utility Commission on the treatment of carbon dioxide (C02) regulatory risk. ~ Incorporation of the Energy Gateway Transmission project in the portfolio analysis. ~ State commission 2007 IRP acknowledgment orders calling for modeling methodology changes and the expansion of resource options to consider, including energy effciency measures (Class 2 demand-side management programs) and additional renewable energy technologies such as solar and geothermaL. . For capital expenditue planning, the Company's challenge has been to minimize customer rate impacts in light of a substantial capital spending requirement needed to address customer load growt, support governent environmental and energy policies, and maintain transmis- sion grid reliability. To address this challenge, PacifiCorp is scrutinizing capital projects for cost reductions or deferrals that make economic sense in today's market environment. . An additional planning challenge has been to respond to and predict the demand response impacts of the economic recession and financial crisis. The Company is curently seeing a continuation of significant industral and commercial sector demand destrction. This wil translate into a reduction in resource need for the near-term. Nevertheless, the depth of the economic recession and the pace of a recovery are uncertain, complicating the resource re- quirements pictue. The table below compares the Company's peak load forecasts prepared in November 2008 and February 2009 without reductions from energy effciency programs, showing the differences though 2018. The February 2009 load forecast was prompted by a review of actual loads through January 2009. PacifiCorp - 2008 IRP Chapter I - £Xecutive Summary . At the same time, volatile economic conditions and commodity prices, combined with regu- latory uncertainty, have complicated the planing pictue, requiring the Company to continu- ously re-evaluate input assumptions and resource acquisition strtegies throughout this plan- ning cycle. For example the thee chars below vividly ilustrte the dramatic price movement of Henr Hub day-ahead natual gas prices, day-ahead wholesale electrcity prices, and car- bon steel prices durg the time this IRP was developed. 520 519 518 517 516 515 514 513 512 il 511 :; 510 ~ $9 58 57 56 55 54 53 52 51 so S i ii ï ii ii g: Ii ¡illl~ ~~ = = = g § ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ § ~ ~- § ~ ~- §- - - - - - 1- Day Ahead Ind -Average ABDUa) Pnee I Source: Intercontinentaxchange, OTC Day-ahead Index 2 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter I - Executive Summary S120 suo SIOO S90 S80 .:S70 ~S60~~S50 S4 S30 S20 SIO so Jan- Feb- Mar- Apr- May- Jun- Jul-8 Aug- Sep- Oct- Nov- Dee Jan- Feb- Mar- Apr-~~~~~~ ~~~~~~~~~ __ Mid-Columbia, On-Peak -i California Oregon Border, On-Peak .. Palo Verde, On-Peak Source: IntercontinentalExchange, OTe Day-ahead Prices 1700 -=1500-="'.. :s.. ~1300~ ~ ;E llOO =-= "£..900'"= E"' -a 700::00=-= of 500..00 00 00 00 00 00 00 00 00 00 00 00 0-U !'!'!'!'!'!'!'!'!'!'!'!'!'N '""'on \0 r-oo 0-:=~0 0 0 0 0 0 0 0 0 -0 -+ World Price: Hot Rolled Steel Coil _ World Price: Hot Rolled Steel Plate ~ North Amerca Price: Hot Rolled Steel Coil _ North Amerca Price: Hot Rolled Steel Plae Source: MEPS (International) LTD, MEPS Steel Prices On-line . The significant price drops in fuels and forward wholesale power in late 2008 and early 2009 signal near-term opportities to lower power supply costs through market purchases before the Company needs to commit to a large new thermal power plant. If constrction markets continue to soften as several experts predict, this wil create additional cost-saving opporti- ties through lower plant prices. 3 PacifiCorp - 2008 IRP Chapter I - Executive Summary . The 2008 IRP reflects evolution of PacifiCorp's corporate resource planning approach. In early 2008, PacifiCorp embarked on a strtegy to more closely align IRP development activi- ties and the annual 10-year business planing process. The purose of the alignent was to adopt consistent planning assumptions, ensure that business planning is informed by the IRP portfolio analysis and that the IRP accounts for near-term resource affordability, and improve resource planning transparency for public stakeholders. . PacifiCorp's 2008 IRP accounts for the Energy Gateway Transmission project. For the 2008 IRP cycle, the Company treated the various planed transmission segments as existing re- sources for portfolio modeling puroses. Going forward, Gateway transmission segments wil be reevaluated from an integrated resource planning perspective durng the IRP and an- nual business planing cycles. 5~:_~~,-~::.;1'1\.~~ . The resource need accounts for load growth, sales obligations, existing resources, and a 12 percent planning reserve margin. Based on a November 2008 load forecast, PacifiCorp ex- periences a capacity deficit beginning in 20 11-the system is short by 498 megawatts (MW). This deficit increases to 1,936 MW in 2012 and 3,528 MW by 2018. The following chart shows the growth in the gap between resources and capacity, requirements based on a 12 percent capacity reserve requirement. The capacity deficit is drven by a coincident system peak load growt rate of2.5 percent for 2009-2018, and expiration of major power contracts such as the Bonnevile Power Administrtion peakng contrct in August 2011. 18,00 16,00 14,00 Obligation + Reserves (12%)"- 12.00 10,000 ~ 8,00 6,00 4,00 2,00 20 2010 2011 2012 2013 2014 2015 2016 2017 208 4 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter I - Executive Summary On an energy basis, the system begins to experience summer short positions by 2012 as indi- cated in the following chart that shows the gap between avaìlable energy and load obliga- tions. 3,00 2,500 2,00 1,500 i 1.000 500 (500) (1,000) (1,500) .. (2.000) ...~ - ~ Q ~ ~ ~~~::: ~~~~ ~ ~ ~~ ~ ~~ ~~ ~ ~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~9122 i ~.... . ~ ~ it . .i . . . ~ I . . .. ~.. i .i": . . ...... i ~"'lr i:":....~~~&l~a 8 l ~ao l~l 8 l~a8 l ~a 8l ~a8l~a 8l~~ø ~ ~a8 . To determine how best to address the capacity deficits, PacifiCorp developed 57 resource portfolios using a capacity expansion model that optimizes resource choice according to a va- riety of input assumptions and capacity planing criteria. The Company simulated most of these portfolios--eveloped with a combination of carbon dioxide regulatory costs, forward electricity and natual gas prices, load forecast scenarios, and other variables-using a pro- duction cost model that accounts for stochastic variation in key variables. These stochastic varables include loads, natual gas prices, wholesale electrcity prices, hydroelectrc genera- tion, and thermal resource availability. . PacifiCorp's state utility commissions require the Company, through their IRP standards and guidelines, to develop a portfolio that is least-cost after accounting for risk, uncertinty, and the long-ru public interest. To make this determination, PacifiCorp uses a wide range of portfolio performance measures that captue cost, risk, and supply reliability attbutes. The Company focuses on seven measures and a weighted composite scoring scheme to isolate the top-performing portfolios. The three measures given the most weight for scoring puroses include the following: o Risk-adjusted Present Value of Revenue Requirements (45% weight) o Customer rate impact - the average anual change in the customer dollar-per- megawatt-hour price for the period 20 i 0 through 2028 (20% weight) o Carbon dioxide cost exposure - reflects a portolio's potential for avoiding worst-case cost outcomes given CO2 regulatory cost uncertainty (15% weight) PacifiCorp focused its final portfolio performance evaluation on the four portfolios with the best performance scores, comparing them on the basis of individual measure performance 5 PacifiCorp - 2008 IRP Chapter I - Executive Summary and considering other factors such as fuel source diversity and risks not captued in the port- folio modeling (for example, procurement and constrction management risks). . PacifiCorp's 2008 IRP preferred portfolio consists of a diverse mix of resources dominated by renewables, demand-side management, gas-fired resources, and firm market purchases. The major resources for the 2009-2018 planning period consist of the following: o Renewables: Wind: 1,313 MW Geothermal: 35 MW Major hydroelectrc upgrades: 75 MW in 2012-2014 o Demand-side management - Energy effciency: 904 MW Dispatchable load control: 205 to 325 MW o Gas-fired capacity: 831 MW in the 2014-2016 period o Coal plant tubine upgrades: 170 MW of emissions-free capacity o Firm market purchases: Ranging from 50 MW to 1,400 MW on an anual basis, con- tingent on the timing and amounts oflong-term resource acquisitions The table below shows the incremental resource additions b CCCT F 2xl, Uta Nor ICAerSCCT Ea Power Puhas A ment 200 Coal Plant Turbine U 44 33 25 2 14Gethen35 Wind 99 249 100 100 100 150 100 100 50 Combined Hea & Power 2 2 2 3 3 3 4 4 4 4Distbute Siadb Genon 4 4 4 4 4 4 4 4 4 4DSM, Clas I. Uta Cool Ke er Load Contl 25 50 40 30 10 10 10 10 10 10 DSM, Clas I, Oter DSM Class 2 42 51 49 52 55 55 56 56 58 59Front Ofce Trantions 75 50 150 394 493 200 202 228 717 800Coal Plant Turine U de 9 9 12 12 42SwiftH U S21 25 2S 25 75Wind 45 20 200 265CHP I I I 2 2 2 16Distbute Siadb Generon 1 I I I 1 1 12DSM, Clas I U to 30DSM, Clas 2 35 36 39 39 38 39 39 39 39 29 372Front Offce Transons 59 839 839 739 739 689 289 582 1/ The 99 MW amount in 2009 is the High Plais projec; the 249 MW in 2010 inlud the 99 MW Th But win PPA, 21 The Swif 1 hydr up are shown in the yea th they ..te in comml sece, . Up to 120 MW of adtion cos-effecve Cla I DSM pro (100 MW ea 30 MW wes) to be ideed thug cotive Req for Prs and phas in as apprpr frm 200-2018, Fir ma purha (3rd qua pr) would be reed by roghy comparle amounts, . The capacity expansion model determined the amount and timing of renewables resources subject to annual system-wide renewable portfolio standard generation requirements estab- lished from existing state targets in place as of late 2008. PacifiCorp manually spread the wind resource quantities relatively evenly across all years of the 10-year business-planning period to support rate and capital spending stability, balance the timing risks associated with uncertin CO2 costs and the possibility of federal renewable production tax credit expiration, among other benefits. 6 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter I - Executive Summary . PacifiCorp is on pace to exceed the previous renewable resource amount identified in the Company's 2007 Renewable Energy Action Plan filed in May 2007 (1,400 MW by 2015), and the amount identified in the 2007 IRP Update report filed in June 2008 (2,000 MW by 2013).1 Since 2005, the Company's projected renewable resource inventory has grown by 1,404 MW, accounting for existing resources and those under constrction, contract, or in- cluded in the capital budget. The incremental renewables identified in the 2008 IRP preferred portfolio and action plan bring the target to about 2,040 MW by 2013. The projected renew- abIes inventory exceeds 2,540 MW by 2018, which represents 18.5% ofPacifiCorp's owned generation capability in that year. . The pie charts below show the resource generation mix in megawatt-hours for 2009 and 2018, assuming that a $45/ton CO2 tax is in place beginning in 2013 with 2% anual infla- tion. 2009 Resource Energy Mix with Preferred Portolio Resources ($45 C02 Tax) Interruptible 0.1 % Front Offce Transactions 1.1% CHP 0.030/. Class 1 DSM 0.00% DSG 0.000%Renewable 4.5% Existing Purchases 7.1% Hydroelectr 8.9% i Both of these documents are available at PacifiCorp's IRP Web site. The link to the Renewable Energy Action Plan is http://www.pacitìcorp.comlFile/File74767.pdf. The link to the 2007 IRP Update is htt://ww.pacificorp.comlFile/File82304 .pdf. 7 PacifiCorp - 2008 IRP Chapter I - Executive Summary 2018 Resource Energ Mix with Preferred Portolio Resources ($45 CO2 Tax) Interrptible 0.1% CHP 0.5% Class2DSM 5.4% Front Office Transactions 7.7% Class 1 DSM 0.02% Gas-SCCT 1.20/0 Renewable 9.7% Existg Purchases 7.8% Hydroelectnc 7.3% GasCCT 19.7% . The increasing mix of clean resources-renewables and demand-side management-reduces the carbon intensity of PacifiCorp' s generation fleet and positions the Company well for meeting future climate change and renewable resource requirements. The following two charts show the declining trend in CO2 emissions per MW of generation, and how the pre- ferred portfolio complies with existing jursdictional renewable portolio standards expressed as a percent of system load. 8 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter I - Exective Summary 2008 IRP Preferred Portolio CO2 Intensity 0,85 0,8 ......,.\~ From 2009 levels, CO 2 intensity drops by 15% in 2018 and 32% by 2028 ~0,75 \~0.7 "..-...".'"..""c:0.65¡." -Â~U .."" 0.6 , 0.55 '" 0.5 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 li Generatin cooists of the ouut from thrmi renewable and hydro resources baed on a $45/ton C02 tax begi in 2013. Renewable Portfolio Standards Compliancel..ei 22% '"20%.. 'S 18%"-co -=16%.."14%..!.12%" ;¡10%:i 8%¡t e,6%~ t"4%....2%¡¡ :æ 0%" ~ ~ ,//...-~-//"/ K 7 I,./~~ 200 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 -I 2001R I'felTd Portoli -+ System-sed Renewabl Poli Standrd Requment The addition of energy effciency resources-reaching 4.2 milion kWh by 2018-reduces the system coincident peak load from a 2.7% average anual growth rate (2009-2018) to 1.9%. The addition of flexible natual gas resources supports the aggressive expansion of in- termittent renewable generation while meeting incremental base load and intermediate load needs. The role of new firm market purchases is to help replace expiring long-term power purchases, and, by adjusting volumes up or down, provide resource flexibility to manage the volatility and uncertainty in load forecasts, commodity prices, and capital costs. 9 PacifiCorp - 2008 IRP Chapter I - Executive Summary . Relative to the preferred portfolio reported in the 2007 IRP Update report (June 2008), the 2008 preferred portfolio relies on significantly less firm market purchases for the period cov- ered in common (2009-2017). For gas resources, the major difference is the addition of a simple-cycle gas plant in 2016; with the acquisition of the Chehalis plant in 2008, there is negligible change in the amount of combined-cycle gas capacity. The 2008 IRP relies more heavily on distributed generation resources, while differences in wind and Class 2 DSM are minimaL. The following table shows the anual resource differences for the two preferred portfolios (2008 IRP less the 2007 IRP Update). Resource Difference - 2008 IR Preferred Portfolio less 2007 IRP Update 150 1008 8 (598) (572)~ w n~ i~2 Z 2 2 3 3 3 3 25(40) (657) (677) (31) 30 (55) (100) (333) NAEnergy Effciency (Clas 2 DSM) 2 2 (2) (3) I 2 3 2 (55) 11 Acquisition of the Chehais 509 MW combine.kycle plat in Washingt. 2J For 2008, actu wid adtions tota 545 MW, coai to the pla ait of 370 MW in the 2007 IR Updte 31 Expanions of the existig Uta COL Kee pr and dihable irgaOl prgr ar trte as existig resoures. Relatve to the 2007 IR Updat quatities, the incrta DSM plaed expion reh 525 MW by 2018.4/ For the 2007 IR Upd, Cla 2 DSM wa tr as a de to loa raer th as a reur included in the preferd porolio, . Although the Company could not accommodate a comprehensive portfolio evaluation based on the February 2009 load forecast without contrvening certain state IRP fiing require- ments, PacifiCorp was neverteless able to conduct a preferred portfolio sensitivity analysis with it. Combining the February 2009 load forecast with the input assumptions from which the original preferred portfolio was derived, PacifiCorp developed an alternate portfolio us- ing its the capacity expansion modeL. o A 2014 combined-cycle combustion tubine (CCCT) resource in the original pre- ferred portfolio was fixed in that same year for the sensitivity analysis model ru, owing to the small capacity deficits that ranged from 61 MW in 2012 to 93 MW in 2016. o The capacity expanion model determined that a 2016 intercooled aeroderivative SCCT was no longer needed, and that deferrl and modest reductions in firm market purchases was cost-effective combined with an increase in customer standby generation and addition of utility-scale biomass resources. . Since the relative resource impact of the February 2009 load forecast is minimal until 2016, PacifiCorp decided to retain the IC aero SCCT in the preferred portolio. Also supportng this decision is the uncertinty over the timing and pace of an economy recovery, combined with the short lead-time for a gas peaking resource and the potential need for such resources to support wind integration. Consideration of the timing and tye of gas resources and other re- 10 ............................................ ............................................ PacifiCorp - 20081RP Chapter I - Executive Summary source changes wil be handled as part of a comprehensive assumptions update and portfolio analysis to be conducted for the next business plan and 2008 IRP update. . The 2008 IRP action plan is based upon the latest and most accurate information available at the time of portfolio study completion. The Company recognizes that the preferred portfolio upon which the action plan is based reflects a snapshot view of the futue that accounts for a wide range of uncertainties. The curent volatile economic and regulatory environment wil likely require near-term alteration to resource plans as a response to specific events and im- proved clarity concerning the direction of the economy and governent energy and. environ- mental policies. . Resource information used in the 2008 IRP, such as capital and operating costs, is consistent with that used to develop the Company's business plan completed in December 2008. How- ever, it is importnt to recognize that the resources identified in the 2008 IRP preferred port- folio are proxy resources and act only as a guide for resource procurement. Resources evalu- ated as part of procurement initiatives may vary from the proxy resources identified in the plan with respect to resource tye, timing, size, cost and location. Evaluations wil be con- ducted at the time of acquiring any resource to justify such acquisition. . The table below constitutes PacifiCorp's 2008 IRP action plan. II Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r I - E x e c u t i v e S u m m a r y 20 0 8 I R P A c t i o n P l a n Ac t i o n i t e m s a n t i c i D a t e d t o e x t e n d b e y o n d t h e n e x t t w o v e a r s , o r o c c u r a f t e r t h e n e x t t w o y e a r s , a r e i n d i c a t e d i n i t a l i c s 2 Fi r m Ma r k e t Pu r c h a s e s 20 0 9 - 2 0 1 3 Ac q u i r e a n i n c r e m e n t a l 1 , 4 0 0 M W o f r e n e w a b l e s b y 2 0 1 S , i n a d d i t i o n t o t h e a l r e a d y p l a n n e d 7 5 M W o f ma j o r hy d r o e l e c t r i c u p g r a d e s i n 2 0 1 2 - 2 0 1 4 ; P a c i f i C o r p ' s p r o j e c t e d r e n e w a b l e r e s o u r c e i n v e n t o r y b y 2 0 1 S e x c e e d s 2, 5 4 0 M W w i t h t h e s e r e s o u r c e a d d i t i o n s . S u c c e s s f u l l y a d d 1 4 4 M W o f w i n d r e s o u r c e s i n 2 0 0 9 t h a t a r e c u r r e n t l y i n t h e p r o j e c t p i p e l i n e , i n c l u d i n g Pa c i f i C o r p ' s 9 9 M W H i g h P l a i n s f a c i l i t y i n W y o m i n g , a n d 4 5 M W o f po w e r p u r c h a s e a g r e e m e n t ca p a c i t y . S u c c e s s f u l l y a d d 2 6 9 M W o f wi n d r e s o u r c e s i n 2 0 1 0 t h a t a r e c u r r e n t l y i n t h e p r o j e c t p i p e l i n e , i n c l u d i n g 11 9 M W o f po w e r p u r c h a s e a g r e e m e n t c a p a c i t y a l r e a d y c o n t r a c t e d . P r o c u r e u p t o a n a d d i t i o n a l 5 0 0 M W o f c o s t - e f f e c t i v e r e n e w a b l e r e s o u r c e s f o r c o m m e r c i a l o p e r a t i o n , su b j e c t t o t r a n s m i s s i o n a v a i l a b i l t y , s t a r t i n g i n t h e 2 0 0 9 t o 2 0 1 1 t i m e f r a m e u n d e r t h e c u r r e n t l y a c t i v e 20 0 9 - 2 0 1 S I r e n e w a b l e r e s o u r c e R F P ( 2 0 0 S R - l ) a n d t h e n e x t r e n e w a b l e r e s o u r c e R F P ( 2 0 0 9 R ) e x p e c t e d t o b e i s s u e d in t h e s e c o n d q u a r t e r o f 2 0 0 9 Th e C o m p a n y i s e x p e c t e d t o s u b m i t c o m p a n y r e s o u r c e s ( s e l f bu i l d o r o w n e r s h i p t r a n s f e r s ) i n th e 2 0 0 9 R R F P . P r o c u r e u p t o a n a d d i t i o n a l 5 0 0 M W o f c o s t - e f f e c t i v e r e s o u r c e s f o r c o m m e r c i a l o p e r a t i o n , s u b j e c t t o tr a n s m i s s i o n a v a i l a b i l t y , s t a r t i n g i n t h e 2 0 1 2 t o 2 0 1 8 t i m e f r a m e v i a R F P s o r o t h e r o p p o r t u n i t i e s Pr o c u r e a t l e a s t 3 5 M W o f vi a b l e a n d c o s t - e f f e c t i v e g e o t h e r m a l o r o t h e r b a s e - l o a d r e n e w a b l e s . M o n i t o r s o l a r a n d e m e r g i n g t e c h n o l o g i e s , g o v e r n m e n t f i n a n c i a l i n c e n t i v e s , a n d p r o c u r e s o l a r o r o t h e r co s t - e f f e c t i v e r e n e w a b l e r e s o u r c e s d u r i n g t h e 1 0 - y e a r i n v e s t m e n t h o r i z o n · C o n t i n u e t o e v a l u a t e t h e p r o s p e c t s a n d i m p a c t s o f R e n e w a b l e P o r t f o l i o S t a n d a r d r u l e s a t t h e s t a t e a n d fe d e r a l le v e l s , a n d a 4 j u s t t h e r e n e w a b l e a c q u i s i t i o n t i m e l i n e a c c o r d i n g l y Im p l e m e n t a b r i d g i n g s t r t e g y t o s u p p o r t a c q u i s i t i o n d e f e r r a l o f lo n g - t e r m i n t e r m e d i a t e l b a s e - l o a d r e s o u r c e ( s ) i n th e e a s t c o n t r o l a r e a u n t i l n o s o o n e r t h a n t h e b e g i n n i n g o f su m e r 2 0 1 4 . A c q u i r e t h e f o l l o w i n g r e s o u r c e s : Up t o 1 , 4 0 0 M W o f e c o n o m i c f r o n t o f f c e t r a n s a c t i o n s o n a n a n u a l b a s i s a s n e e d e d t h r o u g h 20 1 3 , t a k i n g a d v a n t a g e o f f a v o r a b l e m a r k e t c o n d i t i o n s At l e a s t 2 0 0 M W o f l o n g - t e r m p o w e r p u r c h a s e s Co s t - e f f e c t i v e i n t e r r p t i b l e c u s t o m e r l o a d c o n t r a c t o p p o r t i t i e s ( f o c u s o n o p p o r t i t i e s i n Ut a h ) · R e s o u r c e s w i l b e p r o c u r e d t h r o u g h m u l t i p l e m e a n s : ( 1 ) r e a c t i v a t i o n o f th e s u s p e n d e d 2 0 0 S A l l - S o u r c e RF P i n l a t e 2 0 0 9 , w h i c h s e e k s t h i r d q u a r t e r s u m e r p r o d u c t s a n d c u s t o m e r p h y s i c a l c u r i l m e n t Re n e w a b l e s 12 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i O C o r p - 2 0 0 8 I R P C h a p t e r I - E x e c u t i v e S u m m a r y 4 Pl a n t E f f c i e n c y Im p r o v e m e n t s 20 0 9 - 2 0 1 8 co n t r a c t s a m o n g o t h e r r e s o u r c e t y e s , ( 2 ) p e r i o d i c m i n i - R F P s t h a t s e e k r e s o u r c e s l e s s t h a n f i v e y e a r s i n te r m , a n d ( 3 ) b i l a t e r a l n e g o t i a t i o n s . C l o s e l y m o n i t o r t h e n e a r - t e r m n e e d f o r f r o n t o f f c e t r a n s a c t i o n s a n d r e d u c e a c q u i s i t i o n s a s a p p r o p r i a t e i f lo a d f o r e c a s t s i n d i c a t e r e c e s s i o n a r y i m p a c t s g r e a t e r t h a n a s s u m e d f o r t h e F e b r u a r y 2 0 0 9 l o a d f o r e c a s t . A c q u i r e i n c r e m e n t a l t r a n s m i s s i o n t h r o u g h T r a n s m i s s i o n S e r v i c e R e q u e s t s t o s u p p o r t r e s o u r c e ac q u i s i t i o n Pr o c u r e l o n g - t e r m f i r m c a p a c i t y a n d e n e r g y r e s o u r c e s f o r c o m m e r c i a l s e r v i c e i n t h e 2 0 1 2 - 2 0 1 6 t i m e f r a m e . T h e p r o x y r e s o u r c e s i n c l u d e d i n t h e p r e f e r r e d p o r t f o l i o c o n s i s t o f ( I ) a U t a h w e t - c o o l e d g a s c o m b i n e d - cy c l e p l a n t w i t h a s u m m e r c a p a c i t y r a t i n g o f 5 7 0 M W , a c q u i r e d b y t h e s u m m e r o f 2 0 1 4 , a n d ( 2 ) a 2 6 1 MW e a s t - s i d e i n t e r c o o l e d a e r o d e r i v a t i v e s i m p l e - c y c l e g a s p l a n t a c q u i r e d b y t h e s u m m e r o f 2 0 1 6 . P r o c u r e t h r o u g h a c t i v a t i o n o f th e s u s p e n d e d 2 0 0 8 a l l - s o u r c e R F P i n l a t e 2 0 0 9 Th e C o m p a n y p l a n s t o s u b m i t C o m p a n y r e s o u r c e s ( s e l f - b u i l d o r o w n e r s h i p t r a n s f e r s ) o n c e t h e su s p e n s i o n i s r e m o v e d . I n r e c o g n i t i o n o f t h e u n s e t t l e d U . S . e c o n o m y , e x p e c t e d c o n t i n u e d v o l a t i l t y i n n a t u r a l g a s m a r k e t s , a n d re g u l a t o r y u n c e r t a i n t y , c o n t i n u e t o s e e k c o s t - e f f e c t i v e r e s o u r c e d e f e r r a l a n d a c q u i s i t i o n o p p o r t u n i t i e s i n li n e w i t h n e a r - t e r m u p d a t e s t o l o a d / p r i c e f o r e c a s t s , m a r k e t c o n d i t o n s , t r a n s m i s s i o n p l a n s , a n d re g u l a t o r y d e v e l o p m e n t s . Pu s u e e c o n o m i c p l a n t u p g r a d e p r o j e c t s - s u c h a s t u b i n e s y s t e m i m p r o v e m e n t s a n d r e t r o f i t s - a n d u n i t av a i l a b i l i t y i m p r o v e m e n t s t o l o w e r o p e r a t i n g c o s t s a n d h e l p m e e t t h e C o m p a n y ' s f u t u r e C O 2 a n d o t h e r en v i r o n m e n t a l c o m p l i a n c e r e q u i r e m e n t s . S u c c e s s f u l l y c o m p l e t e t h e d e n s e - p a c k c o a l p l a n t t u r b i n e u p g r a d e p r o j e c t s b y 2 0 1 6 , w h i c h a r e e x p e c t e d to a d d 1 2 8 M W o f i n c r e m e n t a l i n t h e e a s t a n d 4 2 M W i n t h e W e s t w i t h z e r o i n c r e m e n t a l e m i s s i o n s . S e e k t o m e e t t h e C o m p a n y ' s a g g r e g a t e c o a l p l a n t n e t h e a t r a t e i m p r o v e m e n t g o a l o f 2 1 3 B t u / k W h b y 20 i t f 3 Pe a k i n g / In t e r m e d i a t e / Ba s e - l o a d Su p p l y - s i d e Re s o u r c e s 20 1 2 - 2 0 1 6 5 Cl a s s 1 D S M . M o n i t o r t u r b i n e a n d o t h e r e q u i p m e n t t e c h n o l o g i e s f o r c o s t - e f f e c t i v e u p g r a d e o p p o r t u n i t i e s t i e d t o f u t u r e pl a n t m a i n t e n a n c e s c h e d u l e s Ac q u i r e a t l e a s t 2 0 0 - 3 0 0 M W o f c o s t - e f f e c t i v e C l a s s i d e m a n d - s i d e m a n a g e m e n t p r o g r a m s f o r i m p l e m e n t a t i o n in t h e 2 0 0 9 - 2 0 1 8 t i m e f r a m e 20 0 9 - 2 0 i 8 I . P u r s u e u p t o 2 0 0 M W o f e x p a n d e d U t a h C o o l K e e p e r p r o g r a m p a r t i c i p a t i o n b y 2 0 1 8 . P u r s u e u p t o 1 3 0 M W o f a d d i t i o n a l c o s t - e f f e c t i v e c l a s s 1 D S M p r o d u c t s ( 9 0 M W i n t h e e a s t s i d e a n d 3 0 MW i n t h e w e s t s i d e ) t o h e d J ! e a J ! a i n s t t h e r i s k o f h i J ! h e r J ! a s v r i c e s a n d a f a s t e r - t h a n - e x v e c t e d r e b o u n d 2 P a c i f i C o m E n e r g y H e a t R a t e I m p r o v e m e n t P l a n , M a r c h 3 1 , 2 0 0 9 . 13 Pa c i f i C o r p - 2 0 0 8 I R P C h a p t e r I - E x e c u t i v e S u m m a r y 6 Cl a s s 2 D S M 20 0 9 - 2 0 1 8 7 Cl a s s 3 D S M 20 0 9 - 2 0 1 8 8 Di s t r i b u t e d Ge n e r a t i o n 20 0 9 - 2 0 1 8 9 Pl a n n i n g Pr o c e s s Im p r o v e m e n t s 20 0 9 - 2 0 1 0 in l o a d g r o w t h r e s u l t i n g f r o m e c o n o m i c r e c o v e r y P r o c u r e t h r o u g h t h e c u r r e n t l y a c t i v e 2 0 0 8 D S M R F P an d s u b s e q u e n t D S M R F P s · F o r 2 0 0 9 - 2 0 1 0 , i m p l e m e n t a s t a d a r d i z e d C l a s s 1 D S M s y s t e m b e n e f i t e s t i m a t i o n m e t h o d o l o g y f o r pr o d u c t s m o d e l e d i n t h e I R P . T h e m o d e l i n g w i l c o m p l i m e n t t h e s u p p l y c u r v e w o r k b y p r o v i d i n g ad d i t i o n a l r e s o u r c e v a l u e i n f o r m a t i o n t o b e u s e d t o e v o l v e c u r e n t C l a s s 1 p r o d u c t s a n d e v a l u a t e n e w pr o d u c t s w i t h s i m i l a r o p e r a t i o n a l c h a r a c t e r i s t i c s t h a t m a y b e i d e n t i f i e d b e t w e e n p l a n s . Ac q u i r e 9 0 0 - 1 , 0 0 0 M W o f c o s t - e f f e c t i v e C l a s s 2 p r o g r a m s b y 2 0 1 8 ( p e a k c a p a c i t y ) , e q u i v a l e n t t o a b o u t 4 3 0 t o 48 0 M W a · P r o c u r e t h r o u g h t h e c u r r e n t l y a c t i v e D S M R F P a n d s u b s e q u e n t D S M R F P s Ac q u i r e c o s t - e f f e c t i v e C l a s s 3 D S M p r o g r a m s b y 2 0 1 8 · P r o c u r e p r o g r a m s t h r o u g h t h e c u r r e n t l y a c t i v e D S M R F P a n d s u b s e q u e n t D S M R F P s · C o n t i n u e t o e v a l u a t e p r o g r a m a t t r i b u t e s , s i z e / d i v e r s i t y , a n d c u s t o m e r b e h a v i o r p r o f i l e s t o d e t e r m i n e th e e x t e n t t h a t s u c h p r o g r a m s p r o v i d e a s u f f c i e n t l y r e l i a b l e f i r m r e s o u r c e f o r l o n g - t e r m p l a n n i n g · P o r t f o l i o a n a l y s i s w i t h C l a s s 3 D S M p r o g r a m s i n c l u d e d a s r e s o u r c e o p t i o n s i n d i c a t e d t h a t a t l e a s t 10 0 M W m a y b e c o s t - e f f e c t i v e ; c o n t i n u e t o e v a l u a t e p r o g r a m s p e c i f c a t i o n a n d c o s t - e f f e c t i v e n e s s i n th e c o n t e x t o f I R P p o r t f o l i o m o d e l i n g Pu r s u e a t l e a s t 1 0 0 M W o f d i s t r b u t e d g e n e r a t i o n r e s o u r c e s b y 2 0 1 8 · P r o c u r e a t l e a s t 5 0 M W o f c o m b i n e d h e a t a n d p o w e r ( C H P ) g e n e r a t i o n : 3 0 M W f o r t h e e a s t s i d e an d 2 0 M W f o r t h e w e s t s i d e , t o i n c l u d e p u r c h a s e o f f a c i l t y o u t p u t p u r s u a n t t o P U R P A r e g u l a t i o n s su p p l y - s i d e R F P s ( r e n e w a b l e s h e l f R F P s a n d A l l S o u r c e R F P s , w h i c h p r o v i d e f o r Q F s w i t h a ca p a c i t y o f 1 0 M W o r g r e a t e r ) , a n d o t h e r o p p o r t u n i t i e s ; f o c u s o n r e n e w a b l e f u e l a n d o t h e r " c l e a n " fa c i l t i e s t o t h e e x t e n t t h a t fe d e r a l a n d s t a t e R e n e w a b l e P r o d u c t i o n T a x c r e d i t r u l e s p r o v i d e ad d i t i o n a l R e n e w a b l e E n e r g y C r e d i t v a l u e t o s u c h f a c i l i t i e s · P r o c u r e a t l e a s t 5 0 M W o f c o s t - e f f e c t i v e c u s t o m e r s t a n d b y g e n e r a t i o n : 3 8 M W f o r t h e e a s t s i d e (s u b j e c t t o a i r p e r m i t t i n g r e s t r i c t i o n s a n d o t h e r i m p l e m e n t a t i o n c o n s t r a i n t s ) a n d 1 2 M W f o r t h e w e s t si d e . P r o c u r e m e n t t o b e h a n d l e d b y c o m p e t i t i v e R F P f o r d e m a n d r e s p o n s e n e t w o r k s e r v i c e a n d / o r in d i v i d u a l c u s t o m e r a g r e e m e n t s · S e e k u p t o a n a d d i t i o n a l 4 0 M W o f c u s t o m e r s t a n d b y g e n e r a t i o n i f t h e e c o n o m i c r e c e s s i o n a n d ma r k e t c o n d i t i o n s c o n t i n u e t o s u p p o r t e l i m i n a t i o n o f s i m p l e - c y c l e g a s u n i t s o r o t h e r p e a k i n g re s o u r c e s a s i n d i c a t e d b y I R p o r t f o l i o m o d e l i n g f o r t h e 2 0 1 0 b u s i n e s s p l a n / 2 0 0 8 I R P u p d a t e Po r t f o l i o m o d e l i n g i m p r o v e m e n t s · C o m p l e t e t h e i m p l e m e n t a t i o n o f S y s t e m O p t i m i z e r c a p a c i t y e x p a n s i o n m o d e l e n h a n c e m e n t s f o r im p r o v e d r e p r e s e n t a t i o n o f C O 2 a n d R P S r e g u l a t o r y r e q u i r e m e n t s a t t h e j u r s d i c t i o n a l l e v e l 14 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P C h a p t e r I - E x e c u t i v e S u m m a r y 10 Tr a n s m i s s i o n 20 0 9 - 2 0 1 1 11 Tr a n s m i s s i o n 20 1 0 12 Tr a n s m i s s i o n 20 1 2 . C o n t i n u e t o i m p r o v e w i n d r e s o u r c e m o d e l i n g b y r e f i n i n g t h e r e p r e s e n t a t i o n o f i n t e r m i t t e n t w i n d re s o u r c e s ; a t t i b u t e s t o c o n s i d e r i n c l u d e i n c r e m e n t a l r e s e r v e r e q u i r e m e n t s a n d o t h e r c o m p o n e n t s t i e d t o sy s t e m i n t e g r a t i o n , g e o g r a p h i c a l d i v e r s i t y i r n p a c t s , a n d p e a k l o a d c a r r i n g c a p a b i l t y e s t i m a t i o n . R e f i n e m o d e l i n g t e c h n i q u e s f o r D S M s u p p l y c u r e s / p r o g r a m v a l u a t i o n , a n d d i s t r i b u t e d g e n e r a t i o n . I n v e s t i g a t e a n d i m p l e m e n t , i f be n e f i c i a l , t h e L o s s o f Lo a d P r o b a b i l i t y ( L O L P ) r e l i a b i l i t y c o n s t r a i n t fu c t i o n a l i t y i n t h e S y s t e m O p t i m i z e r c a p a c i t y e x p a n s i o n m o d e l . C o n t i n u e t o c o o r d i n a t e w i t h P a c i f i C o r p ' s t r a n s m i s s i o n p l a n i n g d e p a r t m e n t o n i m p r o v i n g t r a n s m i s s i o n in v e s t m e n t a n a l y s i s u s i n g t h e I R P m o d e l s . C o n t i n u e t o i n v e s t i g a t e t h e f o r m u l a t i o n o f s a t i s f a c t o r y p r o x y i n t e r m e d i a t e - t e r m m a r k e t p u r c h a s e re s o u r c e s f o r p o r t f o l i o m o d e l i n g , c o n t i n g e n t o n a c q u i r i n g s u i t a b l e m a r k e t d a t a Es t a b l i s h a d d i t i o n a l p o r t f o l i o d e v e l o p m e n t s c e n a r i o s f o r t h e b u s i n e s s p l a n t h a t w i l b e c o m p l e t e d b y t h e e n d o f 20 0 9 , a n d w h i c h w i l s u p p o r t t h e 2 0 0 8 I R P u p d a t e . A f e d e r a l C O 2 c a p - a n d - t r a d e p o l i c y s c e n a r i o a l o n g t h e l i n e s o r i g i n a l l y p r o p o s e d f o r t h i s I R P . C o n s i d e r d e v e l o p i n g o n e o r m o r e s c e n a r i o s i n c o r p o r a t i n g p l u g - i n e l e c t r i c v e h i c l e s a n d S m a r t G r i d te c h n o l o g i e s Ob t a i n C e r t i f i c a t e s o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r U t a h / W y o m i n g / N o r t h w e s t s e g m e n t s o f th e E n e r g y Ga t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f i C o r p l o a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o ma r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . O b t a i n C e r t i f i c a t e o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r a 5 0 0 k V l i n e b e t w e e n M o n a T o O q u i r r h . O b t a i n C e r t i f i c a t e o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r 2 3 0 k V a n d 5 0 0 k V l i n e b e t w e e n W i n d s t a r an d P o p u l u s . O b t a i n C e r t i f i c a t e o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r a 5 0 0 k V l i n e b e t w e e n P o p u l u s a n d He m i n g w a y Pe r m i t a n d b u i l d U t a h / d a h o / N e v a d a s e g m e n t s o f th e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t Pa c i f i C o r p l o a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l i t y , a n d c o n g e s t i o n re l i e f . P e r m i t a n d c o n s t r c t a 3 4 5 k V l i n e b e t w e e n P o p u l u s t o T e r m i n a l Pe r m i t a n d b u i l d U t a h s e g m e n t o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f C o r p l o a d g r o w t h , re g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . P e r m i t a n d c o n s t r c t a 5 0 0 k V l i n e b e t w e e n M o n a a n d O q u i r r h 15 Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r I - E x e c u t i v e S u m m a r y 13 Tr a n s m i s s i o n 20 1 4 14 Tr a n s m i s s i o n 20 1 6 15 Tr a n s m i s s i o n 20 1 7 Pe r m i t a n d b u i l d s e g m e n t s o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f C o r p l o a d g r o w t h , re g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . P e r m i t a n d c o n s t r u c t 2 3 0 k V a n d 5 0 0 k V l i n e b e t w e e n W i n d s t a r a n d P o p u l u s . P e r m i t a n d c o n s t r u c t a 3 4 5 k V l i n e b e t w e e n S i g u r d a n d R e d B u t t e Pe r m i t a n d b u i l d N o r t h w e s t / U t a h / N e v a d a s e g m e n t s o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t Pa c i f C o r p l o a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n re l i e f . P e r m i t a n d c o n s t r c t a 5 0 0 k V l i n e b e t w e e n P o p u l u s a n d H e m i n g w a y Pe r m i t a n d b u i l d W y o m i n g / U t a h s e g m e n t o f th e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f C o r p lo a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . P e r m i t a n d c o n s t r c t a 5 0 0 k V l i n e b e t w e e n A e o l u s a n d M o n a 16 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . c . . . . . . . . . . . ............................................ PacifiCorp - 2008 IRP Chapter 2 - Introduction 2. INTRODUCTION PacifiCorp fies an Integrated Resource Plan (IRP) on a biennial basis with the utility commis- sions of Utah, Oregon, Washington, Wyoming, Idaho, and California. This IRP, representing the 10th plan submitted, fulflls the Company's commitment to develop a long-term resource plan that considers cost, risk, uncertainty, and the long-run public interest. It was developed though a collaborative public process with involvement from regulatory staff, advocacy groups, and other interested parties. This IRP also builds on PacifiCorp's prior resource planning efforts and reflects continued ad- vancements in portfolio modeling and performance assessment. These advancements include (I) extensive expansion of resource options considered, (2) a wider range of portfolios developed with alternative input assumptions using the Company's capacity expansion optimization tool, (3) more detailed presentation of renewable portfolio standard compliance requirements, and (4) adoption of a portfolio preference scoring methodology that incorporates probability-weighting of CO2 cost futues and importance weighting of various portfolio performance measures. The portfolio preference scoring methodology explicitly incorporates CO2 risk into the portfolio se- lection decision, and strctues the key performance measures into a composite ranng system that shows, in a transparent fashion, how PacifiCorp chose the optimal resource plan among sev- eral alternatives. Finally, this IRP reflects evolution of PacifiCorp's corporate resource planing approach. In early 2008, PacifiCorp embarked on a strategy to more closely align IRP development activities and the annual lO-year business planning process. The purose of the alignment was to: . provide corporate benefits in the form of consistent planning assumptions, . ensure that business planning is informed by the IRP portfolio analysis, and, likewise, that the IRP accounts for near-term resource affordability concerns that are the province of capi- tal budgeting, and; . improve the overall transparency of PacifiCorp's resource planning processes to public stakeholders. The planning alignent strategy also follows the 2007 adoption of the IRP portfolio modeling and analysis approach for Requests for Proposals (RFP) bid evaluation.3 This latter initiative was part of PacifiCorp' s effort to unify planning and procurement under the same analytical framework. This chapter outlines the components of the 2008 IRP, summarizes the role of the IRP, describes the IRP/business plan alignent strategy and progress to date, and provides an overview of the public process. 3 For its 2012 Base Load RFP, PacifiCorp used the IR Monte Carlo production cost simulation model to evaluate costs and risks of portfolios with bid resources optimized with different input assumptions (C02 cost, fuel prices, and planing reserve margins). 17 PacifìCorp - 200BIRP Chapter 2 - Introduction The basic components ofPacifiCorp's 2008 IRP, and where they are addressed in this report, are outlined below. · The set of IRP principles and objectives that the Company adopted for this IRP effort, as well as a discussion on customer/investor risk allocation (this chapter). · An assessment of the planning environment, including PacifiCorp's 2009 business plan- developed in 2008 and approved by MidAerican Energy Holdings Company (MEHC) board of directors in December 2008, market trends and fudamentals, legislative and regula- tory developments, and curent procurement activities (Chapter 3). · A description of PacifiCorp's transmission plannng effort and its linkages to the integrated resource planning effort (Chapter 4). · A resource needs assessment covering the Company's load forecast, status of existing re- sources, and determination of the load and energy positions for the i O-year resource acquisi- tion period (Chapter 5). · A profie of the resource options considered for addressing futue capacity deficits (Chapter 6). · A description of the IRP modeling, risk analysis, and portfolio pedormance ranking proc- esses (Chapter 7). · Presentation of IRP modeling results, and selection of top-pedorming resource portfolios and PacifiCorp's preferred portfolio (Chapter 8) · An IRP action plan linkng the Company's preferred portolio with specific implementation actions, including an accompanying resource acquisition path analysis and discussion of re- source risks (Chapter 9) · PacifiCorp's transmission expansion action plan, focusing on the Energy Gateway Transmis- sion project (Chapter 10) The IRP appendices, included as a separate volume, comprise detailed IRP modeling results (Appendices A and B), fulfillment of IRP regulatory compliance requirements, (Appendix C), the public input process (Appendix D), additional load forecast information (Appendix E), the results of PacifiCorp's wind integration cost study (Appendix F), energy efficiency program avoided cost estimates (Appendix G), and additional load and resource balance information per- taining to the Lake Side II combined-cycle gas plant (Appendix H). 18 ............................................ ............................................ Paci~Corp - 2008 IRP Chapter 2 - IntroduCtion ,~;;,iJi'flii_ PacifiCorp's IRP mandate is to assure, on a long-term basis, an adequate and reliable electricity supply at a reasonable cost and in a manner "consistent with the long-ru public interest.,,4 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, 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 tradeoffs, including supporting Request for Proposals (RFP) bid evaluation efforts. As an exter- nal 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 gen- eration, demand-side, and transmission resources. "~"1J7?d~'~% :~,/' Alignment Strategy Overvew The alignment strategy consists of the following four elements: . Scheduling synchronization - PacifiCorp modified its IRP preparation schedule to accom- modate business plan preparation beginning in March 2008 and ending in late November 2008, culminating with plan approval in mid-December 2008 by the MidAmerican Energy Holdings Company (MEHC) board of directors. . Input assumption synchronization - The IRP models are updated on a real-time basis as changes to business plan assumptions occur. These changes include, but are not limited to, revised load forecasts, forward price cures, resource costs, and environmental compliance policy assumptions. Public stakeholders are updated on major changes to input assumptions. . IR modeling support for business plan development - For each business planning sce- naro5, PacifiCorp conducts IRP modeling to produce a resource portfolio for capital budget- 4 The Oregon and Utah Commissions cite "long run public interest" as par of their defmition of integrated resource planning. Public interest pertins to adequately quantifying and captuing for resource evaluation any resource costs external to the utilty and its ratepayers. For example, the Uta Commission cites the risk of futue internalization of environmental costs as a public interest issue that should be factored into the resource portfolio decisionmaking process.5 A business planing scenaro represents a unique set of assumptions for producing a planing outcome and associ- ated fmancial results for a lO-year period. The business planing schedule accounts for preparation of thee scenar- ios. Typically, the goal of each successive scenario is to (1) improve customer service and operational and financial results by optimizing operational expenditues and capital investments in accordance with the Company's business strategy, and (2) incorporate updated assumptions into the business planing process. Each planing scenaro re- quires a complete processing cycle, including input collection and aggregation, tax estimation, cash-flow optimiza- tion through debt issuance and equity investment, quality assurance, and management review. The key product for each planning scenaro is a documentation package that describes the planing assumptions and contains a set of pro-forma financial statements conveying the financial impacts of the planing assumptions. PacifiCorp submits each planing scenario to MidAerican Energy Holdings Company for review and approval on pre-established dates. At the end of the year, after the business plan receives MEHC board approval, high-level business planning information is provided in fiings as required by state and federal regulations. Certin information 19 PadØCorp - 20081RP Chapter 2 - Introduaion ing and rate impact analysis by the corporate finance departent. In an iterative process, re- source constraints are applied to the portfolio optimization modeling to ensure that subse- quent portfolios are deemed affordable and finance able by senior management. · Public process - Through public meetings or other communication methods, the Company's IRP public participants are updated on significant business planning events. The relationship between the business plan and IRP preferred portolios are documented in the IRP action plan. Figue 2. I is a process flow diagram that shows the relationship between IRP activities, business plan preparation, and the public process originally envisioned for the 2008 IRP development cy- cle. Figure 2.1- IRPlBusiness Plan Process Flow ¡ ~: .' : - - - r - - - - - - - - - - - - - r - - - - - - - - - - - - - - - - - - - - - - - - ~:~~ ~:~~;m:~ - - - - - - - - )I I 20081RP Timeline, 2008 - 2009.01 Maron - September . .... ... .... Planning Process Alignment Challenges A key challenge for the alignment was to reconcile the different planning perspectives associated with the two-year IRP development cycle and the annual corporate business planing cycle. As mentioned above, the IRP is a strategic planing roadmap focused on the long-term costs and risks of resource portfolios, accounting for uncertinty. In contrast, PacifiCorp's business plan focuses on maintaining a strong financial position while ensurng customer's generation needs are met economically given the expected operating environment. Centrl to this business plan- ning goal is an emphasis on acquiring and managing the Company's assets to smooth the cost is also released on a confidential basis to vanous rating agencies and in certin regulatory dockets or other venues where necessar. 20 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 2 - Introduction impacts for customers. Successful alignment of the two planning processes thus entails balancing these perspectives as resource decisions are made. Another key challenge for the planing process alignent was to accommodate the preparation timing differences and analytical requirements for the two planning processes. The 10-year busi- ness plan is an annual process that entails frequent input assumption updates and preparation of multiple versions of the plan for internal prudence reviews. On the other hand, the IRP is a bien- nial planning process requirng extensive upfront model preparation, a public input process, and completion of specific analytical tasks cited in the state's IRP standards and guidelines and IRP acknowledgment orders. Meshing the planning processes entails significantly more departental coordination, along with an acceleration of the IRP modeling workflow to start portfolio devel- opment two to three months earlier than is tyically done for the IRP. A final key challenge was to provide modeling support for both the IRP and business plan while at the same time implementing major modeling enhancements. These enhancements included (1) unbundling Class 2 demand-side management programs (energy efficiency) from the load fore- casts and instituting a Class 2 DSM supply curve modeling approach, (2) expansion of resource options to include wind with different resource qualities, additional renewable technologies, en- ergy storage, nuclear, distrbuted generation, fuel cells, and additional front offce transaction product tyes, (3) improvements in modeling renewable portfolio standard (RPS) requirements, (4) computer and network infrastrcture upgrades, and (5) a major upgrade of the Planning and Risk production cost modeL. Given these challenges, the expectation was that the alignent would be conducted over a two- year span. Alignment Strategy Progress PacifiCorp successfully implemented all the planned IRP modeling system improvements, and maintained input consistency with business plan assumptions throughout the planing cycle. Im- portantly, the business plan benefited from implementation of the DSM class 2 supply curves, providing for the first time energy effciency program targets based on integrated resoure port- folio modeling with these resource options included. PacifiCorp also successfully provided an optimized resource portfolio for each business planning scenario. However, two alignment strategy objectives were not met. For the business plan, PacifiCorp originally intended to conduct alternative portfolio development with different input assumptions (basically a subset of the input scenarios defined for the IRP), and ru Monte Carlo production cost simulations to compare portfolio stochastic costs and risks. Additionally, public reporting goals on the progress of business plan preparation could not be accommodated in the schedule. There were two reasons for not meeting these objectives. First, business plan portfolio optimiza- tion modeling required frequent updates in reaction to volatile energy markets, the financial mar- ket crisis, a deteriorating load growth outlook, and continued resource cost increases. This caused a delay of the start of IRP modeling, while the tuaround time for business plan model- ing precluded establishment of a meaningful public comment and response process. Second, the modeling enhancements and system upgrades-particularly for the Planning and Risk model- took longer than expected. 21 PacifiCorp - 2008 IRP Chapter 2 - Introduction As a consequence of the IRP modeling delay, the business plan was approved by the MEHC board of directors in December 2008-prior to the completion of IRP modeling and selection of the 2008 IRP preferred portfolio. In accordance with the alignment strategy, the major resource changes relative to the business plan were analyzed for financial and ratepayer impact by the PacifiCorp Energy Finance Deparent. Major differences between the business plan resources and the 2008 IRP preferred portfolio are described in Chapters 8 and 9. The IRP standards and guidelines for certain states require PacifiCorp have a public process al- lowing stakeholder involvement in all phases of plan development. The Company held 17 public meetings/conference calls during 2008 and early 2009 designed to facilitate information sharing, collaboration, and expectations setting for the IRP. The topics covered all facets ofthe IRP proc- ess, ranging from specific input assumptions to the portolio modeling and risk analysis strate- gies employed. Table 2.1 lists the public meetigs/conferences and major agenda items covered. Table 2.1 - 2008 IRP Public Meetings State Staeholder In ut State Stakeholder In ut State Staeholder In ut State Stakeholder In ut State Stakeholder In ut State Staeholder In ut Worksho Worksho General Meetin General Meetin General Meetin State Staeholder 2/29/2008 4/9/2008 4/10/2008 4/2112008 4/22/2008 4/23/2008 5/14/2008 5/22/2008 5/23/2008 6/26/2008 11112/2008 12/18/2008 1172009 2/2/2009 3/1112009 3/19/2009 2008 IR modelin lan, business Uta staeholder comments Washin ton staeholder comments Idao staeholder comments Uta staeholder comments Uta state commission fili schedule for IR conference call New for this IRP was a series of state stakeholder dialogue sessions conducted from April though May 2008. The purpose of these sessions, targeting a state-specific audience, were to (1) captue key resource planing issues of most concern to each state and discuss how these can be tackled from a system planning perspective, (2) ensure that stakeholders understand PacifiCorp's planning principles and the logic behind its planning process, and (3) set expectations for what can be accomplished in the curent IRP/business planng cycle. This change in public process 22 ............................................ ................ II........................... PaciffCorp - 2008 IRP Chapter 2 - Introduction was intended to enhance interaction with stakeholders early on in the planning cycle, and pro- vided a forum to directly address stakeholder concerns regarding equitable representation of state interests during general public meetings. Appendix D, in the separate appendix volume, provides more details concerning the public meet- ing process and individual meetings. In addition to the public meetings, PacifiCorp used other channels to facilitate resource planning- related information sharng and consultation throughout the IRP process. The Company main- tains a website (http://www.pacificom.comlavigationlavigation23807.html).an e-mail "mail- box" (irpCipacificorp.com), and a dedicated IRP phone line (503-813-5245) to support stake- holder communications and address inquiries by public paricipants. ":7..-rß"".ö:\\TY' MEHC and PacifiCorp committed to continue to produce IRPs according to the schedule and various state commission rules and orders at the time the transaction was in process. Other com- mitments were made to (1) encourage stakeholders to participate in the integrated resource plan- ning process and consider transmission upgrades, (2) develop a plan to achieve renewable re- source commitments, (3) consider utilization of advanced coal-fuel technology such as IGCC technology when adding coal-fueled generation, (4) conduct a market potential study of addi- tional demand-side management and energy effciency opportities, (5) evaluate expansion of the Blundell Geothermal resource, and (6) include utility "own/operate" resources as a bench- mark in futue request for proposals. The Transaction Commitments Annual Report for 2009 is in progress and due to be fied with each Commission on Friday, May 29,2009. 23 ............................................ Paci~Corp - 2008 IRP Chapter 3 - The Planning Environment 3. THE PLANNING ENVIRONMENT This chapter profies the major external influences that impact PacifiCorp's long-term resource planning as well as recent procurement activities drven by the Company's past IRPs. External influences are comprised of events and trends affecting the economy and power industr market- place, along with governent policy and regulatory initiatives that influence the environment in which PacifiCorp operates. A key resource planning consideration has been the faltering U.S. economy and tightening of credit markets. Changing economic circumstances have required the Company to continuously re-evaluate and adjust load growth and market price expectations throughout this planning cycle, a process mentioned in the previous chapter in the context of 2009 business plan preparation. For capital expenditue planning, the Company's challenge has been to minimize customer rate im- pacts in light of a substantial capital spending requirement needed to address customer load growth, support governent environmental and energy policies, and maintain trnsmission grd reliability. To address this challenge, PacifiCorp is scrutinizing capital projects for cost reduc- tions or deferrals that make economic sense in today's market environment. Along these lines, the Company recently decided to seek more cost-effective alternatives to the planned Lake Side II combined-cycle gas plant project in Utah. The implications of this resource decision for the IRP are addressed in this chapter. Concerning the power industr marketplace, the major issues addressed include capacity re- source adequacy and associated standards for the Western Electrcity Coordinating Council (WECC) and the prospects for long-term natual gas commodity price escalation and continued high volatility. As discussed elsewhere in the IRP, futue 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 portolio that best balances low-cost and low-risk planning objectives. On the governent policy and regulatory front, the largest issue facing PacifiCorp continues to be planning for an eventual, but highly uncertin, climate change regulatory regime. This chapter focuses on climate change regulatory initiatives, particularly at the state leveL. A high-level summary of the Company's greenhouse gas emissions mitigation strategy, as well as an over- view of the Electrc Power Research Institute's study on carbon dioxide price impacts on western power markets, follows. This chapter also reviews the significant policy developments for cur- rently-regulated pollutants Other topics covered in this chapter include the Energy Independence and Security Act of 2007, the status of renewable portfolio standards, hydroelectrc licensing, and resource procurement activities. 25 PaeifCorp - 2008 IRP Chapter 3 - The Planning Environment 1i_I..r:1 ik~:l\tjr -"'B.;"'-~V;::T&:;";P-, '-;''';':':UYK~:E''Y~;/'~W'''._ ~~nWjY' ,:x.~--"':%:;t~fF"-"'- 'Oo:,e;;,:%'",:v:ttoV t'~;:¿b~,~o' --~~,,~;úú_:rA~,T~.!t!'-:.o.oo,o,ot:,;,, ,,~,~_._.. *,:,~" '''''''_ In February 2009, PacifiCorp decided to terminate the constrction contract for the Lake Side II combined-cycle plant, which was planned to be in commercial operation by the summer of2012. The decision to seek other resource alternatives was drven by the worsening recessionary envi- ronment, declines in load growth, continued declines in forward electrcity and gas prices, the outlook for future plant constrction costs, and additional transmission import capability into Utah confirmed with recently completed transmission studies. The constrction termination deci- sion occured after initial selection of the 2008 IRP preferred portfolio, but before finalization of the IRP document and preparation of the IRP action plan. Consequently, PacifiCorp decided to conduct additional portfolio analysis to determine the impacts of excluding Lake Side II as a planned resource in 20 i 2, and then update the preferred portfolio and develop the action plan accordingly. This analysis consisted of the following five steps: . Revise the load and resource balance to reflect the absence of the Lake Side II CCCT plant in 2012 (shown in Chapter 5). . Update the IRP models with new transmission and market purchase availability information that can facilitate cost-effective alternatives to a single large 2012 resource addition (de- scribed in Chapter 6). . Use the Company's capacity expansion optimization model to develop a set of alternative portfolios without the Lake Side II plant, applying the same input scenarios ("cases") that yielded the top-performing portfolios in PacifiCorp's original portfolio analysis. (This portfo- lio development is summarized in Chapter 8.) . Conduct stochastic Monte Carlo production cost simulation of the alternative portfolios, and determine the new preferred portfolio with the support of the portfolio preference scoring methodology adopted for this IRP. (The portolio pedormance evaluation is described in Chapter 8.) . Include the findings of the portolio analysis in the IRP action plan and supporting acquisi- tion path analysis. PacifiCorp's system does not operate in an isolated market. Operations and costs are tied to a larger electrc system known as the Western Interconnection which fuctions, on a day-to-day basis, as a geographically dispersed marketplace. Each month, milions of megawatt-hours of energy are traded in the wholesale electrcity market. These trnsactions yield economic effi- ciency by assurng that resources with the lowest operating cost are serving demand in a region and by providing reliability benefits that arise from a larger portfolio of resources. PacifiCorp paricipates in the wholesale market in this fashion, making purchases and sales to keep its supply portolio in balance with customers' constantly varying needs. This interaction 26 ............................................ ............................................ PacifiCorp - 2008 iRP Chapter 3 - The Planning Environment with the market takes place on time scales ranging from hourly to years in advance. Without the wholesale market, PacifiCorp or any other load serving entity would need to constrct or own an unecessarily large margin of supplies that would go unutilized in all but the most unusual 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 experience of the 2000-2001 market crisis, followed by the rapid price escalation during the first half of 2008 and subsequent demand destrction and rapid price declines in the second half of 2008, have under- scored. As with all markets, electrcity markets are faced with a wide range of uncertinties. However, some uncertainties are easier to evaluate than others. Market participants are routinely studying demand uncertainties drven by weather and overall economic conditions. Similarly, there is a reasonable amount of data available to gauge resource supply developments. For example, the Western Electrcity Coordinating Council (WECC) publishes an anual assessment of power supply and any number of data services are available that track the status of new resource addi- tions. The latest WECC power supply assessment, published in November 2008, indicates that the Basin and Rockies sub-regions wil be resource deficit, after accounting for reserves, by 201 1. (It should be noted that this assessment does not account for the recent recessionary im- pacts on load growth and various utilities' resource plans.) There are other uncertainties that are more difficult to analyze and that possess heavy influence on the direction of futue prices. One such uncertinty is the evolution of natual gas prices. Given the increased role of natual gas-fired generation, gas prices have become a critical deter- minant in establishing western electrcity prices, and this trend is expected to continue over the term of this plan's decision horizon. Another critical uncertainty that weighs heavily on this IRP is the prospect of future green house gas policy. A broad landscape of federal, regional, and state proposals aiming to curb green house gas emissions continues to widen the range of plausible future energy costs, and consequently, futue electrcity prices. Each of these uncertainties is explored in the cases developed for this IRP and are discussed in more detail below. Natural Gas Uncertainty Over the last eight years, North American natual gas markets have demonstrated exceptional price escalation and volatility. Figue 3.1 shows historical day-ahead prices at the Henr Hub benchmark from April 2, 2002 though February 3, 2009. Over this period, day-ahead gas prices settled at a low of $1.72 per MMBtu on November 16,2001 and at a high of $18.41 per MMBtu on February 25,2003. Durng the fall and early winter of2005, prices breached $15 per MMBtu after a wave of hurrcanes devastated the gulf region in what tued out to be the most active hur- ricane season in recorded history. More recently, prices topped $13 per MMBtu in the sumer of 2008 when oil prices began their epic climb above $140 per barreL. During this period, the natual gas market was also concerned that declining imports and slow growt in domestic pro- duction would create a storage shortfall going into the heating season. However, as the year pro- gressed, it became increasingly evident that gains in unconventional supply was growing at an unprecedented pace, quellng fears of an unbalanced market. At the same time, the market began accounting for sharp declines in demand as the financial crisis evolved into a full-scale global recession. Consequently, prices retreated just as quickly as they rose. 27 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment Figure 3.1- Henry Hub Day-ahead Natural Gas Price History $20 $19 $18 $17 $16 $15 $14 $13 $12 S $11= ~ $10 ~ $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 . Tight supplies . Oil price spike coinciding with Nort Korean missile launch into the Sea of Japan . War rhetoric building in ad- vance ofTrao . Most active hurrcane season in recorded history . Katr Rita, and Wilma cause significant shut-ins and eventul pro- duction losses in the Gulf Region . Epic rise in oil prices and general rush to commodi- ties . Fear of storage shortalls going into the heating season ..== § ....N N N ..a a ::::::II II II Io Io Io r-t"t"oo 00 00 i:===========================================~~~~~ § ~~~~~~~~~~ § ~~§ ~~~~~~~~~~N ~N ~N N N ~~QC ~QC QC QC -.QC ~QCNNNN~N................ 1- Day Ahead Index - Average Annual Price I Source: IntercontinentalExchange (ICE), Over the Counter Day-ahead Index Beyond the geopolitical, extreme weather, and economic events that spawned some rather spec- tacular highs in the recent past, natul gas prices have exhibited an underlying upward trend from approximately $3 per MMBtu in 2002 to nearly $7 per MMBtu by 2007. Over much of this period, declining volumes from conventional, matue producing regions largely offset growth from unconventional resources. Figue 3.2 shows a breakdown of u.s. supply alongside natural gas demand by end-use sector. Total supply, led by declines in domestic production, dropped steadily from 2001 through 2005. While total supply posted modest gains in 2006 and 2007, domestic production remained below the levels recorded in 2001. On the demand side, substantial expansion of gas-fired generating resources had more than offset declines in industral demand for natual gas. This shift reduced the amount of industral demand that is most price-elastic and increased inelastic generation de- mand. With higher finding and development costs of unconventional resources, the price level necessary to stimulate such marginal supply had grown. Until the recent economic downtu, substantial oil price escalation also supported higher natual gas prices, lifting the price of mar- ginally competitive gas substitutes and the value of natual gas liquids. Combined, the above factors contrbuted to a pronounced supply/demand imbalance in North American natual gas markets, raising prices sufficiently high to discourage marginal demand and, at times, attacting imports from an equally tight global market. This imbalance also made 28 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment North American markets more susceptible to upset from weather and other event shocks such as those discussed earlier. Figure 3.2 - U.S. Natural Gas Balance History 70 60 50 40 è= 30 20 10 o suppiy Demand II Domestic Supply II Net Pipeline Supply II Net LNG Supply II Res/Com Demand II Industrial Demand II Power Demand II Other Demand Source: U.S. Deparuent of Energy, Energy Information Admnistration The supply/demand balance began to shift in 2007 and 2008 thanks to an unprecedented and un- expected burst of growth from unconventional domestic supplies across the lower 48 states. With rapid advancements in horizontal drllng and hydraulic fracturing technologies, producers began drlling in geologic formations such as shale. Some of the most prominent contrbutors to the rapid growth in unconventional natural gas production have been the Barnett Shale located beneath the city of Fort Wort, Texas and the Woodford Shale located in Oklahoma. Strong growth also continued in the Rocky Mountain region. Looking forward, many forecasters have been expecting that a gradual restoration of improved supply/demand balance would be achieved largely with growth in liquefied natul gas (LNG) imports. Indeed, there has been tremendous growth in global liquefaction facilities located in major producing regions, and additional projects are expected to come online in 2009 and 2010. Concurently, U.S. regasification capacity has grown to overbuild proportions. As of the end of 2008 U.S. regasification capacity was 4.7 times larger than the 1.98 BCF/d of LNG imports logged in 2007, and additional capacity is scheduled to go online in 2009 and 2010. Even with substantial gains in global LNG supplies and in domestic regasification capacity, the Nort 29 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment American market has not been able to consistently lure shipments from Asian and European markets, where gas prices are more directly linked to the price of oiL. With the recent expansion of unconventional production and the evolution of global LNG mar- kets, many forecasters and market participants are beginnng to reassess how mid- to long-term markets wil balance. For example, the U.S. Energy Information Administration's (EIA) Anual Energy Outlook (AEO) from 2007 forecasted that LNG imports would top 8 BCF/d by 2015. In the early look of AEO 2009 released in December 2008, the EIA expects 2015 LNG imports to total 3.4 BCF /d - just 41 percent of the LNG imports projected two years earlier. Beyond the near-term, where demand is being depressed by the curent economic downtu, it is increasingly believed that unconventional supplies from North America are poised to meet incremental de- mand upon economic recovery. Under such a scenaro, North American gas prices would remain decoupled from the global LNG market, and consequently decoupled from Asian and European natual gas markets, which are more heavily influenced by the price of oiL. Several factors contribute to a wide range of price uncertinty in the mid- to long-term. On the downside, technological advancements underlying the recent expansion of unconventional sup- plies opens the door to tremendous growth potential in both production and proven reserves from shale formations across North America. A number of shale formations outside of the Barnett and Woodford have already stared to show upside potential. A sign of the times, the proposed Kiti- mat regasification terminal in British Columbia, Canada anounced that the project was being redesigned as a liquefaction terminal apparently due to interest in the Horn River and Motney shale formations within the province. On the upside, the next generation of unconventional sup- plies may prove to be more diffcult to extract, raising costs, and consequently, raising prices. Moreover, a concerted U.S. policy effort to shift the transportation sector away from oil toward natual gas has potential to significantly increase demand, and thus natual gas prices. Western regional natual gas markets are likely to remain well-connected to overall North American natual gas prices. Although Rocky Mountain region production, among the fastest growing in North America, has caused prices at the Opal and Cheyenne hubs to trnsact at a dis- count to the Henr Hub benchmark in recent years, major pipeline expansions to the mid-west and east coupled with fuher pipeline expansion plans to the west are expected to maintain mar- ket price correlations going forward. In the Nortwest, where natual gas markets are influenced by production and imports from Canada, prices at Sumas have traded at a premium relative to other hubs in the region. This has been drven in large par by declines in Canadian natual gas production and reduced imports into the U.S. In the near-term, Canadian imports from British Columbia are expected to remain below historical levels lending support for basis differentials in the region; however, in the mid- to long-term, production potential from regional shale forma- tions wil have the opportity to soften the Sumas basis. Greenhouse Gas Policy Uncertainty There is a wide range of policy proposals to limit greenhouse gas emissions within the U.S. economy. At the federal level, Senators Bingaman and Specter sponsored the Low Carbon Econ- omy Act of 2007 (the Bingaman Bil), and more recently, Senators Lieberman and Warer intro- duced the Climate Securty Act of 2008 (the Lieberman Warner Bil), while Representatives Waxman and Markey introduced the American Clean Energy and Securty Act of 2009 (H.R. 30 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment 2454). While it remains unclear what tyes of federal proposals wil be debated going forward, there have been clear signals that the Obama administration has more of an appetite than the pre- vious administration to address the climate change issue. At the state and regional level, the Re- gional Greenhouse Gas Initiative (RGGI), a cap-and-trade program to restrct carbon dioxide emissions in Northeastern and Mid-Atlantic states, took affect in 2008. A similar approach is be- ing explored in the Midwest under the Midwest Greenhouse Gas Accord. In the West, the West- ern Climate Initiative continues its work toward establishing rules for its own cap-and-trade pro- gram. Additional details on greenhouse gas policy developments are discussed later in this chap- ter. As the policy debate continues, a cloud of uncertainty continues to hang over the electrc sector, with substantial implications for investment decisions and wholesale electrcity markets. There are a host of uncertainties stemming from the policy debate: . If emission limits are put in place, wil they cover the entire U.S. economy or wil they target specific sectors? . Wil emission reductions be achieved though a cap-and-trade approach, though a carbon tax, or some combination of the two? . What role, if any, wil domestic and international offsets play in achieving emission re- ductions in the U.S.? . Wil emission reductions be achieved through a national program that preempts state and regional initiatives, wil there be a more Balkanized approach, or wil there be a national program layered on top of state and regional initiatives? . How wil renewable portfolio standards be coordinated or integrated with emission re- duction regulations? Regardless of how the policy debate unfolds, one thing remains clear. If limits are placed on greenhouse gas emissions, it is highly probable that the electrc sector wil be required to reduce emissions, and these emission reductions wil come with a cost. Whether the costs are directly assessed in the form of a tax or are indicative of opportity costs monetized in a market devel- oped under a cap-and-trade program, all else equal, the cost to produce electrcity wil increase, and wholesale prices wil respond. The projected cost of greenhouse gas emission reductions are intrnsically tied to policy details and vary considerably. Even for a given policy, there are a wide range of future cost estimates drven by long-term assumptions such as electrcity demand, tech- nological advancements, and varying interpretations of policy implementation rules. For exam- ple, in the December 17, 2008 auction for RGGI carbon dioxide emission allowances, prices cleared at $3.38/ton. In contrast, the Energy Information Administration's (EIA) analysis of the Lieberman Warner Bil projected nominal allowance prices by 2030 ranging from nearly $35/ton to approximately $275/ton, while the U.S. Environmental Protection Agency's preliminar study of the Waxman-Markey Bil cited a scenaro C02 cost range per metrc ton of $17 to $33 by 2020.6 6 A discussion draft of the EPA study is available at: http://www.epa.gov/climatechange/economics/pdfs!WM- Analysis.pdf. The discussion draft notes that are remaining legislative uncertinties that could significantly change study results, and that the study represents limited coverage of bil provisions. 31 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment When a cost is placed on greenhouse gas emissions, it effectively becomes an additional varable cost facing an electrc generator, and in much the same way that fuel costs affect plant dispatch decisions, emission costs influence how a plant operates. Because electrc generators burn dif- ferent tyes of fuel, have varying levels of efficiency, and are bound by different operational limitations, the impact of incremental green house gas costs varies across different types of tech- nologies. To understand how green house gas emission costs wil discriminately affect electricity markets, one can consider a simplified representation of the power system - a system that in- cludes two tyes of resources: (1) a coal-fired plant, and (2) a gas-fired combined cycle plant. Coal-fired assets, with limited operational flexibility and access to relatively low cost fuel, tend run around the clock. This tye of base load capacity is often used to satisfy demand even when it is quite low. On the other hand, while natual gas-fired combined cycle assets tyically have an effciency advantage relative to a coal plant, they are often faced with higher fuel costs and have more operational flexibility to alter their production in response to changing conditions. Consequently, this tye of resource is often ramped up as demand increases and ramped down when demand falls. In this way, coal resources are more likely to establish off-peak electricity prices than on-peak electrcity prices. Conversely, natul-gas fired capacity is more likely to set electricity prices during peak demand periods. When green house gas emission costs are intro- duced, this basic trend can be altered. Figue 3.3 shows ilustrative dispatch costs for a coal plant and a natual-gas fired combined cy- cle plant at different carbon dioxide pricing points - no cost, $8/ton, $45/ton, and $100/ton. The coal plant is assumed to have a heat rate of 10,000 BtuWh and is faced with fuel prices of $2 per MMBtu. The gas-fired plant is assumed to have a heat rate of 7,200 BtuWh and is faced with a fuel price of $6 per MMBtu. Without any incremental carbon cost, Figue 3.3 shows a decided cost advantage for the coal asset. While the operating cost advantage for a coal plant is maintained when carbon costs are at $8/ton, the cost advantage begins to narrow. At $45/ton, both technologies are on nearly equal footing, with a slight advantage now in favor of the gas- fired combined cycle asset. Finally, at $100/ton, the cost advantage is reversed and is now de- cidedly in favor of the gas-fired plant. 32 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment Figure 3.3 - Green House Gas Cost Implications for Electric Generators $140 $120 $100 .= ~~$80-~eU lO=$60¡....i:0 $40 $20 $0 Gas-fired Coal CCCT No C02 Gas-f"ired CCCT CoalCoal $8/ton C02 $45/ton C02 $100/ton C02 I- Fuel Cost i. C02 Cost I From the simplified example in Figure 3.3, one can appreciate how green house gas costs might affect wholesale electricity markets. With no carbon costs, the marginal unit is the gas-fired combined cycle, which, in this example, would support electrcity prices somewhere north of $43 per MWh. When carbon costs climb to $IOO/ton, the marginal coal unit from this example would support wholesale electrcity prices north of $ 120 per MWh. Of course, in reality, the power sys- tem is more complex than this simplified representation. There are additional resources-hydro power, nuclear, gas-fired peaking plants, and renewables-competing in the market. Moreover, there are other interactions that are likely to take place as greenhouse gas costs escalate and op- erational changes are implemented accordingly. For example, as carbon costs rise, it is possible that natural gas demand would increase, exerting upward pressure on gas prices. Similarly, even though natual fired capacity has a cost advantage relative to coal at higher carbon costs, coal does not have the operational flexibility to ramp output up and down with swings in demand. Regardless, given the range of potential policy outcomes, it is evident that the implications for greenhouse gas costs in the wholesale electricity market are highly variable and highly uncertain. There are additional implications for the wholesale electrcity market that extend beyond the di- rect cost impacts discussed above. For example, if carbon costs are exceptionally high and/or particularly volatile, the number of parties wiling and or able to transact may begin to dwindle, and it is possible that depth and liquidity in the forward markets may suffer. Similarly, if a more Balkanized policy landscape materializes, there is a risk that transaction costs among market par- ticipants would increase. In yet another scenario, it is conceivable that poorly coordinated im- 33 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment plementation rules among multiple programs might cause some market participants to retreat from specific trading hubs that are caught in a jursdictional web of rules and ambiguity. Curently, 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 the EPA to establish air quality standards to protect public health and the environment. PacifiCorp's plants must comply with air permit requirements designed to ensure attainment of air quality standards as well as the new source review (NSR) provisions of the CAA. NSR requires existing sources to obtain a permit for physical and opera- tional changes accompanied by a significant increase in emissions. Ozone Final action on the revisions to the National Ambient Air Quality Standads for ozone was com- pleted on March 12,2008. The EPA announced that the National Ambient Air Quality Standards for primary and secondary ground-level ozone would be significantly strengthened. The primary ozone standard, which is designed to protect public health and the secondary standard, which is designed to protect public welfare (including crops, vegetation, wildlife, buildings, national monuments, and visibility) from the negative effects of ozone, were both reduced to 0.075 parts per milion. The new standards took effect on May 27, 2008. States have until March 12,2009, to make rec- ommendations to the EPA as to whether an area should be designated attainment (meeting the standard), nonattainment (not meeting the standard) or unclassifiable (not enough information to make a decision). The EPA must promulgate its attinment!nonattinment designations by March 12,2010, unless a one-year extension is granted because of insuffcient information. By March 12, 2011, or one year after the EPA promulgates its designations, states wil be required to sub- mit their state implementation plans detailing how they wil meet the new stadards. A number of rules have been issued by the EPA that wil potentially help states make progress toward meeting the revised ozone standards, including the Clean Air Interstate Rule to reduce ozone forming emissions from power plants in the eastern United States, and the Clean Diesel Program to reduce emissions from highway, non-road and stationar diesel engines nationwide. Immediately following the promulgation of the strengtened ozone standards, multiple lawsuits were filed against the EPA. New York and thirteen other states sued the Environmental Protec- tion Agency on May 27,2008, demanding strcter air quality standards for ozone. New York was joined in the lawsuit by California, Connecticut, Delaware, Ilinois, Massachusetts, Maryland, Maine, New Hampshire, New Jersey, New Mexico, Oregon, the Pennsylvania Departent of Environmental Protection, and Rhode Island. New York City and the Distrct of Columbia also joined in the lawsuit. A coalition of environmental and public health advocates also filed a law- suit against the Environmental Protection Agency on May 27, 2008, in a bid to strengthen the ozone standard. Meanwhile, Mississippi and a coalition of industr trade groups fied separate petitions for review May 23, 2008, and May 27, 2008, respectively, in the. Distrct of Columbia Circuit Cour of Appeals, arguing the new standards are too strct. 34 ............................................ ............................................. PaeifCorp - 2008 IRP Chapter 3 - The Planning Environment After EPA tightened the 8-hour standard to 0.075 parts per milion, several Utah counties located along the Wasatch Front were put in jeopardy of being designated non-attinment. Utah is now using certified monitored ozone data from 2005-2007 to determine specifically which areas need to be designated non-attainment of the 0.075 parts per milion standard. The state must submit a recommendation to the EPA by March 2009. The EPA wil then either accept or modify the state's recommendation, based on certified data from 2006-2008, and issue a final designation by March 2010. In Utah, ozone is principally a summer time problem when temperatues are high and daylight hours are long, but it may have implications to wintertime particulate problems as well. It is a mix of chemicals emitted mainly from vehicle tailpipes, diesel engines and industral smokestacks. The Utah Departent of Environmental Quality has indicated that its anticipated control strategy would focus on transportation, including tightening regulations for gasoline sta- tions, and possibly consumer products, and certin industral emissions. Curently, with the exception of the Gadsby power plant, all of PacifiCorp Energy's operating fossil-fueled facilities are located in areas that are in attainment with the ozone National Ambient Air Quality Standards. The Gadsby plant is a gas fired facility located in downtown Salt Lake City, Salt Lake County, Utah. Salt Lake County is currently a non-attainment area for ozone. The Utah Departent of Environmental Quality has stated that at this time, no coal- or natual gas-fueled power plants wil be the subject of new control strategies. Particulate Matter On October 17,2006, the EPA issued new National Ambient Air Quality Standards for particle pollution. The final standards addressed two categories of particle pollution: fine particles (PM2.s), which are 2.5 micrometers in diameter and smaller; and inhalable coarse partcles (PMiO), which are smaller than 10 micrometers. The Environmental Protection Agency strength- ened the 24-hour fine paricle standard from the 1997 level of 65 micrograms per cubic meter to 35 micrograms per cubic meter, and retained the curent annual fine particle standard at 15 mi- crograms per cubic meter. The Agency also retained the existing national 24-hour PMiO standard of 150 micrograms per cubic meter and revoked the annual PMiO standard. The new federal standards has put Utah's Wasatch Front - including all of Salt Lake and Davis Counties and portions of Weber, Box Elder and Toole counties - into a "non-attainment" status- as well as the low-lying portions of Utah and Cache Counties. Utah has until 2012 to drft a plan to EPA on how it wil achieve compliance with the fine particulate NAAQS. According to the Utah Departent of Environmental Quality, much of the particulate pollution is attibutable to emissions from automobiles. Utah's monitoring suggests a seasonal problem characterized by episodic periods of very high concentrations of fine pariculate that consists mostly of secondar particulate. The formation of these secondary particles is drven by winter-time temperatue in- versions which trap air in urbanized valleys. The mix of emissions associated with the urbanized areas reacts very quickly under these conditions to produce spikes in the concentration of fine particulate. Under these conditions, the observed concentrations are fairly uniform throughout the entire urbanized area. This underscores the association of urban areas with a mix of emis- sions that inherently reacts under these conditions to form PM2.5, and helps to define PM2.5 somewhat as an "urban" pollutant. All of this serves to highlight the distinction between urban and rual areas. Much of this phenomenon is also due to the fact that population is generally lo- cated within the lowland valley areas in which air is easily trapped by a temperatue inversion. In 35 PacifiCorp - 2008 iRP Chapter 3 - The Planning Environment other words, it is not enough to simply have an urban area with an urban mix of emissions; there must also be a barer to dispersion under these conditions, which allows PM2.5 concentrations to build up over a period of several days and reach concentrations that exceed the NAAQS. This characterization of Utah's diffculties with fine pariculate has shaped the State's approach to making the area designations. Curently, with the exception of the Gadsby power plant, all of PacifiCorp' s operating fossil- fueled facilities are located in areas that are in attainment with the fine particulate National Am- bient Air Quality Standard. The Gadsby plant is a gas-fired facility located in downtown Salt Lake City, Salt Lake County, Utah. Salt Lake County has been proposed as a non-attainment area for fine particulate matter. The Utah Department of Environmental Quality has stated that at this time, no coal- or natual gas-fueled power plants wil be the subject of new fine particulate matter control strategies. Regional Haze Within existing law, EPA's Regional Haze Rule and the related efforts of the Western Regional Air Partership wil require nitrogen oxide, sulfu dioxide, and particulate matter emissions re- ductions to improve visibility in scenic areas. Arzona, New Mexico, Oregon, Utah and Wyo- ming originally submitted state implementation plans addressing regional haze based upon 40 CFR 51.309, focusing on the reduction of sulfu dioxide emissions from large industrial sources located thoughout the West. Regional Sulfu Dioxide Emissions and Milestone Reports, one of the requirements of the 309 state implementation plan, are submitted each year. The reports de- termine whether sulfu dioxide emitted by large industral sources exceeds the sulfur dioxide emission milestones set in the states' Regional Haze state implementation plans. The sulfur diox- ide milestones take into account emissions reductions either achieved or expected to be achieved from the installation of Best Available Retrofit Technology on eligible units. The State of Wyoming submitted revisions to the 2003 309 Regional Haze state implementation plan to EPA Region 8 on November 24, 2008 and wil now focus on impairment caused by sources of nitrogen oxides and partculate mattr. Work on this phase of regional haze planing is underway with a draft SIP expected in the spring of 2009. Utah similarly adopted revisions to its regional haze state implementation plan on September 3, 2008, which became effective and enforceable in Utah on November 10,2008. The package of materials was submitted to the EPA on September 18, 2008 and wil become federally enforceable after EPA approves them. Additionally, administrative rulemakings by EPA, including the Clean Air Interstate Rule wil require significant reductions in emissions from electrcal generating unts that directly impact the national market for sulfu dioxide allowances. Compliance costs associated with anticipated futue emissions reductions wil largely depend on the levels of required reductions, the allowed compliance mechanisms, and the compliance time frame. Mercury In March 2005, the EPA released the final Clean Air Mercur Rule ("CAMR"), a two-phase program that would have utilized a market-based cap and trde mechanism to reduce mercury emissions from coal-buring power plants from the 1999 nationwide level of 48 tons to 15 tons. The CAMR required initial reductions of mercur emission in 2010 and an overall reduction in 36 ............................................ ............................................ PacifìCorp - 2008 IRP Chapter 3 - The Planning Environment mercury emissions from coal-buring power plants of 70 percent by 2018. The individual states in which PacifiCorp operates facilities regulated under the CAMR submitted state implementa- tion plans reflecting their regulations relating to state mercury control programs. On Februar 8, 2008, a three-judge panel of the United States Court of Appeals for the District of Columbia Cir- cuit held that the EPA improperly removed electricity generating units from Section i 12 of the Clean Air Act and, thus, that the CAMR was improperly promulgated under Section 111 of the Clean Air Act. The cour vacated the CAMR's new source performance standards and remanded the matter to the EPA for reconsideration. On March 24, 2008, the EPA fied for rehearing of the decision of the three-judge panel by the full cour; rehearng was denied in May 2008. On Sep- tember 17, 2008, the Utility Air Regulatory Group petitioned the United States Supreme Court for a writ of certorari to review the United States Court of Appeals for the Distrct of Columbia Circuit's February 8, 2008 decision overtrning the rule. The EPA fied a petition to the United States Supreme Court on October 17,2008 seeking to overt the lower cour's ruling. While the Supreme Cour considers whether to grant the petition for a writ of certiorar, all new coal fueled electrc generating units and modifications of existing units wil be required to obtain permits under Section 112 (g) of the Clean Air Act. Under this provision, if no applicable emis- sion limits have been established for a category of listed hazardous air pollutant sources, no per- son may constrct a new major source or modify an existing major source in the category unless the EPA Administrator or the delegated state agency determines on a case by case basis that the unit wil meet standards equivalent to the maximum achievable emission controls. Thus, new major sources or modifications to an existing major source would be required to perform a case by case analysis of the maximum achievable control technology and meet the emissions limita- tion that could be achieved in practice by the best performing sources in that category. If the Su- preme Court decides to hear the appeal, any required maximum achievable control technology analysis requirement wil likely be stayed for the duration of the rehearng. Until the cour or the EPA take further action, it is not known the extent to which futue mercury rules may impact PacifiCorp's curent plans to reduce mercury emissions at their coal-fired facilities. 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 bilion over a ten-year period to install necessary equipment under futue emissions control scenarios to the extent that it's cost-effective. Climate change has emerged as an issue that requires attention from the energy sector, including utilities. Because of its contrbution to United States and global carbon dioxide emissions, the U.S. electrcity industr is expected to playa critical role in reducing greenhouse gas emissions. In addition, the electrcity industr 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 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 7 Refer to the memorandum from Robert Meyers, Deputy Assistant Administrator, Environmental Protection Agency, Office of Air and Radiation, dated Januar 7, 2009. 37 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment generation portfolio such as wind, geothermal, landfill gas, solar, combined heat and power (CHP), and hydro capacity upgrades, as well as investing in on-system and customer-based en- ergy effciency and conservation programs. PacifiCorp also continues to examine risk associated with future CO2 emissions costs. The section below summarzes issues surounding 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 tyes, coal has the highest carbon content, natual gas the lowest, and petro- leum in-between. In the Administration's Annual Energy Outlook 2009 Early Release reference case, energy-related CO2 emissions reflect the quantities of fossil fuels consumed and, because of their varying carbon content, the mix of coal, petroleum, and natual gas. Given the high car- bon content of coal and its use curently to generate more than one-half of U.S. electrcity, pros- pects for CO2 emissions depend in part on growt in electrcity demand. Electrcity sales growth in the AE02009 reference case slows as a result of a varety of regulatory and socioeconomic factors, including appliance and building effciency stadards, higher energy prices, housing pat- terns, and economic activity. With slower electrcity growt and increased use of renewables for electrcity generation influenced by RPS laws in many States, electrcity-related CO2 emissions grow by just 0.5 percent per year from 2007 to 2030. CO2 emissions from transportation activity also slow in comparison with the recent past, as Federal CAFE standards increase the efficiency of the vehicle fleet, and higher fuel prices moderate the growth in trvel. Taken together, all these factors tend to slow the growt of the absolute level of primary energy consumption and promote a lower carbon fuel mix. As a result, energy-related emissions of CO2 grow by 7 percent from 2007 to 203û-Iower than the 11-percent increase in total energy use. Over the same period, the economy becomes less carbon-intensive as CO2 emissions grow by about one-tenth of the increase in GDP, and emissions per capita decline by 14 percent. According to the U.S. Energy Information Administrtion, the factors that influence growth in CO2 emissions are the same as those that drve increases in energy demand. Among the most significant are population growth and shifts to. warmer regions that increase the need for cooling; increased penetration of computers, electronics, appliances, and office equipment; increases in commercial floor space; growt in industral output; increases in highway, rail, and air travel; and continued reliance on coal and natural gas for electrc power generation. The increases in demand for energy services are partially offset by efficiency improvements and shifts toward less energy-intensive industres. New C02 mitigation progrms, macroeconomic conditions, more rapid improvements in technology, or more rapid adoption of voluntary progrms could result in lower CO2 emissions levels. PacifiCorp carefully tracks CO2 emissions from operations and reports them in its annual emis- sions filing with the California Climate Action Registr. 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 (ED), Japan, 38 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment 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 seven percent below 1990 levels. The Protocol calls for both on-system and off-system emissions reductions. While the U.S. has thus far rejected the Kyoto Protocol, numerous proposals to reduce greenhouse gas emissions have been offered at the federal leveL. The proposals differ in their strngency and choice of policy tools. In June 2008, the Lieberman-Warner Bil-the Climate Security Act (CSA)-failed in the Sen- ate. The CSA set a goal for reducing greenhouse gas emissions of more than 60 percent by 2050.8 Furhermore, the CSA sought to institute a domestic offset program that would allow fa- cilities to meet up to 15 percent of their compliance with allowances generated by offset projects, or by purchasing or borrowing credits. The CSA also included a "Bonus Allowance Account" whereby companies would be awarded for sequestering their carbon emissions.9 Perceived ef- fects on the national economy derailed the CSA's passage. The EPA estimated the CSA would decrease the nation's gross domestic product between $238 bilion and $983 bilion by 2030, while increasing electricity prices 44 percent by 2030.10 Furher, due to rising electrcity costs the average household's consumption would decrease an average of$I,375 by 2030.u In addition to the CSA, On October 7, 2008, the former Chairman of the Committee on Energy and Commerce, John D. Dingell, released draft climate change legislation calling for the lower- ing of emissions to 80 percent of 2005 levels by 2050. The draft legislation proposes to balance its costs through high quality offsets, special reserve emission allowances, and carbon captue and sequestration. 12 Recent Democratic victories in the House, Senate and the Presidency appear likely to boost ef- forts to strengthen U.S. global warming policy. Congress and federal policy makers are consider- ing climate change legislation and a variety of national climate change policies and President Obama has expressed support for an economy-wide greenhouse gas cap and trade program that would reduce emissions 80 percent below 1990 levels by 2050. As a result of these policies, PacifiCorp's electric generating facilities are likely to be subject to regulation of greenhouse gas emissions within the next several years. u.S. Environmental Protection Agency's Advance Notice of Public Rulemaking On July i i, 2008, the Environmental Protection Agency released an Advance Notice of Pro- posed Rulemaking inviting public comment on the benefits and ramifications of regulating greenhouse gases under the Clean Air Act. This Advance Notice of Proposed Rulemaking is one 8 Erin Kelly, "Senate Poised to Take Up Sweeping Global Warming Bil," USA Today, http://www.usatoday.cominews/washingtonienvironment/2008-05-17-global-warmingN.htm. May 17,2008.9 Id 10 U.S. EPA, EPA Analysis of the Lieberman-Warner Climate Securty Act of 2008, available at: http://www .epa. gov / climatechange/ dO\\'lloads/s2191 EPA Analysis.pdf. 11 "U.S. Environmental Protection Agency Estimates Cost of Lieberman-Wamer Bil to Limit Greenhouse Gas Emissions," National Rural Electric Cooperative Association, available at: http://ww.nreca.org/main/RECA/PublicPolicy/issuespotlight/20080319ClimateChange.htm March 19, 2008. 12 John D. Dingell, Climate Change Discussion Draft Legislation, U.s House of Representatives, Committee on En- ergy and Commerce, October 7, 2008; For a complete list of the cap-and-trade legislation introduced in Congress in 2008, see http://\',iww.pewclimate.org/docUploads/Chart-and-Graph-120 108.pdf. 39 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment of the steps the Environmental Protection Agency has taken in response to the United States Su- preme Court's decision in Massachusetts v. Environmental Protection Agency.13 A decision to regulate greenhouse gas emissions under one section of the Clean Air Act could or would lead to regulation of greenhouse gas emissions under other sections of the Act, including sections estab- lishing permitting requirements for major stationary sources of air pollutants. The Advance Notice of Proposed Rulemaking reflects the complexity and magnitude of the question of whether and how greenhouse gases could be effectively controlled under the Clean Air Act. Many of the key issues for discussion and comment in the Advance Notice of Proposed Rulemakng included: · Descriptions of key provisions and progrms in the Clean Air Act, and advantages and disadvantages of regulating greenhouse gas emissions under those provisions. · How a decision to regulate greenhouse gas emissions under one section of the Clean Air Act could or would lead to regulation of greenhouse gas emissions under other sections of the Act, including sections establishing permitting requirements for major stationary sources of air pollutants. · Issues relevant for Congress to consider for possible futue climate legislation and the po- tential for overlap between futue legislation and regulation under the existing Clean Air Act. · Scientific information relevant to, and the issues raised by, an endagerment analysis. · Information regarding potential regulatory approaches and technologies for reducing greenhouse gas emissions. The Environmental Protection Agency accepted public comment on the Advance Notice of Pro- posed Rulemaking until November 28, 2008. PacifiCorp's parent, MidAerican Energy Hold- ings Company submitted comments on the Advance Notice of Proposed Rulemaking. In these comments, MidAmerican stressed the Company's position that Clean Air Act regulations are an inferior strategy for reducing greenhouse gas emissions compared to a comprehensive legislative program that Congress is expected to enact. Promulgating greenhouse gas regulations under the Clean Air Act would be, at best, unnecessar because Congress is expected to enact a program that is economy-wide, market-based, incents technology, and encourages other countres to tae action. MidAmerican fuher highlighted that any mandatory domestic program to reduce green- house gas emissions should be implemented consistent with the following principles: · Technology development and deployment is essential to achieving a 60 to 80 percent re- duction in greenhouse gas emissions. A significant national commitment to fuding and advancing low-carbon technologies is criticaL. 13 In April 2007, the Supreme Cour concluded in that case that greenhouse gas emissions meet the Clean Air Act defiition of "air pollutat," and that section 202(a)(l) ofthe Clean Air Act therefore authorizes regulation of green- house gas emissions subject to an Agency detennination that greenhouse gas emissions from new motor vehicles cause or contrbute to air pollution that may reasonably be anticipated to endager public health or welfare (Endan- gennent Finding). 40 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment · Immediate opportities for emissions reduction and avoidance should be purued through investments in energy effciency, renewable energy and increasing the efficiency of existing generation. · Any program to regulate greenhouse gas emissions should seek to avoid short-term re- sponses that do not provide a long-term path to a low carbon futue. · Programs implemented to reduce greenhouse gas emissions should achieve their intended purose-reducing or avoiding emissions-and. not simply serve as a source of revenue or offsetting taxes. In April 2009, the EPA found that concentrations of C02 and five other greenhouse gases pose dangers to human health and welfare, and is in the process of holding public hearings on fuher action to regulate these greenhouse gases under the Clean Air Act. Regional State Initiatives Activities undertaken by regional state climate change initiatives continued to be significant in 2008 and wil continue into 2009. The most notable developments are as follows: Midwestern Regional Greenhouse Gas Accord On November 3,2008, the ten Midwestern Regional Greenhouse Gas Accord Parters released Draft Recommendations, suggesting a taget of between 15-25 percent below 2005 levels by 2020 and a target of between 60-80 percent below 2005 levels by 2050. They also recommended that the program cover a comprehensive slate of activities including electricity generation and imports, industrial combustion sources, credible and measurable industral process sources, transportation fuels, and fuels serving residential, commercial, and industrial buildings. The Ad- visory Group hopes to include 85-95 percent of emissions for each sector, and suggests linking the Midwestern Greenhouse Gas Accord cap-and-trade program to the Regional Greenhouse Gas Initiative, Western Climate Initiative, and other mandatory greenhouse gas emissions reduction programs. Regional Greenhouse Gas Initiative In 2008, the ten Regional Greenhouse Gas Initiative Parters held successful pre-compliance auctions in September and December. The first auction sold 12,565,387 carbon dioxide allow- ances at a clearing price of $3.07 per allowance, raising more than $38.5 milion. The second auction sold 31,505,898 allowances at a clearing price of $3.38 per allowance, raising more than $106 milion. Under the Regional Greenhouse Gas Initiative, this combined $140 milion wil be used on a wide variety of approved efforts to limit and sequester carbon, as well as adapt to the impacts of climate change. Western Climate Initiative In September 2008, the Western Climate Initiative Parers released their proposal for a regional cap-and-trade program begining in 2012. The seven states and four provinces would cover 20 percent of the United States, and 70 percent of the Canadian, economies respectively. Covered emitters include electrcity generators and industrial and commercial stationary sources that emit more than 25,000 metrc tons of carbon dioxide equivalent per year. Beginning in 2015, the mar- 41 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment ket would expand to also cover petroleum-based fuel combustion from residential, commercial, and industral operations, for an overall goal of reducing emissions to 15 percent below 2005 levels by 2020. Individual State Initiatives State Economy-wide Greenhouse Gas Emission Reduction Goals An executive order signed by California's governor in June 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 levels by 2050. The Washington and Oregon governors enacted legislation in May 2007 and Au- gust 2007, respectively, establishing economy-wide goals for the reduction of greenhouse gas emissions in their respective states. Washington's goals seek to, (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25 percent below 1990 levels; and (iii) by 2050, reduce emissions to 50 percent below 1990 levels, or 70 percent below Washington's forecasted emissions in 2050. Oregon's goals seek to (i) by 2010, cease the growth of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10 percent below 1990 levels; and (iii) by 2050, reduce greenhouse gas levels to at least 75 percent below 1990 levels. In 2008, Colorado announced Executive Order D-004-08, setting a goal of reducing greenhouse gas emissions to 20 percent below 2005 levels by 2020, and 80 percent below 2005 levels by 2050. Each state's legislation also calls for state governent developed policy recommendations in the future to assist in the monitoring and achievement of these goals. State Greenhouse Gas Emission Penormance Standards In addition, California and Washington have adopted legislation that impose grenhouse gas emission performance standards to all electrcity generated within the state or delivered from outside the state to serve retail load. The greenhouse gas emissions performance standard is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation facility, effectively prohibiting the use of new pulverized coal generation to serve re- tail load. The state of Idaho had adopted a de-facto prohibition on new pulverized coal genera- tion located within the state when it decided not to partcipate in the federal Clean Air Mercur Rule's cap-and-trade program, and as a result received a zero state budget for mercury emissions. Other Recent State Accomplishments In October 2008, the California Public Utilities Commission and the California Energy Commis- sion completed a collaborative proceeding to develop and provide recommendations to the Cali- fornia Air Resources Board on measures and strtegies for reducing greenhouse gas emissions in the electrcity and natual gas sectors. The October 16,2008 final decision14 is the second policy decision to be issued pursuant to this effort. In an earlier decision, Decision 08-03-018 issued in March 2008, the Commissions provided their initial greenhouse gas policy recommendations to the Air Resources Board. In December, the Air Resources Board adopted the "Assembly Bil 32 Scoping Plan to Reduce Greenhouse Gas Emissions in California." The strategy relies on 31 new rules, including a cap-and-trde progrm, set to begin in 2012, impacting power plants, refiner- ies, and large factories. Assembly Bil 32 (2006) requires California to cut greenhouse emissions 14 Order Instituting Rulemaking to Implement the Commission's Procurement Incentive Framework and to Examine the Integration of Greenhouse Gas Emissions Stadads into Procurement Policies, available at: http://docs.cpuc.ca.gov/word pdf/AGENDA DECISION/92288.pdf. 42 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment to 1990 levels by 2020. The Air Resources Board is also implementing mandatory greenhouse gas reporting with a regulation that was approved by the Board in December 2007, and became effective on December 2, 2008.15 In October 2008, the Oregon Environmental Quality Commission approved new mandatory greenhouse gas reporting rules. The reporting rules are aimed at developing a statewide strategy for reducing emissions to 10 percent below 1990 levels by 2020, and to 75 percent below 1990 levels by 2050. Additionally, the Legislature passed Oregon House Bil 3619 expanding the business energy tax credit progrm with additional incentives for manufacturers of renewable energy equipment located in Oregon. Senate Bil 80, which implements a state C02 cap-and- trade system and emission reporting rules, is under consideration. In 2008, the Utah Legislature passed Senate Bil 202 establishing a renewable energy target of 20 percent by 2025, with zero-carbon emitting electrcity facilities exempt from the target. The bil also establishes a process for establishing a carbon captue and storage regulatory framework. The Utah Carbon Captue and Geologic Sequestration Workgroup was subsequently formed. In June 2008, the Washington Departent of Ecology adopted its final rules implementing a greenhouse gas emissions pedormance standard of 1, i 00 pounds of greenhouse gas per mega- watt (MW) for all new electrcal generation built within Washington, or used to serve the Wash- ington retail load. The Departent also adopted guidelines for carbon captue and sequestration projects. House Bil 2815 directs the Deparent of Ecology to develop, in coordination with the Western Climate Initiative, a design for a cap and trade system to meet the state's greenhouse gas emissions reductions limits of 50 percent below 1990 levels by 2050. In December 2008, the Departent delivered to the legislature specific recommendations for approval, and requested authority to implement the preferred design of the greenhouse gas reduction system in order to have the system in effect by January i, 2012.16 Second, House Bil 2815 requires operations emitting at least 10,000 metric tons, or on-road motor vehicle fleets that emit 2,500 tons of greenhouse gases, to report their emissions to the Washington Deparent of Ecology beginning in 2010 for 2009 emissions. House Bil 2687 addresses the Departent of Ecology's authority and direction for participation in the Western Climate Initiative, and directs the state to ensure that a design for a cap-and-trade system confers equitable economic benefits and opportities to electric utilities. Further, the language directs the state to advocate for a regional system that ad- dresses competitive disadvantages that could be experienced because of implementing strct greenhouse gas reduction programs. Senate Bil 6580 requires the Department of Community, Trade, and Economic Development to develop and provide advisory climate change responses to counties and cities, establish a local governent global warming mitigation and adaptation pro- gram to address climate change through land use and transportation planning, and present a re- port to the legislatue regarding policies to address and assess the impacts of climate change. Wyoming House Bil 89, Pore Space Ownership, and House Bil 90, Carbon Captue and Se- questration, were signed into law on March 4, 2008. House Bil 89 is intended to affrm the 15 Mandatory Greenhouse Gas Emissions Reporting, available at: http://ww.arb.ca.gov/cc/reportinglghg-rep/ghg- rep.htm.16 Growing Washington's Economy in a Carbon-Constrained World: A Comprehensive Plan to Address the Chal- lenges and Opportities of Climate Change, available at: http://www.ecy.wa.gov/pubs/0801025.pdf. 43 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment "American or Majority Rule" that the ownership of "pore space" in underground strta below the surface lands and waters of the state of Wyoming is vested in the several owners of the surace, but can be severed from the sudace rights and sold separately. "Pore space" is defined to mean subsurace space that can be used as storage space for CO2 or other substances. Wyoming House Bil 90 establishes a permit program for carbon storage and sequestration underground injection wells. The law establishes a permit program for injection of CO2 and associated constituents for sequestration to be issued by Wyoming Deparent of Environmental Quality. The law specifi- cally states that injection of CO2 for enhanced recovery of oil or gas approved by Wyoming Oil and Gas Conservation Commission is not subject to the new permit program. The Wyoming Carbon Sequestration Working Group was subsequently formed. 17 Corporate Greenhouse Gas Mitigation Strategy PacifiCorp is committed to engage proactively with policymakng focused on GHG emissions issues through a strategy that includes the following elements. · Policy - PacifiCorp has supported legislation that enables GHG reductions while ad- dressing core customer requirements. PacifiCorp wil 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 C02 in the 2008 IRP in concert with numerous alternative futue scenarios to reflect the risk of futue regulations that can affect relative resource costs. The Company is engaged in augmenting its regulatory analysis capabilties, including enhancing its IRP models to capture a more detailed representation of climate change rules. It is involved with such organizations as the Electrc Power Research Institute for continued study of regulatory impacts on utilities and customers. Additional voluntar actions to mitigate greenhouse gas emissions could increase customer rates and represent key public policy decisions that the Company wil not underte without prior consultation with regulators and law- makers at state and federal levels. · Procurement - PacifiCorp recognizes the potential for futue C02 costs in requests for proposal (RFPs), consistent with its treatment in the IRP. Commercially available carbon- captung and storage technologies at a utility scale do not exist today. Carbon-captuing technologies are under development for both pulverized coal plant designs and for coal gasification plant designs, but require research to increase their scale for electric utility use. · Accounting - PacifiCorp has adopted transparent accounting of GHG emissions by join- ing the California Climate Action Registr. The Registr applies rigorous accounting standards, based in part on those created by the World Business Council on Sustainable Development and the World Resources Institute, to the electrc sector. The curent 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 strtegy and wil continue to play a key role in future pro- curement efforts. 17 http://deg.state.wy.us/carbonseguestration.htm 44 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment In 2008, the Electrc Power Research Institute (EPRI) organized and conducted a broad-brush study to identify and analyze the likely effects of climate change policy for western U.S. (WECC region) generators and customers. A diverse collection of nine western generation companies, including PacifiCorp, fuded and participated extensively in this effort. The WECC region has certain unique power system characteristics, which make it an interesting laboratory to study the effects of climate policy. These include a large existing base of hydro generation supporting the regional market, as well as a growing collection of state-level Renew- able Portfolio Standard targets. These existing and anticipated generation resources together form an important baseline serving this region if their potential can be realized. On the other hand there are significant uncertinties surounding this realization, including the sustainability of hydro generation into the futue, and the feasibility of infrastrcture investments (i.e. trans- mission capacity, backup generation) needed to realize such an extensive renewables build out. The study results attempt to reflect and recognize uncertainties in futue power markets, though an examination of several alternative futue scenarios. A Reference Case, reflecting a largely stable and optimistic futue, was described for baseline puroses. In addition, a case called "Wild Card", reflecting a more pessimistic view of futue events, was presented as an alternative. The study was designed to examine macro-level effects of alternative CO2 price levels on power sys- tem dispatch, new generation investment decisions, emissions levels and power prices. The analysis included: representation of a full electrc system supply-demand balance; capacity ex- pansion and retirement methodology drven by the relative economics of both existing and new resources, and; a demand response representation, allowing futue load growth to respond to fu- tue price changes. Key conditioning assumptions of the Reference Case include: futue load growt in this market was assumed equal to the recent historical period 1995-2005, at 1.73 percent per year; natual gas prices (real 2006 dollars) were set to a recent (May 6, 2008) NYMEX forward cure projec- tion through the year 2020, then held constant at 2020 levels; capital costs for new generating plant were drven by EPRI internal estimates from 2007, and fuher inflated 25 percent in rec- ognition of continual and inexorable escalation (at least until very recently) in all global con- strction markets, and; western state RPS targets were assumed to be met in futue years, per in- dividual state law. The behavior of the power system and electrc customers was investigated over a futue period 2006 through 2030, for a series of CO2 price points (starting at $O/ton and escalating up to $100/ton) imposed beginning in 2012. The analysis assumed that the CO2 price would remain constant (in real 2006 $) from 2012 through 2030. This flat scenario CO2 price strctue was designed to show how the electrc sector would equilibrate to specific prices levels over time. The results of this analysis show, in the first instance, that a higher C02 price wil drve up the power price and drve down emissions. The power price in the initial year (2012) increases al- most linearly with the CO2 price, because the power system has very limited response capability in the very short term. There is some capability to switch resource usage from coal to natual gas, 45 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment but it is actually quite limited in WECC, so the only real option is to pass price increases on to consumers. Similarly, the short-term ability to reduce emissions is virtally nil except at very high CO2 prices where the level of demand itself is reduced through price effects. This inflexibility is much less tre as time marches on. In later years the response is both more pronounced for emissions and more limited for power prices, as the generating stock begins to tu over and new investments are made in non-emitting generation. Note in particular that emissions reductions by 2030 accelerate significantly once the $50-$60 CO2 price range is reached, when nuclear generation stas to penetrate the market. It is only when wholesale power prices reach roughly the $100 range that the nuclear technology can expect to cover its invest- ment and carring costs. The response of power price to C02 price is also more moderated in later years, as low-busbar cost, non-emitting technologies enter the mix and temper power prices. The generation mix details of these phenomena are equally iluminating. In the absence of a CO2 policy the existing mix of generation is not appreciably affected. As time marches into the fu- ture, demand growth is largely met with new renewable generation and new natual gas-fired generation. A small amount of customer response to rising prices tempers demand growth just a bit. Emissions keep growing. A $50/ton CO2 price brings about noticeable future changes. In the first instance, it is interesting to note that this represents the "stabilization" price, or the price that essentially flattens emissions growth into the futue. As power prices are also drven up in this case, customer response is also greater and demand growth is tempered even fuer. Higher power prices also begin to affect the generation mix, pushing out existing coal over time and eliciting more gas generation as re- placement energy. Notably, at a $50 CO2 price there is stil little change in the overall genera- tion mix over time, as the power price is not yet quite high enough to usher in significant capac- ity in non-emitting technologies. At CO2 prices of $85 and higher, the generation mix begins to change noticeably due to the new technology opportnities presented by higher power prices. Note first that in this case emissions shrnk significantly over time, in reaction to both increased customer price response and to changes in generation technology. Existing coal generation shrnks virtally to nothing by 2030, and is replaced in part with non-emitting nuclear generation - assumed to be available in the 2020 timeframe - as well as renewables. On the other hand, power prices actually moderate over time at the $85 CO2 level, due in large part to the switch out of coal generation (and its $85/ton surcharge) and into very low busbar-cost alternatives such as nuclear and renewables. An alternative, more pessimistic case was investigated as well. The "Wild Card" case represents an alternative futue - one in which both events and policy responses to them work against futue greenhouse gas control. Key differences in assumptions for the "Wild Card" case include: an assumed higher load growth rate; assumed higher natul gas prices; higher capital costs (25 per- cent premium); an assumed lower customer demand response, and; assumed nuclear power un- availability for the duration of the study. The "Wild Card" futue requires a higher C02 price than the Reference Case to stabilize emis- sions over time (closer to the $70-$80 range). Due to higher capital costs overall, as well as the 46 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment nuclear penetration constraint, capital stock tuover is much more sluggish in the pre-2030 time frame, and emissions are stil growing at the $50 CO2 price leveL. Existing generation - coal and gas - is necessarily used more heavily, and emissions stubbornly resist reduction. Even at a $ 1 00 CO2 price, emissions reductions in the "Wild Card" case are stil minimaL. In fact it takes a CO2 price in the range of $125-$150 to effect significant reduction, under a "Wild Card" futue. Power prices are impacted as well. The "Wild Card" futue leads to a persistent $20 premium in wholesale power prices, regardless of the size of the C02 price assumed. The foregoing analysis of western power markets was an attempt to postulate several alternative futues, and examine the implications of each on suppliers and consumers. The analysis is ag- gregate - high-level and suggestive - and certainly glosses over many details and intricacies in an attempt to focus squarely on the larger picture. Many "devils in the details" have been un- doubtedly simplified, including the following. All details of power system operations are treated abstractly, at best. This abstraction is clearest in the representation of renewable generation and its growt potentiaL. Realistically, there wil need to be significant infrastrcture (i.e. transmission capacity, backup combustion tubine gen- eration or energy storage to mitigate intermittency) built in the west, additional to renewable generation capacity, to support its usage. This additional infrastrctue has been represented in the analysis as a simple capital adder to the renewables cost estimate. Whether this additional investment wil be financially - or politically - feasible is certainly an open question. It may be that the renewables contribution has been overestimated. On the other hand, the base renewables projections (the vast bulk of the renewables capacity in any scenario) used in this analysis are merely what has been mandated by numerous western states as their avowed targets, and these targets are already today well within reach in many states. Natual gas prices are also an important driver of the analysis, and they have been notoriously volatile for the last 30 years. Among knowledgeable professionals there are resource depletion arguents that indicate prices wil go up, and liquefied natural gas emergence arguents that indicate prices wil go down. Stil and all, the NYMEX forward cure remains the best consen- sus estimate of what wil happen to gas prices in the futue; this has formed the basis of the esti- mates in this analysis. Customer response to price changes is universally recognized as a real phenomenon, and just as universally acknowledged as impossible to accurately measure. In this analysis the long-term elasticity parameter finally chosen (-0.50) is based on EPRI studies from early in the decade, but it could well be overstated. The above caveats notwithstanding, there are several important conclusions that can be drawn from the analysis. These include the following. It is certainly possible to wrng emissions growth out of the power sector in western states, given high enough CO2 price signals and sufficient time. In the Reference Case futue, a price of about 47 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment $50 wil flatten emissions growth, and a price of about $80 wil substantially reduce it. In the "Wild Card" futue, it wil require about an $80 price to flatten growth and a price in excess of $ i 25 to make substantial reductions. CO2 prices in these ranges are unprecedented, and wil lead to unprecedented retail power prices as well, in the range of 40-80 percent higher (depending on CO2 price level)-in the immediate aftermath of price imposition-than they are in WECC today. Such levels wil cause anxiety for the electrcity sector and its customers as welL. However, over time (18 years is the horizon of this analysis, actually, higher prices wil create investment incentives for the addition of non- emitting generation, and more such capacity wil enter the market if it functions reasonably well. This wil tend to temper power price differentials over time. In the analysis retail prices in 2030 are projected to end up more like 15-30 percent higher than the $0 case, a far cry from the differ- entials in 2012. Customer response to price increases wil tend to hold power price levels down in its tu as well. Without this effect prices might be expected to rise even higher. This is a mixed blessing at best, as it wil represent a real loss in consumer welfare, albeit not measured explicitly in the analysis. Natural gas price and availability are critical linchpins in the Western power system in early years, as short-term reductions in emissions wil depend on the ability of natual gas generation to fill the gaps left by coal cutbacks. This criticality wil fade over time, as new non-emitting technologies increasingly wil enter the market and fill the void. For the western power industr, the EPRI analysis helps inform possible decisions by highlight- ing two important CO2 price signals necessary to effectuate changes within the electricity sector. The first is the CO2 price that is just high enough to encourage a utility interested in building new electrcity generation to choose a lower-emitting-albeit more expensive-technology over a cheaper, but higher-emitting technology. A second C02 price is one that is sustained at a high enough level as to make existing fossil-fueled power plants uneconomic to continue operating. Under either situation, higher costs will inevitably be passed on to consumers in the form of higher electrcity rates, but if accompanied by suffcient time to adapt to the new regulatory re- gime, costs can be mitigated. In late December 2007, Congress passed the Energy Independence and Securty Act (P.L. i 10- 140, which has three major provisions covering corporate average fuel economy standards, the renewable fuels standard, and appliance/lighting effciency standards. For corporate average fuel economy, the law sets a target of35 miles per gallon for the combined fleet of cars and light trucks by model year 2020. Also, a fuel economy program is established for medium- and heavy-duty trcks, and a separate fuel economy standad is created for work trcks. These were the first new corporate average fuel economy standards in 32 years, and the increases represent a roughly 40 percent increase over today's requirements. 48 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment For the renewable fuels standard, the law sets a modified standard that starts at 9.0 bilion gallons of renewable fuel in 2008 and rises to 36 bilion gallons by 2022. Of the latter total, 21 bilion gallons is required to be obtained from cellulosic ethanol and other advancedbiofuels. This represents a six-fold increase over the mandate that is in place. In the area of energy efficiency (specifically appliance and lighting efficiency standads), the law set energy effciency standards for broad categories of incandescent lamps (light bulbs), incan- descent reflector lamps, and fluorescent lamps. A required target is set for lighting efficiency, and energy effciency labeling is required for consumer electronic products. The law wil effec- tively phase out most common tyes of incandescent light bulbs over the next four to six years by increasing the energy effciency standards of light bulbs by 30 percent. The new standard is technology-neutral, allowing consumers a choice among several effcient lighting technologies, including improved halogen-incandescent bulbs, compact fluorescent lamps and eventually light- emitting diodes and other advanced lighting technologies. The impact of the lighting efficiency standards has been accounted for in PacifiCorp's load forecasting and IRP portfolio modeling (See Chapter 5, Resource Needs Assessment). Effciency standards are set by law for external power supplies, residential clothes washers, dishwashers, dehumidifiers, refrgerators, refrigera- tor/freezers, freezers, electric motors, residential boilers, commercial walk-in coolers, and com- mercial walk-in freezers. Furer, the U.S. Departent of Energy is directed to set standards by rulemaking for fuace fans and battery chargers. The Act also requires a 30 percent reduction in energy consumption by 2015 in federal buildings. (The General Services Administration owns and leases over 340 milion square feet of space in more than 8,900 buildings, located in every state.) The Act also encourges the development of carbon captue technology by (1) expanding and improving the Departent of Energy's existing carbon sequestration research, (2) requiring a national assessment of capacity tò sequester carbon, (3) requirng the Secretary of Energy to conduct seven large-scale geologic sequestration tests, with at least one as an international par- nership, an d(4) increasing the fuding authorization for all projects included in the new carbon captue and storage research, development and demonstration program, with an emphasis on large-scale geologic carbon dioxide injection demonstration projects. Another title of the Act is the Advanced Geothermal Energy Research and Development Act of 2007. It calls for research, development, demonstration, and commercial application in five ma- jor areas: (1) geopressured resource production, which is co-produced in oil and gas fields; (2) cost-sharig driling; (3) enhanced geothermal systems; (4) creation of a national exploration and development geothermal technology trnsfer and information center; and (5) international geo- thermal collaboration. A renewable portfolio standard (RPS) is a policy that obligates each retail seller of electrcity to include in its resource portfolio (the resources procured by the retail seller to supply its retail cus- tomers) a certain amount of electrcity from renewable energy resources, such as wind and solar energy. The retailer can satisfy this obligation by either (1) owning a renewable energy facility 49 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment and producing its own power, or (2) purchasing renewable electricity from someone else's facil- ity. 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 curently implemented at the state level (although interest in a federal RPS is expanding), and vary considerably in their requirements with respect to time frame, resource eli- gibility, treatment of existing plants, arrangements for enforcement and penalties, and whether they allow trading of renewable energy credits. By 2008, twenty-five states adopted mandatory renewable portfolio standards, five states adopted voluntar renewable portfolio standard, and foureen states had adopted no form of renewable portfolio standad. Within PacifiCorp's service terrtory, California, Oregon, and Washington have mandatory re- newable portfolio standards, with Utah having adopted a voluntary renewable portfolio standard. Each state is summarized in Table 3.1 and additional discussion below. Table 3.1- Summary of state renewable goals (as applicable to PacifCorp) California Obtain 20 percent of electrcity from renewable resources by 2010. Obtain 25 percent of electrcity from renewable resources by 2025 in the following increments: . 5 percent: 2011 - 2014 . 15 percent: 2015 - 2019 · 20 percent: 2020 - 2024 · 25 ercent: 2025 and be ond By 2025, obtain 20 percent of anual adjusted retail sales from cost effec- tive renewable resources, as determined by the Public Service Commission or renewable energy certficates. Obtain 15 percent of electrcity from renewable resources by 2020 in the following increments: · 3 percent by Janua 1,2012 though December 31,2015 . 9 percent by January 1,2016 though December 31,2019 · 15 percent by January 1,2020 and each year thereafter Oregon Utah Washington California California law requires electrc utilities to increase their procurement of renewable resources by at least one percent of their anual retail electrcity sales per year so that 20 percent of their an- nual electrcity sales are procured from renewable resources by no later than December 31, 2010. In May 2008, PacifiCorp and other small multi-jursdictional utilities received fuher guidance from the California Public Utilities Commission on the treatment of small multi-jursdictional 50 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment utilities in the California Renewable Portfolio Standard program within decision, D.08-05-029. In August 2008, concurent with its annual renewable portfolio standard compliance filing, PacifiCorp, joined by Sierra Pacific Power Company, fied a Joint Motion for Review of the de- cision. As discussed in D.08-05-029, since the inception of the Renewable Portfolio Standard program, PacifiCorp and other small multi-jurisdictional utilities operated in a state of regulatory uncertainty regarding the natue of their Renewable Portfolio Standard program compliance ob- ligations. PacifiCorp's filing represented its interpretation of D.08-05-029, including banking of renewable portfolio standard procurement made while it awaited fuher guidance from the Cali- fornia Public Utilities Commission on the treatment of small multi-jurisdictional utilities durng the 2004-2006 period. PacifiCorp believes its interpretation is consistent with D.08-05-029 and best serves the interests of its customers by recognizing past, good faith efforts to comply with California's Renewable Portfolio Standard program beginning Januar 1, 2004. PacifiCorp is currently awaiting the California Public Utilities Commission's response to the Joint Motion for Review. Oregon In June 2007, the Oregon Renewable Energy Act was adopted, providing a comprehensive re- newable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the Oregon Renewable Energy Act, PacifiCorp and other qualifying electrc utilities must meet minimum qualifying electrcity requirements for electrcity sold to retail customers of at least five percent in 2011 through 2014, 15 percent in 2015 through 2019, 20 percent in 2020 through 2024, and 25 percent in 2025 and subsequent years. Qualifying renewable energy sources can be located anywhere in the United States portion of the Western Electrcity Coordi- nating Council area, and unbundled renewable energy credits can be used. The Oregon Public Utilities Commission and the Oregon Departent of Energy have undertaken additional rule- making proceedings to fuher implement the initiative. Utah In March 2008, Utah's governor signed Utah Senate Bil 202, "Energy Resource and Carbon Emission Reduction Initiative;" legislation supported by PacifiCorp. Among other things, this provides that, beginning in the year 2025, 20 percent of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electrc sales wil be ad- justed by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy effciency and demand-side management programs. Qualifying renewable energy sources can be located anywhere in the Western Elec- trcity Coordinating Council areas, and unbundled renewable energy credits can be used. Washington In November 2006, Washington voters approved a ballot initiative establishing a RPS require- ment for qualifying electrc utilities, including PacifiCorp. The requirements are three percent of retail sales by January 1, 2012 though 2015, nine percent of retail sales by January 1, 2016 through 2019 and 15 percent of retail sales by Januar 1, 2020. Qualifying renewable energy sources must be located within the Pacific Northwest. The Washington Utilities and Transporta- tion Commission adopted final rules to implement the initiative. 51 PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment Federal Renewable Portfolio Standard Congress has taken up federal energy policy legislation, including the possibility of a federal RPS. President Obama has pledged to "spark the creation of a clean energy economy" as part of his plan aimed at reinvigorating the U.S. economy, in par by doubling production of "alternative energy" in the next three years-aided by subsidies for "low emissions coal plants," biofuels and renewable energies-and by pursuing a federal renewable portfolio standard mandating that 25 percent of U.S. electrcity come from renewable sources by 2025. Passage ofa federal renewable portfolio standard would break a major standoff in Congress as both the House and Senate have passed various forms of a renewable portfolio standard in recent years but failed to concur on the details. The Waxman-Markey Bil represents the latest effort, and specifies a renewable electrc compliance requirement of 20 percent by 2020. Proponents of a national renewable portfolio standad argue it would ease the move toward a mandatory cap on greenhouse gas emissions by requiring utilties to invest in low-carbon energy sources. Enactment of a federal renewable portfolio standad would be a significant shift in the way electric utilities are regulated, drmatically increasing the authority of the federal govern- ment to dictate the makeup of a utilty's energy portfolio-a power currently exercised by state governments. Renewable Energy Certifcates Absent either a RPS compliance obligation or an opportity to bank unbundled renewable en- ergy certificate (RECs) for futue year RPS compliance, PacifiCorp has historically relied on an assumption that a renewable project may generate $5 per megawatt-hour for five years from the sale of unbundled RECs. Unbundled REC sales have helped mitigate the near-term cost differen- tial between new renewable resources and trditional generating resources. However, once greenhouse gas emissions are regulated, surlus unbundled REC sales would cease. PacifiCorp assumes if an unbundled REC is sold, then the underlying power (aka "null" power) would likely have a carbon emissions rate imputed upon it by regulatory authorities, thus obligating PacifiCorp to purchase either allowances or carbon offsets sufficient to cover the im- puted carbon emissions. By sellng an unbundled REC, PacifiCorp may generate revenue, but risks incurrg a new carbon liabilty. Once greenhouse gases are regulated-and until the un- bundled REC and carbon markets are reconciled-PacifiCorp plans to cease selling unbundled RECs. The issues involved in relicensing hydroelectrc facilities are multifaceted. They involve numer- ous federal and state environmental laws and regulations, and participation of numerous stake- holders including agencies, Indian trbes, non-governental organizations, and local communi- ties and governments. The value to relicensing hydroelectrc facilities is continued availability of hydroelectrc 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- 52 ............................................ ............................................ Paci~Corp ~ 2008 IRP Chapter 3 - The Planning Environment tent renewable resources such as wind. In addition to operational flexibilty, hydroelectrc gen- eration does not have the emissions concerns of thermal generation. With the exception of two hydroelectrc projects, all ofPacifiCorp's applicable generating facilities now operate under con- temporary Orders from the Federal Energy Regulatory Commission (FERC). The Klamath River hydroelectrc project continues to work with parties to reach a settlement agreement on futue project conditions, and the Condit project is seeking a Surender Order to decommission the pro- ject. FERC hydroelectrc relicensing is administered within a very complex regulatory framework and is an extremely political and often controversial public process. The process itself requires that the project's impacts on the surounding environment and natual resources, such as fish and wildlife, be scientifically evaluated, followed by development of proposals and alternatives to mitigate for those impacts. Stakeholder consultation is conducted throughout the process. If 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 relic ensing, 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 hydroelectrc projects on navigable waterways, federal lands, and under other certin criteria. The FERC must find that the project is in the broad public interest. This requires 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 Administrtion 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 wil be made in a project and can render some projects uneconomic. Also, because a myrad of other state and federal laws come into play in relic ens- ing, most notably the Endangered Species Act and the Clean Water Act, agencies' interests may compete or conflct with each other leading to potentially contrar, 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. The FERC welcomes settlement agreements into the relicensing process, and with associated recent license orders, has generally accepted agreement terms. Potential Impact Relicensing hydroelectrc facilities involves significant process costs. 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 arse durng the process. As of December 31, 2008, PacifiCorp had incured $56.6 milion in costs for ongoing hydroelectrc relicensing, which are included in Constrction work-in-progress on PacifiCorp's Consolidated Balance Sheet. As re1icensing and/or decommissioning efforts con- tinue for the Klamath River and Condit hydroelectrc projects, additional process costs are being incured that wil need to be recovered from customers. Also, new requirements contained in 53 Paci~Corp - 2008 IRP Chapter 3 - The Planning Environment FERC licenses or decommissioning Orders could amount to over $1.2 bilion over the next 30 to 50 years. Such costs include capital and operations and maintenance investments made in fish passage facilities, recreational facilities, wildlife protection, cultural and flood management measures as well as project operational changes such as increased in-stream flow requirements to protect fish resulting in lost generation. Over 95 percent of these relicensing costs relate to PacifiCorp's thee largest hydroelectrc projects: Lewis River, Klamath River and North Um- pqua. Treatment in the IRP The known or expected operational impacts mandated in the new licenses are incorporated in the projection of existing hydroelectrc resources discussed in Chapter 4. PacifiCorp's Approach to Hydroelectric Relicensing PacifiCorp continues to manage this process by pursuing a negotiated settlement as part of the Klamath River relicensing process. PacifiCorp believes this proactive approach, which involves meeting agency and others' interests through creative solutions is the best way to achieve envi- ronmental improvement while managing costs. PacifiCorp also has reached agreements with li- censing stakeholders to decommission projects where that has been the most cost-effective out- come for customers. 2012 Request for Proposals for Base Load Resources PacifiCorp issued this RFP on April 5, 2007, to procure up to 1,700 MW of base-load resources for 2012-2014. In December 2008, PacifiCorp submitted an application for "Approval ofSignifi- cant Energy Resource Decision and for Certficate of Public Convenience and Necessity" to the Public Service Commission of Utah for the Lake Side II combine-cycle plant. As discussed above, in February 2008, the Company termated the constrction contract for this plant. 2008 All-Source Request for Proposals The 2008 All-Source RFP, which was issued on October 2, 2008, sought up to 2,000 MW of sys- tem-wide base-load capacity, intermediate load capacity, third-quarter market purchases, load curailment, PURP A Qualifying Facilities, and dispatchable/schedulable renewables, with on- line dates between 2012 though 2016.18 Both the Public Utility Commission of Oregon and the Public Service Commission of Utah approved the RFP. In late February 2009, PacifiCorp suspended this RFP due to uncertinty caused by the ongoing financial crisis, the economic recession and its impact on loads, and belief that ratepayers and the Company might get a better deal than the proposals submitted in the RFP as the year goes on and markets continue to adjust to the economic environment. Additionally, PacifiCorp also believes suppliers wil be much more likely to secure financing once the bankg sector has stabilized. 18 PacifiCorp's website for competitive solicitations: http://ww.pacificorp.com/Aricle/Article62880.htmL. 54 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 3 - The Planning Environment PacifiCorp wil monitor the market over the next six to eight months with the intention to lift the suspension, issue an Amendment to the RFP and request updated proposals from the existing bidders and new proposals. PacifiCorp also intends to refresh its benchmark proposals at that time. Renewable Request for Proposal (RFP 2008R) PacifiCorp issued RFP 2008R on January 31, 2008 for renewable resources of less than 100 MW for resources greater than five years in length, or greater than 100 MW for resources less than or equal to five years in length. The 2008R RFP solicited renewable resources that have a commer- cial operation date prior to December 31, 2009. On September 5, 2008, PacifiCorp executed a 20-year power purchase agreement with Duke Energy Corporation for the entire output of the 99-MW Campbell Hil project, located in Wyoming. Renewable Request for Proposal (RFP 2008R-l) PacifiCorp issued RFP 2008R-I on October 6,2008. This RFP solicited 500 MW of renewable generation projects-with no single resource greater than 300 MW-with on-line dates prior to December, 2011. An amendment to this RFP was filed in Utah on January 12,2009 and in Ore- gon on January 8, 2009. Bidders for existing proposals that have been received wil have an op- portity to update their pricing. The amendment also allows new bidders to participate. The amendment was fied and approved by the Oregon Public Utility Commission January 20,2009. The Company has developed its shortlist of bidders, and anticipates makig procurement deci- sions by July 2009. PacifiCorp also fied notices with state commissions regarding its intent to issue its next renewables RFP (2009R). Demand-side Resources The Company released a comprehensive demand-side management RFP (2008 DSM RFP) in November 2008. This RFP constitutes one of the items in PacifiCorp's IRP action plan, docu- mented in the 2007 IRP Update report (June 2008, page 25). The 2008 DSM RFP requested bids on eighteen defined products: four Class 1 products and foureen Class 2 products. The RFP also allowed for proposals on three non-defined products, one for Class 1 load management products, one for Class 2 energy effciency products, and one for Class 3 price-responsive products. The non-defined product requests allowed bidders to propose products not initially identified in the RFP that they believe may be of benefit to the Company. Contracting for new products accepted under the 2008 DSM RFP wil be concluded by mid-summer with regulatory approvals and im- plementation scheduled to begin the four quarter of 2009. Other procurement work anticipated in 2009 includes the issuance of RFPs for program evalua- tions of legacy products, engineering resources in support of commercial, industral and agrcul- tual program delivery, and the procurement of ongoing irrgation load management services in Utah and Idaho. 55 ............................................ PacifiCorp - 2008 IRP Chapter 4 - Transmission Planning 4. TRASMISSION PLANNING The basic purose of PacifiCorp's bulk transmission network is to reliably transport electrc en- ergy from generation resources (generation or market purchases) to various load centers. There are several related benefits associated with a robust transmission network: 1. Reliable delivery of power to continuously changing customer demands under a wide va- riety of system operating conditions. 2. Ability to supply aggregate electrcal demand and energy requirements of customers at all times, taking into account scheduled and reasonably unscheduled outages. 3. Economic exchange of electrc power among all systems and industr participants. 4. Development of economically feasible renewable generation in areas where it is best suited. 5. Protection against extreme market conditions where limited transmission constrains en- ergy supply. 6. Ability to meet obligations and requirements of PacifiCorp's Open Access Transmission Tariff. 7. Increased capabilty and capacity to access Western energy supply markets. PacifiCorp's transmission network is a critical component of the IRP process and is highly inte- grated with other transmission providers in the western United States. It has a long history of reliable service in meeting the bulk transmission needs of the region. Its purpose wil become more critical in the future as energy resources become more dynamic and customer expectations become more demanding. _111',13::ß..,i¡fE;: .~l'_~. ,;_;.:; ......, ll,_,,~__,i¥L ,_ _ &k _ _ _ -,z,w _ .3m._ __ , c._ _ _ ,_ Transmission constrints and the ability to address capacity or congestion issues in a timely maner represent important planning considerations for ensurng that peak load and energy obli- gations are met on a reliable basis. The cycle time to add significant transmission infrastrcture is often longer than adding generation resources or securing third par resources. Transmission additions must be integrated into regional plans and then permits must be obtained to site and constrct the physical assets. Inadequate transmission capacity limits the utilities abilty to access what would otherwise be cost effective generating resources. Transmission assets tend to be long lived which go beyond a twenty-year planning horizon tyi- cally considered for resource planning. The result is a set of transmission assets modeled for least cost planing that addresses PacifiCorp' 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 following sections, PacifiCorp is engaged in a significant transmission ex- pansion effort called Energy Gateway that requires cooperative transmission planning with re- gional and sub-regional planning groups across the Western Interconnection. Transmission infra- 57 Paci~Corp - 2008 IRP Chapter 4 - Transmission Planning strctue wil continue to play an important role in future IRP plans as segments are added due to Energy Gateway along with other system reinforcement projects. Various regional planning processes have developed over the last several years in the Western Interconnection19. It is expected that, in the futue, these processes wil be the primar forums where major transmission projects are identified, evaluated, developed and coordinated. In the Western Interconnection, regional planning has evolved into a thee tiered approach where an interconnection-wide entity, the Western Electrcity Coordinating Council (WCC) conducts regional planning at a very high level, several sub-regional planning groups focus with greater depth on their specific areas and transmission providers perform local planning studies within their sub-region. This coordinated planning helps to insure that customers in the region are served reliably and at the least cost. In 2006, WECC took on a larger and more defined responsibility for interconnection-wide transmission expansion planning under the Federal Energy Regulatory Commission's Order 890. WECC's role in meeting the region's need for regional economic transmission planning and analyses is to provide impartial and reliable data, public process leadership, and analytical tools and services. The activities of WECC in this area are guided and overseen by a board-level committee and the Transmission Expansion Planing Policy Committee (TEPPC). TEPPC's three main fuctions include: (1) overseeing database management, (2) providing pol- icy and management of the planing process, and (3) guiding the analyses and modeling for Western Interconnection economic trsmission expansion planning. These fuctions 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. Specific responsibilities include: · Steering decisions on key assumptions and the process by which economic transmission expansion planing data are collected, coordinated and validated; · Approving transmission study plans, including study scope, objectives, priorities, overall methods/approach, deliverab1es, and schedules; · Steering decisions on analytical methods and on selecting and implementing production cost and other models found necessary; · Ensurng the economic transmission expanion planng process is impartial, trnsparent, properly executed and well communcated; · Ensurng that regional experts and staeholders participate, including state/provincial en- ergy offces, regulators, resource and transmission developers, load serving entities, envi- ronmental and consumer advocate stakeholders through a stakeholder advisory group; · Advising the WECC Board on policy issues affecting economic transmission expansion planning; and 19 The Western Interconnection stretches from Wester Canada South to Baja California in Mexico, reaching eastward over the Rockies to the Great Plains. 58 ............................................ ............................................ Paci~Corp ~ 2008 IRP Chapter 4 - Transmission Planning . Approving recommendations to improve the economic transmission expansion planing process. TEPPC analyses and studies focus on plans with west-wide implications and include high level assessments of congestion and congestion costs. The analyses and studies also evaluate the eco- nomics of resource and trnsmission expansion alternatives on a regional, screening study basis. Resource and transmission alternatives may be targeted at relieving congestion, minîmizing and stabilizing regional production costs, diversifying fuels, achieving renewable resource and clean energy goals, or other purposes. Alternatives often draw from state energy plans, integrated re- source plans, large regional expansion proposals, sub-regional plans and studies, and other sources if relevant in a regional context. Members and stakeholders of TEPPC includes transmission providers, policy makers, govern- mental representatives, and others with expertise in planning, building new economic transmis- sion, evaluating the economics of transmission or resource plans; or managing public planning processes. Similar to the TEPPC activities and process at WECC, a similar process exists under the. over- sight of the Planning Coordination Committee which provides for the reliability aspects of transmission system planning. Sub-regional Planning Groups Recognizing that planning the entire western interconnection in one forum is impractical due to the overwhelming scope of work, a number of smaller sub-regional groups have been formed to address specific challenges in various areas of the interconnection. Generally all of these forums provide similar regional planning fuctions, including the development and coordination of ma- jor transmission plans within their respective areas; however it is these sub-regional forums where the majority of transmission projects are expected to be developed. These forums coordi- nate with each other directly through liaisons and through TEPPC. A curent list of sub-regional groups is provided below: . NTTG - Nortern Tier Transmission Group . CCPG - Colorado Coordinated Planing Group . CG - Columbia Grid . NTAC - Northwest Transmission Assessment Committee . STEP - Southwest Transmission Expansion Planning . SWAT - Southwest Area Transmission Study . CA - California Independent System Operator . WestConnect - A southwest sub-regional planning group that includes paricipants from CCPG, SWAT and other utilties PacifiCorp is one of the founding members of Northern Tier Transmission Group (NTTG). Originally formed in early 2007, NTTG has an overall goal of improving the operation and ex- pansion of the high-voltage transmission system that delivers power to consumers in seven west- ern states. The NTTG footprint includes approximately 2.7 milion customers and more than 27,000 miles of transmission lines within Oregon, Washington, California, Idaho, Montaa, 59 PacifiCorp - 2008 IRP Chapter 4 - Transmission Planning Wyoming and Utah. In addition to PacifiCorp, other members include Deseret Power Electrc Cooperative, NorthWestern Energy, Idaho Power, Portland General Electrc, and the Utah Asso- ciated Municipal Power Systems. The geographical areas covered by these sub-regional planning groups are approximately shown in Figure 4. i below: Figure 4.1 - Sub-regional Transmission Planning Groups in the WECC CG Columbia ~Grid j¡j¡ ~Wll'UljWl~MI~ I ~ NTAC :\~ MI WI Nortwest Trasmis- ~ MI sion Assessment ¿¡!lWlWl~MI WI Norter Tier Transmission Group CCPG Colorao Coordi- nated Planng Group CA STEP Southwest Tranmis- sion Expanion Plan- Southwest Area Trasmission Study Energy Gateway Since the last major transmission infrastrctue constrction in the 1970s and early 1980s, load growth and increased use of the western transmission system has steadily eroded the surplus ca- pacity of the network. In the early 1990s when limited transmission capacity in high growth re- gions became more severe, low natual gas prices generally made adding gas fired generation close to load centers less expensive than transmission inastrctue additions. As natul gas prices stared moving up in the year 2000, transmission constrction became more attactive, but long transmission lead times to resource centers and rate recovery uncertainty suppressed new transmission investment. Repeated sub-regional studies, including the Rocky Mountain Area Transmission Study dated September 2004, the Western Governor's Association Transmission Task Force Report dated May 2006 and the Northern Tier Transmission Group Fast Track Project Process in 2007 plus subsequent PacifiCorp planning studies concluded the critical need to alleviate transmission con- gestion and move transmission constrained energy resources to regional load centers. 60 ............................................ ............................................ Paci~Corp - 2008 IRP Chapter 4 - Transmission Planning The recommended bulk electric transmission additions for PacifiCorp took on a consistent foot- print which is now known as Energy Gateway by establishing a triangle over Idaho, Utah and Wyoming with paths extending into Oregon and Washington. Prior to 2007, PacifiCorp transmission activity was primarily focused on maintaining existing transmission reliability, executing queue studies, addressing compliance issues, and participating in shaping regional policy issues. Investments in main grid assets for load service, regional ex- pansion or economic expansion to meet specific customer requests for service were addressed as transmission customers requested service. New Transmission Requirements Historically, transmission planning took place at the utility level and was focused on connecting specific utility generation resources to designated load centers. Under 888/889 Federal Energy Regulatory Commission rules, customer requests for transmission service were sporadic and un- coordinated with high levels of uncertainty in many markets which inibited transmission in- vestments. Due to PacifiCorp's transmission system being a major component of the Western Interconnec- tion, the Company has the responsibility to provide network customers adequate transmission capability that optimizes generation resources and provides reliable service both today and into the futue. Based on curent projections, loads and the dynamic blend of energy resources are expected to become more complex over the next twenty years which wil challenge the existing capabilities of the transmission network. In addition to ensurng sufficient capacity is available to meet the needs of its network custom- ers, the Federal Energy Regulatory Commission in Order 890 encourages transmission providers such as PacifiCorp to plan and implement regional solutions for transmission reliability and ex- pansion. Based on the aggregate needs of PacifiCorp and others utilities in various sub-regional planing groups, a blueprint for transmission expansion was developed. The expansion plan is a culmin- tion of prior studies and multiple utilities' integrated resource plans (PacifiCorp, Idaho Power, NorthWestern, and Portland General Electrc) as well as identified potential plans of independent resource developers. It identifies a transmission expansion plan that wil support multiple load centers, resource locations and resource tyes. In total the expansion plan, now referred to as En- ergy Gateway calls for the constrction of numerous transmission segments - totaling approxi- mately 2,000 miles. The Energy Gateway blueprint uses a "hub and spoke" concept to most efficiently integrate transmission lines and collection points with resources and loads centers aimed at serving PacifiCorp customers while keeping in sight Regional and Sub Regional needs. In addition to regulatory requirements for regional planning, future siting and permitting of new transmission lines wil require significant paricipation and input from many stakeholders in the west. As part of new transmission line permitting PacifiCorp wil have to demonstrate that sev- 61 PacifiCorp - 2008 IRP Chapter 4 - Transmission Planning eral key requirements have been met; I) the Company has satisfied an ongoing requirement for transmission to serve customers, 2) the Company is planing and building for the futue and is obtaining corrdors and mitigating environmental impacts prudently, and 3) that any projects be- ing proposed economically meet the reliability and infrastrctue needs of the region over all. This regional process and the Western Electrcity Coordinating Council's planning process are considered critical to gaining wide support and acceptance for PacifiCorp' s transmission expan- sion plan. Reliabilty PacifiCorp's transmission network is increasingly measured against new Federal Energy Regula- tory Commission (FERC) / National Electrc Reliability Corporation (NERC) mandatory reliabil- ity standards which require infrastrctue to be in place in case of unplanned outage events. Mandatory compliance with the NERC planing standards is required of the NERC Regional Councils (Regions) and their members as well as all other electrc industr participants if the re- liability of the interconnected bulk electrc systems is to be maintained in the competitive elec- tricity environment.2o The majority of these new mandatory standards are the responsibilty of the transmission owner. NERC Planing standards define reliability of the interconnected bulk electrc system in terms of adequacy and security. Adequacy means the electrc system needs to be able to supply aggregate electrcal demand for customers at all times. Securty means the electrc system must withstand sudden distubances or unanticipated loss of system elements. 21 Increasing transmission capac- ity often requires redundant facilities in order to meet NERC reliability criteria. The ability to recover from system distubances impacting main grd trnsmission often require accommodating multiple contingency scenaros which Energy Gateway helps facilitate along with other system reinforcement projects. There have been a number of main grd transmission outages in the latter part of 2007 resulting in curailment of schedules, curilments of interrpti- ble loads and generation curailments. These outages occured on main grd paths and the ability to recover was severely limited because mitigation measures were electrcally restrcted due to lack of transmission capacity. Resource Locations As an extension of the 'hub and spoke' strtegy, PacifiCorp must consider logical resource loca- tions for the long-term based on environmental constraints, economical generation resources, and federal and state energy policies. PacifiCorp's primary energy resources in descending order are located in Utah, Wyoming, desert southwest and the west. Energy Gateway leverages the dy- namic and future mix of energy resources and market access points at key locations and supports the Company's preferred resource portfolio. Energy Gateway anticipates the availability and/or development of new resources including re- newable energy resources in each of these key areas. The combination of resources cited in the 2008 IRP action plan and Energy Gateway support building to these resource locations. 20 Western Electricity Coordinating Council Reliabilty Criteria 21 Western Electricity Coordinating Council Reliabilty Criteria 62 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 4 - Transmission Planning As a complement to the 'hub and spoke' concept, the Western Governors Association has been developing a process for identifying western renewable energy zones (WRZ). These renewable energy zones would be used to facilitate needed infrastrcture to integrate and deliver large vol- umes of renewable energy to the west. Energy Gateway is well positioned access key renewable energy zones, primarily in Wyoming. The geographical areas for wind power potential are ap- proximately shown in Figure 4.2 below. Figure 4.2 - Western States Wind Power Potential Up to 25,000 Megawatts (Class 5 Wind Locations or Higher) Energy Gateway Transmission Expansion NewtrÎssionliri wlilprde~ce~ tö¡ire With strong reewable energdeopel'poen Wind po potial . Surb.O~ri . Exctllet . Go _FarII l1Oto Plne tnlss ii - so IN mhmii vo - 3-S IN mhmu vo - 23 IN mbimu'l TlUrm hub. $uti . Gencon pliiti ~~lf£.OJ €olhhe"""....~_~MI llO As another indicator of the importance of Energy Gateway to customers and the region, the De- partent of Energy sponsored a study through Idaho National Laboratories to assess the eco- nomic impact of not building transmission on the Pacific Nortwest. The report was published in July 2008 and references: "The model indicates that the PNWER (Pacifc Northwest Economic Region) has a potential economic loss of $15B to $25B annually and 300,000 to 450,000 jobs over 30 years if just the one infastrcture transmission line project with the 63 Paci~Corp - 2008 IRP Chapter 4 - Transmission Planning greatest economic impact is not built (i.e., BC to NorCal), and upwards of $55B to $85B annually and 1,750,000 jobs over 30 years if the five transmission line projects of greatest economic impact are not built (i.e., Alberta to PacNW Pro- ject, Be to NorCal, Gateway West, Southern Xing & 1-5 Corridor Projects, and Mountain States 1ntertie). These transmission line projects ... transport bulk power and are considered critical for access to preferred electrical generation by areas with high economic development and growth. Note, however, that even if these five projects come to frition, the added power wil not adequately serve the projected PNWER population increase, assuming consumption habits remain the same ".22 "Preliminary engineering review and analysis of planned transmission projects within the PNWER region resulted in the following initial ranking of the projects based on estimates of potential economic value of each project, the likelihood of project execution, the resource area(s) being accessed, the size of the project, and the value of the project to the transmission system as a whole. This analysis was subjective in nature and conducted for comparison purposes only before the full economic analysis and ranking was performed. This ranking was partially based on project listings in the 1RPs, knowledge of potential generation resource areas and load centers, areas of transmission need, etc. As stated above, this report ranks evaluated projects according to the 1NL's assessment of their overall eco- nomic impact to PNWER according to the specifc factors used in the evaluation. Other analyses may place diferent emphasis on diferent factors, resulting in a diferent overall ranking of projects. Despite these potential diferences, all of the projects are considered valuable and necessary to adequately address lrowing electric power needs. The INL 's preliminary ranking is shown in Table 1: 3 1 BC to NorCal 2 Alberta to PacNW Project 3 Gateway West - PacifCorp 4 Southern Crossing 5 Gateway South - PacifCorp 9 Inland Project (W to Las Vegas) 10 In/and Project (MT to Las Vegas 11 McNary - John Day 12 Southwest Intertie Project (SWIP) North 13 Alstom to San Francisco Bay project 'Alaska to Alstom ro "ect not included I4 Montana Alberta Tie 15 Port Angeles-Juan de Fuca" 6 Gateway Central- PacifCorp 7 Mountain States Intertie 8 Interstate 5 Corridor Lines The greater par of the Energy Gateway project originates in Wyoming and Utah and migrates west to Oregon and Washington and south to southern Utah and Nevada. The Energy Gateway 22 Idao National Laboratory: The Cost of Not Building Trasmission, page vi 23 Idao National Laboratory: The Cost of Not Building Transmission, page 5 64 ............................................ ............................................ Paci~Corp - 2008 IRP Chapter 4 - Transmission Planning project takes into account the existing 2006 transaction commitments which include transmission facilities from southern Idaho to nortern Utah (Path C), Mona to Oquirrh and Walla Walla to McNary. PacifiCorp is actively pursuing the Energy Gateway transmission project under the following overarching key objectives: . Network customer driven - Energy Gateway is primarly drven by PacifiCorp's retail and network customers' needs. Including Energy Gateway as a base allows PacifiCorp to move forward with the knowledge that over the coming years, transmission lines wil be utilized to their fullest potentiaL. . Support multiple resource scenarios - The transmission expansion project must be able to accommodate a variety of futue resource scenarios including meeting renewable port- folio standards, supporting natual gas fueled combustion tubines and market purchases, and recognizing that clean coal-based generation may re-emerge as a viable resource. . Consistent with past and current regional plans - The proposed projects are consistent with a number of regional planning efforts. The need to expand transmission capacity has been known for years and should not be a surrise to the regional planning process and justification of need. The regional planning process should reduce the number of parties that may be publicly opposed to these projects due to the scrutiny placed on justi- fication. . Get it built - A significant barrer to achieving "steel in the ground" has historically been frstrated by lengthy multi-part negotiations related to planning and governance strc- tue. Minimizing the impacts of these barers through action-oriented objectives wil be key to project success. . Secure the support of state and federal utilty commissions for rate recovery - Thoughout the process, the project wil seek input of state and federal regulators to en- sure concerns are communicated early and addressed. The project should be undertaken in a manner that is acceptable to commissions and customers. . Protect the investment to the benefit of customers - An appropriate balance must be strck to ensure that network customers do not subsidize third par use and ensure that PacifiCorp's long-term network allocation requirements are retained. Phasing of Energy Gateway PacifiCorp has been clear in its position regarding the initial announcement of Energy Gateway that significant infrastrctue of new transmission capacity is needed to adequately serve Pacifi- Corp's existing and future loads over the long-term. The Company's position has not changed in this regard and requires 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South) of new transmission capacity to adequately serve its customers load and growt needs for the long-term. PacifiCorp also recognized in its originally anounced Energy Gateway Program the need and benefits of potentially ''up sizing or scaling up" the Energy Gateway Program to increase trans- mission capacity by two-fold (6,000 MW). This upsizing would potentially provide a number of local and regional benefits such as: maximizing the use of new proposed corrdors, potential to reduce environmental impacts, provide economies of scale needed for large infrastrctue, lower 65 Paci~Corp - 2008 IRP Chapter 4 - Transmission Planning cost per megawatt of transport capacity made available, and improved opportity for third par- ties to obtain new long-term firm transmission capacity. PacifiCorp stil believes there are viable expectations and reasons for upsizing Energy Gateway and has vigorously pursued other participants the past year and a half. To this point, significant barrers stil exist preventing PacifiCorp and other third pares from makig a business decision to upsize the Energy Gateway Progrm without taing signficant financial and delivery risk. PacifiCorp believes that both short-term and long-term benefits exist as a result of upsizing the Energy Gateway Program and that existing barers may be overcome at some futue date. How- ever; the Company must prudently move ahead now with steps necessary to serve its customers while keeping in sight these potential benefits perceived by upsizing. PacifiCorp is proceeding with efforts regarding planing and rating requirements for the Energy Gateway Program which facilitates a planned ultimate transmission capacity of 3,000 MW for Gateway West and 3,000 MW for Gateway South (6,000 MW total). In order to achieve the rat- ings while meeting customer requirements, PacifiCorp plan to achieve the ratings in stages or phases based on need and constrction timing The core transmission expanion plan wil constrct lines and stations required to deliver 1,500 MW on Gateway West and 1,500 MW on Gateway South (3,000 MW total) of transmission ca- pacity required to meet PacifiCorp's long-term regulatory requirement to serve loads. Additional stages may continue at some futue date as determined by, economic, business and regulatory drvers that may be better defined in the upcoming year. Furer expansion to the Desert South- west wil also be considered. Each segment wil be justified individually within the overall progrm. A combination of bene- fits including net power cost savings derived from the IR, reliability, capital offsets for renew- able resource development in low yield geogrphic regions and system loss reductions wil be used to assess the viability of each segment. The primary justification due to net power cost savings is derived from modeling alternative re- source options under an assortent of forecast assumptions with and without Energy Gateway. The difference between the Energy Gateway build options and no transmission expansion yields a net power savings. Additional considerations listed above are considered on a segment-by- segment basis. Each Energy Gateway segment wil be reviewed again before signficant commitments are made to ensure its justification. Therefore, depending on conditions or alternatives certin segments could be deferred or not constrcted if not warranted. It is also reasonable to expect certain core segments wil be justified in multiple scenarios. Segments wil be reevaluated during each IRP cycle and annual business plan similar to generation/market resource plans to ensure they are re- quired. 66 ........'................\..................\... ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment 5. RESOURCE NEEDS ASSESSMENT This chapter presents PacifiCorp' s assessment of resource need, focusing on the first 10 years of the IRP's 20-year study period, 2009 through 2018. 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 surlus on both a capacity and energy basis for each year of the planning horizon. Methodology 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. Forecasts are based on statistical and econometrc model- ing techniques. These models are driven by county and state level forecasts of employment and income that are provided by public agencies or purchased from commercial ecónometrc fore- casting services.24 Appendix E provides additional details on the state-level forecasts. Evolution and changes in Integrated Resource Planning Load Forecasts Through the course of the 2008 integrated resource planning cycle, PacifiCorp relied on the No- vember 2008 load forecast for the development of the load and resource balance and portfolio evaluations. Portfolio analysis started as early as June 2008 with preliminary load forecast and continued through December 2008. Under stable economic conditions, the Company would normally prepare one load forecast per year. However, the unstable and volatile economic condi- tions required the Company to update its load forecasts frequently to attempt to capture price and usage changes between June 2008 and November 2008. Because of the magnitude ofthe forecast changes and the Company's plan to align IRP fiing with the Business Plan, the Company de- cided that it was prudent to incorporate latest load forecast updates in the IRP. Consequently, PacifiCorp's IRP analysis from November 2008 onward reflects the November 2008 load fore- cast. In order to improve sales and load forecasting methods, capabilties, and accuracy, several im- provements in the load forecasting approach were identified jointly by the Company and the Company's consultant, ITRON, and the load forecast methodology was changed to incorporate these improvements. Forecast improvements were drven primarily by six major changes in fore- cast assumptions. First, load research data was used to model the impact of weather on monthly retail sales and peaks by state by class. The Company collects hourly load data from a sample of customers for each class in each state. These data are primarily used for rate design, but they also 24 PacifiCorp relies on county and state level economic and demographic forecasts provided by Global Insight, in addition to state offce of planing and budgeting sources. 67 PadfiCorp - 20081RP Chapter 5 - Resource Needs Assessment provide an opportity to better understand usage patterns, particularly as they relate to changes in temperatue. The greater frequency and data points associated with this hourly data make it better suited to captue load changes drven by changes in temperatue than the monthly data used in the Company's prior forecasts. Second, the time period used to define normal weather was updated from the National Oceanic and Atmospheric Administration's 30-year period of 1971-2000 to a 20-year time period of 1988-2007. The Company identified a trend of increasing summer and winter temperatues in the Company's service terrtory that was not being captued in the thirt year data. ITRON sureys have identified that many other utilties are also using more recent data for determining normal temperatues. Based on this review and on the recommendation from ITRON, the Company adopted a 20-year rolling average as the basis for determining normal temperatues. This better captues the trend of increasing temperatues observed in both summer and winter. Third, the historical data period used to develop the monthly retail sales forecasts was updated to cover 1997-2007. Fourh, monthly peaks were forecasted for each state using a peak model and estimated with his- torical data from 1990-2007. As an improvement to the forecasting process, the Company devel- oped a model that relates peak loads to the weather that generated the peak. This model allows the Company to better predict monthly and seasonal peak. The peak model is discussed in greater detail in the following section. Fifth, system line losses were updated to reflect actul losses for the 5-years ending December 31, 2007. The Company previously used the results of the most recent system line loss study, which was based on calendar-year 2001 data. The Company had observed that actual losses were higher than those from the previous line loss study. Investigation and discussions with the con- sultant who prepared the previous line loss study indicated that the previous study only reflected losses associated with retail load. Because there are also system losses associated with wholesale sales, the prior loss value was understated. The use of actul losses is a reasonable basis for cap- tung total system losses and has been incorporated in this forecast. Finally, analyses were performed and adjustments made for the impact of curent economic con- ditions. Because the model is estimated over a period of relative prosperity, it is necessary to make an explicit adjustment for the economic downtu, and hence the forecast was revised. In October 2008, the near-term forecast was adjusted downward to reflect the recent recession im- pacts mirroring load changes experienced in the previous recession (2001-2002). In the Novem- ber update, the forecast was fuher adjusted downward in the Industral sector for Utah (2010 onwards) and Wyoming (2009 onwards) to reflect the additional recession impacts. In addition to these forecast methodology changes, energy effciency (Class 2 DSM) was han- dled differently relative to past IRPs. Rather than treating Class 2 DSM as a decrement to the load forecast, PacifiCorp modeled Class 2 DSM as a resource option to be selected as part of a cost-effective portfolio resource mix using the Company's capacity expansion optimization modeL. To accomplish this, the load forecast used for IRP portfolio development excluded fore- casted load reductions from Class 2 DSM. The capacity expansion model then determines the 68 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment amount of Class 2 DSM-expressed as supply cures that relate incremental DSM quantities with their costs-given the other resource options and inputs included in the modeL. The use of Class 2 DSM supply curves, along with the economic screening provided by using the capacity expansion model, determines the cost-effective mix of Class 2 DSM for a given scenario. For retail load forecast reporting, PacifiCorp deducts the Class 2 DSM load reductions reflected in the 2008 IRP preferred portfolio from the original "pre-DSM" load forecast. Modeling overview The following section describes the modeling techniques used to develop the load forecast. The load forecast is developed by forecasting the monthly sales by customer class for each jurs- diction. The residential, commercial, irrgation, public street lighting, and sales to public author- ity sales forecasts by jurisdiction is developed as a use per customer times the forecasted number of customers. The residential use-per-customer is forecasted by statistical end-use forecasting techniques. This approach incorporates end use information (satution forecasts and efficiency forecasts) but is estimated using monthly biling data. Satution trends are based on analysis of the Company's satuation surey data and efficiency trends are based on EIA forecasts that incorporate market forces as well as changes in appliance and equipment efficiency standards. Major drvers of the statistical end use based residential model are weather-related variables, end-use information such as equipment shares, satuation levels and effciency trends, and economic drvers such as household size, income and energy price. The commercial, irrgation, public street lighting, and sales to public authority use-per-customer forecast is developed using an econometrc modeL. For the commercial class, sales per customer are forecasted using regression analysis techniques with non-manufactung employment serving as the major economic driver in addition to weather related variables. For other classes, sales per customer are forecasted through regression analysis techniques using time trend variables. The customer forecasts are generally based on a combination of regression analysis and expo- nential smoothing techniques using historical data from 1997 to 2007. For the residential class, the customer forecasts are developed using a regression model with Global Insight's forecast of the states' number of households serving as the major drver. For the commercial class, forecasts rely on a regression model with the forecasted residential customer numbers being used as the major drver. For other classes (irrgation, street lighting, and public authority), customer fore- casts are developed based on exponential smoothing models. The industral sales forecast is developed for each jursdiction using a model which is dependent on input for the Customer Account Managers (CAMs). The industrial customers are separated into three categories: existing customers that are tracked by the CAMs, new large customers or expansions by existing large customers, and industral customers that are not tracked by the CAMs. Customers are tracked by the CAMs if (1) they have a peak load of five MW or more or if (2) they have a peak load of one MW or more and have a history of large variations in their monthly usage. The forecast for the first two categories is developed through the data gathered by the CAM assigned to each customer. The account managers have ongoing direct contact with 69 PocifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment large customers and are in the best position to know about the customer's plans for changes in business processes, which might impact their energy consumption. The portion of the industral forecast related to new large customers and expansion by existing large customers is developed based on direct input of the customers, forecasted load factors, and the probability of the project occurrence. Projected loads associated with new customers or ex- pansions of existing large customers are categorized into three groups. Tier I customers are those with a signed master electrc service agreement ("MESA") or engineering material and procurement agreement ("EMP A"). When a customer signs a MESA or EMP A, this contractu- ally commits the Company to provide services under the terms of agreement. Tier 2 includes customers with a signed engineering services agreement (ESA). This means that customer paid the Company to perform a study that determines what improvements the Company wil need to make to serve the requested load. Tier 3 consists of customers who made inquiries but have not signed a formal agreement. Projected loads from customers in each of these tiers are assigned probabilities depending on project-specific information received from the customer. Smaller industrial customers are more homogeneous and are modeled using regression analysis with trend and economic variables. Manufactug employment serves as the major economic driver. The total industral sales forecast is developed by aggregating the forecast for the three industrial customer categories. The segments are forecasted differently within the industrial class because of the diverse makeup of the customers within the class. After monthly energy by customer class is developed, hourly loads are estimated in two steps. First, PacifiCorp derives monthly and seasonal peak forecasts for each state. The monthly peak model uses historic peak-producing weather for each state, and incorporates the impact of weather on peak loads through several weather varables. These weather variables include the average temperature on the peak day and average daily temperatues for two days prior to the peak day. Second, hourly load forecasts for each state are obtained from the hourly load models using state-specific hourly load data and daily weather varables. Hourly load forecasts are de- veloped using a model that incorporates the 20-year average temperatues, the actual weather pattern for a year, and day-tye varables such as weekends and holidays. The model uses HDD (heating degree days) and CDD (cooling degree days) values for each of the twenty years and averages the results using a Ran and Average method instead of averaging by date as in the previous thirt-year process. This helps to incorporate both mild and extreme days in weather patterns, thereby more effectively representing the daily volatility in weather experienced during a tyical year. Also, the method preserves the extreme temperatues and maps them to a year to produce a more accurate estimate of daily temperatues. The hourly load forecasts are adjusted for line losses and calibrated to monthly and seasonal peaks. After PacifiCorp develops the hourly load forecasts for each state, hourly loads are aggregated to the total Company system leveL. System coincident peaks are then identified as well as the contrbution of each jursdiction to those monthly system peaks. The following sections describe the November 2008 energy and coincident peak load forecasts used for IRP portfolio modeling. 70 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Energy Forecast Table 5.1 shows average annual energy load growth rates for the PacifiCorp system and individ- ual states. Growth rates are shown for the forecast period 2009 though 2018. Table 5.1 - Forecasted Average Annual Energy Growth Rates for Load The total net control area load forecast used in this IRP reflects PacifiCorp's forecasts of loads growing at an average rate of 2.1 % percent annually from fiscal year 2009 to 20 i 8. Table 5.2 shows the forecasted load for each specific year for each state served by PacifiCorp and the aver- age annual growth (AAG) rate over the entire time period. Table 5.2 - Annual Load Growth forecasted (in Megawatt-hours) 2009 through 2018 2009 61558,392 15,475,197 4,481,972 1,006,036 24,211,643 10,077,831 3,746,722 2,558,992 2010 62,572,227 15,488,359 4,490,263 1,036,284 24,766,082 10,422,330 3,784,242 2,584,666 2011 63,979,543 15,733,361 4,528,860 1,072,927 25,331,349 10,873,984 3,825,481 2,613,580 2012 65860922 16,096,835 4,564,434 1,108,124 26,227,765 11,341,534 3,875,330 2,646,900 2013 67,602,494 16,395,770 4,586,107 1,119,431 26,990,389 11,738,006 4,024,940 2,747,851 2014 69,299,539 16,648,638 4,620,452 1,128,072 27,811,230 12,117,11 1 4,142,098 2,831,937 2015 70,735,798 16,790,823 4,652,542 1,136,689 28,631,507 12,498,120 4,172,873 2,853,245 2016 72,193,764 16,979,579 4,692,854 1,148,202 29,355,209 12,926,718 4,211,552 2,879,649 2017 73,110,441 17,080,573 4,709,745 1,153,152 29,791,003 13,240,453 4,237,529 2,897,985 2018 74348970 17281,372 4,752,289 1 165,356 30,363899 13,581,557 4,278,351 2,926146 2009-18 2.1%1.2%0.7%1.6%2.5%3.4%1.5%1.5% 2018-28 1.2%1.1%0.9%1.1%1.6%0.6%0.9%0.9% 2009-28 1.60/0 1.2%0.8%1.3%2.0%1.9%1.2%1.2% System-Wide Coincident Peak Load Forecast The system coincident peak load is the maximum load required on the system in any hourly pe- riod. Forecasts of the system peak for each month are prepared based on the load forecast pro- duced using the methodologies described above. From these hourly forecasted values, the coin- cident system peaks and the non-coincident peaks (within each state) durng each month are ex- tracted. In the 1990's the annual system peak usually occurred in the winter. After 2000, the annual sys- tem peak has generally occured in the summer. The system peak has switched to the summer as a result of several factors. First, the increasing demand for summer space conditioning in the residential and commercial classes and a decreasing demand for electrc related space condition- ing in the winter has contributed to shift from a winter peak to a summer peak. This trend in space conditioning is expected to continue. Second, Utah with a summer peak that is relatively higher than the winter peak has been growing faster than the system. This growth also has con- trbuted to a shift from a winter peak to a summer peaking system. 71 PaciffCorp - 20081RP Chapter 5 - Resource Needs Assessment Total system load factor is expected to be relatively stable over the 2009 to 2018 time period. There are several factors working in opposite directions, leading to this result. First, the rela- tively high growth in high load factor industral sales, particularly in Wyoming, tends to push up the system load factor. Second, as discussed above, the shift in space conditioning tends to push down the system load factor. And, third, efficiency standards such as the 2012 federal lighting standards also tend to push down the system load factor. Table 5.3 - Forecasted Coincidental Peak Load Growth Rates PacifiCorp's eastern system peak is expected to continue growing faster than the western system peak, with average anual growth rates of 2.7 percent and 1.6 percent, respectively, over the forecast horizon. Table 5.4 below shows that for the same time period the total peak is expected to grow by 2.4 percent. Table 5.4 - Forecasted Coincidental Peak Load in Megawatts 2009 10,143 2,463 761 167 4,509 1,253 628 362 2010 10,360 2,476 768 174 4,626 1,290 654 372 2011 10,631 2,526 780 181 4,708 1,354 682 401 2012 10,978 2,579 816 187 4,854 1,394 716 431 2013 11,261 2,638 800 190 5,008 1,440 748 437 2014 11,451 2,695 815 189 5,174 1,485 691 402 2015 11,730 2,728 826 191 5322 1,530 718 414 2016 12,032 2,763 836 194 5,458 1,577 759 446 2017 12,251 2,795 846 199 5,568 1,616 773 454 2018 2,836 889 197 5,686 1,656 786 473 2009-2018 2.4%1.6%1.8%1.9%2.6%3.1%2.5%3.0% 2018-2028 1.4%1.4%1.1%1.2%1.8%0.7%0.9%0.6% 2009-2028 1.9%1.5%1.4%1.5%2.2%1.9%1.7%1.8% One noticeable aspect of the states contrbution to the system coincidental peak forecast is that they do not smoothly increase from year to year, and in Idaho, the contrbution to system coinci- dent peak decreases in 2014. Idaho's contrbution to the coincident peak is forecasted to decrease in 2014 even though the to- tal system peak increases 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 differ- ences 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 contrbution to the system coinci- 72 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment dent 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 wil move within the season, month or day, and each state's contrbution wil move accordingly, sometimes resulting in a reduced contrbution 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 history. For example, the Idaho state load is drven in the sumer months by the activity in the irrgation class. The planting and irrgating practices usually cause this state to experience the maximum load in late June or early July. This load then quickly decreases week by week. Consequently, there can be as much as 300 MW of load difference between the maximum load and the loads during the last weeks of July. Jurisdictional Peak Load Forecast The economies, industr mix, appliance and equipment adoption rates, and weather patterns are different for each jurisdiction that PacifiCorp serves. Because of these differences the jursdic- 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 contrbution to the system peak demand. Table 5.5 reports the jurisdictional peak demand growth over the forecast horizon. Table 5.5 - Jurisdictional Peak Load forecast, 2009 through 2018 (Megawatts) 2009 2,781 850 187 4,678 1,343 776 434 2010 2,795 856 197 4,796 1,371 785 448 2011 2,825 863 204 4,875 1,419 795 453 2012 2854 876 210 5,033 1,473 806 485 2013 2,914 884 212 5,202 1,532 835 491 2014 2,958 897 214 5,360 1,581 858 497 2015 2,989 909 216 5,522 1,631 867 493 2016 3,010 919 218 5,662 1,680 874 511 2017 3,033 931 221 5,775 1,729 881 518 2018 3,059 942 223 5,902 1,776 890 536 2009-2018 1.1%1.1%2.0%2.6%3.2%1.5%2.4% 2018-2028 1.3%1.4%1.2%1.8%0.7%0.9%0.9% 2009-2028 1.2%1.3%1.6%2.20/0 1.8%1.2%1.6% 73 PocißCorp - 2008 IRP Chapter 5 - Resource Needs Assessment For the forecasted 2009 summer peak, PacifiCorp owns, or has interest in, resources with an ex- pected system peak capacity of 13,145 MW. Table 5.6 provides anticipated system peak capacity ratings by resource category as reflected in the IRP load and resource balance for 2009. Table 5.6 - Capacity Ratings of Existing Resources Pulverized Coal 6, i 28Gas-CCCT 2,025Gas-SCCT 380 Hydroelectric 1,450Class i DSM ** 345Renewables 247Puchase *** 2,061 Qualifying Facilities 271Interrptible 237Total 13,145 * Represents the capacity available at the time of system peak. ** Class 1 Demand-side management is PacifiCorp's dispatchale load contrl. *** Purchases constitute contracts that do not fall into other categories such as hydrelectrc, renewables, and natural gas. 46.6% 15.4% 2.9% 11.0% 2.6% 1.9% 15.7% 2.1% 1.8% 100% Thermal Plants In September 2008, the Chehalis combine cycle combustion tubine plant began operations add- ing 509 MW of summer peak capacity to the PacifiCorp thermal fleet. Table 5.7 lists existing PacifiCorp's coal fired thermal plants and table 5.8 lists existing natual gas fired plants. As a modeling assumption, plant retirements were based on the Company's 2007 depreciation study. The end of the depreciable life of Gadsby unts 1-3 is curently 2017, while the depreciable life for Carbon units 1 and 2 is 2020. No thermal plants are curently scheduled for retirement. Plant retirement decisions wil be based on an assessment of plant economics that considers the cost for replacement power given environmental compliance requirements, market conditions, and other factors. Table 5.7 - Coal Fired Plants Carbon 1 100%Uta 67.0 Carbon 2 100%Uta 105.0 Cholla4 100%Arzona 395.0 Colstrp 3 10%Montaa 74.0 Colstrp 4 10%Montaa 74.0 Craig 1 19%Colorado 82.5 Craig 2 19%Colorado 82.5 Dave Johnston 1 100%Wyoming 106.0 Dave Johnston 2 100%Wyoming 106.0 74 ............................................ ............................................ PaciØCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Dave Johnston 3 100%Wyoming 220.0 Dave Johnston 4 100%Wyoming 330.0 Hayden 1 24%Colorado 45.1 Hayden 2 13%Colorado 33.0 Hunter 1 94%Uta 403.1 Hunter 2 60%Utah 259.3 Hunter 3 100%Uta 460.0 Huntington 1 100%Uta 445.0 Huntington 2 100%Uta 450.0 Jim Bridger 1 67%Wyoming 353.3 Jim Bridger 2 67%Wyoming 353.3 Jim Bridger 3 67%Wyoming 353.3 Jim Bridger 4 67%Wyoming 353.3 Naughton 1 100%Wyoming 160.0 Naughton 2 100%Wyoming 210.0 Naughton 3 100%Wyoming 330.0 Wyodak 80%Wyoming 268.0 Table 5.8 - Natural Gas Plants Curant Creek 100% Utah 541Gadsby 1 100% Uta 60Gadsby 2 100% Uta 75Gadsby 3 100% Utah 100Gadsby 4 100% Uta 40Gadsby 5 100% Uta 40Gadsby 6 100% Uta 40Hermiston 1 . 50% Oregon 124Hermiston 2 · 50% Oregon 124Lake Side 100% Utah 544 Chehalis 100% Washington 520 * Remainder of Hermiston plant under purchase contract by the Company for a total of 248 MW. Renewables PacifiCorp's renewable resources, presented by resource tye, are described below. Wind PacifiCorp acquires wind power from owned plants and various purchase agreements. Since the 2007 IRP, PacifiCorp has acquired several large wind resources including Seven Mile I and II, and Marengo II, Glenrock I and III, and Rolling Hils. These projects came on line in 2008. The 75 PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Company also entered into 20-year power purchase agreements for the total output of several projects including Mountain Wind I and II and Spanish Fork in 2008, Duke Energy's (Three Buttes Windpower LLC) Campbell Hil project and Oregon Wind Farm I in 2009, and Oregon Wind Farm II in 2010. Table 5.9 shows existing and firm planed wind facilities owned by PacifiCorp, while Table 5.10 shows existing wind power purchase agreements. For the year ended December 31, 2008, PacifiCorp's total installed wind capacity totaled 802 MW, along with 315 MW of purchased power capacity. Table 5.9 - PacifiCorp-owned Wind Resources Foote Creek 11/ Leanin Juni er Goodnoe Hils East Wind Maren 0 Glenrock Wind I Glenrock Wind II Maren 0 II Rolln Hils Wind Seven Mile Hil Wind Seven Mile Hil Wind II Hi h Plains Under Constrction TOTAL 33.0 100.5 94.0 140.4 99.0 39.0 70.2 99.0 99.0 19.5 99.0 893.0 2005 2006 2007 2007 2008 2008 2008 2008 2008 2008 2009 WY OR WA WA WY WY WA WY WY WY WY 11 Net total capacity for Foote Creek I is 41 MW. Table 5.10 - Wind Power Purchase Agreements Foote Creek II 25.2 2005 WY Foote Creek IV 16.8 2005 WY Wolverine Creek 64.5 2005 il Rock River I 50.0 2006 WY Mountain Wind Power I 60.0 2008 WY Mountain Wind Power II 79.5 2008 WY S anish Fork 18.9 2008 UT Thee Buttes Wind Power uke 99.0 2009 WY Ore on Wind Far I 45.0 200 OR Ore on Wind Far II 20.0 2010 OR TOTAL 478.9 PacifiCorp also has wind integration, storage and retu agreements with Bonnevile Power Ad- ministration, Eugene Water and Electric Board, Public Service Company of Colorado, and Seat- tle City Light. 76 ............................................ ............................................ PaciffCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Geothermal PacifiCorp owns and operates the Blundell Geothermal Plant in Utah, which uses natually cre- ated steam to generate electrcity. The plant has a net generation capacity of 34 MW. Blundell is a fully renewable, zero-discharge facility. The bottoming cycle, which increased the output by 11 MW, was completed at the end of2007. Biomass Since the 2007 IRP, PacifiCorp has acquired power through power purchase agreements, as well as from several small biomass facilities under Qualifying Facility Agreements. Examples are found in Table 5.11. Table 5.11 - Existing Biomass resources 25.0 1.6 6.25 8.3 10.0 20.0 1.28 9.5 Oregon Uta Oregon Oregon Oregon Oregon Oregon Wyoming Biogas Since the 2007 IRP, PacifiCorp has acquired power through power purchase agreements, as well as from several small biomass facilities under Qualifying Facility Agreements. Examples are found in Table 5.12. Table 5.12 - Existing Biogas resources 0.15 0.125 0.95 2.5 0.05 1.2 4.8 3.2 Uta Uta Utah Utah Uta Washington Oregon Oregon Solar PacifiCorp has invested in Solar II, the world's largest solar energy plant, located in the Mojave Desert. The Company has installed panels of photovoltaic (PV) cells in its service area, includ- ing The High Desert Museum in Bend Oregon, PacifiCorp offce 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 photovoltaic solar panels. Other locations in the service terr- tory with solar include a 60 unit apartent in Salt Lake City, Utah and the North Wasco School 77 PocifìCorp - 2008 IRP Chapter 5 - Resource Needs Assessment distrct at Mosier, Oregon. Currently, there are 410 net meters throughout the Company, mostly residential, and most have solar technology followed by wind and hydroelectrc. Hydroelectric Generation PacifiCorp owns or purchases 1,450 MW of hydroelectrc generation. These resources account for approximately i 1 percent ofPacifiCorp's total generating capability, in addition to providing operational benefits such as flexible generation, spinning reserves and voltage control. Hydroe- lectrc plants are located in California, Idao, Montana, Oregon, Washington, Wyoming, and Utah. The amount of electrcity PacifiCorp is able to generate from its hydroelectrc 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 ruoff, PacifiCorp is able to generate a higher than average amount of electrcity using its hydroelectrc plants. However, when these factors are unfavorable, PacifiCorp must rely to a greater degree on its more expensive thermal plants and the purchase of electrcity to meet the demands of its customers. PacifiCorp has added approximately 5 MW of additional capacity to its hydroelectrc portfolio since the release of the 2007 IRP. This additional capacity is found in Table 5.13. Table 5.13 - Hydroelectric additions 0.45 0.5 0.85 0.075 0.04 0.05 0.08 2.95 Idaho Oregon Uta Oregon Oregon Oregon Oregon Washington Table 5.14 provides an operational profie for each of PacifiCorp's hydroelectrc generation fa- cilities. The dates listed refer to a calendar year. Table 5.14 - Hydroelectric Generation Facilties - Nameplate Capacity as of January 2009 Clearwater 1 Clearater 2 Co co 1 California 78 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Co co2 East Side Fish Creek Iron Gate IC Bo Ie Lemolo 1 Lemolo 2 Merwin Ro e Slide Creek Soda S rin s Swift 1 Toketee West Side Yale 27.00 3.20 11.00 18.00 97.98 31.99 33.00 136.00 46.76 18.00 11.00 240.00 42.50 0.60 134.00 18.11 California California Bear River 108.73 IDIUT Varous 2006 2006 2038 2006 2006 2038 2038 2058 Varous 2038 2038 2058 2038 2006 2058 Varous 2046 2016 2038 2046 2046 2038 2038 2058 Vanous 2038 2038 2058 2038 2016 2058 Small East H dro** 33.85 IDIUTIW Various Various * Includes Bend, Condit, Fall Creek, and Wallowa Falls ** Includes Ashton, Pars, Pioneer, Weber, Stairs, Granite, Snake Creek, Olmstead, Fountain Green, Veyo, Sand Cove, Viva Naughton, and Gunlock. Note: Operational Capacity may differ from Nameplate Capacity due to operating conditions. Hydroelectric Relicensing Impacts on Generation Table 5.15 lists the estimated impacts to average annual hydro generation from FERC license renewals. PacifiCorp assumed that all hydroelectrc facilities currently involved in the relicens- ing process wil receive new operating licenses, but that additional operating restrctions imposed in new licenses, such as higher bypass flow requirements, wil reduce generation available from these facilities. Table 5.15 - Estimated Impact of FERC License Renewals on Hydroelectric Generation 2009 2010 2011 2012 2013 2014 2015 160,356 160,356 160,356 195,560 195,560 195,560 338,917 79 PocifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment 2016 415,3282017 415,3282018 413,4352019 415,5662020 415,5662021 415,5662022 415,5662023 415,5662024 415,5662025 415,5662026 415,5662027 415,5662028 415,566 Note: Excludes the decommssioning of Condit, Cove, Powerdae, and American Fork. Demand-side Management Demand-side management resources/products vary in their dispatchability, reliability of results, term of load reduction benefit and persistence over time. Each has its value and place in effec- tively managing utility investments, resource costs and system operations. Those that have greater persistence and firmess (can coUit on them to be delivered) can be relied upon as base resources for planning puroses; 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 condi- tions, plant outages, market prices, and unanticipated system failures. Demand-side management resources/products can be divided into four general classes based on their relative characteristics, the classes are: · Class 1 DSM: Resources from fully dispatchable or scheduled firm capacity product offerings/programs - Class 1 progrms are those for which capacity savings occur as a re- sult of active Company control or advanced scheduling. Once customers agree to participate in Class i DSM program, the timing and persistence of the load reduction is involuntary on their part within the agreed limits and parmeters of the program. In most cases, loads are shifted rather than avoided. Examples include residential and commercial central air condi- tioner load control programs ("Cool Keeper") that are dispatchable in nature and irrgation load management and interrptible or curtilment progrms (which may be dispatchable or scheduled firm, depending on the particular program). · Class 2 DSM: Resources from non-dispatchable, firm energy and capacity product of- ferings/programs - Class 2 progrms are those for which sustainable energy and capacity savings are achieved though facilitation of technological advancements in equipment, appli- ances, lighting and strctues. Class 2 programs generally provide financial and/or service in- centives to customers to replace equipment and appliances in existing customer owned facili- ties (or to upgrade in new constrction) to more efficient lightig, motors, air conditioners, insulation levels, windows, etc. Savings wil endure over the life of the improvement (firm). Program examples include air conditioning efficiency progrms ("Cool Cash"), comprehen- sive commercial and industral new and retrofit energy effciency programs ("Energy Fin- swer") and refrigerator recycling progrms ("See ya later refrgerator"). 80 ............................................ ............................................ Paci~Corp - 2008 IRP Chapter 5 - Resource Needs Assessment . Class 3 DSM: Resources from price responsive energy and capacity product offer- ings/programs - Class 3 DSM programs seek to achieve short-duration (hour by hour) en- ergy and capacity savings from actions taken by customers voluntarily, based on a financial incentive or signaL. Savings are measured at a customer-by-customer level (via metering and/or metering against baselines), and customers are compensated or charged in accordance with a program's pricing parameters. As a result of their voluntary natue, savings are less predictable, making them less suitable to incorporate into resource planning exercises, at least until such time that their size and customer behavior profie provide sufficient informa- tion for a reliable diversity result for modeling and planning purposes. Savings tyically only endure 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 Ex- change"), time-of-use pricing plans, critical peak pricing plans, and inverted tariff designs. . Class 4 DSM: Resources from energy effciency education and non-incentive based vol- untary curtailment programs/communications/pleas - Class 4 programs resources may be in the form of energy and/or capacity reductions. The reductions are tyically achieved from voluntary actions taken by customers, behavior changes, to save energy and/or reduce costs, benefit the environment or in response to public or utility company pleas to conserve or shift their usage to off peak hours. Program savings are diffcult to measure and in many cases tend to var over time. While not specifically relied upon in resource planning, Class 4 sav- ings appear in historical load data therefore into resource planning through the plan load forecasts. The value of Class 4 DSM is long-term in natue. Class 4 programs help foster an understanding and appreciation as to why utilities seek customer participation in Class 1, 2 and 3 programs, as well provide a foundational understanding of how to use energy wisely. Program examples include Utah's PowerForward program, Company brochures with energy savings tips, customer news letters focusing on energy effciency, case studies of customer energy efficiency projects, and public education and awareness programs such as "Do the bright thing" and "Let's tu the answers on". Studies have shown potential savings up to 15% from behavior changes25, especially when coupled with complimentary DSM programs to assist customers with a portion of the actions taken.26 Although these behavior savings are often difficult and costly to track and measure, enough studies have measured their effects to expect at least a very modest degree of savings (equal to or greater than those expected to be acquired through DSM programs; e.g. 1+%) to be realized and reflected in customer usage and future load forecasts. 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 through 4) and resource planning considerations. Company investments continue to increase year on year with 2008 investments exceeding $76 25 Lyn Fryer Stein, "California Information Display Pilot Technology Assessment" (December 2004), prepared by Prien Inc., for Southern California Edison. 26 John Green and Lisa A. Skuatz, "Evaluating the Impacts of Education/Outreach Programs: Lessons on Impacts, Methods and Optimal Education, "paper presented at the American Council for an Energy Effcient Economy sum- mer Study on Energy Effciency in Buildings (2000). 81 PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment milion (all states). Work continues on the expansion of program portfolios in the states of Utah, Washington, Idaho and California. In late 2008 the Company received approval to begin offering DSM programs to Wyoming customers beginning in Januar 2009. In Oregon the Company is working closely with the Energy Trust of Oregon on helping to identify additional resource op- portities, improve delivery and communication coordination, and ensure adequate fuding and Company support in puruit of DSM resource targets. The following represents a brief summar of the existing resources by class. Class 1 Demand-side Management Currently there are four Class i programs running across PacifiCorp' s six state service area; Utah's "Cool Keeper" residential and small commercial air conditioner load control program; Idaho's and Utah's scheduled firm irrgation load management programs; Idaho's and Utah's dispatchable irrgation load management programs; and special contrct curailment agreements with large business customers. In 2008 the programs provided approximately 560 megawatts of Class 1 DSM program resources durng the highest sumer peak load hours. Class 2 Demand-side Management The Company curently manages thireen distinct Class 2 products, many of the products are of- fered in multiple states. In all, the combination of Class 2 programs across the Company's six state service area total thirt-four. The cumulative historical energy and capacity savings (1992- 2008) associated with Class 2 DSM progrm activity has accounted for nearly 3.4 milion megawatt hours and over 600 megawatts of load reductions. Class 3 Demand-side Management The Company has numerous Class 3 progrms curently available. They include metered time- of-day and time-of-use pricing plans (in all states, availability varies by customer class), residen- tial seasonal inverted rates (Utah), residential year-around inverted rates (California, Oregon, and Washington) and Energy Exchange programs (Oregon, Uta, Idaho, Wyoming and Washington). Savings associated with these programs are captued within the Company's load forecast, with the exception of the more immediate call-to-action progrs like Energy Exchange and Utah's PowerForward programs. The impacts of these programs are thus captued in the integrated re- source planing framework. Energy Exchange and Uta's PowerForward are examples of Class 3 programs relied upon as reliability resources as opposed to base resources. System-wide par- ticipation in metered time-of-day and time-of-use programs as of December 31,2008 was about 21,700 customers, up from about 21,200 in 2006. Approximately 1.28 milion residential cus- tomers-89% of the Company's residential customer base-are curently subject to inverted rate plans either seasonally or year-around. PacifiCorp continues to evaluate Class 3 programs for applicability to long-term resource plan- ning. As discussed in Chapter 6, five additional programs were provided as resource options in preliminary IRP modeling scenaros. Class 4 Demand-side Management Educating customers regarding energy efficiency and load management opportities 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, bil inserts, bil messages, 82 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment newsletters, school education programs, and personal contact. Specific firm load reductions due to Class 4 DSM activity wil show up in Class 2 DSM program results and non- program/documented reductions in the load forecast over time. Table 5.16 summarizes the existing DSM programs, and describes how they are accounted for as planned resources. Table 5.16 - Existing DSM Summary, 2009-2018 1 Residential/small commer- cial air conditioner load control Irrgation load mana ement Interr tible contracts Company and Energy Trut of Oregon programs Yes 100 MW sumer peak Yes 220 MW summer peak Yes 237MW 483 MWa and 908 MW 2008 IRP selections 0-37 MW (assumes no other Class 3 competing products runin MWaI unavailable 22.,000 customers MWaI unavailable 1.28 millon residential Yes 2 No, leveraged as economic and reliability resource dependent on market rices/s stem loads No, historical behavior captued in load forecast No, historical behavior captued in load forecast No, leveraged as economic and reliabilty resource dependent on market rices/s stem loads No, captued in load forecast over time and other Class 1 and Class 2 ro ram results Energy Exchange 3 Time-based pricing Inverted rate pricing PowerForward 0-80 MW sumer peak 4 Energy Education MW aI unavailable Power Purchase Contracts PacifiCorp obtains the remainder of its energy requirements, including any changes from expec- tations, through long-term firm contracts, short-term firm contracts, and spot market purchases. Figue 5.1 presents the contract capacity in place for 2008 through 2018 as of Januar 2009. As shown, major capacity reductions in purchases and hydro contracts occur. (For planning pur- poses, PacifiCorp assumes that curent qualifying facility and interrptible load contracts are ex- tended to the end of the IRP study period.) Note that renewable wind contracts are shown at their capacity contrbution levels. 83 PacißCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Figure 5.1 - Contract Capacity in the 2008 Load and Resource Balance 4,500 4,000 3,500 3,000 2,500 :;:2 2,000 1,500 1,000 500 0 2009 2010 2011 II Purchase II Hydro cRenewable IiQF . Interrptible 2012 2013 2014 2015 2016 2017 2018 Listed below are the major contrct expirations expiring between the summer 2011 and summer 2012: . BP A Peaking . Morgan Stanley . Morgan Stanley . Colockum Capacity Exchange . Rocky Reach . Grant Displacement 575MW 100MW 100MW 108MW 65MW 63MW Figure 5.2 shows the year-to-year changes in contrct capacity. Early year fluctuations are due to changes in short-term balancing contrcts of one year or less, and expiration of the contracts cited above. 84 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Figure 5.2 - Changes in Contract Capacity in the Load and Resource Balance 200 0 (200) (400) 3:: (600) (800) (1,000) (1,200) 2010 2011 o Purchase ElHydro . Renewable E:QF El Interrptible 2012 2016 2017 2018201320142015 Capacity and Energy.Balance Overvew The purose of the load and resource balance is to compare the annual obligations for the first ten years of the study period with the 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 futue resource deficits. It was developed by first determining the system coincident peak load hour for each ofthe first ten years (2009-2018) 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 anual system peak hours. The annual resource deficit (surlus) 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 surlus (deficit) of energy over the first ten years of the planning horizon (2009-2018). The average obligation (load plus sales) was computed and subtracted from the average existing resource availability for each month and time-of-day period. This was done for each side of the PacifiCorp system as well as at the system leveL. The energy balance complements the capacity balance in that it also indicates when resource deficits occur, but it also provides insight into what tye of resource wil best fill the need. The usefulness of the energy balance is limited as it does not address the cost of the 85 PaciØCorp - 2008 IRP Chapter 5 - Resource Needs Assessment available energy. The economics of adding resources to the system to meet both capacity and energy needs are addressed with the portfolio studies described in Chapter 8. Capacity and energy balance inormation is reported for two scenarios: with the Lake Side II combined-cycle plant included as a firm planned resource in 2012, and Lake Side II excluded as a resource, resulting in a larger capacity deficit beginning in that year. 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 are shown in Table 5.6 by resource category and summed to show the total available existing resource capacity for the east, west and for the PacifiCorp system. A description of each ofthe resource categories follows: · ThermaL. This category includes all thermal plants that are wholly-owned or partially-owned by PacifiCorp. The capacity balance counts them at maximum dependable capability at 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 i i coal- fired plants, six natul gas- fired plants, and two co-generation units. These thermal re- sources account for roughly two-thirds of the firm capacity available in the PacifiCorp sys- tem. · Hydro. This category includes all hydroelectrc generation resources operated in the Pacifi- Corp system as well as a number of contrcts providing capacity and energy from various counterparties. The capacity balance counts these resources by the maximum capability that is sustainable for one hour at the time of system peak, an approach consistent with curent WECC capacity reporting practices. The energy associated with critical level stream flow is estimated and shaped by the hydroelectrc dispatch from the Vista Decision Support System modeL. The energy impacts of hydro relicensing requirements, such as higher bypass flows that reduce generation, are also accounted for. Over 90 percent of the hydroelectrc capacity is situated on the west side of the PacifiCorp system. The Utah commission, in its 2007 IRP acknowledgment order, directed the Company to in- vestigate the hydro capacity accounting methodology curently under consideration for re- gional resource adequacy reporting puroses in the Pacific Northwest. This accounting meth- odology extends the one-hour sustained peaking period to the six highest load hours over three consecutive days of highest demand. This sustained peaking-period definition was adopted in 2008 by the Nortwest Power and Conservation Council (NPCC) as part the ca- pacity resource adequacy standard developed by the Pacific Nortwest Resource Adequacy Foru. The hydro sustained peak capacity methodology is stil being evaluated to work out certain methodology details and to determine how best to implement it on a regional basis. 86 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment The Pacific Northwest Resource Adequacy Forum hired a consultant to conduct the study, which is expected to be completed by the end of 2009. PacifiCorp conducted a cursory analysis of hydro resource capacity using the NPCC sus- tained peaking-period definition. The impact of moving from a one-hour sustained peaking period to an 18-hour period was found to be negligible. · Demand-Side Management (DSM). In 2009, there are projected to be about 345 mega- watts of Class 1 demand-side management programs included as existing resources. These are fuher projected to increase to 525 MW by 20 i 8. Both the capacity balance and the en- ergy 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 one geothermal project, 21 existing wind projects and two planned wind projects. The capacity balance counts the geothermal plant by the maxi- mum dependable capability while the energy balance counts the maximum dependable capa- bility after forced outages. Project-specific capacity credits for the wind resources were sta- tistically determined. Wind energy is counted according to hourly generation data used to model the projects. . Purchase. This includes all of the major contracts for purchases of firm capacity and energy in the PacifiCorp system. The capacity balance counts these by the maximum contract 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 Facilties (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 wil stay in place for the entire duration of the 20-year planning period. It should be noted that thee 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 237 MW of load interrption capa- bility at time of system peak. Both the capacity balance and energy balance count these re- sources at the level of full load interrption on the executed hours. Interrptible resources di- rectly curil load and thus planning reserves are not held for them. Obligation The obligation is the total electrcity demand that PacifiCorp must serve, consisting of forecasted retail load and firm contracted sales of energy and capacity. The following are descriptions of each of these components: 87 PaciffCorp - 200BIRP Chapter 5 - Resource Needs Assessment · Load. The largest component of the obligation is the retail load. The capacity balance counts the peak load (MW) at the hour of system coincident peak load. The energy balance counts the load as an average of monthly time-of-day energy (MWa). Due to new federal lighting standads being implemented under the Energy Policy Act of 2005, the load forecast required adjustment because lighting efficiency measures were em- bedded in the Class 2 DSM supply cures provided to PacifiCorp. Increasing the load fore- cast to account for this available energy efficiency "supply" ensures that an appropriate quan- tity of Class 2 DSM is selected by the capacity expansion modeL. Table 5.17 shows the im- pact of the hourly energy adjustments to the annual system coincident peak loads used in the 10-year capacity load and resource balance. (Note that this upward load adjustment applies only for capacity expansion modeling puroses. The Company's offcial load forecast is re- ported net of this DSM adjustment.) Table 5.17 - Federal Lighting Standard Impact on System Peak loads 2009 6.3 10,143 10,150 2010 10.3 10,360 10,371 2011 8.5 10,631 10,640 2012 12.2 10,978 10,991 2013 20.3 11,261 11,281 2014 50.8 11,451 11,501 2015 69.2 11,730 11,798 2016 94.1 12,032 12,127 2017 132.7 12,251 12,384 2018 151.6 12,522 12,674 2019 144.5 2020 173.1 2021 174.6 2022 200.9 2023 217.7 2024 226.2 2025 232.0 2026 234.1 2027 239.4 2028 245.0 · Sales. This includes all contracts for the sale of firm capacity and energy. The capacity bal- ance counts these contracts by the maximum obligation at time of system peak and the en- ergy balance counts them by optimum model dispatch. All sales contracts are firm and thus planning reserves are held for them in the capacity view. 88 ............................................ ............................................ PacifiCorp ~ 2008 IRP Chapter 5 - Resource Needs Assessment 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 tyes of reserves follows: . Planning reserves. This is the total reserves that must be held to provide the planning re- serve margin. It is the net firm obligation multiplied by the planning reserve margin as in the following equation: Planning reserves = (Obligation - Purchase - DSM - Interrptible) 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 70 megawatts on the west and east-sides, respectively. Position The position is the resource surlus (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 wil 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- cates that existing resources do not meet obligation. If existing resources equals the obligation, then the reserve margin is 0%. 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. CapaCIty Balance Determination Methodology The capacity balance is developed by first determining the system coincident peak load hour for each of the first ten years of the planing horizon. Then the annual firm-capacity availability of the existing resources is determined for each of these anual system peak hours and sumed 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 anual system peak hours to compute the annual peak-hour obligation: Obligation = Load + Sales The amount of reserves to be added to the obligation is then calculated. This is accomplished by first removing the firm purchase and load curailment components of the existing resources from the obligation. This resulting net obligation is then multiplied by the planing reserve margin. 89 PacifiCorp - 200BIRP Chapter 5 - Resource Needs Assessment 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 anual capacity position is derived by adding the computed reserves to the obliga- tion, and then subtracting this amount from existing resources as shown in the following for- mula: Capacity Position = Existing Resources - Obligation - Reserves Firm capacity transfers from PacifiCorp's western to eastern control areas are reported for the east capacity balance, while capacity transfers from the eastern to western control areas are re- ported for the west capacity balance. Capacity transfers represent the optimized control area in- terchan~e at the time of the system coincident peak load as determined by the System Optimizer modei.2 Load and Resource Balance Assumptions The assumptions underlying the curent load and resource balance are generally the same as those from the 2007 IRP update with a few exceptions. The following is a summar of these as- sumption changes: · Wind Commitment. In the 2007 IRP, 400 megawatts of the overall 1,400-megawatt com- mitment are included in the load and resource balance. The remaining 1,000 megawatts were treated as part of the overall wind resource potential evaluated in portfolio modeling. In the 2008 IRP, there are 263 MW of firm planed wind projects included in the load and resource balance. · Coal plant turbine upgrades. The curent load and resource balance assumes 162 MW of coal plant tubine upgrades, which is down from the 202 MW assumed in the 2007 IRP Up- date Report. Capacity Balance Results Table 5.18 shows the annual capacity balances and component line items using a target planning reserve margin of 12 percent to calculate the planing reserve amount. (Capacity balance infor- mation with Lake Side II included as a planned resource in 2012 is provided in Appendix H.) 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 sys- tem is planned for and dispatched on a system basis.) For comparison puroses, Table 5.19 shows the system-level capacity balance assuming a 15 percent planing reserve margin. Figues 5.3 through 5.5 display the anual capacity positions (resource surlus or deficits) for the system, west control area, and east control area, respectively. The decrease in resources in 2008 27 West-to-east and east-to-west trasfers should be identicaL. However, decimal precision of a transmission loss parameter internal to the System Optimizer model results in a slight discrepancy (less than 2 MW between reported values. 90 ............................................ ...PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment..is caused by the expected expiration of the West Valley lease agreement. The slight increase in.2009 is due to executed front office transactions and an increase in the curilment portion of the Monsanto contract. The large decrease in 2012 is primarily due to the expiration of the BPA.peaking contract in August 2011. Additionally, Figue 5.4 highlights a decrease in obligation in.the west starting in 2014 attbutable to the expiration of the Sacramento Municipal Utility Dis-.trct and City of Redding power sales contracts..Table 5.18 - System Capacity Loads and Resources (12% Target Reserve Margin).Year 2009 2011 2012 2013 2014.5,983 5,998 6,025 6,066 6,066 6,078.Hydro 135 135 135 135 135 135 135 135 135 135 DSM 345 395 435 465 475 485 495 505 515 525.Renewable 157 157 157 157 157 157 154 154 154 154 Purchase 751 546 541 341 341 341 341 320 320 320.QF 151 151 151 151 151 151 151 151 151 151.Interrptible 237 237 237 237 237 237 237 237 237 237 Trafers 1,150 952 602 422 440 230 490 504 265 414.East Exiting Resources 8,910 8,572 8,284 7,975 8,003 7,814 8,082 8,093 7,865 7,800.Load 6,757 6,949 7,150 7,404 7,643 7,779 8,029 8,303 8,491 8,696 Sale 781 768 758 747 745 745 745 745 659 659.East Obligation 7,538 7,717 7,908 8,151 8,388 8,524 8,774 9,048 9,150 9,355.Planng reserves 745 785 803 853 880 895 924 958 969 993.Non-owned reserves 70 70 70 70 70 70 70 70 70 70 East Reserves 815 855 874 923 951 966 995 1,029 1,040 1,063.East Obligation + Reserves 8,352 8,572 8,781 9,074 9,339 9,490 9,769 10,077 10,190 10,418.East Position 558 1 (498)(1,099)(1,336)(1,676)(1,686)(1,984)(2,325)(2,619) East Reserve Margin 19%12%6%(1%)(4%)(8%,)(7%)(10'%)(13%)(16%)..2,550 2,559 2,568 2,579 2,591 2,591 2,577 Hydro 1,315 1,218 1,216 980 1,009 1,046 1,157 1,149 1,146.DSM.Renewable 90 96 96 90 90 90 90 90 90 90 Puchase 1,310 1,203 753 115 144 ILL 111 111 111 139.QF 120 120 120 120 120 120 120 120 120 120 Trafers (1,152)(953)(603)(422)(442)(228)(489)(504)(263)(415).West Exiting Resources 4,233 4,242 4,150 3,462 3,513 3,729 3,580 3,558 3,783 3,656.Load 3,393 3,422 3,490 3,587 3,638 3,722 3,769 3,824 3,893 3,978 Sale 499 490 290 258 258 258 158 108 108 108.West Obligation 3,892 3,912 3,780 3,845 3,896 3,980 3,927 3,932 4,001 4,086.Planng reserves 310 325 363 448 450 464 458 459 467 474.Non-owned reserves 7 7 7 7 7 7 7 7 7 7 West Reserves 316 332 370 454 457 471 464 465 473 480.West Obligation + Reserves 4,208 4,243 4,149 4,299 4,353 4,451 4,391 4,397 4,474 4,566.West Position 25 (1)0 (837)(840)(721)(811)(839)(691)(909) West Reserve Margin 13%12%12%(10%)(10%)(6%)(9%)(9%)(5%)(10%)..1 1 1.Obligation 11,430 11,628 11,687 11,996 12,284 12,504 12,701 12,980 13,151 13,441 Reserves 1,131 1,187 1,243 1,377 1,407 1,437 1,459 1,494 1,513 1,543.Obligation + Reserves 12,561 12,815 12,931 13,373 13,692 13,940 14,160 14,474 14,664 14,984 System Position 583 (0)(498)(1,936)(2,176)(2,397)(2,498)(2,823)(3,016)(3,528).Reserve Margi 17%12%8%(4%)(6%)(7%)(80/0)(lOOÆ)(11%)(14%)..91.. PacifiCorp - 200BIRP Chapter 5 - Resource Needs Assessment Table 5.19 - System Capacity Loads and Resources (15% Target Reserve Margin) Calendar Year 2010 2011 2012 2013 2015 2016 2018 Total Resources 13,143 12,815 12,433 11,437 11,515 11,543 11,662 11,651 11,648 11,456 Obligation 11,430 11,628 11,687 11,996 12,284 12,504 12,701 12,980 13,151 13,441 Reserves 1,395 1,464 1,535 1,703 1,740 1,776 1,805 1,848 1,872 1,910 Obligation + Reserves 12,824 13,092 13,222 13,698 14,024 14,280 14,505 14,828 15,023 15,351 System Position 319 (277)(789)(2,261)(2,509)(2,737)(2,843)(3,17)(3,375)(3,895)Reserve Margn 18%13%8%(4%)(5%)(7%)(7%)(9%)(11%)(14%) Figure 5.3 - System Capacity Position Trend 18,00 16,000 Obligation + Reserves (12% & 15%) "'14,000 12,00 10,000 ~:: 8,00 6,00 4,00 2,00 0 209 2010 2011 202 2013 204 2015 206 2017 2018 92 ............................................ ............................................ PadfìCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Figure 5.4 - West Capacity Position Trend 14,00 12,000 10,000 3::; 8,00 6,000 4,000 18,000 16,000 Obligation + ReSèiveS. (12%& 15"1)"' 2,000 o 200 2017 20182010201120122015201620132014 Figure 5.5 - East Capacity Position Trend 18,00 16,00 14,00 12,000 10,00 3::; 8,00 6,00 4,00 2,00 Obligation + Reserves (12"1 & 15%)~ o 2009 201820102016201720112012201320142015 93 PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Energy Balance Determination Methodology The energy balance shows the average monthly on-peak and off-peak surlus (deficit) of energy. The on-peak hours are weekdays and 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 + Interrptible 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 (12% PRM) Energy Balance Results Figues 5.6 through 5.8 show the energy balances for the system, west control area, and east con- trol area, respectively. They indicate the energy balance on a monthly average basis across all hours, and also indicate the average anual energy position. The cross-over point, where the sys- tem starts to become energy deficient on a sumer hour basis, is 2012, absent any economic considerations. 94 ............................................ ............................................. PacifiCorp - 2008 IRP Chapter 5 - Resource Needs Assessment Figure 5.6 - System Average Monthly and Annual Energy Balances 3,000 2,500 2,000 1,50 i 1,000 500 o (500) (1,000) (1,500) limimiF Annual Balance -Monthly Balance (2,000)~ Q~ ~ 0 a c 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ . . . . ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~9 9 ~ 9 ~ ~ S! ~ ~ S ~ ~ ~ S ~ ~ ~ ~ ~ ~ ~ S ~ ~ ~ ~ ~ ~ ~ S ~ ~ ~ S ~ ~ ~S sl ~~ & l ~~ 8 l ~ ~ & l ~~ & l ~~ & l ~~ 8 l ~~ 8 l ~~ 8 l ~~ 8 l ~~ 8 Figure 5.7 - West Average Monthly and Annual Energy Balances 3,000 2,500 2,000 1,500 1,000 500 .. ~0 (500) (1,000) (1,500) $::: (2,000)Q ~ ~ Q~~~~~ ~~~~~~~~~~~~~~~~~~~~~~~~ ~ ~ ~ ~~~~9~~i.~~~ '~~tt .~~,.~ '' '~~ I .~~ r '~~~ I~~~~~~~l ~~8l ~~ &l ~~ö l ~~8l ~~8l ~~8l ~~&l ~~ &l ~~8~ ~~o 95 PacifiCorp - 200BIRP Chapter 5 - Resource Needs Assessment Figure 5.8 - East Average Monthly and Annual Energy Balances 3,000 2,500 2,000 1,50 i 1,000 500 o (500) (1,00) (1,500) ¡Mid Annual Balanc -Monthly Balance (2,000) .~ ~ ~ Q~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~9~22'~~~ r~~~ '~~~ 'á~~ 't~~ .t~. .t~~ .~~~ 't~~l~a~l~ao l~a~l~a~l~ a~l~ao l~a8l~ao l~a~l~a~ Load and Resource Balance Conclusions The Company projects a sumer peak resource deficit for the PacifiCorp system beginning in 2010 to 2011, depending on the planning reserve margin assumed. The PacifiCorp deficits prior to 2012 wil be met by additional renewables, demand-side programs, market purchases, and coal plant turbine upgrades. The Company wil consider other options during this time frame if they are cost-effective and provide other system benefits. Then, beginning 2012, base load, intermedi- ate load, or both tyes of resource additions wil be necessar to cover the widening capacity deficit. The capacity balance at a 12 percent planing reserve margin indicates the start of a defi- cit beginning in 2011-the system is short by 498 MW. For 2012, the capacity deficit increases to 1,936 MW. By 2018, the deficit increases to 3,528 MW. The Company becomes deficit with respect to summer energy by 2012. 96 ...................:........................... ............................................ PacifiCorp - 2008 IRP Chapter 6 - Resource Options 6. RESOURCE OPTIONS This chapter provides background information on the various resources considered in the IRP for meeting futue capacity and energy needs. Organized by major category, these resources consist of supply-side generation (utility-scaled and distrbuted resources), 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 at- tributes, and describes the technologies. In addition, for supply-side resources, the chapter de- scribes how PacifiCorp addressed long-term cost trends and uncertainty in deriving cost figues. Resource Selection Criteria The list of supply-side resource options has been modified in relation to previous IRP resource lists to reflect the realities evidenced through permitting, public meeting comments, and studies undertaken to better understand the details of available generation resources. For instance, coal options have been decreased with a greater emphasis on carbon captue and sequestration. Natu- ral gas options have been expanded to include a dr-cooled combined cycle option and separate gas options were developed for Wyoming. Alternative energy resources have been given a greater emphasis. Specifically additional solar generation options and geothermal options have been included in the analysis compared to the previous IRP. Additional solar resources include utility-size (10 MWs or greater) concentrated photovoltaic as well as solar thermal with six hours of thermal storage. Energy storage systems continue to be of interest, and advanced large batter- ies (1 MW) have been reviewed as well as traditional pumped hydro and compressed air energy storage. Derivation of Resource Attributes The supply-side resource options were developed from a combination of resources. The process began with the list of major generating resources from the 2007 IRP. This resource list was re- viewed and modified to reflect public input and permitting realities. Once the basic list of re- sources was determined, the cost and performance attbutes for each resource were estimated. A number of information sources were used to identify parameters needed to model these re- sources. Supporting utility-scale resources were a number of engineering studies conducted by PacifiCorp to understand the cost of coal and gas resources in recent years. Additionally, experi- ence with the constrction of the 2xl combined cycle plants at Currt Creek and Lake Side as well as other recent simple-cycle projects at Gadsby and West Valley provided PacifiCorp with a detailed understanding of the cost of new power generating facilities. Preparation of benchmark submittls for PacifiCorp's recent generation RFPs were also used to update actual project ex- perience, while governent studies were relied upon for characterizing futue carbon captue costs. Extensive new studies on the cost of the coal-fired options were not prepared in keeping with the reduced emphasis on these resources for new near-term generation. 97 PacifiCorp - 2008 IRP Chapter 6 - Resource Options The results of these estimating efforts were compared with other cost databases, such as the one supporting the IPM(ß market model developed by ICF International, which the Company now uses for national emissions policy impact analysis among other uses. The IPM(ß cost estimates were used when cost agreement was close. The WorleyParsons Group was contracted to conduct a high-level renewable generation study specifically for solar, biomass and geothermal resources. The geothermal cost was adjusted to be consistent with estimated project costs for a third unit expansion at Blundell. Wind costs are based on actual project experience in both the nortwest and Wyoming, as well as curent projections. Wind costs have been subject to increasing prices due to a lack of sup- ply.28 Nuclear costs are reflective of recent cost estimates associated with preliminary develop- ment activities as well as published estimates of new projects. Hydrokietic, or wave power, has been added based on proposed projects in the Northwest. Other generation options, such as en- ergy storage and fuel cells, were adopted from PacifiCorp' s previous IRP. In some cases costs from the previous IRP were updated using cost increases for other studied resources. New to PacifiCorp's IRP process is the addition of a varety of small-scale generation resources, consisting of distrbuted standby generators (DSG), combined heat and power (CHP), and onsite solar supply-side resource options. Together these small resources are referred to as distrbuted generation. Quantec LLC (now called the Cadmus Group, Inc.) originally provided the distrib- uted generation costs and attibutes as par of the DSM potential study conducted for PacifiCorp in 2007.29 The DSM potential report identified the economic potential for distributed generation resources by state. Handling of Technology Improvement Trends and Cost Uncertainties The capital cost uncertainty for many of the proposed generation options is high. Various factors contrbute to this uncertainty. Recent experience with lump-sum contractig indicates a greater risk premium is being used by bidders for the trditional tu-key contracts preferred by Pacifi- Corp for major projects. Shortage of skilled labor and volatile commodity prices are a large part of the increase in project costs for lump-sum contrcting. For example, Figure 6.1 shows the trend in Nort American and world carbon steel prices for selected commodity products. This trend is expected to continue, although the economic slowdown could increase the competitive- ness of futue proposals as supply and demand reach a better balance. 28 For example, in April 2008, General Electrc ~ounced a wind tubine backlog wort $12 bilion (CNet News.com, April 13, 2008). In 2008, Siemens Power Generation also anounced a four-year backlog in tubine orders. For a review of tubine market trends, see, U.S. Departent of Energy, Anual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 2007 (May 2008). 29 Quantec LLC, Assessment of Long-Ter, System Wide Potential for Demad-Side and Other Supplemental Re- sources, July 2007. 98 ............................................ ............................................ PaciffCorp - 2008 IRP Chapter 6 - Resource Options Figure 6.1 - North American and World Carbon Steel Price Trends 1700 ~ 1500 i~ 1300~ ~ ;e 1100 = ~;ì 900 ~~ 1 700..rI = C) ~ 500 U co~o co~No co~Mo co~"'o co~oro co~'"o co~t-o co~coo co~o- co~N a-~-o co~a-o co~ -. World Pnce: Hot Rolled Steel Coil __ World Pnce: Hot Rolled Steel Plate -- North American Pnce: Hot Rolled Steel Coil -e North Amercan Pnce: Hot Rolled Steel Plate Projects in high demand, such as wind turbines, have seen cost increases as much as 40 percent since the 2007 IRP was developed due to tight turbine supplies. The wind capital costs in the supply-side table were escalated at 5 percent for the years 2009 to 2011 to reflect a continuation of near-term real cost escalation as the backlog of turbine orders is reduced, then retu to the nominal inflation rate of about 2 percent thereafter. Note that subsequent to completion of its 2008 IRP portfolio analysis in late 2008 and early 2009, the Company has witnessed price de- clines for wind tubines and other power plant equipment. These cost declines were not incorpo- rated in portfolio cost estimates. Long-term resource pricing remains challenging to forecast. Technologies, such as IGCC and some proposed renewable concepts like solar, have a greater uncertainty because only a few demonstration units have been built and operated. There is a po- tential for futue relative cost decreases for these technologies. As these technologies matue and more plants are built and operated the costs of such new technologies may decrease relative to more mature options such as pulverized coal and conventional natual gas-fired plants. The supply-side resource options tables below do not consider the potential for such savings since the benefits are not expected to be realized until the next generation of new plants are built and operated for a period of time. Any such benefits are not expected to be available until after 2020, and futue IRPs wil be able to incorporate the benefit of such futue cost reductions. A range of estimated capital costs is displayed in the supply-side resource tables. The capital cost 99 PacifCorp - 2008 IRP Chapter 6 - Resource Options range was created by adjusting the base-line estimates by 5 percent on the low end and 20 per- cent on the high end. Introduction of many new distrbuted generation technologies designed to fill the needs of niche markets has helped spur reductions in capital and operating costs. In the DSM potential report, Quantec LLC provided installed cost reduction percentages reflecting these cost trends. Table 6.1 shows the percentage cost reductions by technology tye. PacifiCorp applied these cost reduc- tions to the resources included in the IRP models. Table 6.1 - Distributed Generation Installed Cost Reduction Resource Options and Attributes Tables 6.2 and 6.3 present cost and pedormance attbutes for supply-side resource options des- ignated for PacifiCorp's east and west control areas, respectively. Tables 6.4 through 6.7 present the total resource cost attbutes for supply-side resource options, and are based on estimates of the first-year real levelized cost per megawatt-hour of resources, stated in June 2008 dollars. The resource costs are presented for both the $8 and $45 CO2 ta levels in recognition of the un- certainty in characterizing emission costs. As mentioned above, the attbutes were mainly derived from PacifiCorp's recent cost studies and project experience with certain technologies adjusted to be more in line with the IPM data- base for ICF InternationaL. These options are included in PacifiCorp's IRP models but some du- plicate gas technologies, such as the CCCT F 1x1 that were not selected in prior IRP's, were turned off to improve the System Optimizer model performance. Cost and performance values reflect analysis concluded by September 2008. Additional explanatory notes for the tables are as follows: · Capital costs are intended to be all-inclusive, and account for Allowance for Funds Used Durng Constrction (AFUDC), land, EPC (Engineering, Procurement, and Constrction) cost premiums, owner's costs, etc. Capital costs in Tables 6.2 and 6.3 reflect mid-2008 current dollars, and do not include escalation from the current year to the year of com- mercial operation. · Wind sites are modeled with differig peak load carring capability levels and capacity factors. These levels are reported for each wind site in the Wind Capacity Planning Con- trbution section of Appendix F. · Certain resource names are listed as acronyms. These include: PC - pulverized coal ¡GCC - integrated gasification combined cycle 100 ............................................ ............................................ PacifrCorp - 2008 IRP Chapter 6 - Resource Options SCCT - simple cycle combustion tubine CCCT - combined cycle combustion turbine CHP - combined heat and power (cogeneration) CCS - carbon captue and sequestration REG - recovered energy generation . PacifiCorp' s October 2008 forward price cures were used to calculate the levelized fuel costs reported in Tables 6.4 though 6.6. . The costs presented do not include any investment tax credits with the exception of utility solar projects that qualify for the 30% federal tax credit under the Emergency Economic Stabilization Act of 2008 signed into law in October 2008. The utility solar projects do not qualify for the federal production tax credit. . Gas backup for solar with a heat rate of 11,750 BtuWh is less efficient than for a stand- aloneCCCT. . For the nuclear option, costs do not include fuel disposal but do include the cost of transmission. . The capital cost colums in Tables 6.2 and 6.3 reports the low and high capital cost esti- mates. The average capital cost is reported in Tables 6.4 through 6.7. . The capacity shown for retrofitting CCS on existing pulverized coal plants is a net change from curent capacity (proportional to 500 MW). The heat rate is the total net plant heat rate based on a nominal 10,000 BtuWh without CCS. . The wind resources entered in the table are representative resources included in the IRP models for planning puroses. Cost and performance attbutes of specific resources would be pedormed as part of the acquisition process. Also, the listed capacity factors are not intended to characterize wind quality for a particular region. . Heat rates are not adjusted for degradation over time. PacifiCorp assumes that efficiency improvements wil offset degradation impacts. 101 Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 2 - E a s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s Lo c a t i o n I T i m i n ø Pla n t D e t a i l s Ou t a e 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 De s i g n An u a l Ma i n t . Eq u i v a l e n t Lo w E s t i m a t e Hi g h Es t i t e In s a l l a t i o n Se r v i c e D a t e Ca p a c i t y Pla n t L i f e Ho a R a Ou t a g e FO f c e d O u t a e Ca p i t a l Co s t Ca p i t a l C o s t Va r , O & M Fix e d O & M S0 2 NO x Hg CO 2 De s r i p t i o n Lo c a t i o n Mid - Y e a r IM W l in Ye a r s BT U I k W b Ra t e Ra ( E F O R ) ($ / k W ) ($ / k W ) ($ / M W ) ($ / k - v r l Ib s I M B T U Ib s I M B T U Ib s l t u Ib s l M M B T I Ea s t S i d e O p t i o n s ( 4 5 0 0 ' ) Co a l Uta h P C w i t h o u t C a r b o n C a t u & S e a u s t t i o n Ut a 20 2 0 60 0 40 91 0 6 5% 4% 27 8 8 35 2 1 $ 0,9 6 $ 38 , 8 0 0, 1 0 0 om o OA O 20 5 . 3 5 Ut a P C w i t h C a r o n C a o t u e & S e a u e s t r t i o n Ut a 20 2 5 52 6 40 13 0 8 7 5% 5% 50 4 0 63 6 7 $ 6, 7 1 $ 66 , 7 0, 0 5 0 0,0 2 0 02 0 20 5 4 Uta I G C e w i t h C a r b o n C a o t u & S e a u e t r t i o n Ut a 20 2 5 46 6 40 10 8 2 3 7% 8% 48 8 0 61 6 4 $ IL 2 8 $ 53 , 4 0, 5 0 0, 0 1 1 0, 4 20 5 4 Wv o m i m r P C w i t h o u t C a r b o n C a o t u e & S e c u e s t r t i o n Wy o m i 20 2 0 79 0 40 92 1 4 5% 4% 31 5 6 39 8 7 $ L2 7 $ 36 . 0 0 0, 1 0 0 0, 0 7 0 0, 0 20 5 , 3 5 Wv o m i n a P C w i t h C a r o n C a p t u & S e q u e s t r a t o n Wy o m , 20 2 5 69 2 40 13 2 4 2 5% 5% 57 0 7 72 0 9 $ 7. 6 $ 61 3 7 0.0 5 0 0, 0 2 0 0, 3 0 20 , 5 4 WV O m i l i I G C C w i t h C a r b o n C a o n i & S e u e s t r t i o n WV O I I I l 20 2 5 45 6 40 II 0 4 7 7% 8% 55 2 5 69 7 9 $ l3 5 2 $ 58 , 0 0 0,0 5 0 0.0 1 1 0,0 6 20 5 4 Ex i s t n g P C w i t h C a r b o n C a p e & S e q u a t i o n ( 5 0 0 M W ) UT / W Y 20 2 5 11 9 20 14 . 3 7 2 5% 5% 1,2 5 3 1,5 8 3 $ 6,7 1 $ 66 , 0 7 0,5 0 0,0 1 1 0,3 0 20 5 4 Na t o r a l G . . Uti l i t y C o i r e r a t i o n Ut a 20 1 1 10 25 49 7 4 10 % 8% 48 2 2 60 9 1 $ 23 , 9 $ L8 6 0,2 6 11 8 , 0 0 Fu e l C e l l - L a . . Ut a 20 1 3 5 25 72 6 2 2% 3% 17 0 4 21 5 3 $ 0, 0 $ 8,4 0 0.0 0 1 02 6 11 8 , 0 0 SC C T A e o Ut a 20 1 2 11 8 30 97 7 3 4% 3% 10 7 0 13 5 1 $ 5, 6 $ 9, 9 5 0,0 0 1 0,0 1 1 02 6 11 8 , 0 0 In t e r o o l e d A e r S e C T Ut a 20 1 2 17 4 30 94 0 2 4% 3% 99 9 12 6 2 $ 2,1 $ 4, 0 4 0.0 0 1 0,0 1 1 02 6 11 8 , 0 0 In t e t c o o l e d A e r o s e e r Ut a 20 1 2 26 1 30 94 0 2 4% 3% 99 9 12 6 2 $ 2,7 1 $ 4, 0 4 0.0 0 1 0.0 1 1 0,2 6 11 8 , 0 0 In t e r c o o l e d A e r o S e c T Wv o n a 20 1 2 24 1 30 94 0 2 4% 3% 10 8 3 13 6 8 $ 2,9 4 $ 43 9 0,0 0 1 0,0 1 1 0,2 6 11 8 , 0 0 In t e l C o m b u s t i o n E n i i i n s Uta h 20 0 9 15 3 30 85 0 0 5% 1% L2 5 8 15 8 9 $ 5,2 0 $ 12 . 8 0 0, 0 0 1 0.0 1 7 02 6 11 8 , 0 0 SC C T F r a e ( 2 F r a " F " I Ut a 20 1 2 30 2 35 II 6 5 9 4% 3% 71 0 89 7 $ 4.7 $ 3,7 4 0. 0 1 0.0 5 0 0,2 6 11 8 , 0 0 SC C T F r a e ( 2 F r a " F " ) WY o i 20 1 2 27 5 35 II 6 5 9 4% 3% 77 0 97 2 $ 4,5 $ 4,0 5 0, 0 0 1 0,0 5 0 02 6 11 8 , 0 0 CC C T ( W e t " F " 1 . 1 ) Ut a 20 1 3 22 2 40 7 3 0 2 4% 3% 12 9 8 16 4 0 $ 2,9 4 $ 12 , 7 9 0. 0 0 1 0,0 1 1 0,2 6 11 8 , 0 0 cc c r D u t F i r i i ( W e t " F " 1 . 1 ) Ut a 20 1 3 50 40 88 6 9 4% 3% 53 0 66 9 $ 0,3 9 $ L6 0 0, 0 0 1 0.0 1 1 02 6 11 8 , 0 0 CC C T ( W e t " F " 2 . 1 ) Ut a 20 1 3 50 6 40 70 9 8 4% 3% 11 8 2 14 9 3 $ 2.9 4 $ 7, 7 0, 0 0 1 0.0 1 1 02 6 11 8 , 0 0 cc c r D u t F i r i ( W e t " F " 2 . 1 1 Ut a 20 1 3 64 40 85 5 7 4% 3% 59 6 75 3 $ 03 9 $ L6 0 0, 0 0 1 0. 1 1 02 6 11 8 , 0 0 CC C T ( D r " F " 2 2 1 ) Ut a 20 1 7 43 8 40 7 3 6 8 4% 3% 12 1 2 15 3 0 $ 33 5 $ 9,6 9 0, 0 0 1 0,0 1 1 02 6 11 8 , 0 0 CC C T D u t F i r i n , ( D r " F " 2 . 1 ) Ut a 20 1 7 98 40 8 9 5 0 4% 3% 61 1 77 2 $ 0, 1 1 $ L6 0 0, 0 0 1 0, 1 1 02 6 11 8 , 0 0 CC C T ( W e t " G " 1 . 1 ) Ut a 20 1 3 33 3 40 6 8 8 4 4% 3% 12 2 7 15 5 0 $ 4, 5 6 $ 6,7 5 0.0 1 0,0 1 1 0, 2 6 11 8 , 0 0 CC C T Du c t Fi r n 2 ( W e t "0 " I x n Ut a 20 1 3 72 40 90 2 1 4% 3% 52 0 65 6 $ 03 6 $ 1. 6 3 0,0 0 1 0. 1 1 0, 2 6 11 8 , 0 0 CC C T A d v a n c e ( W e t ) Ut a 20 1 8 40 0 40 67 6 0 4% 3% 13 5 5 17 1 2 $ 45 6 $ 6.7 5 0,0 0 1 0. 1 1 02 6 11 8 , 0 0 CC C T A d v a n c e d D u c t F i r i i i ( W e t l Ut a 20 1 8 75 40 90 2 1 4% 3% 66 5 84 0 $ 03 6 $ 1. 6 3 0,0 1 0, 0 1 1 0, 2 6 11 8 , 0 0 Olh e r " R e n e w a h l . . Ea s t ( W y o m i , ) W i a d ( 3 5 % C F ) Wv o n a 20 1 0 10 0 25 nla nl a nl a 22 1 5 29 5 4 $ 3L 4 3 Ea s S i d e G e o t e m ( B l u n l l Ut a 20 1 3 35 40 nl a 5% 5% 57 8 2 7, 3 0 4 $ 5. 9 4 $ 11 0 , 8 5 Ea s S i d e G e o t h e n l ( G r e n F i e l d ) Ut a h 20 1 3 35 40 nl a 5% 5% 57 8 2 73 0 4 $ 5, 9 4 $ 11 0 , 8 5 Ba t t e l V S l o r a . . Ut a h 20 1 4 5 30 12 0 0 0 2% 5% 1,9 8 0 2.5 0 1 $ 10 , 0 0 $ LO O 0,1 0 0 OA O O 3, 0 0 20 5 3 5 Pi m e d S t o e Ne v a 20 1 8 35 0 50 13 0 0 0 5% 5% 16 8 4 2.1 2 7 $ 43 0 $ 4,3 0 0,1 0 0 OA O O 3, 0 0 20 5 3 5 C~ ~ s s A i E o e " " S l o r a a e ( C A E ) Wy o m i , 20 1 5 35 0 30 II 9 8 0 4% 3% 14 8 3 18 7 3 $ 55 0 $ 3.8 0 MO l 0.0 1 1 0,2 6 11 8 , 0 0 Re c v e r e d E o e " " G e n e r a t i o s ( C I I I UT / W Y 20 1 1 12 30 8% 8% 55 0 0 55 0 0 $ 91 . 9 2 Nu c l e a Ut a h 20 2 5 16 0 0 40 10 7 1 0 7% 8% 5,1 8 8 6, 5 5 3 $ 1. 6 3 $ 14 6 , 7 0 So l a r C o n c e n t r a t I D J ( P V ) ~ 3 0 % C F Ut a 20 1 5 10 20 nl a nl a nla 61 9 4 78 2 4 $ 18 0 , 0 0 So l a r C o n c e n t a t i i i ( n a t u i i a s b a c k u o l w 2 5 % s o l a r Uta h 20 1 5 25 0 20 nl a nl a nla 39 4 3 49 8 0 $ 19 5 . 0 So l a r C o n c e n t r t i r n ( t h e r m s t 0 e ) - 3 0 % s o l a r Ut a 20 1 2 25 0 30 nl a nl a nla 4,4 1 8 5, 5 8 0 $ 13 9 5 0 10 2 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 3 - W e s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s Lo c a t i n I T i m i o l l Pla n t De t a U s Ou t u e I n f o r m a t i o n Co s s Em i s s i o n s Ea r l i e s t In - Av e g e De s i g n An u a l Ma i n Eq u i v a l e n t Lo w Es t i m a t e Hi g h Es t i m a t e In s l l a t i o n Se r v i c e D a t e Ca a c i t y Pla n t L i f e Ho a R a Ou t a e Fo r e d Ou t a g e Ca p i t a l Co s t Ca p i t a l C o s t Va r , O & M Fix e d O & M S0 2 NO x Hg CO 2 De s e r l o t l o n Lo c a t i o n Mid . Y e a r IM W l in Ye a r s BT U I k W h Ra Ra . . I E F O R l ($ / k W l ($ / k W ) ($ 1 M 1 I$ / k - " " Ib s I M B T U Ib s I M B T U Ib s l Ib s / M B T U We s t S i d e O p t i o n s ( 1 5 0 ' ) Na t u r a l Ga s Fu e l C e l l - L a r ~ No r t w e 20 1 3 5 25 72 6 2 2% 3% 17 0 4 2,1 5 3 $ 0.0 3 $ 8A O 0, 0 1 02 6 11 8 , 0 0 SC C T A e No r w e s t 20 1 2 13 0 30 97 7 3 4% 3% 97 2 12 2 8 $ 5,1 2 $ 9,0 4 0, 0 0 1 0, 0 1 02 6 11 8 , 0 0 In t e r c o o l e d A e r S C C T No r t e s 20 1 2 28 7 30 94 0 2 4% 3% 90 8 11 4 7 $ 1, 6 $ 3, 6 8 0, 0 0 1 0,0 1 1 02 6 11 8 , 0 0 In t e l C o m b u s t i o n E n o i n e s No r t w e s t 20 1 2 16 8 30 85 0 0 5% 1% 11 4 3 14 4 4 $ 52 0 $ ~2 , 0 0, 0 0 1 0,1 7 02 6 11 8 , 0 0 SC C T F r a m 1 2 F r a m e " F " I No r t w e s t 20 1 2 33 8 35 11 6 5 9 4% 3% 64 5 81 5 $ 4,0 7 $ 3, 0 0, 0 0 1 0.0 5 0 02 6 11 8 , 0 0 CC C T l W e t " F " l x l \ No r w e s t 20 1 3 24 4 40 73 0 2 4% 3% 11 8 0 1,4 9 1 $ 2,6 7 $ 11 , 6 2 0, 0 0 1 0, 0 ~ 0,2 6 11 8 , 0 0 CC C T D w t F i r i " . l W e t " F " l x l \ No r t e s t 20 1 3 55 40 88 6 9 4% 3% 48 2 60 8 $ 03 6 $ 1,4 5 0, 0 0 1 0, 0 ~ 02 6 11 8 , 0 0 CC C T l W e t " F " 2 x l \ No r t w e s t 20 1 3 55 7 40 7,0 9 8 4% 3% 10 7 4 1,3 5 7 $ 2,6 7 $ 7,0 7 0, 0 0 1 0, 0 1 0,2 6 11 8 . 0 0 CC C T D u c t F l r i n a l W e t " F " 2 x 1 I No r t w e s t 20 1 3 70 40 85 5 7 4% 3% 54 2 68 5 $ 03 6 $ lA S 0, 0 0 1 0,0 1 1 0,2 6 11 8 , 0 0 CC C I W e t " 0 " I x l l No r t w e s t 20 1 3 36 7 40 68 8 4 4% 3% 11 1 6 1, 4 0 9 $ 4,1 4 $ 6,1 3 0, 0 0 1 0,0 1 1 02 6 11 8 , 0 0 CC C D u e l F l r i . a I W e t " 0 " I x l l No r t e s t 20 1 3 80 40 90 2 1 4% 3% 47 2 59 7 $ 03 3 $ IA 8 0,0 1 0.0 1 1 02 6 11 8 , 0 0 CC C T A d v a n d l W e t l No r t w e s t 20 1 8 44 0 40 67 6 0 4% 3% 12 3 2 15 5 6 $ 4,1 4 $ 6,1 3 0.0 0 1 0,0 1 1 02 6 11 8 , 0 0 CC C T A d v a n c e d D u c t F i r " . ( W e t ) No r t w e s t 20 1 8 83 40 9,0 2 1 4% 3% 60 5 76 4 $ 03 3 $ IA 8 0,0 0 1 0,0 1 1 02 6 11 8 , 0 0 Ot h e r - R e n e w a b l e s We s t Wi n d No r t w e s 20 1 0 50 25 nl a nl a nla 23 5 0 31 3 4 $ 31 ' 4 3 Bi o m s s No r t w e s t 20 1 5 50 30 10 9 7 9 5% 4% 31 7 9 40 1 6 $ 0.9 6 $ 38 , 8 0 0, 1 0 0 03 5 0 OA O 20 5 3 9 We s S i d e G e o t h l I G r e n F i e l d l No r w e s t 20 1 3 35 40 nl a 5% 5% 57 8 2 73 0 4 $ 5,9 4 $ 11 0 , 8 5 C~ s s d A i E n ~ S _ a e I C A B l No r w e s t 20 1 5 38 5 30 11 9 8 0 4% 3% 14 8 3 18 7 3 $ 5,0 0 $ 3, 5 0,0 1 0,0 1 1 02 6 11 8 , 0 0 Hv d r o k i n e c I W a v e ) . 2 1 % C F No r t w e s t 20 1 5 10 0 20 nl a nl a nla 5,7 0 0 7, 2 0 0 $ 18 0 , 0 0 We s t S i d e O p t i o n s ( S e L e v e l ) Na i u r a l G a s Fu e l C e l l - L a No r t w e s t 20 1 3 5 25 72 6 2 2% 3% 17 0 4 21 5 3 $ 0, 0 $ 8A O 0, 0 0 1 0,2 6 11 8 , 0 0 SC C T A e o No r h w e s t 20 1 2 13 6 30 97 7 3 2% 3% 92 4 11 6 7 $ 4,8 7 $ 85 9 0, 0 0 1 0, 0 ~ 0,2 6 11 8 , 0 0 In t e o o l e d A e S e C T No r t w e s t 20 1 2 30 2 30 94 0 2 4% 3% 86 3 10 9 0 $ 23 5 $ 3, 9 0, 0 0 1 0,0 1 1 02 6 11 8 , 0 0 In t e r n C o m b u s t i o n E n i r n e s No r t w e s t 20 1 2 17 7 30 85 0 0 4% 1% 10 8 6 13 7 2 $ 5.2 0 $ 12 , 0 0, 0 1 0,0 7 02 6 11 8 , 0 0 SC C T F r a 1 2 F r a e " F " I No r t w e s t 20 1 2 35 6 35 11 6 5 9 5% 3% 61 3 77 4 $ 3.8 7 $ 3, 3 0, 0 0 1 0,0 5 0 0,2 6 11 8 , 0 0 CC C T I W e t " F " I x l ' No r t w e s t 20 1 3 25 7 40 73 0 2 4% 3% 11 2 1 14 1 6 $ 2,5 5 $ 11 , 0 7 MO l 0,0 1 1 0,2 6 11 8 , 0 0 CC C T D u c t F l r i n a l W e t " F " I x l l No r t 20 1 3 58 40 88 6 9 4% 3% 45 8 57 8 $ 03 4 $ 1.3 8 MO l 0, 0 ~ 0,2 6 11 8 , 0 0 CC C T l W e t " F " 2 x l l No r t e s t 20 1 3 58 6 40 70 9 8 4% 3% 10 2 0 12 8 9 $ 2.5 5 $ 6, 7 3 0, 0 0 1 0,0 1 02 6 11 8 , 0 0 CC C T D u c F i r i " . l W e t " F " 2 x l ) No r t w e 20 1 3 74 40 85 5 7 4% 3% SI S 65 0 $ 03 4 $ 13 8 0, 0 0 1 0, 0 ~ 02 6 11 8 , 0 0 CC T l W e t " 0 " I x l l No r t w e s t 20 1 3 38 6 40 68 8 4 4% 3% 10 6 0 13 3 9 $ 3,9 4 $ 5, 8 4 0,0 0 1 0,0 1 1 0,2 6 11 8 , 0 0 CC C T D u e F i r n a i w . t " 0 " 1 x l l No r t w e s 20 1 0 84 40 90 2 1 4% 3% 44 9 56 7 $ 03 1 $ IA I 0, 0 0 1 0,0 1 1 0,2 6 11 8 , 0 0 CC C T A d v a n d I W e t ' No r t e s t 20 1 8 46 3 40 67 6 0 4% 3% 11 7 0 14 7 9 $ 3,9 4 $ 5, 8 4 0,0 0 1 0,0 1 1 02 6 11 8 , 0 0 CC C T A d v a n c e D w t F i r n a l W e t l No r t w e s t 20 1 8 87 40 9,0 2 1 4% 3% 57 4 72 5 $ 03 1 $ 1,4 1 0,0 0 1 0,0 1 1 02 6 11 9 , 0 0 10 3 Pa c i f C o r p - 2 0 0 8 I R P Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 4 - T o t a l R e s o u r c e C o s t f o r E a s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s , $ 8 C O 2 T a x Ca i t a l C o s t $ I k W Fb e d C o s t Co n v e r t t o M l U s Va r i a b l e C o s t s To t a l An u a l Fi x e d O & M $ / k W . Y r mi l l s l W h Re s o u r c e To t a l Pa y m e n t Pa y m t To t a F i x e d Ca p a c i t y To t a F i x e d Le v e l i z e d F u e l Co s t Fa c t o r "" Ca p i t a l O& M Tr a s p o r t i De s c r i n t i o n Co s t Fa c t o r ($ l W - Y r ) O& M 0I ~ T. i . ($ l W - Y r ) MiU s l k W h Ø/m m B t u MiI l s W h ($ / M W ) Wi n d In t e g i t i o n Ta x Cr e d i t s En v i m e n t a (M i l . / k W h ) Ea s t S i d e O p t i o n s ( 4 5 0 0 ' ) Co a l Ut a P C w i t h o u t C a r o n C a n m r & S P n u e s t r a t i o n 29 3 4 8.4 0 % $ 24 6 , 5 7 $ 38 , 8 0 $ 6,0 0 $ 44 , 8 0 $ 29 1 3 7 91 % 36 , 3 9 21 6 , 2 3 19 , 6 9 $ 0,9 6 5,1 0 62 , 1 4 Uta P C w i t h C a r b o n C a n n i . . & S e a u s t a t i o n 53 0 6 8.2 5 % $ 43 7 . 0 $ 66 , 7 $ 6, 0 0 $ 72 , 0 $ 50 9 , 6 8 90 % 64 , 6 5 21 6 , 2 3 28 , 3 0 $ 6,7 1 0,7 8 10 0 , 4 Ut a l a c C w i t h C a C " " " e & S e m . . s t r a t i o n 51 3 6 8.0 1 % $ 41 1 3 2 $ 53 , 2 4 $ 6, 0 0 $ 59 , 2 4 $ 47 0 , 5 6 85 % 63 , 2 0 21 6 , 2 3 23 . 4 0 $ 11 , 8 0,6 4 98 5 2 Wv o m i n o P C w i t h u t C a r o n C i ¡ n t m & S e m " ' s t r o n 3 3 2 2 8.4 0 % $ 27 9 , 1 9 $ 36 , 0 0 $ 6.0 0 $ 42 . 0 0 $ 32 L l 9 91 % 40 , 1 2 23 8 . 4 5 21 . 9 7 $ 1.2 7 5,1 6 68 . 5 2 Wv o m i o P C w i t b C a r o n C l I n t u e & S e n u e t r t i o n 60 0 7 8.2 5 % $ 49 5 . 5 0 $ 61 3 7 $ 6, 0 $ 67 , 3 7 $ 56 2 , 8 6 90 % 71 3 9 23 8 . 4 5 31 , 8 $ 7,2 6 0, 7 9 11 1 . 0 2 Wv o m i n . 1 0 C C w i t h C a r b o n C a t n e & S e o u e t r t i o n 58 1 6 8.0 1 % $ 46 5 , 7 4 $ 58 , 0 0 $ 6,0 0 $ 64 , 0 0 $ 52 9 , 7 4 85 % 7L l 4 23 8 , 4 5 26 , 3 4 $ 13 , 5 2 0, 6 6 11 1 . 6 6 Ex i s t i n g P C w i t h C a r b o n C a p t u & S e q u e s t r a t i o n ( 5 0 0 M W ) 1, 3 1 9 10 . 7 1 % $ 14 1 . 2 3 $ 66 , 0 7 $ 6,0 0 $ 72 , 0 $ 21 3 , 3 0 90 % 21 0 5 23 8 . 4 5 34 , 2 7 $ 6, 7 1 0, 8 6 68 , 8 9 Na t u r a l G . . Ut i l i t v C o _ o n 5,0 7 6 10 . 1 2 % $ 51 3 , 4 6 $ 1.8 6 $ 05 0 $ 23 6 $ 51 5 , 8 2 82 % 71 . 8 1 69 9 , 2 2 34 . 8 $ 23 . 9 4,1 7 15 8 13 5 , 6 3 Fu l C e l l - L a r ' e 17 9 4 8.7 2 % $ 15 6 , 3 4 $ 8A O $ 0.5 0 $ 8, 9 0 $ 16 5 . 2 4 95 % 19 , 8 6 69 9 2 2 50 , 7 8 $ O, O 6.0 9 23 0 79 , 0 6 se e r A e r 1,1 2 6 9.0 8 % $ 10 2 . 2 1 $ 9,9 5 $ 0.5 0 $ 10 . 4 5 $ 11 2 . 6 6 21 % 61 , 2 4 69 9 . 2 2 68 , 3 4 $ 5. 6 3 8.2 0 HO 14 6 , 5 1 In t r c o o l e d A e r s c e r I U b o , I 74 M W I 10 5 2 9.0 8 % $ 95 , 5 $ 4.0 4 $ 0,5 0 $ 4, 5 4 $ 99 . 9 9 21 % 54 3 6 69 9 , 2 2 65 , 7 4 $ 2.7 1 7, 9 2,9 8 13 3 , 8 In t e o o l e d A e r s e e r l 1 . . h 2 6 1 M W I 1,0 5 2 9,0 8 % $ 95 , 5 $ 4,0 4 $ 0.5 0 $ 4.5 4 $ 99 , 9 9 21 % 54 3 6 69 9 , 2 2 65 , 7 4 $ 2,7 1 7,8 9 2,9 8 13 3 , 6 8 In t e o o l e d A e r S C C T ( W v n n n . 2 4 1 M W I 11 4 0 9.0 8 % $ lO B O $ 4.3 9 $ 05 0 $ 4. 9 $ 10 8 . 3 8 21 % 58 , 9 2 69 9 , 2 2 65 , 7 4 $ 2. 9 4 6, 3 2,9 8 13 1 , ~ In t e C o b u t i o n E n 2 i n e s 13 2 4 9, 8 % $ 12 0 , 1 8 $ 12 . 0 $ 0.5 0 $ 13 , 0 $ 13 . 4 8 94 % 16 , 2 ~ 69 9 , 2 2 59 A 3 $ 5. 2 0 7,1 3 2,7 0 90 , 6 7 SC C F r a ( 2 F r a " F " l 74 7 8.2 % $ 64 . 3 9 $ 3,7 4 $ 0. 5 0 $ 4.2 4 $ 68 . 2 21 % 37 3 0 69 9 , 2 2 81 , 5 3 $ 4.4 7 9,7 8 3,7 0 13 6 , 7 8 sc e r F r a ( 2 F r a " F " l 81 0 8.6 2 % $ 69 . 8 2 $ 4,0 5 $ 0. 5 0 $ 4,5 5 $ 74 3 7 21 % 40 , 3 69 9 . 2 2 81 , 3 $ 4.8 5 8A 7 3, 0 13 8 , 9 7 cc e r ( W e t " F " I x l ' 13 6 6 8,5 9 % $ 11 . 3 2 $ 12 . 7 9 $ 0, 5 0 $ 13 , 2 9 $ 13 0 . 6 1 56 % 26 . 2 69 9 , 2 2 51 . 0 6 $ 2.9 4 6,1 3 23 2 89 , 0 cc e r D u F i , ; n . ( W e t " F " I x l i 55 8 8.5 9 % $ 47 . 8 8 $ 1,6 0 $ 05 0 $ 2, 1 0 $ 49 , 9 8 16 % 35 , 6 6 69 9 , 2 2 62 , 0 1 $ 0.3 9 1, 4 2,~ 10 8 3 2 CC C I W e t " F " 2 x l l 12 4 4 8.5 9 % $ 10 6 , 7 9 $ 7, 7 $ 0. 5 0 $ 8,2 7 $ 11 . 0 6 56 % 23 , 6 69 9 , 2 2 49 , 3 $ 2.9 4 5,9 6 2,2 5 84 . 4 CC C T D u F i r i ' ( W e t " F " 2 x l \ 62 8 8.5 9 0 1 0 $ 53 , 8 $ 1,6 0 $ 0, 5 0 $ 2. 1 0 $ 55 , 9 8 16 % 39 , 9 4 69 9 . 2 2 59 . 8 4 $ 0,3 9 7,1 8 2,7 1 11 0 , 0 6 CC C T " ' " F " 2 x l \ 12 7 5 8.5 9 % $ 10 9 , 5 0 $ 9,6 9 $ 0. 5 0 $ 10 , 1 9 $ 11 9 , 7 0 56 % 24 A O 69 9 , 2 2 51 , 5 2 $ 3,3 5 6,1 8 2.3 4 87 , 9 cc e r D u e t F i n n . ( D ~ " F " 2 x I I 64 4 8.5 9 % $ 55 . 5 $ 1,6 0 $ 0, 5 0 $ 2,1 0 $ 57 3 5 16 % 40 , 9 1 69 9 , 2 2 62 5 8 $ 0,1 1 75 1 2,4 11 3 , 9 5 CC C T I W e t " 0 " I x l l 12 9 2 8.5 9 % $ 11 0 . 9 3 $ 6,7 5 $ 0, 5 0 $ 7,2 5 $ 11 8 , 1 8 56 % 24 , 0 9 69 9 , 2 2 48 , 1 4 $ 4,5 6 5.7 8 2,1 8 84 , 7 4 cc e r D u F i , ; n . ( W e t " 0 " I x l i 54 7 8.5 9 % $ 46 , 9 6 $ 1,6 3 $ 0, 5 0 $ 2,3 $ 49 , 9 16 % 35 , O 69 9 , 2 2 63 . 0 8 $ 0,3 6 7.5 7 2,8 6 10 8 , 8 9 CC C A d v a ( W e t 14 2 7 8,5 9 % $ 12 2 , 4 9 $ 6.7 5 $ 0, 5 0 $ 7,5 $ 12 9 , 7 4 56 % 26 . 5 69 9 . 2 2 47 , 2 7 $ 4,5 6 5, 6 7 2,4 86 , 8 cc e r A d v o n c e d D u F i n n ' ( W e t ' 70 0 8.5 9 % $ 60 , 1 0 $ 1,6 3 $ 05 0 $ 2,1 3 $ 62 , 2 4 16 % 44 . 0 69 9 , 2 2 63 0 8 $ 03 6 7.5 7 2.8 6 11 8 , 2 7 Ot h e r " R e n e w a b l e s Eo s t I W v m i n . ) W i n d 1 3 5 % C F \ 25 6 6 8.7 2 % $ 22 3 , 5 8 $ 31 . 4 3 $ 05 0 $ 31 , 9 3 $ 25 5 5 1 35 % 83 . 4 11 , 7 5 (2 0 , 7 0 74 3 8 Ea t S i d e O e o t h a l ( B l u n d e l l ) 60 8 7 7. 4 2 % $ 45 1 , 6 4 $ 11 0 , 8 5 $ 05 0 $ 11 1 3 5 $ 56 2 , 9 9 90 % 71 , 4 1 $ 5,9 4 12 0 , 7 0 56 , 6 4 Ea S i d e G e o t h r m ( G r e n F i e l d ' 76 0 8 7.4 2 % $ 56 4 5 5 $ 22 1 , 0 $ 05 0 $ 22 2 , 2 0 $ 78 6 . 7 4 90 % 99 , 7 9 $ ~1 , 8 8 12 0 , 7 0 90 , 9 7 Ba t e r S t n e 20 8 4 8. 2 9 % $ 17 2 7 7 $ 1,0 0 $ 05 0 $ 15 0 $ 17 4 , 2 7 21 % 94 , 7 3 69 9 , 2 2 83 , 9 1 $ 10 . 0 0 ~0 , 7 6, 7 3 20 5 , 3 Pu e d S t o m . e 17 7 3 8. 1 9 % $ 14 5 , 1 4 $ 43 0 $ 13 5 $ 5,6 5 $ 15 0 , 7 9 20 % 86 , 6 69 9 , 2 2 90 , 9 0 $ 43 0 10 , 9 1 7,9 19 9 , 4 6 Co m _ s e d A i r E n e a v S t o = e ( C A B S I 15 6 1 8. 2 9 % $ 12 9 . 4 1 $ 3,8 0 $ 13 5 $ 5, 1 5 $ 13 4 , 5 6 47 % 32 , 9 69 9 , 2 2 83 7 7 $ 5,5 0 8, 7 0 3,8 0 13 4 , 6 6 Re c o v e r e d E n e ø v G e n e r a o n t e H P ) 55 0 0 9. 3 9 % $ 51 6 . 7 $ 91 , 9 2 $ 91 , 9 2 $ 60 8 5 9 84 % 82 , 7 1 82 . 7 1 Nu c l e a r 54 6 1 8. 3 0 % $ 45 3 . 2 6 $ 14 6 , 7 0 $ 6,0 0 $ 15 2 , 7 0 $ 60 5 , 9 5 85 % 81 3 8 11 3 , 9 8 ~2 , 1 $ 1,6 3 95 , 2 2 So l a r C o n c e a t i n . ( P V l - 3 0 % C F 65 2 0 6. 4 8 % $ 42 2 . 4 3 $ 18 0 , 0 0 $ 6, 0 0 $ 18 6 , 0 $ 60 8 , 4 30 % 23 1 5 2 11 , 9 22 9 , 9 So l a r C o n c t r t i n . ( n a t ' o s b a t n m \ . 2 5 % s o l a r 41 5 0 6. 4 8 % $ 26 8 , 8 8 $ 19 5 , 6 0 $ 6, 0 $ 20 1 , 6 0 $ 47 0 , 8 33 % 16 2 , 5 69 9 , 2 2 18 , 9 6 2, 2 8 (1 5 9 0, 8 6 ~8 3 2 6 So l a r C o n c e t r t i o ( t h e s t r a o e \ - 3 0 % s o l a r 46 5 0 5. 4 6 % $ 25 3 , 8 0 $ 13 9 5 0 $ 6, 0 $ 14 5 5 0 $ 39 9 3 0 30 % 15 1 , 9 4 ~1 , 9 15 0 , 3 5 10 4 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 5 - T o t a l R e s o u r c e C o s t f o r W e s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s , $ 8 C 0 2 T a x C.n l l a C o s t S I k W Fii e d C o s t Co n v e r t t o M i l l s Va r i a b l e C o s t s To W An l Fix e d O & M $ / k W - Y r mi1 s / W b Re s o r c e To t a l Pa y t Pa y m e n t To t a F i x e d Ca p a c i t y To t a Fi x e d Le e l i z e d F u e l Co s t Fa c t o r Ga . Ca p i t a O& M Tr a s p t i o n ! De s c r i D t i o n Co s t Fa e l I$ l W - Y , ) O& M Ot ~ T" " ($ I k W . Y r \ Mil l s l W J r/m m t u Mi l l l k W h ($ / M W ) Win d l n t e g r t i o i Ta x Cr e d i t s En v i r o n m e n (M i U o I W h ) 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 Fu e l C e n - L a r o e 17 9 4 8. 7 2 % $ 15 6 3 4 $ 8A O $ 05 0 $ 8,9 0 $ 16 5 , 2 4 95 % 19 , 8 6 81 4 , 0 0 59 , 1 l $ 0, 0 53 3 23 0 86 , 6 3 SC C T A e r o 10 2 4 9. 0 8 % $ 92 , 9 2 $ 9,0 4 $ 05 0 $ 9, 5 4 $ 10 2 A 6 21 % 55 , 7 0 81 4 , 0 0 79 5 5 $ 5,1 2 7, 7 3,1 0 15 0 , 6 4 In t e r c o o l e d A e o S e C T 95 6 9. 0 8 % $ 86 , 7 7 $ 3,6 8 $ 0, 5 0 $ 4, 1 8 $ 90 , 9 5 21 % 49 A 4 81 4 , 0 0 76 5 3 $ 2, 6 6, 9 0 2,9 8 13 8 3 2 In t e C o m b u s o n E n i r n e s 12 0 4 9.0 8 % $ 10 9 , 2 5 $ 12 , 8 0 $ 0,5 0 $ 13 3 0 $ 12 2 5 5 94 % 14 , 8 8 81 4 , 0 0 69 , 1 9 $ 5, 2 0 6,2 4 2,7 0 98 , 2 0 SC C T F , , , 1 2 F r a " F " ) 67 9 8. 6 2 % $ 58 5 3 $ 3.0 $ 05 0 $ 3, 0 $ 62 , 4 21 % 33 , 9 4 81 4 . 0 0 94 , 9 1 $ 4, 0 7 85 6 3,7 0 14 5 , 1 6 CC C T I W e t " F " I x l \ 12 4 2 8. 5 9 % $ 10 6 , 6 $ ~1 , 6 2 $ 0,5 0 $ 12 , 1 2 $ 11 8 , 7 8 56 % 24 . 1 81 4 , 0 0 59 . 4 $ 2, 6 7 53 6 23 2 94 , 0 0 CC C T D u c I F i r i n a l W e t " F " l x l ) 50 7 8. 5 9 % $ 43 , 5 3 $ 1,4 5 $ 0,5 0 $ 1,9 5 $ 45 A 8 16 % 32 , 5 81 4 , 0 0 72 , 1 9 $ 03 6 6.5 1 2,~ 11 4 3 2 CC C T ( W e t " F " 2 x l l 11 3 8. 5 9 % $ 91 0 8 $ 7, 0 7 $ 0,5 0 $ 75 7 $ 10 4 , 6 5 56 % 21 3 3 81 4 , 0 0 57 , 8 $ 2, 6 7 5,2 1 2,2 5 89 , 2 5 CC C T D u F i r i n . f W e t " F " 2 x l l 57 0 8.5 9 % $ 48 , 9 8 $ IA 5 $ 05 0 $ 1,9 5 $ 50 , 9 3 16 % 36 3 4 81 4 , 0 0 69 , 6 6 $ 03 6 6,2 8 VI 11 5 3 5 CC C T l W e t " G " I x l ) 11 7 5 8.5 9 % $ 10 0 . 8 5 $ 6, 1 3 $ 05 0 $ 6, 6 3 $ 10 1 , 8 56 % 21 , 9 1 81 4 , 0 0 56 , 4 $ 4, 1 4 5,0 5 2,1 8 89 3 2 CC C T D u F i r i a l W e t " G " l x l \ 49 7 8.5 9 % $ 42 . 6 9 $ IA 8 $ 0,5 0 $ 1,9 8 $ 44 , 6 8 16 % 31 , 8 8 81 4 , 0 0 73 . 3 $ 03 3 6,6 2 2,8 6 11 5 , 1 2 CC C T A d v a n c e ( W e t l 12 9 7 8.5 9 % $ ll L 3 6 $ 6,1 3 $ 05 0 $ 6, 6 $ 11 7 , 9 9 56 % 24 , 0 5 81 4 , 0 0 55 , 0 2 $ 4,1 4 4,9 6 2,1 4 90 3 2 CC C A d v a n c e d D u F i r . . ( W e t ) 63 6 8.5 9 % $ 54 . 4 $ 1,4 8 $ 0,5 0 $ 1,9 8 $ 56 , 2 16 % 40 , 4 0 81 4 , 0 0 73 . 3 $ 03 3 6,6 2 2,8 6 12 3 , 6 4 Ot b e r - R e n e w a b l e s We s t Wi n d 26 1 2 8.7 2 % $ 22 7 5 9 $ 31 , 4 3 $ 27 , 4 $ 59 , 1 7 $ 28 6 , 7 6 29 % 11 2 , 8 8 ~1 , 5 (2 0 , 7 0 10 3 , 9 3 Bi o m s 33 4 7 8.1 0 % $ 27 1 2 2 $ 38 , 8 0 $ 0,5 0 $ 39 3 0 $ 3\0 5 2 91 % 38 , 7 8 59 0 , 0 64 , 7 8 $ 0,9 6 12 0 , 7 0 6,1 5 89 , 9 7 We s t S i d e G e o t h e r a l I G r e e n F i e l d ) 76 0 9 7.4 2 % $ 56 4 . 2 $ 22 1 , 7 0 $ 0,5 0 $ 22 2 , 0 $ 78 6 , 8 2 90 % 99 , 8 0 $ 11 , 8 8 12 0 , 7 0 90 , 9 8 CO l s s e d A i r E 1 U S t o m o e ( C A B S 15 6 1 8.2 9 % $ 12 9 A I $ 3. 5 $ 13 5 $ 4, 8 0 $ 13 4 . 2 1 47 % 32 , 8 1 81 4 , 0 0 97 , 5 2 $ 5,0 0 8,7 9 3,0 14 7 , 9 1 Hv d r o k i e t c ( W a v e ' . 2 1 % C F 6, 0 0 9.6 9 % $ 58 1 , 5 8 $ 18 0 , 0 0 $ 6,0 0 $ 18 6 , 0 0 $ 76 7 , 5 8 21 % 41 7 . 2 5 4\ 7 , 2 5 We s t S i d e O p t i o n s ( S e . . L e v e l ) Na i u r a l G . . Fu e l C e l l . L a r i i e 17 9 4 8.7 2 % $ 15 6 3 4 $ 8A O $ 0,5 0 $ 8, 9 0 $ 16 5 , 2 4 95 % 19 , 8 6 81 4 , 0 0 59 , 1 l $ 0, 0 53 3 23 0 86 , 3 SC C T A e r 97 2 9.0 8 % $ 88 , 2 7 $ 85 9 $ 05 0 $ 9,0 9 $ 97 3 6 21 % 52 , 9 3 81 4 , 0 0 79 5 5 $ 4.8 7 7,1 7 3,0 14 7 , 6 3 In t e r o o l e d A e r o s c e r 90 8 9.0 8 % $ 82 A 3 $ 3. 9 $ 0,5 0 $ 3, 9 9 $ 86 . 3 21 % 46 , 9 8 81 4 , 0 0 76 5 3 $ 23 5 6,9 0 2,9 8 13 5 , 7 4 In t e C o m b u s t i o n E n o i n e s 11 4 3 9.0 8 % $ 10 3 . 9 $ 12 , 8 0 $ 05 0 $ 13 3 0 $ 11 7 , 0 9 94 % 14 . 2 81 4 , 0 0 69 , 1 9 $ 5, 2 0 6,2 4 2,7 0 97 , 5 4 se C T F r a m ( 2 F r a e " F " 64 5 8.6 2 % $ 55 , 6 1 $ 3, 3 $ 05 0 $ 3. 7 3 $ 59 3 4 21 % 32 , 2 6 81 4 , 0 0 94 , 9 1 $ 3, 7 85 6 3. 0 14 3 , 9 CC C T ( W e t " F " I x \ ) 11 8 0 8.5 9 % $ 10 1 3 2 $ 11 , 0 7 $ 05 0 $ 11 . 7 $ 11 2 , 8 9 56 % 23 , 0 1 81 4 , 0 0 59 , 4 4 $ 25 5 53 6 23 2 92 , 6 7 CC C T D u c t F i r i n . ( W e t " F " I x l l 48 2 8. 5 9 % $ 41 . 5 $ 1.3 8 $ 05 0 $ 1, 8 8 $ 43 2 3 16 % 30 , 8 5 81 4 , 0 0 72 1 9 $ 03 4 65 1 2, 8 1 11 2 , 7 0 CC C T l W e i " F " 2 x l \ 10 7 4 85 9 " 1 0 $ 92 , 3 $ 6, 7 3 $ 05 0 $ 7, 3 $ 99 , 4 6 56 % 20 . 2 7 81 4 . 0 0 57 , 8 $ 25 5 5,2 1 2,2 5 88 , 0 6 CC C T D u F i r i n e ( W e t " F " 2 x l ' 54 2 8.5 9 % $ 46 , 5 3 $ 13 8 $ 05 0 $ 1,8 8 $ 48 . 4 2 16 % 34 , 5 4 81 4 , 0 0 69 , 6 6 $ 03 4 6,2 8 VI 11 3 5 3 CC C T l W e t " G " I x l l 11 1 6 8.5 9 % $ 95 . 8 1 $ 5, 8 4 $ 05 0 $ 6J 4 $ 10 2 , 1 5 56 % 20 , 8 2 81 4 , 0 0 56 , 0 4 $ 3. 9 4 5,0 5 2,1 8 88 . 0 4 CC C T D u t F i n n . I W e t " G " I x l l 47 2 8. 5 9 % $ 40 5 6 $ 1.4 1 $ 0,5 0 $ 1,9 1 $ 42 . 4 7 16 % 30 3 0 81 4 , 0 0 73 . 3 $ 03 1 6, 2 2,8 6 ll J , 3 CC C T A d v a n c e l W e t 12 3 2 8. 5 9 % $ 10 5 , 7 9 $ 5. 4 $ 0.5 0 $ 63 4 $ 11 2 , 1 3 56 % 22 , 8 6 81 4 , 0 0 55 , 0 $ 3, 9 4 4,9 6 2,1 4 88 , 9 3 CC C A d v a n c e d D u F i r i n . I W e t ) 60 5 8. 5 9 % $ 51 , 9 1 $ 1,4 1 $ 05 0 $ 1,9 1 $ 53 , 8 2 16 % 38 A O 81 4 , 0 0 73 . 3 $ 03 1 6, 2 2,8 9 12 1 , 6 5 10 5 Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 6 - T o t a l R e s o u r c e C o s t f o r E a s t S i d e S u p p l y - S i d e R e s o u r c e O p t i o n s , $ 4 5 C O 2 T a x Ca o l t a l C o s t S / k W Fix e d Co s t Co n v e r t t o M i l s Va r i a b l e C o s t s To t a l An n u a l Fix e d O & M $ / W - Y r mi l s / W b Re l l u r e e To t a l Pa y m e n t Pa y m e n t To t Fix e d Ca p a c i t y To t a l F i x e d Le v e l i z e F u e l Co s t Fa c t o r 0.. Ca p i t a l Tr a n s p r t t i o n O& Wm d De s c o t i o n Co s t Fa c r ($ l W - Y r ) O& M Ot ~ To t a ($ i : W - Y r ) MiI s l W h ,i n u t u MiU s l k W h (S / M ) In t e g r t i o n Ta x C r i s En v i r o n m e n t a (M W o I W b ) Ea s t S i d e O p t i o n . ( 4 5 0 0 ' ) Co a l U~ ~ ~ ~ i n ~ o o C M M e & S ~ r e ~ t i o o 29 3 4 8.4 0 % $ 24 6 5 7 S 38 , 8 0 $ 6,0 0 $ 44 , 8 0 $ 29 1 , 3 7 91 % 36 , 3 9 21 6 , 2 3 19 , 6 9 $ 0,9 6 28 , 3 2 85 3 6 Ut a h P C w i t h C a r o n C a t u & S e a u e s t r a t i o n 53 0 6 8.2 5 % $ 43 7 , 6 0 S 66 , 0 7 $ 6,0 0 $ 72 , 0 $ 50 9 , 8 90 % 64 , 6 5 21 6 , 2 3 28 3 0 $ 6, 7 1 4, 1 1 10 3 , 7 6 Uta h I G C C w i t h C a o n C a o t & S e o u e s t r t i o n 51 3 6 8.0 1 % S 41 1 , 3 2 $ 53 . 4 $ 6, 0 S 59 , 2 4 $ 47 0 , 5 6 85 % 63 2 0 21 6 , 2 3 23 . 0 $ ~1 , 8 3. 0 10 1 , 2 8 Wv o m i n a P C w i t h o u t C a r o n C a n t u e & S e a u e t r t i o n 33 2 2 8.4 0 % $ 27 9 , 1 9 $ 36 , 0 0 $ 6,0 0 $ 42 , 0 0 $ 32 L 1 9 91 % 40 , 1 2 23 8 , 4 5 21 , 9 7 $ 1, 7 28 , 6 92 , 0 2 Wv o m t l P C w i t h C a o n C a o t u & S e a u e s t r a t i o n 60 0 7 8.2 5 % $ 49 5 5 0 $ 61 3 7 $ 6,0 0 $ 67 3 7 $ 56 2 , 8 6 90 % 71 3 9 23 8 , 4 5 31 , 8 $ 7,2 6 4, 6 11 4 , 3 9 Wv o m i n a l G C C w i t h C a r b o n C a o n i e & S e a u s t r i o n 58 1 6 8.0 1 % $ 46 5 . 7 4 $ 58 . 0 0 $ 6,0 0 $ 64 , 0 0 S 52 9 , 7 4 85 % 7L 1 4 23 8 , 5 26 , 3 4 $ 13 5 2 3. 7 11 4 , 4 7 Ex i n g P C w i t h C a r o n C a e & S e q u e t r t i o n ( 5 0 0 M W ) 1,3 1 9 10 . 7 1 % S 14 1 , 3 $ 66 , 0 7 $ 6,0 0 S 72 , 0 $ 21 3 , 3 0 90 % 21 0 5 23 8 . 4 5 34 2 7 $ 6,7 1 45 1 72 5 4 Na t o r a l G a Uti l i i v C 0 2 O o r o n 50 7 6 10 . 1 2 % $ 5\ 3 4 6 $ 1,8 6 S 05 0 S 2, 3 6 S 51 5 , 8 2 82 % ?L 8 1 72 2 . 1 9 35 . 9 2 S 23 , 2 9 4, 1 8, 7 14 4 , 0 6 Fu e l C e l l - L a 17 9 4 8.7 2 % $ 15 6 . 3 4 $ 8.4 0 S 0,5 0 $ 8, 0 $ 16 5 . 2 4 95 % 19 . 8 6 72 2 , 1 9 52 , 4 4 $ 0, 0 6, 0 9 12 . 9 5 91 3 7 SC C T A e r 11 2 6 9. 0 8 % $ 10 2 , 2 ~ $ 9. 9 5 $ 05 0 S 10 . 4 5 $ 11 2 . 6 21 % 61 , 2 4 72 2 , 1 9 70 5 8 $ 5, 6 3 8, 2 0 IH 3 16 3 , 0 8 ln o o 1 e d A e r o S C C T ( U t a 1 7 4 M W l 10 5 2 9. 0 8 % $ 95 . 5 $ 4. 0 4 $ 0,5 0 $ 45 4 $ 99 . 9 9 21 % 54 3 6 72 2 , 9 67 . 9 0 $ 2.7 1 7,8 9 16 , 7 7 14 9 . 6 2 Im e r o o l e d A e r S C C ( U t a 2 6 1 M W l 10 5 2 9. 0 8 % $ 95 . 5 $ 4. 0 4 $ 0.5 0 S 45 4 $ 99 . 9 9 21 % 54 3 6 72 2 , 1 9 67 , 0 $ 2,7 1 7,8 9 16 , 7 7 14 9 , 2 In t e r c o o l e d A e r S C C T ( W v o m i n a , 2 4 1 M W ) 11 4 0 9, 0 8 % $ 10 3 . 0 $ 4, 3 9 $ 0,5 0 $ 4, 9 $ 10 8 . 3 8 21 % 58 , 9 2 72 2 , 9 67 , 9 0 $ 2, 9 4 6,8 3 16 , 7 7 15 3 3 6 In t e r n a l C o m b u s t i o n E n o i n e s 13 2 4 9. 0 8 % $ 12 0 . 1 8 $ 12 , 0 S 0, 5 0 $ 13 3 0 S 13 3 . 8 94 % 16 , 2 1 72 2 , 1 9 61 3 8 $ 5,2 0 7,1 3 15 , 1 6 10 5 , 0 8 SC C T F r a ( 2 F r a " F " ) 74 7 8. 6 2 % $ 64 . 3 9 S 3. 7 4 S 05 0 $ 42 4 S 68 . 6 2 21 % 37 , 3 0 72 2 . 1 9 84 , 2 0 $ 4. 7 9,7 8 20 , 7 9 15 6 5 5 SC C T F r a ( 2 F r a " F " 81 0 8. 6 2 % $ 69 . 8 2 S 4.0 5 S 0, 5 0 $ 4,5 5 S 74 , 3 7 21 % 40 , 4 3 72 2 . 1 9 84 , 2 0 $ 4,8 5 8,4 7 20 , 7 9 15 8 , 7 4 CC C T l W e t " F " 1 x 1 i 3 6 6 8. 5 9 % $ 11 7 . 3 2 $ 12 . 7 9 S 0, 5 0 $ 13 . 2 9 $ 13 0 , 6 1 56 % 26 , 2 72 2 . 1 9 52 , 7 3 $ 2,9 4 6,1 3 13 . 2 10 1 , 4 5 CC C T D u c F i t i n a l W e t " F " I x l l 55 8 8. 5 9 % $ 47 , 8 S 1,6 0 $ 05 0 $ 2.1 0 S 49 , 9 8 16 % 35 , 6 6 72 2 , 1 9 64 . 0 5 S 03 9 7.4 4 15 , 2 12 3 . 3 6 CC C T ( W e t " F " 2 x l l 12 4 4 8, 5 9 % $ 10 6 . 7 9 $ 7, 7 S 0. 5 0 $ 8. 2 7 S 11 5 . 0 6 56 % 23 . 6 72 2 . 1 9 51 , 2 6 $ 2,9 4 5,9 6 12 , 6 6 %,2 7 CC C T D u F i r i u ( W e t " F " 2 x l l 62 8 8. 5 9 % $ 53 , 8 8 $ 1,6 0 $ 0, 5 0 $ 2, 0 $ 55 . 9 8 16 % 39 . 9 4 72 2 , 9 61 . 8 0 $ 0.3 9 7J 8 15 , 2 6 12 4 . 5 7 CC C T I D " F " 2 x n 12 7 5 8, 5 9 % S 10 9 5 0 $ 9.6 9 $ 0. 5 0 $ 10 . 1 9 $ 11 9 . 7 0 56 % 24 . 0 72 2 , 9 53 , 2 1 $ 33 5 6,1 8 13 . 1 4 10 0 2 8 CC C T D u c t F i r i n a I D " F " 2 x 1 ) 64 4 8. 5 9 % S 55 . 2 5 $ 1,6 0 $ 0. 5 0 $ 2, 0 $ 57 , 5 16 % 40 . 9 1 72 2 , 9 64 , 6 3 $ 0.1 1 75 1 15 , 9 6 12 9 . 1 3 CC C T l W e t " G " 1 x l l 12 9 2 8.5 9 % $ 11 0 . 9 3 $ 6.7 5 $ 0. 5 0 $ 7. 5 $ 11 8 , 1 8 56 % 24 . 0 9 72 2 . 1 9 49 . 7 2 $ 4,5 6 5.7 8 12 , 2 8 96 . 4 2 CC C T D u c t F i r n a ( W e t " G " I x l l 54 7 8.5 9 % $ 46 , 9 6 $ 1. 6 3 $ 0, 5 0 $ 2.1 3 $ 49 , 0 9 16 % 35 , 0 72 2 , 1 9 65 . 1 5 $ 03 6 75 7 16 , 0 9 12 4 , 9 CC C T A d v a c e d l W e t ) 14 2 7 8.5 9 % $ 12 2 . 9 $ 6,7 5 $ 0, 5 0 $ 7. 5 $ 12 9 . 7 4 56 % 26 , 5 72 2 . 1 9 48 . 8 2 $ 45 6 5,6 7 12 . 0 6 97 , 5 5 CC C T A d v a n e d D u F i r a ( W e t ) 70 0 85 9 % $ 60 . 1 0 $ 1, 6 3 $ 05 0 $ 2, 3 $ 62 , 2 4 16 % 44 . 4 0 72 2 , 9 65 . 1 5 $ 0.3 6 7.5 7 16 , 9 13 , 5 7 Ot b e r R e n e w a b l e . Ea s r ( W v o m o a ) W i n d 1 3 5 % C F ) 25 6 6 8.7 2 % $ 22 3 . 8 $ 31 , 4 3 $ 05 0 $ 31 , 9 3 $ 25 5 5 1 35 % 83 3 4 11 , 7 5 (2 0 , 7 0 74 , 3 8 Ea s t S i d e G e o t h e r ( B l o n e l l ) 60 8 7 7.4 2 % $ 45 1 , 6 4 $ 11 0 , 8 5 $ 05 0 $ 1I l . 5 $ 56 2 . 9 90 % 71 , 4 1 $ 5,9 4 (2 0 . 7 0 56 , 6 4 Ea s t S i d e G e o t ( G r e n F i e l d ) 76 0 8 7.4 2 % $ 56 4 , 5 5 $ 22 1 , 7 0 $ 0, 5 0 $ 22 2 . 2 0 $ 78 6 , 7 4 90 % 99 , 7 9 $ 11 , 8 8 (2 0 , 7 0 90 , 9 7 Ba i i S t o a a e 20 8 4 8.2 9 % $ 17 2 7 7 $ 1, 0 0 $ 0, 5 0 $ 1'5 0 $ 17 4 2 7 21 % 94 . 3 72 2 , 1 9 86 , 6 $ 10 , 0 0 10 , 0 7 37 , 3 3 23 8 , 7 9 Pm o e S t o m a e 17 7 3 8.1 9 % $ 14 5 , 1 4 $ 43 0 $ 13 5 $ 5,6 5 $ 15 0 , 7 9 20 % 86 , 0 6 72 2 . 1 9 93 , 8 $ 4.3 0 10 , 9 1 40 , 4 23 5 . 6 0 C~ s s e A i E n e r ~ S t o = e ( C A E S ) 15 6 1 8.2 9 % $ 12 9 , 4 $ 3, 0 $ 13 5 $ 5,1 5 $ 13 4 5 6 47 % 32 , 8 9 72 2 . 1 9 86 5 2 $ 55 0 8.7 0 21 3 7 15 4 , 9 8 Re o v e r E n e r a v G e n e r a t i o n ( C H ) 55 0 0 9.3 9 % $ 51 6 . 6 7 $ 91 , 9 2 $ 91 , 9 2 $ 60 8 5 9 84 % 82 , 7 1 82 , 7 1 Nu c l e a r 54 6 1 8; 3 0 % $ 45 3 , 2 6 $ 14 6 , 7 0 $ 6, 0 0 $ 15 2 , 7 0 $ 60 5 . 9 5 85 % 81 3 8 11 3 , 9 8 \2 , 2 1 $ 1,6 3 95 , 2 2 So l a r C o c e n t r t i n o ( P V ) - 3 0 % C F 65 2 0 6.4 8 % $ 42 2 , 4 $ 18 0 , 0 0 $ 6, 0 $ 18 6 , 0 $ 60 8 , 4 30 % 23 1 , 2 (1 , 9 22 9 , 9 3 So l a r C o n c e n i r ( n a t u a l a a s b a c k u ) - 2 5 % s o l a r 41 5 0 6.4 8 % $ 26 8 . 8 8 $ 19 5 . 6 0 $ 6. 0 0 $ 20 1 , 6 0 $ 47 0 . 4 8 33 % 16 2 . 5 72 2 , 1 9 19 5 9 2,2 8 (1 , 5 9 4,8 4 18 7 , 8 6 So l a C o n c e n t r t i n e . ( t h e n l s t o r a i æ ) . 3 0 % s o l a r 4, 6 5 0 5.4 6 % $ 25 3 , 8 0 $ 13 9 . 5 0 $ 6, 0 $ 14 5 , 5 0 $ 39 9 3 0 30 % 15 1 . 9 4 (1 5 9 15 0 , 3 5 10 6 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 7 - 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 - S i d e R e s o u r c e O p t i o n s , $ 4 5 C 0 2 T a x Ca n l ' a l C o . , $ / k W FlI e d C o s t Co n v e r t t o M i D i Va r i a b l e C o s t s To t a l Aiu u a l Fi x e d O & M $ ! k W - Y r mi l s l W h Re s o u r c e To t a l Pa y m e n t Pa y m e n t To t a F i x e d Ca p a c i t y To t a l F i x e d Le e l i z e d F u e l Co s t Fa c t o r "" Ca p i t a l Tr a n s p o i o n O& M Wi n d De s p t i o n Co s t Fa c t o r ($ l W - Y r ) O& M Oth e r To t a ($ I k W - Y r ) Mil l s l W b tl n u t u Mi l l s W l ($ / M ) bi t e o n Ta x Cre i t s En v i m m t a (M i U o I W h ) 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 s ! Fu e l C e l l - i . r o e 17 9 4 8.7 2 % $ 15 6 3 4 $ 8A O $ 0, 5 0 $ 8,9 0 $ 16 5 , 2 4 95 % 19 , 8 6 86 9 , 9 0 63 , 7 $ Q,3 53 3 12 , 9 5 10 1 3 3 Se C T A e r o 10 2 4 9. 0 8 % $ 92 , 9 2 $ 9.0 4 $ 0. 5 0 $ 9,5 4 $ 10 2 , 6 21 % 55 , 7 0 86 9 , 9 0 85 , 0 2 $ 5,1 2 7, 1 7 17 , 4 17 0 , 4 In t o o l e d A e r o S e C T 95 6 9. 0 8 % $ 86 , 7 7 $ 3,6 8 $ 0. 5 0 $ 4,1 8 $ 90 , 9 5 21 % 49 A 4 86 9 , 9 0 81 , 7 9 $ 2, 6 6, 9 0 16 , 7 7 15 7 3 6 In t e C o m u s t i o n E n i r n e 12 0 4 9. 0 8 % $ 10 9 . 2 5 $ 12 , 8 0 $ 0, 5 0 $ 13 3 0 $ 12 2 . 5 5 94 % 14 , 8 8 86 9 , 9 0 73 , 9 4 $ 5,2 0 6, 2 4 15 , 1 6 11 5 , 2 SC C T F r a 1 2 F r a " F " 67 9 8.6 2 % $ 58 . 5 3 $ 3,0 $ 0, 5 0 $ 3,9 0 $ 62 , 3 21 % 33 , 4 86 9 , 9 0 10 1 , 4 3 $ 4,0 7 8. 5 6 20 , 7 9 16 8 , 7 8 CC C T l W e t " F " 1 x l l 12 4 2 8. 5 9 % $ 10 6 , 6 6 $ 11 , 6 2 $ 0, 5 0 $ ~2 , 2 $ 11 8 , 7 8 56 % 24 . 1 86 9 , 9 0 63 . 5 2 $ 2,6 7 53 6 1M 2 10 8 , 7 9 CC C T D u l F i r n a ( W e t " F " I x l l 50 7 8. 5 9 ' 1 0 $ 43 . 5 3 $ 1,4 5 $ 0. 5 0 $ 1, 9 5 $ 45 A 8 16 % 32 , 5 86 9 , 9 0 71 1 5 $ 03 6 6,5 1 15 , 8 2 13 2 , 2 8 CC C T I W e t " F " 2 x l l 11 3 1 8. 5 9 % $ 97 0 8 $ 7. 0 7 $ 0. 5 0 $ 7.5 7 $ 10 4 , 6 5 56 % 21 3 3 86 9 , 9 0 61 , 7 5 $ 2,6 7 5,2 1 12 , 6 6 10 3 . 2 CC C T D u Fir i n o I W e t " F " 2 x 1 \ 57 0 8. 5 9 % $ 48 , 9 8 $ lA S $ 0.5 0 $ 1,9 5 $ 50 , 9 3 16 % 36 3 4 86 9 , 9 0 74 A 4 $ 03 6 6,2 8 15 , 2 6 13 2 , 6 8 CC C T l W e t " 0 " I x l l 1,1 7 5 8. 5 9 % $ 10 0 , 8 5 $ 6,1 3 $ 0.5 0 $ 6,6 3 $ 10 7 A 8 56 % 21 , 9 1 86 9 , 9 0 59 , 8 9 $ 4,4 5,0 5 IU 8 10 3 , 2 7 CC C T D u t F i r i a ( W e t " 0 " 1 x J \ 49 7 8. 5 9 % $ 42 , 6 9 $ 1A 8 $ 0,5 0 $ 1,9 8 $ 44 , 6 8 16 % 31 , 8 8 86 9 , 9 0 78 . 4 8 $ 03 3 6, 2 16 , 0 9 13 3 3 9 CC C T A d v a n c e d ( W e t ) 12 9 7 8.5 9 % $ 11 1 3 6 $ 6,1 3 $ 0.5 0 $ 6.6 3 $ 11 7 , 9 9 56 % 24 , 0 5 86 9 , 9 0 58 . 8 0 $ 4,1 4 4,9 6 12 , 0 6 10 4 , Q CC C T A d v a n e d D u F i r i n a ( W e t ) 63 6 8.5 9 % 1 $ 54 , 4 $ 1,4 8 $ 0.5 0 $ 1,9 8 $ 56 . 2 16 % 40 A O 86 9 , 9 0 78 A 8 $ 03 3 6,6 2 16 , 9 14 1 , 9 1 Otb e r - R e n e w a b l e s We s t W i n 26 1 2 8.7 2 % $ 22 7 . 5 9 $ 31 , 4 3 $ 27 , 4 $ 59 , 1 7 $ 28 6 , 7 6 29 % 11 2 . 8 11 , 5 12 0 , 7 0 10 3 , 9 3 Bi o m a s 33 4 7 8.1 0 % $ 27 1 , 2 2 $ 38 . 8 0 $ 0.5 0 $ 39 3 0 $ 31 0 . 5 2 91 % 38 , 7 8 59 0 , 0 0 64 . 8 $ 0,9 6 12 0 , 7 0 34 , 1 6 11 7 , 9 7 We s t S i d e O e o t h e n n I G r F i e l d ) 76 0 9 7.4 2 % $ 56 4 , 6 2 $ 22 1 . 7 0 $ 05 0 $ 22 2 , 0 $ 78 6 , 8 2 90 % 99 , 8 0 $ ~1 , 8 8 12 0 , 7 0 90 , 9 8 Co m n r e s s e d A i r E n e r ø v S t o r a ø e ( C A B S ) 15 6 1 8.2 9 % $ 12 9 , 4 1 $ 3, 5 $ 13 5 $ 4, 8 0 $ 13 4 . 1 47 % 32 , 8 1 86 9 , 9 0 10 4 , 2 1 $ 5,0 0 8,7 9 21 3 7 17 2 , 1 8 Hy d r k i n e t i c l W a v e \ - 2 1 % C F 6, 0 0 0 9.6 9 % $ 58 1 , 8 $ 18 0 , 0 0 $ 6.0 0 $ 18 6 , 0 0 $ 76 7 5 8 21 % 41 7 . 5 41 7 . 5 We . t S i d e O p t i o n . ( S e a L e v e l ) Na t u r a l Ga s Fu e l C e l l - L a a e 17 9 4 8. 7 2 % $ 15 6 3 4 $ 8. 4 0 $ 0,5 0 $ 8,9 0 $ 16 5 , 2 4 95 % 19 , 8 6 86 9 , 9 0 63 , 7 $ 0,0 53 3 12 . 9 5 10 1 3 3 SC C T A e r n 97 2 9.0 8 % $ 88 , 2 7 $ 8. 5 9 $ 05 0 $ 9,0 9 $ 97 3 6 21 % 52 , 9 86 9 , 9 0 85 , 0 2 $ 4,8 7 7,1 7 17 , 4 16 1 , 2 In t o l e d A e r o S e c T 90 8 9. 0 8 % $ 82 , 3 $ 3. 9 $ 0.5 0 $ 3,9 9 $ 86 . 3 21 % 46 , 9 8 86 9 , 9 0 81 , 9 $ 2.3 5 6.9 0 16 . 7 7 15 4 , 7 8 In t e r n l C o b u s t i o n E m r i n e s 11 4 3 9. 0 8 % $ 10 3 . 7 9 $ 12 . 0 $ 0,5 0 $ IB O $ 11 7 , 0 9 94 % 14 . 2 86 9 , 9 0 73 , 9 4 $ 5,2 0 6,2 4 15 , 1 6 11 4 , 7 5 SC C T F r a m 1 2 F r a " F " \ 64 5 8. 6 2 % $ 55 , 6 1 $ 3, 2 3 $ 0,5 0 $ 3,7 3 $ 59 3 4 21 % 32 , 6 86 9 , 9 0 10 1 , 4 3 $ 3,7 8,5 6 20 , 7 9 16 6 , 9 0 Ce c T I W e t " F " I x 1 \ 11 8 0 8. 5 9 % $ 10 1 3 2 $ ~1 , 0 7 $ 0, 5 0 $ 11 , 7 $ 11 2 , 8 9 56 % 23 , Q 86 9 , 9 0 63 5 2 $ 25 5 53 6 13 , 0 2 10 1 , 6 CC C T D u t F i r i n . l W e t " F " I x l 48 2 8. 5 9 % $ 41 3 5 $ 13 8 $ 05 0 $ 1, 8 8 $ 43 , 2 3 16 % 30 , 8 5 86 9 , 9 0 71 1 5 $ 03 4 65 1 ~5 , 2 13 0 , 6 6 CC C T ( W e t " F " 2 x l l 10 7 4 8. 5 9 % $ 92 . 2 3 $ 6, 7 3 $ 05 0 $ 7,2 3 $ 99 . 4 6 56 % 20 , 2 7 86 9 , 9 0 61 , 7 5 $ 2,5 5 5,2 1 12 . 6 10 2 . 4 4 CC C T D u t F i r n a I W e t " F " 2 x l l 54 2 8. 5 9 % $ 46 5 3 $ 13 8 $ O,S O $ 1, 8 8 $ 48 . 4 2 16 % 34 5 4 86 9 . 9 0 74 , 4 $ 03 4 6,2 8 15 , 2 6 13 0 , 8 7 CC C T IW e t "0 " l x i ' 11 1 6 8. 5 9 % $ 95 , 1 $ 5, 4 $ 05 0 $ 63 4 $ 10 2 , 5 56 % 20 , 8 2 86 9 , 9 0 59 , 8 9 $ 3,9 4 5,0 5 12 , 2 8 10 1 , 9 8 CC C T D u t F i r i n e ( W e t " 0 " I x I ' 47 2 8. 5 9 % $ 40 5 6 $ 1,4 1 $ 0.5 0 $ 1, 9 1 $ 42 , 7 16 % 30 3 0 86 9 , 9 0 78 . 4 8 $ 03 1 6, 2 16 , 9 13 1 , 8 0 CC C T A d v a n c e d ( W e n 12 3 2 8. 5 9 % $ 10 5 , 7 9 $ 5, 4 $ 05 0 $ 63 4 $ 11 2 , 3 56 % 22 , 8 6 86 9 , 9 0 58 , 8 0 $ 3,9 4 4,9 6 12 , 0 6 10 2 . 2 CC C T A d v a n e d D u c t F i r n e ( W e t ) 60 5 8. 5 9 % $ 51 , 1 $ 1,4 1 $ 05 0 $ 1, 9 1 $ 53 . 8 2 16 % 38 . 4 0 86 9 , 9 0 78 . 8 $ 03 1 6,6 2 16 , 2 2 14 0 , 0 10 7 PacifCorp - 2008 IRP Chapter 6 - Resource Options Distributed Generation Table 6.8 reports cost and performance attbutes for small distrbuted standby generation, com- bined heat and power, and on-site solar supply-side resource options. Tables 6.9 and 6.10 present the total resource cost attbutes for these resource options, and are based on estimates of the first-year real levelized cost per megawatt-hour of resources, stated in June 2008 dollars. The resource costs are presented for both the $8 and $45 CO2 tax levels in recognition of the uncer- tainty in characterizing emission costs. Certin technologies were adjusted to reflect benefits that were identified outside of the Quantec DSM potential study and cost of emissions. Maintenance and forced outage data were taken from comparable technologies in the supply-side table. Addi- tional explanatory notes for the tables are as follows: . A 15-percent administrative cost (for fixed operation and maintenance) is included in the overall cost of the resources. . The avoided transmission and distrbution credit of $23/kW-year is included in the resource costs to reflect a rough estimate of savings by avoiding transmission and distrbution invest- ments. . Federal tax benefits are included for microtuines at $200/kW capacity, while fuel cells re- ceive $500 per 0.05 kW of capacity. . Installation costs for on-site ("micro") solar generation technologies are treated on a total re- source cost basis; that is, customer installation costs are included. However, capital costs are adjusted downward to reflect federal and state tax benefits. The percentages applied included an 80 percent reduction to capital cost for Oregon, 31 percent for Utah, and 25 percent for all other states. The Quantec DSM potential study included the following benefits for commer- cial and residential customers: - Utah - Commercial Credits: The federal credit is 30 percent of the investment; the state credit is 1 percent of investment - Residential Credits: The federal credit is 30 percent of the investment up to $2,000 for Residential Energy Effciency; Uta receives up to $2,000 - Oregon - Commercial Credits: The federal credit is 30 percent of the investment; the state Business Credit is 50 percent of investment up to $20 milion received over 5 years; The Energy Trust of Oregon credit is $1.25 per watt - Residential Credits: The federal credit is 30 percent of the investment up to $2,000 for Residential Energy Effciency; the state credit is 5 percent of invest- ment; the Energy Trust of Oregon credit is $2 per watt - Other States - Commercial Credits: The federal credit is 30 percent of the investment - Residential Credits: The federal credit is 30 percent of the investment up to $2,000 for Residential Energy Effciency 108 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 6 - Resource Options . The resource cost for Industral Biomass reflects the Company's recent avoided cost, which reflects the minimum price the Company would pay. Factoring in the income tax benefits would lower the resource cost below the Company's avoided cost. 109 Pa c i f i C o r p - 2 0 0 8 I R Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 8 - D i s t r i b u t e d G e n e r a t i o n R e s o u r c e O p t i o n s 20 0 8 D o l l a r s ) 1s t Un i t Siz e MW De s i g n An n u a l Ma i n t Eq u i v a l e n t Ca p i t a l I Em i s s i o n s I In t a l l a t i o n Ye a r Av e r a g e Lif e He a t Ra t e Ou t a g e Fo r c e d O u t a e Co s t Va r . O & M Fi x e d O & M S0 2 I NO x I H~ I CO 2 I De s c r i p t i o n Lo c a t i o n Av a i L . Ca p . (M W ) Fu e l in Y e a r s BT U / k W h Ra t e Ra t e ( E F O R ) $ / k W ($ / M W h ) ($ / k W - y r ) I lb s l M M B T U ( H g : I b s l 1 i u ) I Sm a l l C o m b i n e d H e a t & P o w e r Re c i o r o c a t i n g E n g i n e Ut a 20 0 8 0.6 Na t u r a l G a s 20 50 0 5 2% 3% $ 1,9 6 9 - $ 79 . 0 0 0. 0 0 1 0.1 0 1 0.2 5 5 11 8 . 0 0 Re c i o r o c a t i n ~ E n i t e Wy o m i n g 20 0 8 0.6 Na t u a l G a s 20 50 0 5 2% 3% $ 1,9 6 9 - $ 79 . 0 0 0. 0 0 1 0. 1 0 1 02 5 5 11 8 . 0 0 Re c i o r o c a t i n g E n g i n e Or e g o n 20 0 8 0. 6 Na t u r a l G a s 20 5, 0 0 5 2% 3% $ 19 6 9 - $ 79 . 0 0 0. 0 0 1 0. 1 0 1 02 5 5 11 8 . 0 0 Ga s T u r b i n e Ut a 20 0 8 32 Na t u r a l G a s 20 66 0 0 2% 3% $ 18 3 8 - $ 58 . 0 0 0. 0 0 1 0.0 5 0 0.2 5 5 11 8 . 0 0 Ga s T u r i n e Wy o m i g 20 0 8 3. 2 Na t u a l G a s 20 66 0 0 2% 3% $ 18 3 8 - $ 58 . 0 0 0. 0 0 1 0. 0 5 0 02 5 5 11 8 . 0 0 Ga s T u r b i n e Or e f l o n 20 0 8 3. 2 Na t u a l Ga s 20 66 0 0 2% 3% $ 18 3 8 - $ 58 . 0 0 0. 0 0 1 0. 0 5 0 02 5 5 11 8 . 0 0 Mi c r o t u b i n e Ut a 20 0 8 0. 2 Na t u r a l G a s 15 7, 4 5 4 2% 3% $ 28 3 1 - $ 71 . 0 0 0. 0 0 1 0. 1 0 1 02 5 5 11 8 . 0 0 Mi c r o t u b i n e Wy o i n n ~ 20 0 8 0. 2 Na t u r a l G a s 15 74 5 4 2% 3% $ 2,8 3 1 - $ 71 0 0 0. 0 0 1 0. 1 0 1 0. 2 5 5 11 8 . 0 0 Mi c r o t u b i n e Or g o n 20 0 8 0.2 Na t u a l G a s 15 74 5 4 2% 3% $ 2. 8 3 1 - $ 71 . 0 0 0. 0 0 1 0. 1 0 1 0. 2 5 5 11 8 . 0 0 Fu e l Ce l l Ut a 20 0 8 0.5 Na t u r a l Ga s 10 57 0 6 2% 3% $ 56 9 7 $ 17 . 0 0 0. 0 0 1 0. 0 0 3 0. 2 5 5 11 8 . 0 0 Fu e l C e n Wy o m i g 20 0 8 0.5 Na t u r G a s 10 57 0 6 2% 3% $ 56 9 7 - $ 17 . 0 0 0.0 0 1 0, 0 0 3 02 5 5 11 8 . 0 0 Fu e l C e n Or e g o n 20 0 8 0.5 Na t u G a s 10 57 0 6 2% 3% $ 5,6 9 7 - $ 17 . 0 0 0,0 0 1 0. 0 0 3 0. 2 5 5 11 8 . 0 0 Co m m e r i a l B i o m a s , A n r o b i c D i g e s t e Ut a h 20 0 8 0.4 Bio m a s s 15 - 10 % 10 % $ 3,2 1 9 - $ 67 . 0 0 - - - Co m m e r c i a l B i o m a s , A n r o b i c D i g e s t e r Wy o m i g 20 0 8 0.4 Bi o m a s s 15 - 10 % 10 0 1 0 $ 3, 2 1 9 - $ 67 . 0 0 - - - Co m m e r i a l B i o m a s s A n a e r o b i c D i g e s t e r Or e g o n 20 0 8 0.4 Bi o m a s s 15 - 10 % 10 0 1 0 $ 32 1 9 - $ 67 . 0 0 - - - In d u s t r i a l B i o m a s s W a s t e Ut a 20 0 8 4.8 Bi o m a s s iS - 5% 5% $ 1,8 0 0 - $ 39 . 0 0 - - - - In d u s t r l B i o m a s W a s t e Wy o m i n g 20 0 8 4.8 Bi o m a s s 15 - 5% 5% $ 1,8 0 0 - $ 39 . 0 0 - - - - In d u s m a l B i o m a s s , W a s t e Or e g o n 20 0 8 4.8 Bi o m a s s 15 - 5% 5% $ 1,8 0 0 - $ 39 . 0 0 - - - - So l a r Ro o f t P h o t o v o l t a c Ut a 20 0 8 0. 0 0 5 So l a 25 - $ 9, 0 0 0 - $ 1 0 0 . 0 0 - - - - Ro o f t P h o t o y o l t a c Wy o m i n g 20 0 8 0. 0 0 5 So l a 25 - $ 9, 0 0 0 - $ 1 0 0 . 0 0 - - - - Ro o f t p P h o t o v o l t a i c Or g o n 20 0 8 0. 0 0 5 So l a 25 - $ 90 0 0 - $ 1 0 0 . 0 0 - - - - Wa t e r H e a t e r s Uta h 20 0 8 0. 0 0 2 So l a 15 - $ 35 0 0 - - - - Wa t e r H e a t e r s Wy o m i n g 20 0 8 0. 0 0 2 So l a r 15 - $ 3, 5 0 0 - - - - - Wa t e r H e a t e r s Or e g o n 20 0 8 0. 0 0 2 So l a r 15 - $ 35 0 0 - - - - At t i c F a n s Ut a 20 0 8 0. 0 0 0 0 1 0 So l a r 10 - $ 54 0 0 0 - - - - - - At t i c F a n s Wy o m i g 20 0 8 0. 0 0 0 0 1 0 So l a r 10 - $ 54 , 0 0 0 - - - - - - At t i c F a n Or g o n 20 0 8 0. 0 0 0 0 1 0 So l a r 10 - $ 54 , 0 0 0 - - - - - Di s p a t c b l b l e G e n e r a t o r s Dis p a t c h i b l e S t a d b y G e n e r t o r s E x i s t i n a Ut a h 20 0 8 1. 0 Di e s e l 20 99 7 5 $ 25 0 - $ 7. 5 0 0. 0 3 0 0. 1 0 1 0.2 5 5 11 8 . 0 0 Dis o a t e h i b l e S t a d b v G e n e r t o r s E x i s t i n g Wy o m i n g 20 0 8 1. 0 Di e s e l 20 99 7 5 $ 25 0 - $ 7. 5 0 0. 0 3 0 0. 1 0 1 0.2 5 5 11 8 . 0 Di s p a t e h i b l e S t a d b y G e n e r t o r s E x i s t i n a Or e g o n 20 0 8 1. 0 Di e s e l 20 99 7 5 $ 25 0 - $ 7. 5 0 0. 0 3 0 0. 1 0 1 0.2 5 5 11 8 . 0 0 Dis p a t c h i b l e S t a d b y G e n e r a t o r s N e w Ut a h 20 0 8 1. 0 Di e s e l 20 99 7 5 $ 17 5 - $ 5. 0 0 0. 0 3 0 0, 1 0 1 0. 2 5 5 11 8 . 0 0 Di s o a t e h i b l e S t a n d b y G e n e r a t o N e w Wy o m i n g 20 0 8 1. 0 Di e s e l 20 99 7 5 $ 17 5 - $ 5. 0 0 0. 0 3 0 0. 1 0 1 0.2 5 5 11 8 . 0 0 Dis p a t e h i b l e S t a d b y G e n e r a t o r s N e w Or e g o n 20 0 8 1. 0 Di e s e l 20 9,9 7 5 $ 17 5 - $ 5. 0 0 0. 0 3 0 0. 1 0 1 0. 2 5 5 11 8 . 0 0 11 0 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R Ta b l e 6 . 9 - D i s t r i b u t e d G e n e r a t i o n T o t a l R e s o u r c e C o s t s , $ 8 C O 2 t a x 20 0 8 D o l l a r s ) Ch a p t e r 6 - R e s o u r c e O p t i o n s De s c r p t i o t Sm a l l C o m b i n e d H e a t & P o w e r ~c i M o c ~ n 2 E ~ ~ $ Re c i o r o c a t i ~ E n l ! n e $ Re c i M o c ~ n 2 E n l ! n e $ Ga s T u r b i n e $ Ga s T u r i n e $ Ga s T u r i n e $ Mi c r o t u i n e $ Mi c r t u i n e $ Mi c r t u i n e $ Fu e l C e l l $ Fu e l C e l l $ Fu e l C e l l $ Co m m e r c i a l B i o m s . A n o b i c D i 2 e s t e r $ Co m m e r c i a l B i o m a s s , A n a e o b i c D i 2 e s t $ Co m m e r c i a l B i o m a s s A n a e r o i c D i 2 e s t $ In d u t r a l B i o m a , W a s e $ In d u t r a l B i o m a , W a s $ In d u t r a l B i o m a , W a s e $ $ 9 , 0 0 0 $ 9 , 0 0 $ 9 , 0 0 $ 3 , 5 0 0 $ 3 , 5 0 0 $ 3 , 5 0 0 $ 5 4 , 0 0 0 $ 5 4 , 0 0 0 $ 5 4 , 0 0 0 Ca ø C o s t Ta x Be n e f i t s Tr a m i s s i o n & D i s t r b u t i o n Cr e d i t 26 4 $ 26 4 $ 26 4 $ 20 2 $ 20 2 $ 20 2 $ 15 4 $ 15 4 $ (1 5 4 ) $ 21 $ 21 $ 21 $ 21 $ 21 1 $ (2 1 ) $ Ca o i t a l C o s t $ / W Ad m n i s t r t i v e 29 5 $ 29 5 $ 29 5 $ 27 6 $ 27 6 $ 27 6 $ 42 5 $ 42 5 $ 42 5 $ 85 5 $ 85 5 $ 85 5 $ $'$'$'$'$'$ 1,3 5 0~1.5 0 52 5 52 5 52 5 !! 8, 1 0 0 8, 1 0 0 $ 7 , 2 9 6 $ 7 , 8 3 6 $ 2 , 8 8 6 $ 2 , 8 4 3 $ 2 , 9 4 8 $ 2 , 4 9 3 $ 6 1 , 9 4 6 $ 6 1 , 9 4 6 $ 6 1 , 9 4 6 Pa y m e n t I A n n u a l P m t Fi x e d C o s t Fix e d O & M $ / W . Y r Co n v e r t t o M i l l s To t a l F i x e d I C a p a c i t y I T t l F i x e d I L e v e l i z e d F u e l Va r a b l e C o s t s mil l s l W h Ne t Ca i t a l Cn s t s Fa c t o r I I / k W . Y r I O & M Oth e r To t a I/ k W . Y r Fa c t o r I M i l s / k W h 90 % 3 9 . 4 6 90 % 3 9 . 4 6 90 % 3 9 . 4 6 95 % 3 2 2 95 % 3 2 . 8 2 95 % 3 2 . 8 2 90 % 5 0 3 0 90 % 5 0 3 0 90 % 5 0 3 0 95 % 9 9 . 1 0 95 % 9 9 . 1 0 95 % 9 9 . 1 0 80 % 0 . 0 0 80 % 0 . 0 0 80 % 0 . 0 0 90 % 0 . 0 0 90 % 0 . 0 0 90 % 0 , 0 0 14 % 6 0 0 . 0 1 14 % 6 3 8 . 1 8 13 % 3 0 8 . 6 8 14 % 2 6 4 . 4 4 14 % 2 7 4 . 2 1 13 % 2 4 9 . 7 3 14 % 7 5 5 8 . 4 2 14 % 7 5 5 8 . 4 2 13 % 8 1 3 9 . 8 3 0. 9 % 2 1 t J 5 0. 9 % 2 1 3 5 0. 9 % 2 1 t J 5 0. 9 % 5 8 . 1 0 0, 9 % 5 8 . 1 0 0. 9 % 5 8 . 1 0 l/ n n i u Mil l s W h O& M Av o i d e C o s t I E n v i o n t a To t a l Re s o u r c e C o s t (M i l s / W h ) 76 , 4 76 . 0 4 8L 7 9 8L 0 6 8L 0 6 88 . 6 3 10 4 . 7 8~11 3 3 3 i4 14 0 . 8 1 i4 46 . 1 0 58 . 1 7 62 . 1 3 46 . 1 0 58 3 7 62 3 3 $'$'$'$'$'$'$'$'$ 60 0 . 0 1 63 8 3 8~26 4 . 4 4 27 4 . 2 1 24 9 . 7 3 7,5 5 8 . 4 2 7,5 5 8 . 4 2 8,1 3 9 . 8 3 1,9 6 9 1, 9 6 9 1,9 6 9 bi 1, 8 3 8~2,8 3 1 2,8 3 1 2,8 3 1~~5, 6 9 7 $ . $ $ . $ $ - $ $ . $ $ - $ $ . $ $ ( 2 0 0 $ $ ( 2 0 0 $ $ ( 2 0 0 $ $ 1 1 0 0 0 $ $ 1 1 0 0 0 $ $ ( 1 0 0 $ $ - $ $ . $ $ - $ $ . $ $ . $ $ - $ ~ $ ~ $ ~ $ H $ H $ H $ ~2,0 6 0 2,0 6 0 121212 2, 8 5 4 2, 8 5 4b.~5, 3 9 8 5,3 9 8 i L 2 7 % $ 2 3 2 . 0 8 $ 7 9 . 0 0 11 . 7 % $ 2 3 2 . 0 8 $ 7 9 , 0 0 11 . 7 % $ 2 3 2 . 0 8 $ 7 9 . 0 0 11 . 7 % $ 2 1 5 . 1 1 $ 5 8 . 0 0 11 . 7 % $ 2 1 5 . 1 1 $ 5 8 . 0 0 11 . 7 % $ 2 1 5 . 1 1 $ 5 8 . 0 0 11 . 1 % $ 3 2 5 5 3 $ 7 L O O i L 4 1 % $ 3 2 5 5 3 $ 7 L O O 11 . 4 1 % $ 3 2 5 . 5 3 $ 7 L O O 14 . 9 6 % $ 8 0 7 . $ 1 7 . 0 0 14 . 9 6 % $ 8 0 7 . $ 1 7 , 0 0 14 . 9 6 % $ 8 0 7 . $ 1 7 . 0 0 ~11 . 1 % 11 . 4 1 % 1 !.!. 11 . 1 % $ 7 9 . 0 0 $ 3 1 L 0 8 $ 7 9 , 0 0 $ 3 1 L 0 8 $ 7 9 . 0 0 $ 3 1 L 0 8 $ 5 8 . 0 0 $ m i l $ 5 8 . 0 0 $ 2 7 3 . $ 5 8 . 0 0 $ m i l $ 7 L O O $ 3 9 6 5 3 $ 7 L O O $ 3 9 6 . 5 3 $ 7 1 0 0 $ 3 9 6 5 3 $ 1 7 . 0 0 $ 8 2 4 . $ 1 7 . 0 0 $ 8 2 4 . 7 3 $ 1 7 . 0 0 $ 8 2 4 . 7 3 $ 1 0 0 . 0 0 $ 7 3 5 . 8 5 $ 1 0 0 . 0 0 $ 7 8 2 . 2 $ 1 0 0 . 0 0 $ 3 5 L 5 2 rJ rT 'f $9 , 2 6 9 . 6 4 $9 , 2 6 9 . 6 4 $9 , 2 6 9 . 6 4 LI $ 8 . 6 3 $ 1 6 . 9 1 LI $ 8 . 6 3 $ 1 6 . 9 1 LI $ 8 . 6 3 $ 1 6 . 9 1 0. 7 5 $ 5 . 7 5 $ 4 . 6 5 0. 7 5 $ 5 . 7 5 $ 4 . 6 5 0. 7 5 $ 5 , 5 $ 4 . 6 5 69 9 . 2 2 69 9 . 2 2 81 4 . 0 0 69 9 . 2 2 69 9 . 2 2 !! 69 9 . 2 2 69 9 . 2 2 81 4 . 0 0 69 9 . 2 2 69 9 . 2 2 81 4 . 0 0 35 . 0 0 35 . 0 0~46 . 1 5 46 . 1 5 51 7 2 52 . 1 2 52 . 1 2 60 , 6 8 l2 39 . 9 0 46 . 5 15 9 $ 15 9 $ 15 9 $ 2, 0 9 $ 2. 0 9 $ 2. 0 9 $ 2. 1 6 $ 23 6 $ 23 6 $ L8 1 $ L8 1 $ L8 1 $ 46 . 1 0 $ 58 3 7 $ 62 3 3 $ 46 3 0 $ 58 3 7 $ 62 3 3 $ 47 L 2 6 47 47 1 . 6 31 8 . 0 1 31 8 . 0 1 31 8 m f7 2 , 7 9 0 $ $ ( 2 5 0 $ $( 7 0 0 $ $ ( 9 8 0 $ $ ( 8 7 5 $ $ 1 1 3 3 0 $ $ - $ $ - $ $ - $ 25 0 $ 25 0 $ 25 0 $ 17 5 $ 17 5 $ 17 5 $ 8.7 2 % $ 6 3 5 . 8 5 T $ 1 0 0 . 0 0 8.7 2 % $ 6 8 2 . 2 I $ 1 0 0 . 0 0 8. 7 2 % $ 2 5 L 5 2 I $ 1 0 0 . 0 0 II A 1 % $ 3 2 4 3 1 IL 4 1 % $ 3 3 6 . 2 9 1 L 4 1 % $ 2 8 4 3 9 14 . 9 6 % $ 9 , 2 6 9 . 6 14 . 9 6 % $ 9 2 6 9 . 6 4 14 . 9 6 % $ 9 2 6 9 . 6 4 76 76 76 iõ!i (1 0 ) 10 . 8 8 % $ 8 . 2 8 $ 7 5 0 $ 10 . 8 8 % $ 8 . 2 8 $ 7 5 0 $ 10 . 8 8 % $ 8 . 2 8 $ 7 5 0 $ 10 . 8 8 % $ 1 1 . 0 $ 5 . 0 0 $ ~0 , 8 8 % $ 1 1 . 0 $ 5 . 0 0 $ ~0 , 8 8 % $ ( 1 . 0 ) $ 5 . 0 0 $ 25 7 4 25 7 4 25 7 4 I5 25 7 4 I5 25 6 . 7 2 25 6 . 7 2~~25 6 . 7 2 iš 11 9 $ 11 9 $ 11 9 $ 3. 1 9 $ 1I 9 $ 11 9 $ II I Pa c i f C o r p - 2 0 0 8 I R Ch a p t e r 6 - R e s o u r c e O p t i o n s Ta b l e 6 . 1 0 - D i s t r i b u t e d G e n e r a t i o n T o t a l R e s o u r c e C o s t , $ 4 5 C O 2 T a x 20 0 8 D o l l a r s ) Ca i t a l C o s t $ / k W Fi x e d C o s t Co n v e r t t o M i l s Va r a b l e C o s t s To t a l Pa y m e n t An n u a l P m t Fi x e d O & M $ / k W - Y r To t a l F i x e d Ca p a c i t y Tt l F i x e d Le v e l i z e d F u e l mil s l W h Re s o u r e C o s t Tr a n s m i s s i 00 & Ne t Ta x Di s t r i b u t i o Ca p i t a l De s c r p t i o n Ca p Co s t Be n e f i t s nC r e d i t Ad m n i s t r v Co s t s Fa c t o r II k W . Y r O& M Oth e r To t a SlW . Y r Fa c r MiU s W b t/ n u t u Mi U s / W b O& M Av o i d e C o En v i r o n m e n t a (M i l s / W h ) Sm a l l C o m b i n e d H e a t & P o w e r Re i o r o c a t i . E l I i n $ 19 6 9 $ $ 20 4 $ 29 5 $ 20 6 0 11 . 7 % $ 2 3 2 . 0 8 $ 79 . 0 0 $ 79 . 0 0 $ 31 1 . 0 8 90 % 39 . 4 6 72 2 . 1 9 36 . 1 5 8, 9 3 $ 84 . 5 3 Re i o r o a t i n . E n i n e $ 1, 9 6 9 $ $ 20 4 $ 29 5 $ 20 6 0 11 . 2 7 % $ 2 3 2 . 0 8 $ 79 0 0 $ 79 . 0 0 $ 31 1 . 0 8 90 % 39 . 4 6 72 2 . 1 9 36 . 1 5 8. 9 3 $ 84 . 5 3 Re c i o r o c a t i n . E o l ! o e $ 19 6 9 $ $ 20 4 $ 29 5 $ 20 6 0 11 . 7 % $ 2 3 2 . 0 8 $ 79 . 0 0 $ 79 . 0 0 $ 31 1 . 0 8 90 % 39 , 4 6 86 9 . 9 0 43 . 5 4 8. 9 3 $ 91 . 9 2 Ga s T u r i n e $ 1, 8 3 8 $ $ 20 4 $ 27 6 $ 19 1 0 11 . 2 7 % $ 2 1 5 . 1 1 $ 58 . 0 0 $ 58 . 0 0 $ 27 3 . 1 1 95 % 32 . 8 2 72 . 1 9 47 . 6 6 11 . 7 7 $ 92 . 2 5 Ga s T u r i n e $ 1, 8 3 8 $ $ 20 4 $ 27 6 $ 19 1 0 11 . 2 7 % $ 2 1 5 . 1 1 $ 58 . 0 0 $ 58 . 0 0 $ 27 1 1 1 95 % 32 . 8 2 72 2 . 1 9 47 . 6 6 11 . 7 7 $ 92 , 5 Ga s T u r i n e $ 18 3 8 $ $ 20 4 $ 27 6 $ 19 1 0 11 . 7 % $ 2 1 5 . 1 1 $ 58 . 0 0 $ 58 . 0 0 $ 27 3 . 1 1 95 % 32 . 8 2 86 9 . 9 0 57 . 4 1 11 . 7 7 $ 10 2 . 0 0 Mi c r i n e $ 28 3 1 $ 1 2 0 0 $ 20 2 $ 42 5 $ 28 5 4 11 , 4 1 % $ 3 2 5 . 5 3 $ 71 . 0 0 $ 71 . 0 0 $ 39 6 . 5 3 90 % 50 3 0 72 . 1 9 53 . 8 3 13 . 2 9 $ 11 7 , 4 2 Mic r o t u i n e $ 28 3 1 $ 20 0 $ 20 2 $ 42 5 $ 28 5 4 II A l % $ 3 2 5 . 5 3 $ 71 . 0 0 $ 71 . 0 0 $ 39 6 . 5 3 90 % 50 3 0 72 2 . 1 9 53 . 8 3 13 . 2 9 $ 11 . 4 2 Mic r o t u i n e $ 28 3 1 $ ( 2 0 0 $ 20 2 $ 42 5 $ 28 5 4 11 , 4 1 % $ 3 2 5 . 5 3 $ 71 . 0 0 $ 71 . 0 0 $ 39 6 . 5 3 90 % 50 3 0 86 9 . 9 0 64 . 8 4 13 . 2 9 $ 12 8 . 4 Fu e l C e l l $ 56 9 7 $ 1 0 0 0 $ 15 4 $ 85 5 $ 53 9 8 14 . 9 6 % $ 8 0 7 . 7 3 $ 17 . 0 0 $ 17 . 0 0 $ 82 4 . 7 3 95 % 99 . 1 0 72 . 1 9 41 . 2 1 10 . 1 8 $ 15 0 , 4 9 Fu e l C e l l $ 5, 6 9 7 $ 1 1 0 0 0 $ 15 4 $ 85 5 $ 53 9 8 14 , 9 6 % $ 8 0 7 . 7 3 $ 17 . 0 0 $ 17 . 0 0 $ 82 4 . 7 3 95 % 99 . 1 0 72 2 . 1 9 41 . 1 10 . 1 8 $ 15 0 , 4 9 Fu e l C e l l $ 56 9 7 $ 1 0 0 0 $ 15 4 $ 85 5 $ 53 9 8 14 . 9 6 % $ 8 0 7 . 7 3 $ 17 . 0 0 $ 17 . 0 0 $ 82 4 . 7 3 95 % 99 . 1 0 86 9 . 9 0 49 . 6 4 10 . 1 8 $ 15 8 . 9 2 Co m m e r c i B i o m a s s A n a e b i c D i . e s t e r $ $ $ $ $ 11 . 1 % 80 % 0. 0 0 46 3 0 $ 46 3 0 Co m m e r c i a l B i o m a s s A n a e b i c D i i r t e $ $ $ $ $ 11 . 1 % 80 % 0. 0 0 58 3 7 $ 58 3 7 Co m m e r i a l B i o a s A n a e o b i c D i . e s t e $ $ $ $ $ 11 , 4 1 % 80 % 0. 0 0 62 3 3 $ 62 3 3 In d u t r a l B i o m a s , W a s $ $ $ $ $ 11 . 4 1 % 90 % 0. 0 0 46 3 0 $ 46 3 0 In d u s t r i a l B i o m a s s . W a s $ $ $ $ $ 11 . 4 1 % 90 % 0, 0 0 58 3 7 $ 58 3 7 In d u s t r a l B i o m a s , W a s $ $ $ $ $ 11 . 4 1 % 9O / Ó 0. 0 0 62 3 3 $ 62 3 3 So l a r Ro o f t o P h o t o v o l t a c $ 90 0 0 $ 2 7 9 0 $ 26 4 $ 13 5 0 $ 7 9 6 8. 7 2 % $ 6 3 5 . 8 5 $ 1 0 0 , 0 0 $ 1 0 0 . 0 0 $ 73 5 . 8 5 14 % 60 0 . 0 1 $ 60 0 , 0 1 Ro o f t p P h o t o v o l t c $ 90 0 0 $ ( 2 2 5 0 $ 26 4 $ 13 5 0 $ 78 3 6 8. 7 2 % $ 6 8 2 . 9 2 $ 1 0 0 . 0 0 $ 1 0 0 . 0 0 $ 78 2 . 9 2 14 % 63 8 3 8 $ 63 8 3 8 Ro o f t o P h o t o v o l t a c $ 90 0 0 $ 7 2 0 0 $ 26 4 $ 13 5 0 $ 28 8 6 8. 7 2 % $ 2 5 1 . 5 2 $ 1 0 0 . 0 0 $ 1 0 0 . 0 0 $ 35 1 . 5 2 13 % 30 8 . 6 8 $ 30 8 . 6 8 Wa t e He a t e $ 35 0 0 $ 1 9 8 0 $ 20 2 $ 52 5 $ 28 4 3 11 . 1 % $ 3 2 4 3 1 $ 32 4 3 1 14 % 26 4 . 4 4 $ 26 4 . 4 Wa t e He a t e $ 35 0 0 $ 87 5 $ 20 2 $ 52 5 $ 29 4 8 11 . 4 1 % $ 3 3 6 . 2 9 $ 33 6 . 2 9 14 % 27 4 . 2 1 $ 27 4 . 2 1 Wa t e r H e a t e r s $ 35 0 0 $ 1 1 3 3 0 $ 20 2 $ 52 5 $ 24 9 3 11 . 4 1 % $ 2 8 4 3 9 $ 28 4 3 9 13 % 24 9 . 7 3 $ 24 9 . 7 3 At t c Fa n $ 5 4 0 0 0 $ $ 15 4 $ 81 0 0 $ 6 1 9 4 6 14 . 9 6 % $9 2 6 9 . 6 4 $ 9 2 6 9 . 6 4 14 % 75 5 8 , 4 2 $ 75 5 8 . 2 At t c Fa n $ 5 4 0 0 $ $ 15 4 $ 81 0 0 $ 6 1 9 4 6 14 . 9 6 % $9 2 6 9 . 6 4 $ 9 2 6 9 . 6 4 14 % 75 5 8 , 4 2 $ 75 5 8 , 4 2 Att c F a D S $ 5 4 , 0 0 0 $ $ 15 4 $ 8,1 0 0 $ 6 1 , 9 4 6 14 . 9 6 % $9 , 2 6 9 . 6 4 $ 9 , 2 6 9 . 6 4 13 % 81 3 9 . 8 3 $ 8,1 3 9 . 8 3 Di s p a t c h l b l e G e n e r a t o r s Dis n a t c l ú b l e S t a y G e n e r t o r s E x i s t i n $ 25 0 $ $ 2l $ 38 $ 76 10 . 8 8 % $ 8. 2 8 $ 7. 5 0 $ U3 $ 8. 6 3 $ 16 . 9 1 0. 9 % 2l 3 5 25 7 4 25 6 . 7 2 17 . 8 1 $ 48 5 . 8 8 Dis o a t c l ú b l e S t a y G e e r t o r s E x i s t n . $ 25 0 $ $ 2l $ 38 $ 76 10 . 8 8 % $ 8. 2 8 $ 7. 5 0 $ 1. 3 $ 8, 6 $ 16 . 9 1 0. 9 % 2l 3 5 25 7 4 25 6 . 7 2 17 , 8 1 $ 48 5 . 8 8 Di s n a t c l ú b l e S t a n d b y G e n e r t o r s E x i s t i n $ 25 0 $ $ 21 1 $ 38 $ 76 10 . 8 8 % $ 8. 2 8 $ 7. 5 0 $ 1. 3 $ 8. 6 3 $ 16 . 9 1 0. 9 % 21 U 5 25 7 4 25 6 . 7 2 lU i $ 48 5 . 8 8 Di s o a t c h i b l e S t a d b y G e n e r t o N e w $ 17 5 $ $ 2l $ 26 $ 10 10 , 8 8 % $ UO $ 5. 0 0 $ 0. 7 5 $ 5.7 5 $ 4.6 5 0. 9 % 58 . 1 0 25 7 4 25 6 , 7 2 17 . 8 1 $ 33 2 . 6 3 Di s o a t h i b l e S t a n d b y G e n e r a t o r N e w $ 17 $ $ 2l $ 26 $ 11 0 10 . 8 8 % $ 1 1 . 0 $ 5, 0 0 $ 0. 7 5 $ 5. 5 $ 4,6 5 0. 9 % 58 . 1 0 25 7 4 25 6 . 7 2 17 . 8 1 $ 33 2 . 6 3 Di s a t c h i b l e S t a d b y G e n e r t o r s N e w $ 17 5 $ $ 2l $ 26 $ 10 10 . 8 8 % $ 1. 0 $ 5. 0 0 $ 0. 7 5 $ 5. 7 5 $ 4.6 5 0. 9 % 58 . 1 0 25 7 4 25 6 . 7 2 17 . 8 1 $ 33 2 . 6 3 11 2 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............................................ Paci~Corp - 2008 IR Chapter 6 - Resource Options Resource Option Description Coal Potential coal resources are shown in the supply-side resource options tables as supercritical pul- verized coal boilers (PC) and integrated gasification combined cycles (IGCC) in Utah and Wyo- ming. Costs for large coal-fired boilers, since the 2007 IRP, have risen by approximately 50% to 60% due to many factors involving material shortages, labor shortges, and the risk of fixed price contracting. Additionally the uncertinty of future carbon regulations and a diffculty in obtaining constrction and environmental permits for coal based generation alternatives has en- couraged the Company to postpone the selection of coal as a resource before 2020. Supercritical technology was chosen over subcritical 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 manu- factuers only offer supercritical boilers in the 500-plus megawatt sizes. Due to the increased ef- ficiency of supercritical boilers, overall emission quantities are smaller than for a similarly sized subcritical unit. Compared to subcritical boilers, supercritical boilers caI follow loads better, ramp to full load faster, use less water, and require less steel for constrction. The smaller steel requirements have also leveled the constrction cost estimates for the two coal technologies. The costs for a supercritical pulverized coal facility reflect the cost of adding a new unt at an existing site. PacifiCorp does not expect a significant difference in cost for a multiple unit at a new site versus the cost of a single unit addition at an existing site. Carbon dioxide capture and sequestration technology represents a potential cost for new and ex- isting coal plants if futue regulations require it. Research projects are underway to develop more cost-effective methods of captung carbon dioxide from the flue gas of conventional boilers. The costs included in the supply side resource tables utilize amine based solvent systems for carbon captue. Sequestration would bur the CO2 underground for long-term storage and monitoring. PacifiCorp and its parent Company MEHC are monitoring CO2 captue technologies for possible retrofit opportnities at its existing coal-fired fleet, as well as applicability for futue coal plants that could serve as cost-effective alternatives to IGCC plants if C02 removal becomes necessary in the future. An option to captue C02 at an existing coal-fired unit has been included in the supply side resource tables. Curently there are only a couple of large-scale sequestration pro- jects in operation around the world and a number of these are in conjunction with enhanced oil recovery. Carbon captue and sequestration (CCS) is not considered a viable option before 2025 due to risk issues associated with technological maturity and underground sequestration liability. An alternative to supercritical pulverized-coal technology for coal-based generation would be the use ofIGCC technology. A significant advantage for IGCC when compared to conventional pul- verized coal with amine-based carbon captue is the reduced cost of capturig carbon dioxide from the process. Gasification plants have been built and demonstrated around the world, primar- ilyas a means of producing chemicals from coaL. Only a limited number of IGCC plants have been constrcted specifically for power generation. In the United States, these facilities have been demonstration projects and cost significantly more than conventional coal plants in both 113 PacifiCorp - 2008 IR Chapter 6 - Resource Options capital and operating costs. These projects have been constrcted with significant funding from the federal governent. 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 wiling to provide IGCC plants on a lump-sum, tu-key basis. However, in to- day's market, the wilingness of these consortia to design and constrct IGCC plants on lump- sum tu key basis is in question. The costs presented in the supply-side resource options tables reflect recent studies of IGCC costs associated with efforts to parer PacifiCorp with the Wyo- ming Infrastrctue Authority to investigate the acquisition of federal grnt money to demon- strate western IGCC projects. PacifiCorp was selected by the Wyoming Infrastrctue Authority (WIA) to paricipate in joint project development activities for an IGCC facility in Wyoming. The ultimate goal was to de- velop a Section 4 i 3 project under the 2005 Energy Policy Act. PacifiCorp commissioned and managed feasibility studies with one or more technology suppliers/consortia for an IGCC facility at its Jim Bridger plant with some level of carbon captue. Based on the results of initial feasibil- ity studies, PacifiCorp declined to submit a proposal to the federal agencies involved in the Sec- tion 413 solicitation. PacifiCorp is a member of the Gasification User's Association. In addition, PacifiCorp commu- nicates regularly with the primary gasification technology suppliers, constrctors, and other utili- ties. The results of all these contacts were used to help develop the coal-based generation pro- jects in the supply side resource tables. Over the last two years PacifiCorp has help a series of public meetings as a part of an IGCC Working Group to help provide a broader level of under- standing for this technology. Coal Plant Efficiency Improvements Fuel efficiency gains for existing coal plants (which are manifest in lower plant heat rates) are realized by (1) emphasizing continuous improvement in operations, and (2) upgrading compo- nents if economically justified. Such fuel effciency improvements can result in a smaller emis- sion footprint for a given level of plant capacity, or the same footprint when plant capacity is in- creased. The effciency of generating units degrades gradually as components wear out over time. Durng operation, controllable process parameters are adjusted to optimize unit output and effciency. Typical overhaul work that contrbutes to improved efficiency includes (1) steam tubine over- hauls, (2) cleaning and repairng condensers, feed water heaters, and cooling towers and (3) cleaning boiler heat transfer suraces. When economically justified, efficiency improvements are obtained though major component upgrades. Examples include tubine upgrades using new blade and sealing technology, improved seals and heat exchange elements for boiler air heaters, cooling tower fill upgrdes, and the addi- tion of cooling tower cells. Such upgrade opportities are analyzed on a case by case basis, and it is difficult to plan far in advance since decisions are tied to the existence of commercially- proven technology advancements available durng a plant's next major overhaul cycle. Pacifi- Corp is taking advantage of improved upgrade technology though its "dense pack" coal plant tubine upgrade initiative. This initiative, to be completed by 2016, is factored into the 2008 IRP via a 170 MW coal plant capacity gain without a corresponding increase in fuel consumption, 114 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options heat input, or emissions. Capacity expansion modeling to support the 2008 business plan indi- cated that this upgrade initiative was cost-effective. This resource is included in the curent IRP models as a result. 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 tubines are included. A dr cooled combined cycle has been included. As with other gen- eration technologies, the cost of natual gas generation has increased substantially from previous IRPs. Costs for gas generation have increased by 40% to 70%, depending on the option, due not only to general utility cost issues mentioned earlier, but also due to the decrease in coal-based projects thereby putting an increased demand on natural gas options that can be more easily per- mitted. Combustion turbine options include both simple cycle and combined cycle configutions. The simple cycle options include traditional frame machines as well as aero-derivative combustion tubines. Two aero-derivative machine options were chosen. The General Electrc LM6000 ma- chines are flexible, high effciency machines and can be installed with high temperatue SCR systems, which allow them to be located in areas with air emissions concerns. These tyes of gas tubines are identical to those recently installed at Gadsby and West Valley. LM6000 gas tu- bines have quick-start capability (less than 10 minutes to full load) and higher heating value heat rates near 10,000 BtuWh. Also selected for the supply-side resource options table is General Electrc's new LMS-100 gas tubine. This machine was recently installed for the first time in a commercial ventue. It is a cross between a simple-cycle aero-derivative gas tubine and a frame machine with significant amount of compressor intercooling to improve effciency. The ma- chines have higher heating value heat rates of less than 9,500 BtukWh 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 effciencies. Other natual gas-fired generation options include internal combustion engines and fuel cells. Internal combustion engines are represented by a large power plant consisting of 14 machines at 10.9 megawatts. These machines are spark-ignited and have the advantages of a relatively attac- tive heat rate, a low emissions profie, and a high level of availability and reliability due to the number of machines. At present, fuel cells hold less promise due to high capital cost, partly at- tributable to the lack of production capability and continued development. Fuel cells are not ready for large scale deployment and are not considered available as a supply-side option until after 2013. Combined cycle power plants options have been limited to 1xl and 2xl applications of"F" style combustion tubines and a "G" lxl facility. The "F" style machine options would allow an ex- pansion of the Lake Side facility. Both the lxl and 2xl 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 tubines. 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 natual gas technologies are considered mature and installation lead times and 115 PacifiCorp - 2008 IR Chapter 6 - Resource Options capital costs are well known. The capital cost pressure curently being observed with constrct- ing large coal-based generation plants is also being experienced with natual gas-fired plants. Wind Representation of wind projects was accomplished by developing a set of proxy wind sites com- posed of 100-MW blocks that could be selected as distinct resource options in the System Opti- mizer modeL. (Note that the 100-megawatt size reflects a suitable average size for modeling pur- poses, and does not imply that acquisitions are of this size.) Table 6.11 shows the regions in which wind resources are located and the representative capacity factors and quantity limits available to the System Optimizer model for selection. Note that these are aggregate limits for the entire modeling simulation period. Table 6.11- Proxy Wind Sites and Characteristics Southwest Wyoming 24 29 35 24 29 35 24 29 35 24 29 24 29 35 24 29 24 29 35 24 29 35 24 29 1,400 1,300 1,300 1,400 1,300 1,300 500 500 500 300 300 200 300 300 300 200 700 500 100 100 100 100 200 200 Southwest Wyomig Norteast Wyoming Norteast Wyomig Wyoming (Aeolus substation)Southwest Wyomig Goshen Southeat Idao Walla Walla Southeast Washington Yakma South Centrl Washington West Main Central Oregon Mid-Columbia Southwest Washington Utah Nortern Uta For other wind resource attbutes, the Company used multiple sources to derive attibutes. Capi- tal costs were derived from recent PacifiCorp projects and offers by developers. The EPRI TAG database was also used for certin cost figues, such as operation and maintenance costs. These costs were adjusted for curent market conditions. Wheeling costs, applicable for wind projects cited in the west, and average incremental transmission costs for east-side resources needed be- yond local interconnection and 230 kV step-up were included in the resources as appropriate. 116 ............................................ ............................................. PacifiCorp - 2008 IR Chapter 6 - Resource Options Other Renewable Resources Other renewable generation resources included in the supply-side resource options table include geothermal, biomass, landfill gas, waste heat and solar. The financial attbutes of these renew- able options are based on the TAG database and have been adjusted based on PacifiCorp's recent construction and study experience. Geothermal The geothermal resources in Tables 6.2 and 6.3 represent a dual flash design with a wet cooling tower. The 35 MW values per project are suggested by engineering studies associated with a third unit at the Blundell site using technology similar to the Company's existing geothermal re- sources. The expansion of the Blundell site represents the best cost for geothermal energy cur- rently available to the Company. Speculative risks associated with steam field development, as well as recent escalation in drllng costs, are not captued in the geothermal cost characteriza- tion. The Company chose 100 MW as a reasonable upper bound for geothermal resource additions based on its experience with locating sizable quantities of geothermal generation either under development or suitable for development. Considerations included the Company's current view of realistic commercial resource opportities given issues with project locations (development in sensitive areas and local opposition) and well performance related to temperature and resource adequacy as reported in recent geologic studies. Using the 35-MW representative size for a geo- thermal project yields a total of three geothermal projects as resource options, for a total of 105 MW. The Company has not yet conducted a geothermal commercial potential study looking at long-term prospects for geothermal energy utilizing both Blundell technology and other alterna- tive geothermal technologies. One of the fudamental barrers to geothermal development is the difficulty in characterizing the tye, quality, and conditions ofa particular geothermal re- source. This characterization requires a significant investment for well drllng and testing in or- der to develop a reliable and provable assessment. Biomass and Solar The biomass project would involve the combustion of whole trees that would be grown in a plan- tation setting, presumably in the Pacific Nortwest. Three solar resources were defined. A con- centrating photovoltaic (PV) system represents a utility scale PV resource. Optimistic perform- ance and cost figues were used equivalent to the best reported PV effciencies. Solar thermal projects are represented by both a solar concentrating design (trough system with natual gas backup) and a solar concentrating design (thermal tower arrangement with 6 hours of thermal storage). The system parameters for these systems were suggested by the WorleyParons Group study and reflect current proposed projects in the desert southwest. 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 storage. These technologies convert off-peak capacity to on-peak energy and thereby reduce the quantity of required overall capacity installed for peakng needs. Battery applications are tyi- cally smaller systems (less than i 0 megawatts) that can have the most benefit in a smaller local area. Utility-scale demonstrations are just begining to be conducted. Advanced battery applica- tions are not available for selection in the modeling before 2014. 117 PadfiCorp - 2008 IR Chapter 6 - Resource Options Pumped hydro is dependent 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 specific pumped hydro projects under development and does not consider this a viable resource before 2018 be- cause of the necessary study and permitting issues. Compressed air energy storage (CAES) can be an attctive means of utilizing intermittent en- ergy. In a CAES plant, off-peak energy is used to pressure an underground cavern. The pres- surized air would then feed the power tuine porton of a combustion tubine saving the energy normally used in combustion turbine to compress air. CAES plants operate on a simple cycle ba- sis and therefore displace peaking resources. A CAES plant could be built in conjunction with wind resources to level the production for such an intermittent resource. A CAES plant, whether associated with wind or not, would have to stad on its own for cost-effectiveness. Only two CAES plants have been built in the world. CAES is not considered practical for PacifiCorp until 2015. Combined Heat and Power and Other Distributed Generation Alternatives CHP are a small (ten megawatts or less) gas compressor heat recovery system using a binary cy- cle. These projects would be contracted at the customer site. They are labeled as Recovered En- ergy Generation (CHP) and utilty cogeneration in the supply-side table. A large CHP (40 to 120 megawatts) combustion turbine with significant steam based heat recov- ery from the flue gas has not been included in PacifiCorp's supply side table for the eastern ser- vice terrtory due to a lack of large potential industral applications. These CHP opportities are site-specific, and the generic options presented in the supply-side resource options table are not intended to represent any paricular project or opportity. Small distrbuted generation resources are unque in that they reside at the customer load. The generation can either be used to reduce the customer load, such as net metering, or sold to the utility. Distrbuted standby generation provides peak load reductions over a contracted number of hours from on-site generators owned by the customer but managed by the utility. Small CHP re- sources generate electrcity and utilize waste heat for space and water heating requirements. Fuel is either natual gas or renewable biogas. On-site solar resources, also referred to as "micro so- lar", include electrc generation and energy-effciency measures that use solar energy. The DG resources are up to 4.8 MW in size. Table 6.12 shows the megawatt economic potential for distrbuted standby generation cited in the DSM potential study and the amount of the resource included in the IRP models. Due to the small potential in PacifiCorp' s California, Yaka, Walla Walla, and Idao service terrtories, these resources were excluded as model options. For distrbuted CHP, Tables 6.13 and 6.14 show the economic potential and amounts included in the IRP models, respectively. PacifiCorp used screening thresholds of 5 MW by state and 8 MW by technology to exclude resources from the IRP models. Such screening for small distrbuted generation resources was necessary to accom- modate the large number of other resource options included in the IRP models. The size screen- 118 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options ing eliminated all but the West Main (Oregon and northern California) rooftop photovoltaic sys- tem.30 Table 6.12 - Standby Generation Economic Potential and Modeled Capacity 2009 6.9 9.9 16.8 5.7 9.5 15.2 2010 9.3 14.9 24.2 8.0 14.2 22.2 2011 11.8 19.9 31.6 10.3 18.9 29.2 2012 16.6 24.8 41.14.9 23.6 38.5 2013 21.5 29.8 51.19.4 28.4 47.8 2014 28.8 34.8 63.6 26.3 33.1 59.4 2015 36.1 39.7 75.9 33.1 37.8 71.0 2016 43.5 44.7 88.2 40.0 42.5 82.6 2017 50.8 49.7 100.5 46.9 47.3 94.1 2018 50.8 54.6 105.4 46.9 52.0 98.9 2019 50.8 59.6 110.4 46.9 56.7 103.6 2020 50.8 64.6 115.4 46.9 61.5 108.3 2021 50.8 69.5 120.3 46.9 66.2 113.0 2022 50.8 74.5 125.3 46.9 70.9 117.8 2023 50.8 79.5 130.3 46.9 75.6 122.5 2024 50.8 84.4 135.2 46.9 80.4 127.2 2025 50.8 89.4 140.2 46.9 85.1 132.0 2026 50.8 94.4 145.2 46.9 89.8 136.7 2027 50.8 99.3 150.1 46.9 94.6 141.4 2028 50.8 99.3 150.1 46.9 99.5 146.4 30 As a sensitivity test, the Company allowed its capacity expansion model to select from the entire set of micro- solar resources given the input assumptions from which the 2008 IRP preferred portfolio was derved. The model did not choose any micro-solar resources. This result is due to the higher fixed costs and lower availability relative to small competing resources such as CHP and DSM. 119 Paci~Corp - 200BIR Chapter 6 - Resource Options Table 6.13 - Distributed CHP Economic Potential (MW 2009 0.3 0.0 0,0 0.0 0,4 0,0 0.2 0,0 0.0 Ll 2010 ~,4 0.2 0,1 0.1 1.9 0,1 0.8 0.1 0.0 4.7 2011 3.0 0.4 0.2 0.2 4.1 0.3 1.6 0.2 0.1 ioo 2012 6.2 0,8 0,4 0,4 8.3 0.5 2,9 0.3 0,1 20,0 2013 10.5 L3 0,7 0.7 14.2 0.9 4.3 0,4 0.2 33.2 2014 14,8 1.8 1.0 1.0 20.0 L3 5.9 0.5 0.2 46.5 2015 19.1 2,4 L3 L3 25.8 1.6 7A 0,7 0.3 59.9 2016 23.5 2.9 1.6 1.6 31.6 2,0 9,1 0.8 0.3 73A 2017 27.8 3,4 1.9 1.9 37.5 2,4 10,7 0.9 0.3 86,8 2018 32,1 4.0 2.2 2.2 43.3 2.7 12.3 1.0 0,4 100.2 2019 36,4 4.5 2.5 2.5 49.1 3.1 13.6 i.0,4 113. 2020 40,7 5,0 2.8 2.8 55.0 3,4 14.7 1.2 OA 126,1 2021 45.1 5.6 3.1 3.1 60.8 H 15.7 1.2 0.5 138.8 2022 49,4 6.1 3A 3A 66.6 4.2 16,4 L3 0.5 151.2 2023 53.1 6.5 3.7 3.6 71.6 4.5 17,0 L3 0.5 161.9 2024 56.2 6.9 3,3.8 75,8 4.8 17,6 L3 0.5 170,8 2025 58.0 7,2 4.0 3.9 78.3 4.9 18.0 L3 0.5 176.2 2026 59.9 7.4 4.2 4.1 80,8 5.1 18,4 ~,4 0.5 181.6 2027 61.7 7.6 4.3 4.2 83.3 5.2 18.8 ~,4 0.5 187.1 2028 63.6 7,8 4A 4.3 85.SA 19.2 ~,4 0.5 192,6 Table 6.14 - Distributed CHP Resources Included as IRP Model Options 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 0.3 1.2 2.7 5.4 9.2 13.0 16.8 20.6 24.4 28.2 32.1 35.9 39.7 43.5 46.7 49.4 51. 52.7 54.3 56.0 0.3 1.5 3.2 6.6 11. 15.7 20.3 24.9 29.5 34.1 38.7 43.3 47.8 52.4 56.4 59.6 61.6 63.6 65.5 67.6 0.2 0.7 1.4 2.5 3.7 5.0 6.4 7.9 9.2 10.6 11.8 12.7 13.5 14.2 14.7 15.2 15.5 15.9 16.3 16.6 0.8 3.4 7.2 14.5 24.1 33.8 43.6 53.4 63.2 73.0 82.5 91.8 101.0 110.1 117.8 124.3 128.2 132.2 136.1 140.2 Nuclear An emissions-free nuclear plant has been included in the supply-side resource options table. This option is based recent internal studies, press reports and information from a paper prepared by 120 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options the Uranium Information Centre Ltd., "The Economics of Nuclear Power," May 2008. A 1,600 MW plant is characterized utilizing advanced nuclear plant designs. Nuclear power is not con- sidered a viable option in the PacifiCorp service terrtory before 2025. Resource Options and Attributes Source of Demand-side Management Resource Data Demand-side resource opportity estimates used in the development of the 2008 IRP were de- rived from data provided from the "Assessment of Long-Term, System-Wide Potential for De- mand-Side and Other Supplemental Resources" study completed in June 2007 (DSM potential study). Preliminar results from the DSM potential study were initially incorporated in the 2007 IRP Update. However, these estimates were not modeled under the prescribed supply-curve methodology until the development of the 2008 IRP. The DSM potential study provided a broad estimate of the size, tye, location and cost of demand-side resources. The demand-side resource information was converted into supply-cures by tye of DSM; e.g. capacity-based Classes 1 and 3 DSM and energy-based Class 2 DSM for modeling against competing supply-side alternatives. Demand-side Management Supply Curves Resource supply curves are a compilation of point estimates showing the relationship between the cumulative quantity and costs of resources. Supply cures incorporate a linear relationship between quantities and costs (at least up to the maximum quantity available) to help identify at any parcular cost how much of a particular resource can be acquired. Resource modeling utiliz- ing supply cures allows utilities to sort out and select the least-cost resources (products and quantities) based on each resource's cost versus quantity in comparison against the supply curves of alternative and competing resource tyes. As with supply-side resources, the development of demand-side resource supply cures requires specification of quantity, availability, and cost attbutes. Attbutes specific to demand-side sup- ply curves include: · Resource quantities available in year one-either megawatts or megawatt-hours~ recog- nizing that some resources may come from stock additions not yet built, and that elective resources cannot all be acquired in the first year · Resoure quantities available over time; for example, Class 2 energy-based resource measure lives · Seasonal availabilty and hours available (Class 1 and Class 3 capacity resources) · The shape or hourly contrbution of the resource (load shape of the Class 2 energy re- source) · Levelized resource costs (dollars per megawatt per year for Class 1 and 3 capacity re- sources, or dollars per megawatt-hour for Class 2 energy resources) Once developed, demand-side resource supply cures are treated like any other discrete supply- side resource in the IRP modeling environment. A complicating factor for modeling is that the DSM supply curves must be configued to meet the input specifications for two models: the Sys- 121 PacifiCorp - 2008 IR Chapter 6 - Resource Options tem Optimizer capacity expansion optimization model, and the Planning and Risk production cost simulation modeL. Class 1 DSM Capacity Supply Cures Supply curves were created for four discrete Class 1 DSM products: residential air conditioning load control, irrigation load control, dispatchable commercial curilment, and commercial and industrial thermal energy storage. The potentials and costs for each product were provided at the state level resulting in four products across six states, or twenty-four supply curves before ac- counting for system load areas (some states cover more than one load area). After accounting for load areas, a total of fort Class i DSM supply cures were used in the 2008 IRP modeling proc- ess. The starting point for supply cure development was DSM product information originally used for PacifiCorp's 2007 IRP. This information was fuher refined based on the following: . Updated costs · Customer sureys and acceptace data from the DSM potential study information · Adjustments to DSM potential study results based on amended assumptions · Another years experience delivering Class 1 DSM products · The 2007 IRP modeling results. In developing information on the four products and creation of supply cures, assumption changes (from those used in the DSM potential study) were made to two of the four products. The net potential for irrigation load control in the east was increased, as was the cost, to recog- nize the percentage of customers expected to select a dispatchable control option over a sched- uled firm control option. In a second case, a new Class 1 product was created in order to incorpo- rate the potential from a Class 3 product, commercial curilment, for base resource considera- tion. The product recognizes how the Company intends to pursue, though program design, available commercial control opportities (e.g. leverage controllable commercial loads using customer energy management systems combined with contracts for utility dispatched operation of customer distrbuted standby generators.) The potential and cost of the Class 3 commercial curilment product was used to create the new Class 1 product for three reasons. First, the potential captued in the Class 3 product was as- sumed to come from customer control of end-use equipment, not from any distrbuted standby generation capabilities. Second, the potential for distrbuted standby generation was included in the IRP model as a supply-side resource option. (It is already captured as a model resource). Third, the levelized cost for the Class 3 commercial curailment product is in the same range as the levelized cost for distrbuted standby generation; approximately $50-$60 per kilowatt per year. Other product price differences between west and east control areas were drven by resource dif- ferences in each market, such as irrgation pump sizes, tyes of pumping, and product perform- ance differences (for example, residential air conditioning load control in the west is nearly twice the cost of east-side programs due to climatic differences that lead to less control per installed switch.) Pricing is also impacted by resource opportity differences. The DSM potential study 122 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options assumed the same fixed costs regardless of quantify of a partcular product available. Therefore, the weighted average cost per control area for products with less opportity in a particular state have a higher cost per kilowatt-year for that product. The combination residential air conditioning and electrc water heating dispatchable load control product was not provided to the System Optimizer model as a resource option for either control area. In the west, electrc water heating control wasn't included as it adds little additional load for the cost, and electrc water heating market share continues to decline each year as a result of conversions to gas. In the east, electrc water heating control wasn't included because (1) the market potential is very small. (It is predominantly a gas water heating market), (2) an estab- lished program already exists that doesn't include a water heater control component, and (3) the potential identified is assumed to be located in areas where gas is not available; such as more ru- ral and mountainous areas where direct load control paging signals are less reliable. Tables 6.15 and 6.16 show the summar level Class 1 DSM program information, by control area, used in the development of the Class 1 resources supply cures. As previously noted, each of the products were further broken down by quantity available by state and load area in order to provide the model with location-specific details. Table 6.15 - Class 1 DSM Program Attributes West Control Area Sumer Residential Air Con-Yes, with combo 40, not to June 1 to ditioning AC & water heat-exceed 6 Sept. 15 11 $165 2009 ing hours per da Sumer Irgation (50% dis-40, not to June 1 topatchable and 50%No exceed 6 Sept. 15 20 $50 2009 scheduled firm)hours per da Yes, with C&I Commercial Curtail-Direct Load Con-Sumer ment (combination trol, Thermal En-and winter June 1 to dispatchable product,ergy Storage, de-40,80 Sept. 15 excludes DSG in mand buyback,hours total. and Nov. 1 5 $61 2009 potential but wil critical peak pric-Not to ex-to Feb. 28 include in program to ing, real-time ceed6 (29) design)pricing, and dis-hours per tributed stadby day generation Commercial Thermal Sumer 40 June 1 to 2 $150 2009Energy Storage Sept. 15 These costs are before a credit of $23/KW-year is applied for avoided transmission and distrbution investment costs. 123 Pad~Corp - 2008 IR Chapter 6 - Resource Options Table 6.16 - Class 1 DSM Program Attributes East Control Area Sumer Residential Air Con-Yes, with combo 40, not to Jun i toexceed 6 47 $93 2009ditioningAC&WH hours per Sept. 15 day Irigation Sumer 40, not to(50% dispatchable No exceed 6 June 1 to 45 $57 2009and 50% scheduled hour pe Sept. 15 firm)day Yes, with C&I Commercial Curail-Direct Load Con-Sumer ment (combination trol, Thermal En-and winter June 1 to dispatchable product,ergy Storage, de-40,80 Sept. 15 excludes DSG in mand buyback,hour total. and Nov. 1 38 $59 2009 potential but wil critical peak pric-Not to ex-to Feb. 28 include in program to ing, real-time ceed6 (29) design)pricing, and dis-hour per trbuted stadby day eneration Commercial Thermal Sumer 40 June 1 to 7 $153 2009Energy Storage Sept. 15 These costs are before a credit of $23/KW-year is applied for avoided transmission and distrbution investment costs. To configure the supply cures for use in the System Optimizer model, there are a number of data conversions and resource attbutes that are required by the System Optimizer modeL. All programs are defined to operate within a 5x8 hourly window and are priced in $/kW-month. A credit of $23/kW -year for avoided transmission and distrbution investment costs is also applied against the COSt,31 The following are the primar model attbutes required by the model: · The Capacity Planing Factor (CPF): This is the percentage of the program size (capacity) that is expected to be available at the time of system peak. For Class 1 and 3 DSM programs, this parameter is set to 1 (100 percent). · Additional reserves: This parameter indicates whether additional reserves are required for the resource. Firm resources, such as dispatchable load control, do not require additional re- serves. · Daily and annual energy limits: These parameters, expressed in gigawatt-hours, are used to implement hourly limits on the programs. They are obtained by multiplying the hour avail- able by the program size. 31 The Nortwest Power and Conservation Council (NCC) and the Energy Trust of Oregon (ETO) use this value for their DSM avoided cost calculations. 124 ............................................ ............................................ Paci~Corp - 2008 IR Chapter 6 - Resource Options . Nameplate capacity (MW) and service life (years) . Maximum Anual Units: This parameter, specified as a pointer to a vector of values, indi- cates the maximum number of resource units available in the year for which the resource is designated. . First year and month available/last year available . Fractional Units First Year: This parameter tells the model the first year in which a fractional quantity of the resource (as opposed to an integer quantity) can be selected. Year 2008 is en- tered in order to make these DSM resource options fractionally available in all years. After the model has selected DSM resources, a program converts the resource attbutes and quantities into a data format suitable for direct import into the Planning and Risk modeL. Class 3 DSM Capacity Supply Curves This DSM resource tye consists of 50 distinct supply cures, reflecting a combination of prod- ucts, states, and load areas. The Class 3 DSM programs modeled include the following: . Residential time-of-use rates (Res RTP) . Residential critical peak pricing (CPP) . Commercial and industral critical peak pricing (C&I CPP) . Commercial and industrial real-time pricing (C&I RTP) . Commercial and industrial demand buyback (C&I DBB) In providing the data for the constrction of Class 3 DSM supply curves, the Company did not net-out one product's resource potential against a competing product. As Class 3 DSM resource selections are not included as base resources for planning puroses, not taking product interac- tions into consideration poised no risk of over-reliance (or double counting the potential) of these resources in the final resource plan. For instance, in the development of the supply cures for residential time-of-use the program's market potential was not adjusted by the market potential or quantity available of a lesser-cost alternative, residential critical peak pricing. Market potentials and costs for each of the five Class 3 DSM programs modeled were taken from the estimates provided in the DSM potential study and evaluated independently as if it were the only resource available targeting a particular customer segment. Product price differences between west and east control areas were drven by resource opport- nity differences. The DSM potential study assumed the same fixed costs in each state in which it is offered regardless of quantify available. Therefore, states with lower resource availabilty for a paricular product have a higher cost per kilowatt-year for that product. Tables 6. i 7 and 6.18 show the summar level Class 3 DSM program information, by control area, used in the development of the Class 3 resources supply curves. As previously noted, each of the products were further broken down by quantify available by state and load bubble in order to provide the model with location specific information. 125 PacifiCorp - 2008 IR Chapter 6 - Resource Options Table 6.17 - Class 3 DSM Program Attributes West Control area Yes, with Res CPP andRes A/CDLC Yes, with Res TOU and Res Sumer 40 June 1- Sept.A/CDLC 15 Yes, with C&I Sumer and Commercial and In- RTP, DBB and winter 40, dustral CPP commercial 80 hours curilment total Yes, with C&I Sumer and Commercial and In- CPP, DBB and winter 40,dustral RTP C&I curail- 80 hourment tota Yes, with C&I Sumer and Commercial and In- CPP and RTP winter 25, dustral DBB and C&I cur- 50 hour talment tota Feb. 28 29 These costs are before a credit of $23/kW-year is applied for avoided transmission and distrbution investment costs. Residential TOU $173N/A Year around 20098 Residential CPP $91 200922 $339 2009 $8 20091 $18 200910 Table 6.18 - Class 3 DSM Program Attributes East Control area Yes, with Res CPP andRes A1CDLC Yes, with Res TOU and Res Sumer 40 June 1- Sept.A1CDLC 15 Yes, with C&I Sumer and Commercial and In- RTP, DBB and winter 40, dustral CPP commercial 80 hour curailment total Yes, with C&I Sumer and Commercial and In- CPP, DBB and winter 40,dustrial RTP C&I curil- 80 hourment total Yes, with C&I Sumer and Commercial and In- CPP and RTP winter 25,dustral DBB and C&I cur- 50 hour talment tota Feb. 28 29 These costs are before a credit of $23/kW-year is applied for avoided trsmission and distrbution investment costs. Residential TOU N/A $166 2009Year around 11 Residential CPP $88 200930 $12 200961 $6 200914 $18 200927 System Optimizer data formats and parameters for Class 3 DSM programs are similar to. those defined for the Class 1 DSM programs. The data export program converts the Class 3 DSM pro- grams selected by the model into a data format for import into the Planning and Risk modeL. 126 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options Class 2 DSM, Capacity Supply Curves The 2008 IRP represents the first time the Company has utilized the supply cure methodology in the evaluation and selection of Class 2 DSM energy products. The DSM potential study pro- vided the information to fully assess the contrbution of Class 2 DSM resources over IRP plan- ning horizons. Class 2 DSM resource data was provided by state down to the individual measure and facility levels; e.g., specific appliances, motors, air compressors for residential buildings, small offices, etc. In all, the DSM potential study provided Class 2 DSM resource information at the following granularity: · State: Washington, California, Idaho, Utah, Wyoming . Measure: Sixty-two residential measures Seventy-eight commercial measures Thirteen industral measures Three irrgation measures . Facilty type: Six residential facilty tyes Twenty four commercial facility tyes Twenty eight industral facility tyes Two irrgation facilty tyes The DSM potential study also provided total resource costs, which included both measure cost and a 15 percent adder for administrative costs levelized over measure life at PacifiCorp' s cost of capital, consistent with the treatment of supply-side resource costs. The technical potential for all Class 2 DSM resources across five states over the twenty-year DSM potential study horizon totaled 9.9 milion MWh. The technical potential represents the total universe of possible savings before adjustments for what is cost-effective to pursue (eco- nomic), likely to be realized (achievable), and impacts of emerging codes and standards such as the 2007 Energy Policy Act, whose impact full wasn't known at the time the DSM potential study was completed. Despite the granularity of Class 2 DSM resource information available, it was impractical to use this much information in the development of Class 2 DSM resource supply curves. The combina- tion of measures by facility tye and state resulted in 12,500 distinct measures that could be modeled using the supply curve methodology.32 This many supply curves is impossible to han- dle with PacifiCorp's IRP models. To reduce the resource options for consideration, while not losing the overall resource quantity available, the decision was made to consolidate like meas- 32 Not all energy efficiency measures analyzed are applicable to all market segments. The two most common reasons for this are (l) differences in existing and new constrction and (2) some end-uses do not exist in all building tyes. For example, a measure may look at the savings associated with increasing an existing home's insulation up to cur- rent code levels. However, this level of insulation would already be required in new constrction, and thus, would not be analyzed for the new constrction segment. Similarly, certain measures, such as those affecting commercial refrigeration would not be applicable to all commercial building tyes, depending on the building's primary business fuction; for example, offce buildings would not tyically have commercial refrigeration. 127 PacifiCorp - 2008 IR Chapter 6 - Resource Options ures (by weighted-average load shapes and lives) and costs of sets of measures into bundles to reduce the number of combinations to a more manageable number. The bundles were developed based on Class 2 DSM potential study technical potentials (all eco- nomic screens were removed). The achievable assumption was adjusted from that estimated in the DSM potential study to eighty-five percent of the technical potential to account for the prac- tical limits on acquiring all resources in all years. The assumption is consistent with regional planning assumptions in the Northwest. Five cost bundles, across five states, over twenty years equates to 500 supply cures before allocating across the Company load areas shown in Table 6.19. Table 6.19 - Load Area Energy Distribution by State CA OR ID 42%58% UT 100% WA WY 18% 100%4% 96% 25% 75% 82% After the load areas are accounted for (with some states served in more than one load area as noted in table 6.20), the number of supply cures grew to 800, excluding Oregon. Table 6.20 shows the Class 2 DSM cost bundles used in the 2008 IRP and the associated bundle price. The bundle price can be interpreted as the marginal levelized cost for the group of meas- ures. These prices, adjusted for the $23/kW-year trnsmission/distrbution investment deferral benefit, represent the Class 2 DSM price inputs for the IRP models. Table 6.20 - Class 2 DSM Cost Bundles and Bundle Prices Cost Bundle 1 Cost Bundle 2 Cost Bundle 3 Cost Bundle 4 Cost Bundle 5 Cost Bundle 6 $O.Ol/kWh to $0.07/kWh $0.07/kWh to $0.09/kWh $0.09/kWh to $O.ll/kWh $O.l1/kWh to $O.13/kWh $O.13/kWh to $0. 15/kWh $0. 15/kWh to $0. 18/kWh $70 $90 $110 $130 $150 $180 Class 2 DSM resources in Oregon are acquired on behalf of the Company through Energy Trust of Oregon programs. To avoid duplicative potential assessment efforts the scope of PacifiCorp' s DSM potential study excluded the analysis and evaluation of Class 2 resource potentials in Ore- gon. As a result, the Company relied on resource potential information provided by the Energy Trust of Oregon. The ETO economically screened their Oregon Class 2 DSM supply cures by using values compiled from regional and utility-specific valuation data. 128 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options The ETO provided the Company one cost bundle, weighted and shaped by the end-use measure potential for each year over a twenty-year horizon. Allocating these resources over two load ar- eas in Oregon for consistency with other modeling efforts generated an additional 40 Class 2 supply curves (one cost bundle multiplied by two load areas multiplied by twenty years). Table 6.2 i shows the peak megawatt capacity represented by the supply curves for each state. Table 6.21 - Class 2 DSM Supply Curve Capacities by State 47 143 472 1,718 255 290 2,916 In addition to the program attbutes described for the Class I and 3 DSM resources, the Class 2 DSM supply curves also have load shapes describing the available energy savings on an hourly basis. For System Optimizer, each supply cure is associated with an annual hourly ("8760") load shape configued to the 2008 calendar year. These load shapes are used by the model for each simulation year. In contrast, the Planning and Risk model requires for each supply curve a load shape that covers all 20 years of the simulation. The load shape is composed of fractional values that represent each hour's demand divided by the maximum demand in any hour for that shape. For example, the hour with maximum demand would have a value of 1.00 (100%), while an hour with half the maximum demand would have a value of 0.50 (50%). Summing the fractional values for all of the hours, and then multiplying this result by peak-hour demand, produces the annual energy savings represented by the supply curve. Figure 6.2 shows the Utah load shape for a representative day: July 22, 2008. 129 Paci~Corp - 200BIR Chapter 6 - Resource Options Figure 6.2 - Utah Load Shape Utah Load Shape for July 22, 2008 1.2 1 ~~¡;~ ~ 0.8 ~\= .~ ~ 0.6 /,..~= ,g~ 0.4 /..¡~I.. ì0.2 I0 1 2 3 4 5 6 7 8 9 10 ii 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour While the Energy Gateway Transmission project was treated as part of the base topology for the IRP models, PacifiCorp included three transmission options that the System Optimizer could se- lect. These options were recommended by PacifiCorp' s Transmission Department as additional potential investments to supplement the Gateway project. The first option was an incremental addition to the Energy Gateway West project. This expansion option consisted of a 750 MW ca- pacity increase from Path C in Idaho/nortern Uta to the West Main load area, representing Oregon and northern California. This option was available beginning in 2015. The other two op- tions, not associated with the Energy Gateway project, consisted of incremental 200 MW and 400 MW capacities for a Walla Walla to West Main transmission project available beginning in 2014. Resource Option Selection Criteria PacifiCorp and other utilities engage in purchases and sales of electrcity on an ongoing basis to balance the system and maximize the economic effciency of power system operations. In addi- tion to reflecting spot market purchase activity and existing long-term purchase contracts in the IRP portfolio analysis, PacifiCorp modeled front office transactions (FOT). Front offce transac- tions are proxy resources, assumed to be firm, that represent procurement activity made on an anual forward basis to help the Company cover short positions. Table 6.22 shows the front of- fice transaction resources included in the IRP models. Note that the Table distinguishes FOT re- source assumptions made in February 2009 to support additional portfolio analysis based on ter- 130 ............................................ ............................................. PacifiCorp - 2008 IR Chapter 6 - Resource Options mination of the 2012 Lake Side II CCCT constrction contract. East-side FOT assumption changes were prompted by additional transmission availability from Mona to Utah for which the Company recently became aware. Table 6.22 - Maximum Available Front Offce Transaction Quantity by Market Hub Mid-Columbia 3rd Quarer Heavy Load Hour or Flat Anual 400 2009-2028 California Oregon Border 3rd Quarer Heavy Load Hour or Flat Anual 400 2009-2028(COB West Main 3rd Quarter Heavy Load Hour 50 2009-2028 Mead 3rd Quarer Heavy Load Hour 600 2017-2028 Mona 3rd Quarter Heavy Load Hour 200 2009-2028 Utah 3rd Quarter Heavy Load Hour 50 2009-2028 3rd Quaer Heavy Load Hour 3rd Quaer Heavy Load Hour 5792/2013 Mid-Columbia 3rd Qurter Heavy Load Hour or Flat Anual 400 2009-2012 2012-2013Mid-Columbia 3rd Quaer Heavy Load Hour or Flat Anual Mid-Columbia 3rd Quarter Heavy Load Hour or Flat Anual 2014-2028400 1/ Supported by completion of reactive compensation installation at Camp Wiliams substation in Utah, and antici- pated 300 MW of additional firm transmission from Mead to NU provided by Nevada Power. 2/ Supported by completion of the Mona to Oquirh transmission line by the end of2012, and anticipated 300 MW of additional firm transmission from Mead to NUB provided by Nevada Power. To arrve 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 de- livery 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. 131 Paci~Corp - i0081R Chapter 6 - Resource Options The temporary increase in Mid-Columbia FOT market depth, from 400 MW to 775 MW in both 2012 and 2013, is accompanied by an assumed.10 percent price premium. PacifiCorp examined the recent Mid-Columbia transaction history for forward third-quarter heavy load hour (HLH) products to support this short-term increase.33 For example, according to the Intercontinental Exchange (ICE), 2008 transaction volumes reached 3,725 MW for third- quarter HLH products delivered in 2009. Resource Options and Attributes Two front offce transaction tyes were included for portolio analysis: an annual flat product, and a HLH 3rd quarer product. An annual flat product reflects energy provided to PacifiCorp at a constant delivery rate over all the hours of a year. Third-quarter HLH transactions represent pur- chases received 16 hours per day, 6 days per week from July through September. Because these products are assumed to be firm for this IRP, the capacity contrbution of front offce trnsac- tions is grossed up for puroses of meeting the planning reserve margin. For example, a 100 MW front offce transaction is treated as a 112 MW contrbution to meeting PacifiCorp's load obliga- tion plus a 12 percent planning reserve margin, with the sellng counterpar holding the reserves necessar to make the product firm. Prices for front offce transaction purchases are associated with specific market hubs and are set to the relevant forward market prices, time period, and location, plus appropriate wheeling charges. For this IRP, the Public Utility Commission of Oregon directed PacifiCorp to evaluate interme- diate-term market purchases as resource options and assess associated costs and risks.34 In for- mulating market purchase options for the IRP models, the Company lacked cost and quantity in- formation with which to discriminate such purchases from the proxy FOT resources already modeled in this IRP. Lacking such information, the Company anticipated using bid information from the 2008 All-Source RFP, if applicable, to inform the development of intermediate-term market purchase resources for modeling puroses. The Company received no intermediate-term market purchase bids; therefore, such resources were not modeled for this IRP. Resource Description As proxy resources, front offce transactions represent a range of purchase transaction tyes. They are usually standard products, such as HLH, LLH, and/or daily HLH call options (the right to buy or "call" energy at a "strke" price) and tyically rely on standard enabling agreements as a contracting vehicle. Front office transaction prices are determined at the time of the transaction, usually via a third part broker and based on the view of each respective part regarding the then-curent forward market price for power. An optimal mix of these purchases would include a range in terms for these transactions. 33 HLH is the daily time block, hour-ending 7 am - 10 pm, for Monday though Satuday, excluding NERC- observed holidays. 34 Public Utility Commission of Oregon, In the Matter of PacifiC om, dba Pacific Power 2007 Integrated Resource Plan, Docket No. LC 42, Order No. 08-232, Apnl4, 2008, p. 36. 132 ............................................ ............................................ PacifiCorp - 2008 IR Chapter 6 - Resource Options 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 durng quarers and can be available from one to three years or more in advance. The terms, points of delivery, and products wil all vary by individual mar- ket point. 133 ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach 7. MODELING AND PORTFOLIO EVALUATION APPROACH The IRP modeling effort seeks to determine the comparative cost, risk, and reliability attbutes of resource portfolios. These portfolio attbutes form the basis of an overall quantitative portfo- lio performance evaluation. This chapter describes the modeling and risk analysis process that supported portfolio pedormance evaluation. The information drawn from this process, summa- rized in Chapter 8, was used to help determine PacifiCorp's preferred portfolio and support the analysis of near-term resource acquisition risks. The 2008 IRP modeling effort consists of seven phases: (1) define input scenarios-referred to as cases~characterized by alternative carbon dioxide costs, commodity gas prices, wholesale electricity prices, load growth trends, and other cost drvers, (2) case-specific price forecast de- velopment, (3) optimized portfolio development for each case using PacifiCorp's System Opti- mizer capacity expansion model, (4) Monte Carlo production cost simulation of each optimized portfolio to support stochastic risk analysis, (5) selection of top-pedorming portfolios using a composite ranking scheme that incorporates stochastic portfolio cost and risk assessment meas- ures, (6) deterministic risk analysis using the System Optimizer, and (7) preferred portfolio se- lection, followed by acquisition risk analysis of preferred portfolio resources. Figue 7.1 presents the seven phases in flow chart form, showing the main process steps, data flows, and models in- volved for each phase. General modeling assumptions and price inputs are covered first in this chapter, followed by a profile of each modeling phase. Figure 7.1 - Modeling and Risk Analysis Process ........................................................................... I Phase I: Case Definition ¡ i ::=:=~=.==.I~:.~~=~::=::= . Phase 2: Pnee Forecast Development .............................................................., Phase 3: Optimized PortolioDevelopment Phas 5: Top:performingPortolio Selecton ._..___.._.._._.._.._._...__..J ~..~~..~...~~.:::...~...~..........~.......:l.~..~....~'.~~'.~'.'.~'.':.'.~.'.~~~'.'.: i Phase 4: Monte Carlo I .... c'" ~."'. i ¡: \..:::::::::::::::~:::::::::I:::::::::::::::::::::::::::~ Phase 6: Deterministic RiskAssessment ~...~..:.....~.~..~~..:..::..::::...~.I....~:.....~..~..~~'.~:.~.'''.'.~''':.'.~~ ¡ Phase 7: Preferred Portolio ¡¡ Selecon I Aciiuisitin Risk ¡¡ Anarysis ¡I I\..............................................................135 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Study Period and Date Conventions PacifiCorp executes its IRP models for a 20-year period beginning January 1,2009 and ending December 31, 2028. Futue IRP resources reflected in model simulations are given an in-service date of January 1st of a given year. The System Optimizer model requires in-service dates desig- nated as the first day of a given month, while the Planning and Risk production cost simulation model allows any date. Escalation Rates and Other Financial Parameters Inflation Rates Integrated resource planning model simulations and price forecasts reflect PacifiCorp's corporate inflation rate schedule unless otherwise noted. For the System Optimizer model, a single escala- tion rate value is used. This value, 1.9 percent, is estimated as the average of the annual corpo- rate inflation rates for the period 2009 to 2030, using PacifiCorp's June 2008 inflation cure. For the Planning and Risk model, the full series of anual values from 2009 though 2028 is used. Discount Factor The rate used for discounting in financial calculations is PacifiCorp's after-tax weighted average cost of capital (W ACC). The value used for the 2008 IRP is 7.4 percent. The use of the after-tax WACC complies with the Public Utility Commission of Oregon's IRP guideline la, which re- quires that the after-tax WACC be used to discount all futue resource costS.35 Federal and State Renewable Resource Tax Incentives In October 2008, the U.S. Congress provided a one-year extension of the renewable Production Tax Credit (PTC) through December 31,2009. In Februar 2009, Congress granted another ex- tension through December 31, 2012. The curent tax credit of $21/MWh, which applies to the first 10 years of commercial operation, is converted to a levelized net present value and added to the resource capital cost for entr into the System Optimizer modeL. The renewable PTe, or an equivalent federal financial incentive, is assumed to be available for all years in the study period. The Emergency Economic Stabilization Act of 2008 (P.L. i 10-343) allows utilities to claim the 30-percent investment tax credit for solar facilties placed in service by January 1,2017. This tax credit is factored into the capital cost for solar resource options in the System Optimizer modeL. A number of state incentive programs are also included into the renewable resource capital costs for eligible facilities. These programs include the following · Utah - The curent production tax credit for wind, geothermal, and solar facilities located in Utah is $3.5/MWh over 4 years. There is no sunset provision for this tax credit. · Oregon - Oregon's Business Energy Tax Credit (BETC) provides for an investment tax credit of 50 percent of qualifying costs for projects sited in Oregon up to $20 millon for a to- tal credit of $10 milion. Projects receive up to $2 milion per year over 5 years. Qualifying 35 Public Utilty Commission of Oregon, Order No. 07-002, Docket No. UM 1056, Januar 8, 2007. 136 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio £valuation Approach projects include wind, solar, hydro, geothermal, and biomass. Projects are on a first come first served basis up to the Oregon's annual allocated dollars of tax benefits. There is no sun- set provision for this credit, but the cap is likely to change from time to time. . Idaho - 3% Investment Tax Credit (ITC) provision on tangible personal propert. Credit is available to all constrction projects and not unique to renewable projects. Asset Lives Table 7.1 lists the generation resource asset book lives assumed for levelized fixed charge calcu- lations. Table 7.1- Resource Book Lives Frame 40 20 40 50 35 40 20 30 30 30 30 30 25 25 25 30 30 20 40 20 20 15 10 15 15 25 15 10 20 30 15 ClI 137 PadfiCorp - 2008 iRP Chapter 7 - Modeling and Portolio Evaluation Approach Transmission System Representation PacifiCorp uses a transmission topology consisting of 19 bubbles (geographical areas) in its Eastern Control Area and 10 bubbles in its Western Control Area designed to best describe major load and generation centers, regional transmission congestion impacts, importexport availability, and external market dynamics. Firm transmission paths lin the bubbles. The transfer capabilities for these links represent PacifiCorp Merchant fuction's curent firm rights on the transmission lineso This topology is defined for both the System Optimizer and Planing and Risk models, and was also used for IRP modeling support for PacifiCorp's 2009 business plan. Figure 7.2 shows the IRP transmission system model topology. Segments of the planned Energy Gateway Transmission Project are indicated with red dashed lines. Figure 7.2 - Transmission System Model Topology , Load .. Generation . Purchase/Sale Markets _ Contractsxchanges "" "" .. Owed Transmision on PacifCorp 0 , + .. Planned Energy Gateway TransmiŠon '" ...~ Chehalis CCCT Transmision° . Link adde in FBbiy 209 10 imprve tetati of th Chehalis CCCT resourc includ in the West Main bubble. The most significant change to the model topology from the one used for the 2007 IRP Update is the expansion of the single Wyoming bubble into three bubbles: Wyoming Southwest, Wyoming Northeast, and Aeolus (substation). This disaggregation supports a more refined view of poten- 138 ............................................ ............................................ PacißCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approch tial Wyoming resource siting in consideration of transmission constraints~represented as the TOT 4A cut plane-as well as the addition of the planned Aeolus substation that supports En- ergy Gateway Transmission expansion. The other major change to the model topology is the addition of the Hermiston bubble in the Western Control Area, which supports the representation of the Walla Walla to McNar segment of the Gateway project. In February 2009, additional changes were made to the system topology to improve representa- tion of long-term transmission rights for the Chehalis, Washington combined-cycle plant in- cluded in the West Main bubble. One of the changes involved the addition of a uni-directional path from the West Main to Yakima bubble. This path addition is shown as a blue dashed line in Figure 7.2. Additionally, the Energy Gateway segment C path (uni-directional, Mona to Oquirrh) was added to facilitate additional market transfer capability from the Mona bubble to Utah South. The first phase of the IRP modeling process was to define the cases (input scenarios) that the System Optimizer model uses to derive optimal resource expansion plans. The cases consist of variations in inputs representing the predominant sources of portfolio cost variability and uncer- tainty. PacifiCorp generally specified low, medium, and high values to ensure that a reasonably wide range in potential outcomes is captured. PacifiCorp defined two types of cases: core cases and sensitivity cases. Core cases focus on broad comparability of portfolio performance results for thee key variables. These variables in- clude (1) the level of a per-ton carbon dioxide tax, (2) natual gas and wholesale electrcity prices based on PacifiCorp's forward price cures and adjusted as necessar to reflect CO2 tax impacts, and (3) retail load growth. The Company developed 29 core cases based on a combination of in- put variable levels. In contrast, sensitivity cases focus on changes to resource-specific assumptions, alternative C02/renewable energy regulatory policies, and planning assumptions. The resulting portfolios from the sensitivity cases are tyically compared to one of the core case portfolios. PacifiCorp developed 17 sensitivity cases reflecting alternative C02 compliance strategies, clean base load technology availability, an alternative planning reserve margin level, and inclusion of price- responsive demand-side management programs (Class 3 DSM) as resource options. Also in- cluded in the sensitivity case group are two "reference" cases reflecting the 2009 business plan resources for 2009 through 2018, resulting in a total of 19 sensitivity cases. In developing these cases, PacifiCorp kept to a target range in terms of the total number (40 to 50) in light of the data processing and model ru-time requirements involved. To keep the num- ber of cases within this range, PacifiCorp excluded some core cases with improbable combina- tions of certain input levels, such as a $100 C02 tax and high load growth. (With a high C02 tax, a significant amount of demand reduction is expected to occur in the form of conservation, en- ergy effciency improvements, and utility load control programs.) 139 PacifiCorp - 2008 iRP Chapter 7 - Modeling and Portolio Evaluaton Approach PacifiCorp also relied heavily on feedback from public stakeholders. The Company assembled and refined an initial set of cases durng April through June 2008, and held three public meetings durng May and June to solicit recommendations on their design. The focus of comments was on the number of cases that should be modeled and the appropriateness of the CO2 tax levels se- lected. Additional case modifications took place from July through November, reflecting addi- tional stakeholder feedback and input assumption updates made to support the 2009 business plan. For example, PacifiCorp augmented the cases dermed with the June 2008 forward price curves as the base forecast with additional ones that used the October price curves. This expan- sion of cases reflected the desire to account in the IR analysis the rapid and large price de- creases experienced durng the last half of 2008. Case Specifcations Tables 7.2 and 7.3 profile the core and sensitivity!business plan case specifications, respectively. Descriptions of the case variables and explanatory remarks on specific cases follow the tables. 140 ............................................ .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f C o r p - 2 0 0 8 I R P Ch a p t e r 7 - M o d e l i n g a n d P o r t f o l i o E v a l u a t i o n A p p r o a c h Ta b l e 7 . 2 - C o r e C a s e D e f i n i t i o n s Co r e C a s e s 1 C0 2 ta x $0 Lo w Ju n - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 2 C0 2 t a x $0 Me d i u m Ju n - 0 8 Me d i u m Ba s e i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 3 C0 2 t a $0 Hi l ! h Ju n - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 4 C0 2 t a $4 5 Lo w Ju n - 0 8 Lo w Ba s e i f n e e d e d Ba s Ba s e 12 % Ex c l u d e d 5 C0 2 t a $4 5 Lo w Ju n - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 6 CO 2 ta $4 5 Lo w Ju n - 0 8 Hi i i h Ba s e i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 7 C0 2 ta x $4 5 Me d i u m Ju n - 0 8 Lo w Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 8 C0 2 ta x $4 5 Me d i u m Ju n - 0 8 Me d i u m Ba s e . i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 9 C0 2 t a x $4 5 Lo w Oc t - 0 8 Me d i u m Ba s e . i f n e e d e d Ba s e Ba s 12 % Ex c l u d e d 10 C0 2 t a x $4 5 Me d i u m Oc t - 0 8 Me d i u m Ba s e . i f ne e d e d Ba s e Ba s e 12 % Ex c l u d e d 11 C0 2 t a $4 5 Hi e h Oc t - 0 8 Me d i u m Ba s e i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 12 C0 2 t a $4 5 Me d i u m Ju n - 0 8 Hi i i h Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 13 C0 2 t a $4 5 Hi i i Ju n - 0 8 Lo w Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 14 C0 2 t a $4 5 Hi i i Ju n - 0 8 Me d i u m Ba s e i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 15 CO 2 ta $4 5 Hi i i Ju n - 0 8 Hi i i h Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 16 C0 2 t a x $7 0 Me d i u m Ju n - 0 8 Lo w Ba s , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 17 C0 2 ta $7 0 Me d i u m Ju n - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 18 CO 2 ta $7 0 Lo w Oc t - 0 8 Me d i u m Ba s e . i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 19 C0 2 ta $7 0 Me d i u m Oc t - 0 8 Me d i u m Ba s e . i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 20 C0 2 t a $7 0 Hi l ! h Oc t - 0 8 Me d i u m Ba s e i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 21 C0 2 t a $7 0 Hi l ! h Ju n - 0 8 Lo w Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 22 C0 2 t a $7 0 Hi i i h Ju n - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 23 C0 2 ta $1 0 0 Me d i u m Ju n - 0 8 Lo w Ba s e . i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 24 C0 2 ta $1 0 0 Me d i u m Ju n - 0 8 Me d i u m Ba s e . i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 25 C0 2 t a $1 0 0 Lo w Oc t - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s 12 % Ex c l u d e d 26 C0 2 ta $1 0 0 Me d i u m Oc t - 0 8 Me d i u m Ba s e . i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 27 C0 2 ta x $1 0 0 Hi l ! h Oc t - 0 8 Me d i u m Ba s e i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 28 C0 2 t a $1 0 0 Hi e h Ju n - 0 8 Lo w Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 29 C0 2 t a $1 0 0 Hi g h Ju n - 0 8 Me d i u m Ba s e , i f n e e d e d Ba s e Ba s e 12 % Ex c l u d e d 14 1 Pa c i f ì C o r p - 2 0 0 8 I R P Ch a p t e r 7 - M o d e l i n g a n d P o r t f o l i o E v a l u a t i o n A p p r o a c h Ta b l e 7 . 3 - S e n s i t i v i t y a n d B u s i n e s s P l a n R e f e r e n c e C a s e D e f i n i t i o n s 30 Me d i u m Ex c l u d e Hig h Ex c l u d e d Na t i o n a l C 0 2 C a p - a n d - T r a d e P o D c y : L i e b e r m n - W a r n e r " C l i m a t e S e c u r i t y A c t o f 2 0 0 1 " ( S B 3 0 3 6 , I n t r o d u c e d M a y 2 0 , 2 0 0 1 ) 32 I C a p - a n d - T r a d e I 1M I Me d i u m I O c i - 0 8 I Me d i u m I Ba s e I Ba s I Ba s I 12 % I Ex c l u d e d Hi g b - C o s t O u t c o m e 33 I C0 2 t a I $1 0 0 I Hì ì I J u n - 0 8 I Il ì ì I Ba s e I Lì I N i 12 % I Ex c l u d d Cle a n B a s e L o a d G e n e r a t i o n A v a U a b i l 1 t 34 C0 2 t a 54 5 Me d i u m Ju n - 0 8 Me d i u m Ba e G' Ba 12 % Ex c l u d e d 35 C0 2 t a 54 5 Hi . h Ju n - 0 8 Me d i u m Ba s Ba s 12 % Ex c l u d d 36 C0 2 t a $7 0 Me d i u m Ju n - O I Me d i u m Ba s Eü i r Ba s 12 % Ex c l u d e d 37 C0 2 t a $7 0 Hi . h Ju n - 0 8 Me d i u m Ba FJ l h t , Ba s 12 % Ex c l u d e d Hi g b P l a n t C o n s t r u c t i o n C o s t s 38 C0 2 t a 54 5 Me d i u m Ju n - 0 8 Me d i u m Ba s e Ex c l u d e d 39 C0 2 t a $4 5 Hi Ju n - 0 8 Me d i u m Ba s e Ex c l u d e d Or e g o n C 0 2 R e d u c t i o n T a r g e t s ( f r o m H B 3 5 4 3 ) A p p l i e d a s S y s t e m - w i d e H a r d C a p s 40 ii y ¡ ' ¥ ì â Ç j ì ì ì i H N/A I Me d i u m I J u n - 0 8 I Me d i u m I Ba s e I Ba s I Ba I 12 % I Ex c l u d e d Alt e r n a t i v e P l a n n i n g R e s e r v e M a r g i n L e v e l ( 1 5 % ) CO 2 t a 54 5 Me d i u m Ju n - 0 8 Me d i u m Ba s e Ba s Ba s e Ex c l u d e d C0 2 t a $7 0 Me d i u m Ju n - 0 8 Me d i u m Ba s e Ba s Ba s Ex c l u d e d C0 2 t a $1 0 0 Me d u m Ju n - 0 8 Me d i u m Ba s e Ba s e Ba s Ex c l u d e d $8 a l l o w a c e p r c e Me d i u m Oc l - 0 8 Me d i u m Hig h Ex c l u d e d $8 a l l o w a c e r i c e Me d i u m Oc l - 0 8 Me d i u m Ba s l P T C e x i r s Ex c l u d e d Bu s i n e s s P l a n R e f e r e n c e C a s e 46 I C a p - a n d - T r a e I $ 8 a l l o w a c e p r c e I Me d i u m I O c l - 0 8 I Me d i u m Ba s e I Ba s e I 12 % I Ex c l u d e d -- C a p - a n d - T r a e I $8 a l l o w a c e p r i c e 1 Me d i u m I O c l - 0 8 I Me d i u m Ba s e I Ba s e I 12 % I Ex c l u d e d Cl a s s 3 D S M F o r P e a k L o a d R e d u c t i o n 48 I C0 2 i" " I $4 5 I Me d i u m I J u n - 0 8 I Me d i u m I Ba s e I Ba s e I Ba s e I 12 % 14 2 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Carbon Dioxide Compliance Strategy and Costs Given that no single CO2 reduction compliance approach has emerged as a consistent front- ruer for adoption, the long-term planning effort undertaken through this IRP considers a wide range of carbon cost outcomes that are assessed as a direct tax on emissions (each short ton of C02 emitted). As mentioned above, a CO2 tax is modeled for all the core cases. The CO2 tax has an assumed 2013 implementation date, and increases at PacifiCorp's assumed inflation rate. The tax is treated as a variable cost in both the System Optimizer and PaR models. In System Optimizer, the tax is accounted for in both resource investment decisions as well as the model dispatch solution. For the PaR model, the tax is accounted for in the model's unit commit- ment/dispatch solution. The core cases have been specified with four tax levels: no tax, $45/ton, $70/ton, and $100/ton. The $0 tax serves to create reference portfolios from which the incremental cost of CO2 regula- tions can be determined. The $45 tax represents a reasonable intermediate value and starting point at which significant changes in resource mix over the long term can be expected to occur. This value-along with the $70 value-are also in line with the Electrc Power Research Insti- tute's finding that for its reference CO2 price impact modeling case for western electricity mar- kets, "...it takes a CO2 price of roughly $50/ton to flatten the growth of emissions over time, and closer to $70/ton to effect a significant reduction over time.,,36 The $100 tax then reflects a rea- sonable high-end value associated with an aggressive Federal emission reduction policy. For sensitivity cases 30 and 31, PacifiCorp developed a CO2 tax trajectory with a real cost esca- lation, and also assumed that the associated demand response would result in a lower load growth trend beginning in 2021. The CO2 tax values for these cases are shown in Table 7.4. Table 7.4 - C02 Tax Values 2013 49.44 $76.91 $109.87 45.00 2014 50.33 $78.29 $11 1.84 52.86 2015 51.29 $79.78 $113.97 60.71 2016 52.31 $81.37 $116.25 68.57 2017 53.36 $83.00 $118.57 76.43 2018 54.43 $84.66 $120.95 84.29 2019 55.51 $86.36 $123.36 92.14 2020 56.62 $88.08 $125.83 100.00 2021 57.70 $89.76 $128.22 107.86 2022 58.80 $91.46 $130.66 115.71 2023 59.91 $93.20 $133.14 123.57 2024 61.05 $94.97 $135.67 131.43 2025 62.15 $96.68 $138.11 139.29 2026 63.27 $98.42 $140.60 147.14 2027 64.47 $100.29 $143.27 155.00 2028 65.70 $102.19 $145.99 162.86 36 Electric Power Research Institue, Slide Presentation, Collaborative EPRI Analysis of CO2 Price Impacts on Western Power Markets, page 18, June 2008. 143 PadfiCorp - 20081RP Chapter 7 - Modeling and Portolio Evaluaton Approach For sensitivity case 32, The CO2 costs are in the form of allowance market prices resulting from implementation of a federal cap-and-trade program such as the Lieberman-Warner Climate Secu- rity Act of 2008. (This proposed legislation specified a final CO2 emissions target of 71 percent below 2005 levels in 2050.) Due to the complexity of developing the inputs for this sensitivity case, PacifiCorp did not have time to perform this analysis before this IRP was prepared. Pacifi- Corp wil make the results available to IRP stakeholders once the study has been completed. Sensitivity case 40 assumes that PacifiCorp is subject to a system-wide hard CO2 cap. A hard cap is a physical emission limit that canot be exceeded, and is typically expressed as a declining anual value. This sensitivity case is intended to support the following Public Utility Commis- sion of Oregon's 2007 IRP acknowledgment order requirement: For the 2007 IRP update and next planning cycle, develop a scenario to meet the CO2 emissions reduction goals in Oregon HB 3543, including development of a compliant portfolio that meets the Commission's best cost/risk standard.37 Oregon's HB 3543 targets are to achieve greenhouse gas emission levels 10 percent below 1990 levels by 2020, and by 2050, achieve reductions of a least 75 percent below 1990 levels. With a 2012 emissions base of 56.1 milion tons, these targets translate into 41.4 milion tons by 2020 and 33.4 milion tons by 2028. Because PacifiCorp plans on a system basis, and its IRP models are not curently capable of representing Oregon-only emission constraints in the context of such system planning, Oregon's hard cap is applied on a system leveL. The CO2 compliance strategy and cost assumptions for sensitivity cases 46 and 47 reflect those used for PacifiCorp's 2009 business plan, which is based on a Federal cap-and-trade compliance mechanism. Cap-and-trade assumptions include the following: · Emissions peaking in 2012 (56.1 milion tons) and declining to 2007 emission levels (56.5 milion tons by 2025), assuming stright-line annual decreases for modeling pur- poses · Straight-line anual emissions decreasing to 1990 levels by 2030 · An initial CO2 allowance price of $8.79/ton starting in 2013 (in 2008 dollars), and in- creasing at PacifiCorp's annual inflation rates . No auctioning or bankng of allowances 37 Public Utility Commission of Oregon, Order No. 08-232, Docket LC 42, April 24, 2008, p. 36. 144 ............................................ ............................................ Paci~Corp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Table 7.5 - CO2 Prices for the Business Plan Reference Cases 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 8.79 8.95 9.12 9.30 9.49 9.68 9.87 10.07 10.26 10.45 10.65 10.85 11.05 11.25 11.46 11.68 Natural Gas and Electricity Prices Due to the strong correlation between natual gas and wholesale electrcity prices, these variables were linked together as low, medium, or high values for a case. Two sets of gas/electrcity price scenario values were used for defining cases. The June 2008 forward price cures served as the initial base forecast for IRP modeling support for the 2009 business plan and development of IRP scenario price cures reflecting CO2 price responses. Due to the large decline in gas prices following the spring/summer spike, PacifiCorp adopted the October 2008 forward price cures for the final business plan modeling, and incorporated these forecasts as additional cases in the IRP (cases 9, 10, 1 I, 18, 19,20,25,26, and 27). The price forecasting methodology and resulting scenario price forecasts are presented later in this chapter. Retail Load Growth The low and high load growt forecasts reflect a respective one-percentage-point average annual growth rate decrease and increase relative to the growt rate for the medium (l-in-2) forecast. For cases 30 and 31, PacifiCorp combined the medium forecast for 2009 to 2020, and the low forecast for 202 I to 2028, using a smoothing algorithm to determine the data elements around the breakpoint. Figures 7.3 and 7.4 show the annual peak load and energy forecast values used for the case definitions. 145 PacifCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Figure 7.3 - Peak Load Growth Scenarios i 13,000 2008 IRP - Peak Loads 18,000 17,000 16,000 15,000 14,000 12,000 11,000 10,000 9,000 ~Medium -mHigh -oMed-Low ~Low 8,000 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Figure 7.4 - Energy Load Growth Scenarios i 80,000,000 2008 IRP - Annual Energy (MW) 110,000,000 100,000,000 90,00,000 70,000,000 60,000,000 ~Medium -mHigh -oMed-Low ~Low 50,000,000 200920102011 201220132014201520162017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 146 ............................................ .............................................. PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio E.valuaton Approach Renewable Portfolio Standards In addition to the base renewable portfolio standards modeled, sensitivity case 44 tests a scenario for which the renewable generation requirement is higher, reflecting imposition of a Federal standard or more aggressive state standards. (Modeling of renewable portfolio standards is dis- cussed in the section on optimized portfolio development.) For the high RPS generation requirement, PacifiCorp assumed that the curent Revised Protocol under the Multi-state Process remains in place, requiring the Company to acquire suffcient sys- tem resources to meet Oregon's cost allocation share based on their RPS targets. This assump- tion translates into a 25-percent RPS generation requirement with respect to the forecasted sys- tem load by 2026. Renewables Production Tax Credit Expiration Sensitivity case 45 is intended to study how the loss of the PTC affects the timing and magnitude of renewable resource additions. For this sensitivity, the renewables PTC is assumed to fully ex- pire in 2013. Clean Base Load Plant Availabilty Sensitivity cases 34 through 37 evaluate whether clean base load plants-IGCC and new/existing pulverized coal plant retrofits with carbon captue and sequestration-are cost-effective enough to build as early as 2020 given the $45/ton and $70/ton CO2 tax levels and variation in gas prices. The assumed earliest availability for these plants is 2025. High Plant Construction Costs Sensitivity cases 38 and 39 are intended to determine the resource selection impact of increasing capital costs for all resources by 20 percent above their base values under medium and high gas price conditions. Capital-intensive resources wil be disadvantaged under this assumption, so these sensitivities test the extent that such resources are deferred or eliminated from portfolios despite higher gas prices. Capacity Planning Reserve Margin Cases 41 42, and 43 are intended for development of portfolios built to meet or exceed a 15- percent capacity planning reserve margin. The resulting portfolios are compared with their coun- terpar portfolios built to a 12-percent planning reserve margin (cases 8, 17, and 24). These com- parisons are intended to determine the resource mix impact of higher C02 tax levels. Business Plan Reference Cases Cases 46 and 47 represent portfolios that have the major 2009 business plan resources fixed in the modeL. They were optimized with business plan assumptions, including the $8/ton cap-and- trade program assumptions and October 2008 price forecasts. System Optimizer was allowed to select DSM and distrbuted generation resources up to 2018, and allowed to select any resource from 2019 onward subject to the annual quantity constraints outlined in Chapter 6. (Business plan resources only cover the period 2009 through 2018.) The difference between the two cases is that the renewable resources were fixed in case 46 for 2009-20 I 8-reflecting the wind acquisi- 147 Paci~Corp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach tion schedule determined by PacifiCorp's wind development team for the business plan38- whereas for case 47, the model was allowed to optimize the amount and timing of renewables subject to the annual quantity constraints. Class 3 Demand-side Management Programs for Peak Load Reductions For sensitivity case 48, System Optimizer is allowed to select price-responsive DSM programs. These programs, outlined in Chapter 6, include real-time pricing (for commercial and industral customers), demand buyback, curailment, and critical peak pricing. On a central tendency basis, commodity markets tend to respond to the evolution of supply and demand fudamentals over time. Due to a complex web of cross-commodity interactions, price movements in response to supply and demand fudamentals for one commodity can have impli- cations for the supply and demand dynamics and price of other commodities. This interaction routinely occurs in markets common to the electrc sector as evidenced by a strong positive cor- relation between natual gas prices and electrcity prices. Some relationships among commodity prices have a long historical record that have been studied extensively, and consequently, are often forecasted to persist with reasonable confidence. How- ever, robust forecasting techniques are required to captue the effects of secondar or even terti- ary conditions that have historically supported such cross-commodity relationships. For exam- ple, the strong correlation between natul. gas prices and electrcity prices is intrnsically tied to the increased use of natul gas-fired capacity to produce electrcity. If for some reason in the future natual gas-fired capacity diminishes in favor of an alternative technology, the linkage be- tween gas prices and electrcity prices would almost certinly weaken. PacifiCorp deploys a variety of forecasting tools and methods to captue cross-commodity inter- actions when projecting prices for those markets most critical to this IRP - natual gas prices, electrcity prices, and emission prices. Figue 7.5 depicts a simplified representation of the framework used by PacifiCorp to develop the price forecasts for these different commodities. At the highest level, the commodity price forecast approach begins at a global scale with an assess- ment of natual gas market fundamentals. This global assessment of the natual gas market yields a price forecast that feeds into a national model where the influence of emission and renewable energy policies is captued. Finally, outcomes from the national model feed into a regional model where the up-stream gas prices and emission prices drve a forecast of wholesale electrc- ity prices. In this fashion, we are able to produce an internlly consistent set of price forecasts across a range of potential futue outcomes at the pricing points that interface with PacifiCorp' s system. 38 This wind acquisition schedule reflects an assessment of RPS requirements, capital budget impacts, curent and prospective commercial opportities, transmission constraints and expansion considerations (i.e., the Energy Gate- way Transmission Project), operational and system integration issues, locational diversity, state procurement rules, and the MERe renewables acquisition commitment. 148 ......................................1...... ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Figure 7.5 - Modeling Framework for Commodity Price Forecasts The process begins with an assessment of global gas market fundamentals and an associated forecast of North American natual gas prices. In this step, PacifiCorp relies upon a number of third-part proprietary data and forecasting services to establish a range of gas price scenarios. Each price scenaro reflects a specific view of how the North American natural gas market wil balance supply and demand. Given the emergence of liquefied natual gas (LNG) in the global marketplace, the linkage of global gas prices to global oil prices, and the potential need for LNG imports to balance supply with domestic demand, any price forecast for the Nort American market requires a view of global fudamentals. Once a natual gas price forecast is established, the integrated planing model (IPMcI) is used to simulate the entire North American power system. IPMcI, a linear program, determines the least cost means of meeting electrc energy and capacity requirements over time, and in its quest to lower costs, ensures that all assumed emission policies and renewable portfolio standard (RPS) policies are met. Concurently, IPMcI can be configured with a dynamic natual gas price supply cure that allows natual gas prices to respond to changes in demand trggered by environmental compliance. Additional outputs from IPMcI include a forecast of resource additions consistent 149 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach with all specified RPS targets, electrc energy and capacity prices, coal prices, electrc sector fuel consumption, and emission prices for policies administered in a cap-and-trade framework. Once emission prices and the associated gas price response are forecasted with IPMQY, results are used in a regional model named Midas, to produce an accompanying wholesales electrcity price forecast. Midas is an hourly chronological dispatch model confgued to simulate the Western Interconnection and offers a more refined representation of western wholesale electrcity markets than is possible with IPMQY. Consequently, we are able to produce a more granular price projec- tion that covers all of the markets required for the PacifiCorp system models used in the IRP. The gas, wholesale electricity, and emission price forecasts developed under this framework and used in the cases for this IRP are summarized in the sections that follow. Gas and Electricity Price Forecasts A total of five underlying natual gas price forecasts are used to develop the 28 unique gas price projections for the cases analyzed in this IRP. A range of fudamental assumptions affecting how the North American market wil balance supply and demand defines the five underlying price forecasts. Table 7.6 shows representative prices at the Henr Hub benchmark for the five underlying natual gas price forecasts. The five forecasts serve as a point of reference and are adjusted to account for changes in natul gas demand drven by a range of environmental policy and technology assumptions specific to each IRP case. Table 7.6 - Underlying Henry Hub Price Forecast Summary (nominal $/MMBtu) Hi h - June 2008 $18.06 $18.71 $21.21 $23.28 $25.55 Hi h - October 2008 $11.7 $14.68 $19.98 $21.93 $24.07 Medium - June 2008 $11.23 $9.90 $12.31 $13.51 $14.83 Medium - October 2008 $7.83 $8.58 $11.07 $12.85 $14.11 Low - June 200839 $5.83 $6.29 $7.09 $7.78 $8.54 Price Projections Tied to the High June 2008 Forecast The underlying June 2008 high gas price forecast is defined by high oil prices and low LNG im- port, reduced production from matue natual gas fields, disappointments in new production from frontier gas fields, and policies that hold back new coal and nuclear additions, which sup- ports electrc sector natual gas demand despite high prices. Figue 7.6 sumarzes prices at the Henr Hub benchmark and Figure 7.7 summarizes the accompanying electrcity prices for the forecasts developed around the high June 2008 gas price projection. 39 This underlying forecast serves as the reference case for development of the "low - October 2008" price forecast scenaro. 150 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Figure 7.6 - Henry Hub Natural Gas Prices from the High June 2008 Underlying Forecast $32 $30 $28 $26 $24 $22 $20 S $18 ~ $16 ~ $14 $12 $10 $8 $6 $4 $2 $0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 _ High - June 2008 Range -- Case 3 -6 Case 35 .. Case 39 '. Case 33 -- Case 31 .. Cases 13-15 -- Cases 21-22, 37 Figure 7.7 - Western Electricity Prices from the High June 2008 Underlying Gas Price Forecast $300 $275 $250 $225 $200 $175.c ~ $150 ." $125 $100 $75 $50 $25 $0 200 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 _ High - June 2008 Range -- Case 3 -6 Case 35 .. Case 39 . Case 33 --Case 31 Note: Western electrcity pnces are presented as the average of flat prices at Mid-Columbia and Palo Verde. .. Cases 13-15 -- Cases 21-22, 37 151 ~~~Bf9.R July 24, 2009 Errata, 2008 Integrated Resource Plan Page 152-153, Chapter 7, Figure 7.8 and 7.9: These figures were corrected in response to a Oregon PUC data request. They reflect a change on how Case 27 ($100 C02 price) is represented in the char. The graph originally showed an $8/ton C02 value when it should have been $100/ton C02 values. The case was modeled correctly. Figure 7.8 (Revised) - Henry Hub Natural Gas Prices from the High October 2008 Underlying Forecast --..~~~/ S32 S30 S28 S26 S24 S22 S20 =' S18æ :i S16 ~ S14 S12 S10 S8 S6 S4 S2 so 200 2010 2011 2012201320142015201620172018201920202021 2022202320242025202620272028 2029 2~-l 1- High - October 2008 Range -- Case 27 -- Case 11 -+ Case 20 I ~~~r-N'" ~ '"..uiç' ;0rn('rn~ :'1"o 1 ~~~Bgi.R July 24, 2009 Figure 7.9 (Revised) - Western Electricity Prices from the High October 2008 Underlying Gas Price Forecast $300 $275 $250 $225 $200 $175 .i ~ $150 "" $125 $100 $75 $50 $25 $0 200 20102011 20122013 2014 2015 2016 2017 2018 2019 2020 2021 202220232024202520262027202820292030 1- High - October 2008 Range -- Case 27 -- Case 11 -+ Case 20 I Page 156, Chapter 7, Figure 7.13: Corrected caption is "Western Electricity Prices from the Medium Jæ October 2008 Underlying Gas Price Forecast" . Page 245, Chapter 8, Table 8.44: Correction to resource name "DSM, Class 2, Washington Walla Walla". This correction also applies to other detailed portfolio tables supplied in the IR (Appendix A). Page 261-266, Appendix E, Tables E.1 to E.6: These tables included incorrect values for the November 2008 Load Forecast. The entire appendix is provided below with corrected tables and updates to corresponding percentage values cited in the text.""=~c-c=i .1"\. ;;rn("m :i:x \D..c..r c. 2 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Figure 7.10 - Henry Hub Natural Gas Prices from the Medium June 2008 Underlying Forecast $32 $30 $28 $26 $24 $22 $20 ii $18= ~ $16 ~ $14 $12 $10 $8 $6 $4 $2 $0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 _ Medium - June 2008 Range -- Case 40 -6 Cases 7-8, 12 .. Cases 34, 41, 48 . Cases 23-24, 43 -l Case 30 --Case 2 --Case 38 Figure 7.11- Western Electricity Prices from the Medium June 2008 Underlying Gas Price Forecast $300 $275 $250 $225 $200 $175.. ~ $150 $125 $100 $75 $50 $25 $0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 :i020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 _ Medium. June 2008 Range -- Case 40 -6 Cases 7-8, 12 .. Cases 34, 41, 48 . Cases 23-24, 43 -l Case 30 Note: Western electricity prices are presented as the average of flat prices at Mid-Columbia and Palo Verde. ..Case2 --Case 38 154 ............................................ ............................................. Paci~Corp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Price Projections Tied to the Medium October 2008 Forecast As with the high price forecasts, a second underlying medium gas price forecast was added in October 2008 in response to economic developments. In this second medium price forecast, the market portion of the cure is replaced with forwards as of market close on October 20, 2008. The longer-term forecast is slightly lower than the June 2008 medium forecast, which reflects a lower long-term oil price outlook and a more optimistic view of new supply out of Alaska. Fig- ure 7.12 shows Henr Hub benchmark prices and Figue 7.13 includes the accompanying elec- trcity prices for the forecasts developed around the medium October 2008 gas price projection. Figure 7.12 - Henry Hub Natural Gas Prices from the Medium October 2008 Underlying Forecast $32 $30 $28 $26 $24 $22 $20 = $18 I ::: $12 $10 $8 $6 $4 $2 $0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 1- Medium - October 2008 Range -- Cases 44-47 -- Case 10 -6 Case 19 -- Case 261 155 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach a:~er Figure 7.13 - Western Electricity Prices from the Medium,~2008 Underlying Gas Price Forecast $300 $275 $250 $225 $200 $175.. ~ $150.. $125 $100 $75 $50 $25 $0 20092010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20252026 2027 2028 20292030 1- Medium - October 2008 Range -- Cases 44-47 -- Case 10 -- Case 19 -- Case 261 Note: Western electricity prices are presented as the average of flat prices at Mid-Columbia and Palo Verde. Price Projections Tied to the Low June 2008 Forecast The underlying June 2008 low gas price forecast is defined by low oil prices and an extended period of growth from unconventional natural gas fields. Though this period of growth in un- conventional production, it is assumed that knowledge transfer and technological advancements keep production costs on the decline. Concurently, global LNG projects continue to come online while Asian markets experience growth in pipeline gas from China and India. Conse- quently, despite strong domestic growth from unconventional gas fields, LNG imports are di- verted to the North American market. On the demand front, recent gas price spikes steer new power plant development away from gas-fired capacity, thereby keeping demand from the elec- trc sector at bay. Given that the low price forecast is already defined by suppressed demand and an optimistic outlook for low cost supply, a second low price forecast was not added in Oc- tober 2008. Figue 7.14 shows Henr Hub benchmark prices and Figue 7.15 includes the ac- companying electrcity prices for the forecasts developed around the low June 2008 gas price projection. 156 ............................................ ............................................ PacifìCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Figure 7.14 - Henry Hub Natural Gas Prices from the Low June 2008 Underlying Forecast $32 $30 $28 $26 $24 $22 $20 = $18 ~ $16 ~ $14 $12 $10 $8 $6 $4 $2 $0 200 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 la Low - June 2008 Range -- Case 1 .. Cases 4-6 -. Case 9 -I Case 18 -- Case 251 Figure 7.15 - Western Electricity Prices from the Low June 2008 Underlying Gas Price Forecast $300 $275 $250 $225 5200 $175 ..~$150~ 5125 5100 $75 $50 $25 $0 2009 2010 2011 2012 201320142015201620172018201920202021202220232024 2025 2026 2027 2028 2029 2030 la Low - June 2008 Range -- Case 1 .. Cases 4-6 -. Case 9 -I Case 18 -- Case 251 'Western electricity prices are presented as the average of flat prices at Mid-Columbia and Palo Verde. 157 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Emission Price Forecasts As events unfolded in 2008, it became increasingly clear that policy uncertainty is not reserved only for greenhouse gas emissions. In Februar 2008, the D.C. Circuit Cour of Appeals vacated the Clean Air Mercury Rule (CAMR) on the grounds that it was ilegal for the Environmental Protection Agency (EPA) to de-list mercur as a hazardous pollutat. With this ruling, it became evident that a CAMR-based trading program for mercur allowances would not be implemented, and consequently, mercur allowance price forecasts are not studied in this IRP. Nonetheless, across all cases evaluated, it is assumed that all coal-fired supply side resource options are outfit- ted with activated carbon injection control technologies. (All fossil fuel plants are assigned a mercur emission rate, and mercur emissions for each portfolio are reported in Chapter 8.) As with mercur, events in 2008 also introduced increased uncertainty to the sulfu dioxide (S02) allowance market. In July 2008, the D.C. Circuit Cour of Appeals vacated the Clean Air Interstate Rule (CAIR) citing several fatal flaws and remanded it back to EPA with direction to promulgate a new rule. Once CAIR was vacated, the value of existing S02 allowances, which could be used for futue CAIR compliance needs, dropped overnight and prices fell precipi- tously. The market continued to fuction, albeit at light trading volumes and at prices detached from long-term fudamentals. EPA petitioned the court for rehearng in September 2008, and the cour asked petitioners from the case to fie briefs stating their opinion on EPA's request. In December 2008, the cour re- versed its previous finding and remanded the rule back to EPA without vacating the rule in its entirety. In its December decision, the cour explained that its vacatur would sacrifice clear benefits to public health and the environment while EPA fixes the rue. While the latest cour ruling reinstates CAIR, it only does so until EPA can promulgate a new rule that addresses the problems identified in the original finding or until legislative action is taken. Consequently, prices for existing S02 allowance prices remain below the likely cost of future compliance. Given the tremendous uncertainty in the S02 allowance market and considering that curent prices have departed from a fudamentals-view of futue compliance costs, two sets of reference S02 allowance price forecasts were developed for this IRP. The two reference S02 allowance price forecasts are adjusted in response to the specific variables for any given case in much the same way that the underlying gas price forecasts are adjusted. As case variables are changed, IPM~ is used to produce an associated S02 allowance price response, which in tu is used to make adjustments to the appropriate reference price forecasts. Table 7.7 summarzes S02 allow- ance prices developed for the two reference forecasts. Table 7.7 - Reference SOi Allowance Price Forecast Summary (nominal $/ton) June 2008 Au st 2008 $205 $157 $940 $247 $1,204 $271 $333 $206 $616 $232 The June 2008 reference forecast reflects a combination of market forwards and a fudamentals- based price forecast. The market portion of the forecast extends through 2012 and reflects for- wards as of June 20, 2008. Prices from 2013 through 2015 are derived as a gradual transition 158 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach from the market forwards to the subsequent fudamentals-based forecast, which is applied start- ing in 2016. The fundamentals-based forecast is indicative of future compliance costs tied to the marginal cost of installng scrubbers on enough units to achieve the emission reduction targets established under CAIR. Figue 7.16 shows SOi allowance prices for the forecasts developed around the June 2008 reference price projection. Figure 7.16 -S02 Allowance Prices Developed off of the June 2008 Reference Forecast $2,500 $2,250 $2,000 $1,750 $1,500 = ~ $1,250li $1,000 $750 $500 $250 $0 200920102011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 202220232024202520262027202820292030 _June 2008 Range -I Case 39 -Case 40 -eCase38 Cases 28-29 --Case 1 -. Case 3 -I Cases 13-15 -'Cases 21-22, 37 ,""-Case 33 Case 2 Cases 7-8,12 -'Cases 16-17,36,42 + Cases 23-24, 43 -. Case 10 -I Case 19 --Cases 4-6 -'Case 35 "'Case31 £1 Cases 34, 41, 48 -Case 30 --Case 26 The August 2008 reference SOi allowance price forecast is based almost entirely upon market forwards as of August 7, 2008. The market is used for prices though 2021 and escalated at in- flation thereafter. Under this reference price forecast, it is assumed that the uncertinties plagu- ing the SOi allowance market wil continue into the foreseeable futue. Figue 7. i 7 shows SOi allowance prices for the forecasts developed around the August 2008 reference price projection. 159 PadfiCorp - 2008 IRP Chapter 7 - Modeling and Portolio E.valuaton Approch Figure 7.17 - S02 Allowance Prices Developed off of the August 2008 Reference Forecast $2,500 $2,250 $2,000 $1,750 $1,500 c ~ $1,250.. $1,000 $750 $500 $250 $0 200920102011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 _ August 2008 Range -- Case 27 --Cases 44-47 Case 9 ..Case 11 DCase 18 --Case 20 --Case2S For Phase 3, the System Optimizer is executed for each set of case assumptions, generating an optimized investment plan and associated real levelized present value of revenue requirements (PVRR) for 2009 though 2028. System Optimizer operates by minimizing for each year the op- erating costs for existing resources subject to system load balance, reliability and other con- straints. Over the 20-year study period, it also optimizes resource additions subject to resource investment and capacity constrints (monthly peak loads plus a planning reserve margin for each load area represented in the model). To accomplish these optimization objectives, the model performs a time-of-day least-cost dis- patch for existing and potential planed generation, contrct, demand-side management, and transmission resources. The dispatch is based on a representative-week method. Time-of-day hourly blocks are simulated according to a user-specified day-tye pattern representing an entire week. Each month is represented by one week, with results scaled to the number of days in the month and then the number of months in the year. The dispatch also determines optimal electrc- ity flows between zones and includes spot market tractions for system balancing. The model minimizes the overall PVR consisting of the net present value of contract and spot market pur- chase costs, generation costs (fuel, fixed and variable operation and maintenance, unserved en- ergy, and unet capacity), and amortized capital costs for planed resources. 160 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach For capital cost derivation, System Optimizer uses annual capital recovery factors to address end-effects issues associated with capital-intensive investments of different durations and in- service dates. PacifiCorp used the real-levelized capital costs produced by the System Optimizer for portfolio cost reporting by the PaR modeL. Representation and Modeling of Renewable Portfolio Standards PacifiCorp incorporates anual system-wide renewable generation constraints in the System Optimizer model to ensure that each optimized portfolio meets state Renewable Portolio Stan- dard (RPS) requirements.4o For the base case RPS requirement, curent Oregon, Utah, Washing- ton, and California rules are followed. The resulting system generation requirement, using the state end-use energy forecasts as the starting point, reaches two percent of system load for 2011- 2014, five percent for 2015-2019, six percent for 2020-2024, and 15 percent for 2025-2028. A key assumption backing the system-wide RPS representation is that all of PacifiCorp's state ju- risdictions wil adopt renewable energy credit (REC) trading rules through the Multi-state Proc- ess, thus enabling sales and purchase of surlus banked RECs. RPS modeling is conducted as a two-step process. First, for each case the System Optimizer gen- erates a portfolio without any RPS constraints applied. Determining whether the portfolio meets the RPS constraints is an off-line exercise utilizing a spreadsheet accounting modeL. The main components of the model include for each applicable state (1) the annual RPS requirement, (2) the annual generation from qualifying existing renewable facilities and resources selected by the System Optimizer, and (3) tracking of annual cumulative surplus REC bank balances. The quali- fying generation for the all states, divided by the system load, represents the RPS compliance percentage. If this compliance percentage falls short of the generation requirement for a given year, available surlus banked RECs are applied. A portfolio is RPS-compliant if the RPS com- pliance percentage exceeds the RPS generation requirement for all years. For step two, if the portfolio is not RPS-compliant then PacifiCorp re-ru the System Optimizer model with the anual RPS constraints tued on. To the extent the RPS requirement is not met, the model wil add eligible resources to ensure compliance. Comparison of the costs for the RPS non-compliant and compliant portfolios indicates the incremental cost of RPS compliance with additional renewable resources.41 For each case, an RPS compliance report was generated. This report shows the annual system RPS requirements, REC bank balances, REC-adjusted qualifying generation, RPS compliance percentages, and the system load used in the calculations. The report also includes a line chart comparing the RPS compliance and system generation requirements percentages for both the base and high RPS scenarios. The RPS compliance reports are included in Appendix A. Modeling Front Office Transactions and Growth Resources Front offce transactions, described in Chapter 6, are assumed to be transacted on a one-year ba- sis, and are represented as available in each year of the study. For capacity optimization model- 40 The model curently is designed to treat RPS constraints as a generation percentage of system load. PacifiCorp is working with the model vendor on enhancements that enable representation of load-based RPS requirements for multiple jursdictions.41 This two-step approach is intended to address a Uta commssion 2007 IR acknowledgment order requirement. 161 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio E.valuaton Approach ing, System Optimizer engages in market purchase acquisition-both front offce trnsactions, and for hourly energy balancing, spot market purchases-to the extent it is economic given other available resources. The model can select virtally any quantity of FOT generation up to limits imposed for each case, in any study year, independently of choices in other years. However, once a front office transaction resource is selected, it is treated as a must-ru resource for the duration of the transaction period. For this IRP, front offce transactions are available for all years in the study period. (In contrast, front offce trnsactions were only modeled through 2018 in the 2007 IRP, after which the model could select only growt resources to meet load growth.) The front office transactions modeled in the Planing and Risk Module generally have the same characteristics as those modeled in the System Optimizer, except that transaction prices reflect wholesale forward electrc market prices that are "shocked" according to a stochastic modeling process prior to simulation execution. Another resource tye included in the IRP models is the growth resource. This resource is in- tended for capacity balancing in each load area to ensure that capacity reserve margins are met in the out years of each simulation (after 2020). The System Optimizer model can select an annual flat or third-quarter heavy load hour energy pattern priced at forward market prices appropriate for each load area. Growt resources are similar to front office transactions, except that they are not transacted at market hubs. Modeling Wind Resources Wind resources are modeled with an hourly generation shape that reflects average hourly wind variability. The shapes are scaled to capacity factors reflecting representative wind resource qualities across PacifiCorp's system. (See Chapter 6 for more details on wind resource options.) The hourly generation shape is repeated for each year of the simulation, and is used in both the System Optimizer and Planing and Risk models. Because System Optimizer is not a detailed chronological unit commitment and dispatch model, the cost impacts of wind tied to unit commitment are not captued. Also, system costs and reli- ability effects associated with intra-hour wind varabilty are not captued. To capture the costs of integrating wind into the system, PacifiCorp applied a value of $1 L.75/MWh (in 2008 dollars) for portfolio modeling. The source of this value was Portland General Electrc Company's wind integrtion study, which assumed penetration of over 1,000 MW of wind capacity with no addition of supporting flexible thermal resources. This value was selected as a reasonable proxy to use until PacifiCorp's own wind integration cost study is com- pleted. To reflect realistic system resource addition limits tied to transmission availability and other fac- tors such as resource market availability and procurement constraints, System Optimizer was constrained to select up to 500 MW per year of wind prior to 2014, and 750 MW per year in 2014 and thereafter. 162 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Modeling Fossil Fuel Efficiency Improvements For all IRP modeling, PacifiCorp used forward-looking heat rates for existing fossil fuel plants, which account for plant efficiency improvement plans. Previously the Company used four-year historical average heat rates. This change ensures that such planned improvements are factored in the optimized portfolios and stochastic production cost simulations, in line with the goals of the PURP A fossil fuel generation effciency standad that is par of the 2005 Energy Policy Act. Phase 4 entails simulation of each optimized portfolios from Phase 3 using the Planning and Risk model in stochastics mode. The PaR simulation produces a dispatch solution that accounts for chronological commitment and dispatch constraints. Three stochastic simulations were executed for the three CO2 tax levels: $O/ton, $45/ton, and $100/ton. These levels reflect a reasonable middle value along with bookends adopted for portfolio development. All the simulations used the October 2008 forward price curves as the expected gas and electrcity price forecast values. This maintains comparability with the price forecast assumptions used for the 2009 business plan, as well as with the business plan reference cases, numbers 46 and 47. The PaR simulation also incorporates stochastic risk in its production cost estimates by using a stochastic model and Monte Carlo random sampling of five stochastic variables: loads, commod- ity natural gas prices, wholesale power prices, hydro energy availability, and thermal unit avail- ability for new resources. (For existing thermal units, planned maintenance schedules were used.42) Although wind resource generation was not vaijed in the same way as the other stochas- tic variables, the hour-to-hour generation does var throughout the year, but the pattern is re- peated identically for all study years (2009-2028) and Monte Carlo iterations. The Stochastic Model The stochastic model used in PaR is a two-factor (a short-ru and a long-ru factor) short-ru mean reverting modeL. Variable processes assume normality or log-normality as appropriate. Separate volatility and correlation parameters are used for modeling the short-run and long-ru factors. The short-ru process defines seasonal effects on forward varables, while the long-ru factor defines random strctural effects on electrcity and natural gas markets and retail load re- gions. The short-ru process is designed to capture the seasonal pattern inherent in electrcity and natual gas markets and seasonal pressures on electrcity demand. Mean reversion represents the speed at which a disturbed variable wil return to its seasonal ex- pectation. With respect to market prices, the long-run factor should be understood as an expected equilibrium, with the Monte Carlo draws defining a possible forward equilibrium state. In the case of regional electrcity loads, the Monte Carlo draws define possible forward paths for elec- trcity demand. 42 Stochastic simulation of existing thermal unit availability is undesirable because it introduces cost variability un- associated with the evaluation of new resources, which confounds comparative portfolio analysis. 163 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Stochastic Model Parameter Estimation Stochastic model parameters are developed with econometrc modeling techniques. The short- run seasonal stochastic parameters are developed using a single period auto-regressive regression equation (commonly called an AR(l) process). The standard error of the seasonal regression de- fines the short ru volatility, while the regression coefficient for the AR(1) variable dermes the mean reversion parameter. The short-run regression errors are correlated seasonally to captue inter-variable effects from informational exchanges between markets, inter-regional impacts from shocks to electricity demand and deviations from expected hydroelectric generation per- formance. The econometrc analysis uses 48 months of historical data for parameter estimation. The long-run parameters are derived from a "radom-walk with drft" regression. The standard error of the random-walk regression defies the long-ru volatility for the regional electrcity load variables. In the case of the natual gas and electrcity market prices, the standard error of the random walk regression is interpolated with the volatilities from the Company's offcial for- ward price curves over the twenty-year IRP study period. The long-ru regression errors are cor- related to captue inter-variable effects from changes to expected market equilibrium for natual gas and electrcity markets, as well as the impacts from changes in expected regional electrcity loads. PacifiCorp's econometrc analysis is performed for the following stochastic variables: . Fuel prices (natual gas prices for the Company's western and eastern control areas), . Electrcity market prices for Mid-Columbia (Mid C), California - Oregon Border (COB), Four Corners, and Palo Verde (PV), . Electrc transmission area loads (California, Idao, Oregon, Utah, Washington and Wyoming regions) . Hydroelectrc generation F or outage modeling, PacifiCorp relies on the PaR model's Monte Carlo simulation method to create a distrbuted outage pattern for new resources. PacifiCorp does not estimate stochastic pa- rameters for plant outages. Monte Carlo Simulation Durng model execution, PaR makes time-path-dependent Monte Carlo draws for each stochastic varable based on the input parameters. The Monte Carlo draws are of percentage deviations from the expected forward value of the variables, and are the same for each Monte Carlo simula- tion. In the case of natual gas prices, electrcity prices, and regional loads, PaR applies Monte Carlo draws on a daily basis. In the case of hydroelectrc generation, Monte Carlo draws are ap- plied on a weekly basis. The PaR model is configued to conduct 100 Monte Carlo simulation rus for the 20-year study period, so that each of the 100 simulations has its own set of stochastic parameters and shocked forecast values. The end result of the Monte Carlo simulation is 100 production cost rus (itera- tions) reflecting a wide rage of portolio cost outcomes. 164 ............................................ ............................................ PaciØCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Figures 7.18 through 7.21 show the 100-iteration frequencies for market prices resulting from the Monte Carlo draws for two representative years, 2009 and 2018. Figues 7.22 through 7.26 show the annual loads by load area at different percentiles: 10th, 25th, 50th, 75th, and 90th. Figure 7.27 shows the 25th, 50th, and 75th percentiles for hydroelectrc generation. Figure 7.18 ~ Frequency of Western (Mid-Columbia) Electricity Market Prices for 2009 and 2018 2009 2018 60 60 ~ 50 ~ 50:c ~ 40" t 40::~ 'Q 30 'Q 30 ~ 20 ..¡¡ 20.... 6- 10 3 2 6- 10 5 5 5 3 3 .L...4 i:1 ....ro 0 ro 0 42 84 126 169 211 253 295 337 379 421 421+42 84 126 169 211 253 295 337 379 421 421+ ($/MWh)($/MWh) Figure 7.19 - Frequency of Eastern (Palo Verde) Electricity Market Prices, 2009 and 2018 2009 2018 i; 60 ~ 50" ~ 40 'Q 30 ~ 20..= 10 t' 0ro 51 2 11 60 119 179 239 299 358 418 478 538 597 597+ ($/MWh) i; 60 ~ 50" t 40:: 'Q 30 ~ 20 l 1:ro 3 2 60 119 179 239 299 358 418 478 538 597 597+ ($/MWh) Figure 7.20 - Frequency of Western Natural Gas Market Prices, 2009 and 2018 2009 2018 lS 60 i 50 ~ 40 'Q 30 t- 20= !! 10.,~ 0 11 16 22 27 33 39 44 50 55 ($/MMtu) i; 60 ~ 50" ~ 40 'Q 30 ~ 20 ~ 10 æ 0 11 16 22 27 33 39 44 50 55 ($/MMtu) 165 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach ............................................ Figure 7.21 - Frequency of Eastern Natural Gas Market Prices, 2009 and 2018 2009 2018 w 60 l! 60"49~ SO i! so""¡; 40 ¡; 40.:.:'; 30 '; 30 to 20 to 20"" ~ 10 ~ 10..0 ~0..r.r.12 18 24 30 36 43 49 55 61 12 1&24 30 36 43 49 55 61 ($/MMtu)($/MMtu) Figure 7.22 - Frequencies for Idaho (Goshen) Loads 9,000 8,000 7,000 6,000 -=5,000 ~r,4,000 3,000 2,000 1,000 0 .. ..~ ....-- ~ -.~--~..~~-- ---. --/~--~J:----"-J~-~~- .~~'"~~ I.. 90th --75th.. mean -- 25th -' 10th I 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 166 ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach Figure 7.23 - Frequencies for Utah Loads 70,00 60,000 50,00 40,00 -=~C 30,00 20,00 10,000 0 II~-1I~--- II II II I-+ 90th m,lI-75th -- mean '-l" 25th "*lOth I 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Figure 7.24 - Frequencies for Washington Loads 10,00 9,00 8,00 7,00 6,00 ~5,00C 4,00 3,00 2,00 1,00 0 ~..~~--,--.-~.~-~-..~--~~- ~~71 I-+ 90th --75th -- mean -- 25th "*lOth I 2009 2010 2011 2012 2013 2014 2015 2016 2017 201S 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 167 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach Figure 7.25 - Frequencies for West Main (California and Oregon) Loads 30,000 25,000 20,000 .c:;15,000~ 10,000 5,00 0 _-l-_lI-- I-+ 90th --75th -. mean -- 25th -. 10th I 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Figure 7.26 - Frequencies for Wyoming Loads 14,000 12,000 ---- 10,000 ~J,..----........-l-,/__--.i- -j-"-l ~'"'" 8,000 lR '".c:;~ 6,000 4,000 2,000 I-+ 90h --75th.. mean -- 25th -. 10th I 0 200 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 168 ............................................ ............................................ PacißCorp - 200BIRP Chapter 7 - Modeling and Portolio Evaluation Approach Figure 7.27 - Hydroelectric Generation Frequency, 2009 and 2018 2018 2009 8,000 7,000 6,000 5,000 ~ 4,000"3,000 2,000 1,000 o 9,000 &,000 7,000 6,000 ~ 5,000 " 4,000 3,000 2,000 1,000 o 75tb Percentile 50tb Percentie 25tb Pereentie 75tb Percentile 50th Pereentile 25th Pereentile 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 par- ticularly adverse cost conditions, and derives associated cost measures as indicators of high-end portfolio risk. These cost measures, and others used to rank portfolio performance, are described in the next section. Stochastic simulation results for the optimized portfolios were summarized and compared to de- termine which portfolios perform best according to a set of performance measures. These meas- ures, grouped by category, include the following: Cost . Mean PVRR (Present Value of Revenue Requirements) . Risk-adjusted mean PVRR . Minimum PVR cost exposure under CO2 tax outcomes . Customer rate impact . Capital costs for the first ten years of the simulation period (2009-2018) and the total simula- tion (2009-2028) Risk . Uptter-tail Mean PVRR . 95 Percentile PVRR . Production cost standard deviation Supply Reliability . Average annual Energy Not Served (ENS) . Upper-tail ENS . Loss of Load Probability (LOLP) PacifiCorp reports the portfolio results for each CO2 tax simulation, the straight average for the thee C02 tax simulations, and multiple probability-weighted averages. The multiple probability- weighted averages reflect $5/ton increments of the expected value (EV) C02 tax, ranging from 169 PadßCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach $15/ton to $70/ton. This range is in line with long ru values that have appeared in federal and state legislative proposals.43 The average values are converted to a normalized, l-to-1O scaled score to preserve relative differences between measure results when combining the scores for composite ranking of the portfolios. In addition to these stochastic measures, PacifiCorp reports fuel source diversity statistics and the emission footprint of each portfolio, focusing on generator emissions. The following sections describe in detail each of these performance measures as well as the fuel source diversity statistics. MeanPVRR The stochastic mean PVRR for each portfolio is the average of the portfolio's net variable oper- ating costs for 100 iterations of the PaR model in stochastic mode, combined with the real level- ized capital costs for new resources determined by the System Optimizer modeL. The PVRR is reported in 2009 dollars as of January i, 2009. The net variable cost from the PaR simulations, expressed as a net present value, includes system costs for fuel, variable plant O&M, unit star-up, market contracts, spot market purchases and sales, and costs associated with making up for generation deficiencies (Energy Not Served costs; see the section on ENS below for background on ENS and the representation of ENS costs in the PaR modeL.) The variable costs included are not only for new resources but existing system op- erations as well. The capital additions for new resources (both generation and transmission) are calculated on an escalated "real-levelized" basis to appropriately handle investment end effects. Other components in the stochastic mean PVR include renewable production tax credits and emission externality costs, such as a CO2 tax. The PVRR measure captues the total resource cost for each portolio, including externality costs in the form of CO2 cost adders. Total resource cost includes all the costs to the utility and cus- tomer 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. Risk-adjusted Mean PVRR This measure-risk-adjusted PVRR for short-is calculated as the stochastic mean PVRR plus the expected value, EV, of the 95th percentile PVR, where EV = PVRR95 x 5%. This metrc expresses a low-probability portfolio cost outcome as a risk premium applied to the expected (or mean) PVRR based on the i 00 Monte Carlo simulations conducted for each production cost run. The rationale behind the risk-adjusted PVRR is to have a consolidated stochastic cost indicator for portfolio ranking, combining expected cost and high-end cost risk concepts without eliciting and applying subjective weights that express the utility of trding one cost attbute for another. 43 For example, see, Metcalf, G., et aI, Anlysis of U.S. Greenhouse Gas Tax Proposals (Massachusett Institute of Technology, Joint Program on the Science and Policy of Global Change, Report No. 160, April 2008). As an exam- ple of a state legislative CO2 tax proposal, the Kasas House of Representatives considered a $37 /ton CO2 ta to belevied on the state's electrc utilities. . 170 ............................................ ............................................ PaciffCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach PacifiCorp also presents scatter-plot graphs of the stochastic mean PVRR versus upper-tail mean PVRR for portfolios as a means to visualize the tradeoff between expected and high-cost out- comes. Minimum Cost Exposure under Alternative Carbon Dioxide Tax Levels Cost exposure is the difference between a portfolio's risk-adjusted PVRR and the risk-adjusted PVRR of the best-performing portfolio for a given CO2 tax level modeled in the Monte Carlo simulation. Each portfolio is ranked on the basis of the size of its maximum cost exposure real- ized under the three CO2 tax levels: $O/ton, $45/ton, and $100/ton. This raning scheme is based on the Minimax Regret decision criterion, which focuses on avoid- ing the worst possible consequences that could result when making a decision. In decision the- ory, "regret" is defined as the exposure between a course of action taken and the best course of action possible given a particular state of natue.44 If the decision-maker selects the course of ac- tion that tus out to be the best possible one, then the regret is zero. Conversely, the maximum regret occurs if the selected course of action results in the worst outcome among the possibilities. The minimax decision rule is to select the course of action that minimizes the maximum regret across the states of nature evaluated. This is a risk-averse stance applicable to decision-making under uncertainty. To ilustrate the application of the decision rule, the following matrix shows the cost outcomes given two alternative actions and two states of natue, designated as Sl and S2. Under state of nature Si, the best possible cost outcome happens under Alternative 2; under state of natue S2, the superior cost outcome happens under Alternative 1. i 2 Lowest Cost To determine the maximum regret for the two alternatives, a loss matrx is constrcted: Loss Table (DiDion $) The maximum regret for alternative 1 under state of natue Sl is $8 bilion, while the maximum regret for alternative 2 under state of natue S2 is $5 bilion. By applying the minimax decision 44 Regret is also called "opportity loss", or the amount that would be lost by not picking the best alternative. 171 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach rule, alternative 2 would be selected because it has the lowest maximum loss under the two states of natue. For PacifiCorp's minimax evaluation, the states of natue are the stochastic cost outcomes given the three CO2 tax levels modeled in the Monte Carlo simulations ($O/ton, $45/ton, and $1 OO/ton). The alternatives are the resource portfolios developed from the 21 core cases with the medium load growth assumption. Customer Rate Impact PacifiCorp calculates the customer rate impact associated with each of the portolios based on the stochastic production cost results and capital costs reported for the portfolio by the System Optimizer modeL. The rate impact measure is the levelized net present value of the year-to-year changes in the customer dollar-per-megawatt-hour price for the period 2009 through 2028: ( (COSI.-COSI. i)J - P MT NP~=¡2oio-+20281 1 1- Loadi The cost in the rate numerator consist of the stochastic mean system operating cost (fuel cost, environmental cost, and varable O&M costs of all resources), combined with the fixed O&M and capital costs of the new supply-side and trnsmission resources.45 The rate denominator is the retail load. 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 captue projected total system revenue requirements. For example, planned upgrdes for curent 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 curent or proposed multi-jursdictional allocation methodolo- gies. 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. The capital costs are reported by the System Optimizer for each portfolio. Capital costs for the first 10 years of the simulation period, as well as the en- tire simulation period, are reported. The ten-year capital cost view (for resources added in 2009- 2018), is intended to indicate the relative rate impact of the portfolios attbutable to resource constrction costs durng the period considered in PacifiCorp' s business plan. 45 New IR resource capital costs are represented in 2008 dollar and grow with inflation, and sta 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 wil be lower in the early years and higher in the later years when compared to customer rate impacts computed under a rate-making formula. 172 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio E.valuation Approach Risk Measures For this IRP, PacifiCorp relies on four stochastic cost risk measures: upper-tail meanPVRR, 5th and 95th percentile PVRR, and the standard deviation of production costs. Upper-Tail Mean PVRR The upper-tail mean PVRR is a measure of high-end stochastic cost risk. This measure is derived by identifying the Monte Carlo iterations with the five highest production costs on a net present value basis. The portfolio's real levelized fixed costs are added to these five production costs, and the arithmetic average of the resulting PVRRs is computed. 95th and 5th Percentile PVRR The fifth and ninety-fifth percentile stochastic PVRR are also reported. These PVRR values cor- respond to the iteration out of the 100 that represents the fifth and ninety-fifth percentiles on the basis of production costs (net present value basis), respectively. These measures represent snap- shot indicators of low-risk and high-risk stochastic outcomes. As described above, the 95th per- centile PVRR is used to derive the high-end cost risk premium for the risk-adjusted PVRR measure. Production Cost Standard Deviation To capture production cost volatility risk, PacifiCorp uses the standard deviation ofthe stochastic production cost for the i 00 Monte Carlo simulation iterations. The production cost is expressed as a net present value for the anual costs for 2009 through 2028. Supply Reliabilty Average and Upper-Tail Energy Not Served Certain iterations of a PaR stochastic simulation wil have "energy not served" or ENS.46 Energy Not Served is a condition where there is insuffcient generation available to meet load because of physical constraints or market conditions. This occurs when an iteration has one or more stochas- tic variables with large random shocks that prevent the model from fully balancing the system for the simulated hour. Typically large load shocks and simultaneous unplanned plant outages are implicated in ENS events. (Deterministic PaR simulations do not experience ENS because there is no random behavior of model parameters; for example, loads increase in a smooth fash- ion over time.) Consequently, ENS, when averaged across all 100 iterations, serves as a measure of the stochastic reliability risk for a portfolio's resources. For reporting of the ENS statistics, PacifiCorp calculates an average annual value for 2009 though 2028 in gigawatt-hour, as well as the upper-tail ENS (average of the five iterations with the highest ENS). Results using the $45/ton CO2 tax are reported, as the tax level does not have a material influence on ENS amounts. One change from previous IRPs related to the handling of ENS is the estimation of ENS costs included in the portfolio stochastic PVRR. In previous IRPs, PacifiCorp applied a single ENS cost for the PaR model, using the FERC price cap as a reasonable cost proxy for acquirng emer- gency power. PacifiCorp recognizes that, in practice, the planing response to significant ENS is 46 Also referred to as Expected Unserved Energy, or EUE. 173 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluaton Approach different for short-ru versus long-ru ENS expectations. In the short-run, the Company would have recourse to few remedial options, and would expect to pay a large premium for emergency power. On the other hand, the Company has more planing options with which to respond to long-term forecasted ENS growt, including acquisition of peakng resources. Consequently, a tiered pricing scheme has been applied to ENS quatities generated by the Planning and Risk modeL. The ENS cost is set to $4001MWh (real dollars) for the first 50 GWhyr of ENS, $2001MWh for the next 100 GWhyr, and $100/M for all quantities above 150 GWhyr. For large forecasted ENS quantities that occur in the out years of the study period, the acquisition of peaking generation would become cost-effective, with the $100/M reflecting the long-ru all- in cost for such generation. Loss of Load Probabilty Loss of Load Probability is a term used to describe the probability that the combinations of online and available energy resources canot supply sufficient generation to serve the load peak durng a given interval of time. Mathematically, LOLP defined as: LOLP = Prob(S -: L) where S 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 anual measure estimates the generating system's reliability. A high LOLP gen- erally indicates a resource shortge, which can be due to generator outages, insufficient installed capacity, or both. Target values for anual system LOLP depend on the utilties' degree of risk aversion, but a level equivalent of one day per ten years is tyicaL. For reporting LOLP, PacifiCorp calculates the probabilty of ENS events, where the magnitude of the ENS exceeds given threshold levels. PacifiCorp is strongly interconnected with the re- gional 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 shortalls are likely to be resolved with a quick (though expensive) purchase. In Chapter 8, the proportion of iterations with ENS events in July exceeding selected threshold levels are reported for each optimized portfolio simu- lated with the PaR modeL. The LOLP is reported as a study average as well as year-by-year re- sults for an example theshold level of 25,000 MWh. This theshold methodology follows the lead of the Pacific Nortwest Resource Adequacy Forum, which reports the probability of a "significant event" occurg the winter season. Fuel Source Diversity For assessing fuel source diversity on a summary basis for each portfolio, PacifiCorp calculated the new resource generation shares for four broad fuel-tye categories as reflected in the System Optimizer expansion plan: · Renewables and DSM ("no fuel" generation plus a small quantity of biomass fuel) 174 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach . Natual gas . Market . Coal, including all types of coal-based technologies selected for the expansion plan . Nuclear To account for the timing impact of the assumed availability of coal and nuclear resources in the portfolios, the generation shares are reported for years 2013, 2020, and 2028. Conventional su- percritical coal plants are picked up in the 2020 and 2028 snapshots, while nuclear and clean coal resources are picked up in the 2028 snapshot. Another perspective on fuel diversity is the nameplate capacity mix for the portfolios. Appendix A contains area charts for all portfolios developed that show the resource nameplate capacity mix by year. Nameplate capacity for resources selected by the System Optimizer is grouped into the following new resource categories: gas, DSM, distrbuted generation, wind, other renewables, clean coal, conventional coal, energy storage, other renewables, market purchases, and growth resources. For this IRP, PacifiCorp has instituted a weighted scoring scheme that combines selected porto- lio performance measures into an overall composite preference score. The cases selected for per- formance ranking include the core cases defmed with the medium load growth assumption (to maintain cost comparability with respect to the amount of resources required) as well as cases 46 and 47 (the two business plan reference portolios). The measures used in the weighted scoring scheme, along with their importance weights (which sum to 1), include the following: Table 7.8 - Measure Importance Weights for Portolio Ranking CO2 Cost Exposure 15%Production Cost Standad Deviation 5%Average anual ENS 5% Average Annual Probability of ENS events for July exceeding 25 GWh 5% Total 100% Risk-adjusted PVRR represents the long-run cost performance for a portfolio, accounting for the potential for a high-cost outcome and its associated cost on an expected value basis. Conse- quently, this criterion is given the largest weight among the performance measures. The cus- tomer rate impact measure gauges long-ru retail rate variability for a portfolio; given two port- folios with equivalent long-run costs, the portolio that has lower retail rate varability is pre- ferred. The 10-year capital cost criterion reflects the role that near-term capital expenditues 175 PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach plays in determining portfolio affordability and financeability for puroses of business plan preparation. For portfolio risk measures, cost exposure under alternative CO2 tax levels reflects a portolio's potential for avoiding worst-case cost outcomes given CO2 regulatory policy uncertainty; it is a measure of CO2 cost risk, and has been given the largest weight among risk measures included in the preference scoring process. The thee other risk measures reflect variable cost variabilty and supply reliability attbutes, and have been given a combined weight of 15 percent for preference scoring. Table 7.9 shows a sample of the preference-scorig grd for the optimized portfolios. To deter- mine the preference scores for the portfolios, PacifiCorp conducted the following steps: 1. Calculate the normalized (scaled from 1 to 10) ranngs for the probability-weighted av- erage stochastic cost measures (risk-adjusted PVRR, customer rate impact, CO2 cost ex- posure, and the standad deviation of production costs). Rangs are determined for each of 12 expected value CO2 ta levels, ranging from $15 to $70. 2. Calculate the normalized rags for the 10-year capital costs, average annual ENS, and July event LOLP. 3. Populate the portfolio preference-scorig grd with the normalized rankngs. The weighted rankng for each portfolio is the sum of each individual performance rankng multiplied by its importance weight. These weighted ranngs are then converted to final preference scores by scaling the rankngs to a 1 to 10 range. Table 7.9 - Portfolio Preference Scoring Grid 0.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.00.0 0.0 0.0 0.00.0 0.00.0 0.00.0 0.00.0 0.0 176 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach The net result was a set of 12 preference-scoring grids, one for each expected value CO2 tax leveL. For determining the top-performing portfolios, PacifiCorp calculated the average of the preference scores across the CO2 tax levels, as well as inspected the variability of the scores as the CO2 level increased. The top three portfolios on the basis of the preference scores were selected as final preferred portfolio candidates. Three portfolios represent a manageable number in light of the data proc- essing and model ru-time requirements associated with phase 6, deterministic risk assessment of the top-performing portfolios. The purpose of phase 6 is to determine the range of deterministic costs that could result given a fixed set of resources under varying gas/electrcity price and CO2 cost assumptions, the two main sources of portfolio risk. The Public Service Commission of Utah, in its acknowledgment order for PacifiCorp's 2007 IRP, directed the Company to consider this step for the 2008 IRP. PacifiCorp used the System Optimizer to determine PVRRs for the three top-performing portfo- lios under a subset of the core cases (Scenario Risk Cases). For these rus, the System Optimizer dispatches the fixed set of portfolio resources as part of its least-cost portfolio solution. The PVRR comparisons thus indicate the production cost differences under the alternative cost sce- nanos. As with the performance ranking process, PacifiCorp selected only those cases with the medium load growth assumption. Cases were also restrcted to those using the June 2008 forward price cure. These selection rules resulted in 10 cases and total of 30 System Optimizer runs to support this analysis as shown in Table 7.10. Table 7.10 - Cases Selected for Deterministic Risk Assessment 1 $O/ton Low 2 $O/ton Medium 3 $O/ton High 5 $45/ton Low 8 $45/ton Medium 14 $45/ton High 17 $70/ton Medium 22 $70/ton High 24 $100/ton Medium 29 $100/ton High In parallel with the stochastic risk analysis, PacifiCorp reports a measure of centrl tendency (mean PVRR) and variation (PVRR standard deviation) for the portfolio results, as well as ranked each portfolio and computed the rank sum as an overall performance indicator. 177 PacifCorp - 2008 IRP Chapter 7 - Modeling and Portolio Evaluation Approach :::d,d::,:::i_? The preferred portfolio is selected from the thee top-performing portfolios on the basis of the portfolio preference scores, and then consideration of resource risks and fuel source diversity. Using the preferred portolio as the staing point, PacifiCorp conducts a next best alternative (NBA) analysis that applied a number of procurement risk scenarios to determine optimal portfo- lios in the event of unplanned circumstaces. The focus of the NBA analysis is on key firm- planned and new resources reflected in the preferred portfolio. 178 ............................................. ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Se/eeton Results 8. MODELING AND PORTFOLIO SELECTION RESULTS This chapter reports modeling and portfolio performance evaluation results for the portfolios de- veloped with alternate input assumptions using the System Optimizer modeL. The preferred port- folio is presented, along with a discussion of the relative advantages and risks associated with the top-performing portfolios. Discussion of the portfolio evaluation results falls into the following 12 sections. Portfolio Development Results - This section presents the System Optimizer resource portfolios, describing resource preferences as a fuction of the model input assumptions and profiling re- source utilization patterns for each portfolio. Analysis results for several sensitivity case portfo- lios are also presented. · Stochastic Simulation Results - Candidate Portfolios - This section reports the stochastic modeling results and cost/risk measure ranking results for each of the 21 candidate portfolios. . Load Growth Impact on Resource Choice - This section compares the stochastic modeling results for portfolios developed with alternative load growth assumptions. . Capacity Planning Reserve Margin - This section describes the stochastic cost and risk analysis of portfolios developed with 12 and 15 percent capacity planning reserve margins. · Probability-weighted Stochastic Cost Results - This section reports the stochastic cost meas- ures as probability-weighted averages of the results for the thee CO2 tax simulations: $0, $45, and $lOO/ton in 2008 dollars. These results are key inputs in the overall portfolio prefer- ence sconng process. · Fuel Source Diversity - This section provides statistics on generation shares by fuel tye for all the portfolios; three snap shot years are profiled: 2013,2020, and 2028. · Emissions Footprint - This section reports for each portfolio the anual emission quantities of CO2, sulfur dioxide, nitrous oxides, and mercur for 2009-2028. · Top-performing Portfolio Selection - This section describes the results of the portfolio cost/risk measure rankng and preference scoring, and identifies the four top-performing port- folios chosen as final candidates for preferred portfolio selection. · Scenario Risk Assessment - This section describes the deterministic scenaro analysis con- ducted for the thee top-performing portfolios, concluding with a critique of the value of this tye of analysis for the IRP. . Portfolio Impact of the 2012 Gas Resource Deferral Decision - This section describes the portfolio analysis conducted to reflect the removal of the Lake Side II combined-cycle plant as a planned resource for 2012. · Wind Resource Acquisition Schedule Development - This section discusses the model selec- tion of wind resources and how business planning implementations must be considered. · Portfolio Impact of PacifiCorp's February 2009 Load Forecast - This section presents the portfolio developed to account for a new load forecast prepared in February 2009. 179 Paci~Corp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result · Preferred Portfolio Selection - This section compares the top-performing portfolios, profiing their relative advantages and risks and pulling in the portolio analysis conducted for the Lake Side II constrction cancellation and revised load forecast. The. portfolio that is the most desirable after considering cost, risk and uncertainty is then presented. Tables 8.1 and 8.2 show the cumulative capacity additions by resource tye for the portfolios for years 2009-2018 and 2009-2028, respectively. Megawatt amounts for front office transactions and growth resources represent anual averages: 20 year for FOT, and eight years for growth resources. (The detailed portfolio resource tables are included in Appendix A.) 180 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Table 8.1 - Portfolio Capacity Additions by Resource Type, 2009 - 2018 1 $20,045 124 748 108 716 2 $21,512 600 140 85 646 35 2 890 3 $19,503 790 3,291 95 530 155 7 982 5 $40,526 261 1,050 95 691 35 2 901 8 $41,372 2,400 147 663 120 7 955 9 $40,204 261 1,280 95 690 35 2 899 10 $40,319 2,400 117 679 155 7 949 11 $40,559 600 4,814 103 546 155 7 1,001 14 $39,949 600 5,355 107 500 155 7 1,018 17 $51,207 3,900 110 613 155 7 985 18 $49,745 3,900 110 640 155 7 954 19 $50,102 4,100 110 620 155 7 975 20 $50,536 5,250 104 602 155 7 1,007 22 $49,983 600 5,750 101 514 155 7 1,048 24 $60,693 5,739 112 565 155 7 1,009 25 $58,838 5,250 112 742 155 7 1,000 26 $59,660 5,250 112 661 155 7 1,007 27 $60,484 5,750 110 648 155 7 1,045 29 $57,635 5,750 158 538 155 110 1,079 46 $21,532 600 136 641 19 906 822 136 646 29 903 $45 300 91 216 35 $45 1,800 91 172 85 $45 600 4,610 95 121 155 $70 3,599 109 116 155 $70 5,750 95 134 155 $100 5,559 ILL 101 155 $100 5,750 95 242 155 968 1,020 104 920 25 954 983 105 1,036 85 109 900 35 2 877 85 121 945 II All portfolios include 1,520 MW of firm planed resources, consisting of Lae Side 2, a 2012 east PPA, 2009-2010 wind resources under development or contrct, coal plant tubine upgres, and Swif 1 hydro upgrades. 181 PacifCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Table 8.2 - Portfolio Capacity Additions by Resource Type, 2009 - 2028 1 $20,045 Low - June 2008 $0 261 130 1,102 859 108 1,537 2 $21,512 Medium - June 2008 $0 600 261 941 109 880 524 35 2 1,815 3 $19,503 High - June 2008 $0 790 4,003 95 713 437 155 7 1,992 5 $40,526 Low - June 2008 $45 346 261 1,60 1I0 1,089 734 35 2 1,835 8 $41,372 Medium - June 2008 $45 2,40 160 1,090 624 120 7 1,942 9 $40,204 Low - Oct 2008 $45 346 261 1,60 1I0 1,133 623 35 2 1,834 10 $40,319 Medium - Oct 2008 $45 2,60 129 1,124 513 155 7 1,936 11 $40,559 High - Oct 2008 $45 600 5,00 1I4 717 651 155 7 2,024 14 $39,949 High - June 2008 $45 600 466 6,287 120 711 272 155 7 2,066 17 $51,207 Medium - June 2008 $70 876 3,900 122 1,084 609 155 7 2,020 18 $49,745 Low - Oct 2008 $70 876 3,900 122 1,089 667 155 7 1,974 19 $50,102 Medium - Oct 2008 $70 876 4,100 122 1,094 610 155 7 2,009 20 $50,536 High - Oct 2008 $70 876 6,60 1I4 1,60 842 651 155 7 2,035 22 $49,983 High - June 2008 $70 60 876 7,200 101 1,60 616 161 155 7 2,115 24 $60,693 Medium - June 2008 $100 876 6,60 122 3,200 802 280 155 7 2,076 25 $58,838 Low - Oct 2008 $100 876 6,175 122 1,070 777 155 7 2,035 26 $59,660 Medium - Oct 2008 $100 876 6,60 122 3,200 783 311 155 7 2,042 27 $60,484 High - Oct 2008 $100 876 6,680 120 3,200 972 650 155 7 2,098 29 $57,635 High - June 2008 $100 876 46 7,200 167 3,200 575 450 155 1I0 2,183 46 $21,532 Medium - Oct 2008 $8,C&T 60 174 1,388 151 897 468 19 1,825 47 $20,863 Medium - Oct 2008 $8,C&T 60 174 1,3 151 892 469 29 1,822 Low Load Growt Core Cas ," 4 $34,612 Low - June 2008 $45 346 300 110 269 125 35 1,801 7 $34,582 Medium - June 2008 $45 346 1,800 1I0 185 1I5 85 1,857 13 $31,076 High - June 2008 $45 600 4,800 95 71 81 155 2,038 16 $43,523 Medium - June 2008 $70 876 3,599 122 108 1I1 155 1,990 21 $40,517 High - June 2008 $70 876 6,202 95 1,600 124 70 155 2,058 23 $51,692 Medium - June 2008 $100 876 6,60 122 3,200 157 85 155 2,045 28 $47,806 High - June 2008 $100 876 5,800 95 3,200 150 67 155 2,036 Hm Li Grth Core Ca ..,, 6 I $48,140 ILow - June 2008 $45 1 I 1,8381 1,601 209 1,181 1,125 155 126 1,983 12 I $50,146 IMedium - June 2008 $45 600 I I 8881 2,2991 169 1,186 1,125 155 126 2,082 15 1 $50,914 IHigh - June 2008 $45 60 1 461 2611 6,5991 169 1,600 1,148 572 655 125 2,163 Senslti 'i Ca - Real C02 Cost Estin Wi Cbam in Li Growt " " 30 I $48,541 IMedium - June 2008 $45 to $179 1 8761 461 I 7,001 122 3,2001 743 126 155 7 2,091 31 1 $47,552 IHigh - June 2008 $45 to $179 I 8761 I I 7,2001 122 3,2001 815 130 155 7 2,159 sensitity Case - Hleb Cos Olllle 33 1 $69,949 IHigh - June 2008 1 $100 60 I 1 1,1001 7,2001 169 I 762 1,125 655 126 2,294 senstivity C05ll. Clean BaseLod Geratin Ava mv .... 34 $40,564 Medium - June 2008 $45 3,900 152 1,109 539 85 7 1,937 35 $39,853 High - June 2008 $45 600 5,000 97 778 479 120 7 2,022 36 $51,242 Medium - June 2008 $70 876 4,200 169 1,127 762 120 110 2,046 37 $48,949 High - June 2008 $70 876 5,762 95 3,200 468 150 120 7 2,061 Se05titv.C05el -lì Plant Conson Cos ' , 38 1 $41,974 Medium - June 2008 I $45 I 1 2,118 151 1,114 535 85 64 1,970 39 1 $34,791 High - June 2008 I $45 I 600 I 3,255 149 641 580 120 109 2,113 Sè$lvi Cas . svsemwld Oren CO2 Redii T , , 40 $24,761 IMedium - June 2008 HardCap I 876 1 2,2001 124 999 1,000 85 104 1,880Seit'i Cas - Pla,,,ùnl! ReservMØn 15%,"'w' ' 41 $41,542 IMedium - June 2008 $45 261 1,9341 163 1,168 590 155 25 1,941 42 $51,420 IMedium - June 2008 $70 876 261 3,601 122 1,160 679 155 2,017 43 $60,905 IMedium - June 2008 $100 876 6,601 163 3,200 907 291 155 105 2,104Seos Case. :Aerate :Rneabl Plv Am ll ,',' 44 $21,249 IMedium - Oct 2008 I $8,C&T 601 1 5,673 1491 948 161 155 109 1,811 45 $20,875 IMedium - Oct 2008 I $8,C&T 601 I 261 881 1101 904 430 120 2 1,795Seti'i Cas -Class 3 DS rór Peak Lod Reduetn .. 48 $41,268 IMedium - June 2008 I $45 I 1 1 2,400 1221 1,037 6791 85 121 1,932 ii All portolios include 1,520 MW of firm planed resources, consisting of Lae Side 2, a 2012 east PPA, 2009-2010 wid resources under developmet or contract, coal plant tubine upgrdes, and Swift 1 hydro upgrs. 182 ............................................ ............................................. PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Wind Resource Selection Wind resource selection varied considerably across the portfolios, ranging from no resources in one portfolio (case 1, with no CO2 tax and low gas prices) to 7,200 MW in five portfolios (cases 1 1,29,30,31, and 33-all based on high gas prices and a CO2 tax of$70 or greater). For the $45 CO2 tax core cases with medium load growth, the amount of wind capacity averaged over 3,200 MW. For the $70 and $100 CO2 tax core cases with medium load growth, the amount of wind capacity averaged over 5,100 MW and 6,600 MW, respectively. System Optimizer found wind to be cost-effective for displacing gas generation under high gas price scenaros, reducing CO2 taxes, and sellng to markets during off-peak periods. Regarding the timing of wind additions, the model generally started adding wind capacity. early in the study period, from 2010 to 20 i 2, with large and constant amounts included in response to high gas prices, high CO2 tax values, or both. For these cases, the model often selected amounts up to the limit allowed in a year (500 MW prior to 2014, and 750 MW in 2014 and thereafter). In only a few of the cases was wind added after 2020, generally to help meet RPS requirements ow- ing to less wind investment made earlier in the study period (for example, cases 2 and 5). The expiration of the renewable PTC in 2013 (case 45) was found to significantly impact the amount and timing of wind additions; no wind was added after 2012. An important caveat to these results is that System Optimizer does not account for reliability im- pacts and associated costs from adding large amounts of wind to the system. Gas Resource Selection Intercooled aeroderivative (IC aero) SCCT plants were the most common gas resource included in the portfolios, occurng in cases having low gas prices combined with either the $0 or $45 CO2 tax, or medium gas prices combined with no CO2 tax. The SCCT plant (261 MW) was al- ways selected in 20 i 6. Combined-cycle gas plants were selected infrequently, only appearing in three scenaro situa- tions: high load growth and either the low or medium gas price assumptions (cases 6 and 12), and the high-cost bookend scenario (case 33). The model chose only west-side CCCT units with a 2015 in-service date. Class i Demand-side Management Resource Selection The model selected a small amount of Class i DSM capacity, 2 to 7 MW, for most of the portfo- lios, favoring Idaho dispatchable irrgation over other programs. This capacity was added most commonly between 2016 and 2018, with the earliest additions in 2013 for portfolios with no wind capacity chosen in the early years. Additions reached over 100 MW for high load growth scenarios, while no capacity was added in any of the portfolios developed with the low load growth scenaro. Of the core cases with medium load growt, only two cases-numbers 1 and 29-included more than 100 MW. For case i, which was based on no CO2 tax and low gas prices, Class 1 DSM appears to substitute for renewables capacity added in most other portfolios. For case 29, the selection of Class 1 DSM is drven by low utilization of gas plants stemming from the combination of the $100 C02 tax and high gas prices. 183 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecon Results Class 2 Demand-side Management Resource Selection The model selected a sizable amount of Class 2 DSM in all portfolios by 2028, ranging from 1,537 MW to 2,183 MW, and adding this DSM on a relatively constant basis for every year of the simulation period. For the medium load growth portfolios, the average amount included was 1,970 MW. The variation of the DSM among these portfolios, as measured by the standard de- viation, was only about 130 MW. Supercritical Pulverized Coal Resource Selection The model selected supercritical coal plants in response to the following set of conditions: · No C02 tax combined with medium or high gas prices (cases 2 and 3) · The $8 C02 cap-and-trade allowance price (cases 44 and 45, and business plan reference cases 46 and 47) · The $45 CO2 tax combined with high gas prices (cases i i, 14,35, and 39) . The $45 CO2 tax with low load growth, combined with high gas prices (case 13) · The $45 CO2 tax with high load growt, combined with either medium or high gas prices (cases 12 and 15) · The $70 CO2 tax combined with high gas prices (case 22) Only one coal plant was included in these portolios. The plant was always selected in 2018, ex- cept for the two business plan reference cases, where it was added in 2019. The combination of scenario inputs for which supercritical coal plants were chosen indicates that determining a C02 cost trgger point at which coal plants are no longer cost-effective has limited value without considering the impact of gas prices. Geothermal Resource Selection Geothermal was included in a large majority of the case portfolios, and generally selected in 2013-the first year of availability. The Blundell 3 project appeared in all portfolios where this resource was configued as an option, except for case 1 (defined with no CO2 tax and low gas prices). The green-field projects in both the east and west were not cost-effective in a number of low load growt scenaros, but frequently appeared in the portfolios developed with all other combinations of scenario input values. An interesting result of enforcing the high renewable portfolio standard requirement for case 44 was that the geothermal resources were deferred from their tyical 2013 in-service dates: the Blundell 3 project was added in 2015, while the east and west green-field resources were added in 2020 and 2025, respectively. The model followed a similar deferral strategy for case 45, where the production tax credit expired in 2013. For this portolio, Blundell 3 was deferred to 2016, while the west green-field resource was deferred to 2023. Nuclear Resource Selection Nuclear plants become cost-effective resource alternatives under high gas price and CO2 tax sce- narios; they are also always selected in 2025, the earliest in-service year. A 1,600 MW unit was chosen with a $70 CO2 tax combined with high gas prices. The model selected a 3,200 MW unit 184 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results given a $100 CO2 tax and medium or high gas prices. There is no clear preference for nuclear resources given the level of load growth assumed. Clean Coal Resource Selection Clean coal technologies appear under the $45 CO2 tax in limited circumstances; only in combi- nation with low gas and electrcity prices. Under medium gas price scenarios, renewables, energy effciency, and distrbuted generation substitute for a single pulverized coal CCS retrofit project. Only under the highest gas/electrcity prices (June 2008 forward price curve) does IGCC become cost-effective with a $45 CO2 tax. Multiple pulverized coal CCS retrofit units are added in all portfolios specified with the $70 and $100 CO2 tax. IGCC capacity is only added under the June 2008 high gas price scenario. Short-term Market Purchase Selection Reliance on front office transactions varies substantially among the portfolios. They are utilized more heavily under the low and medium gas price scenarios. In contrast, portfolios with large quantities of wind or base-load coal tend to rely less on them. The portfolios do not exhibit a cor- relation between the CO2 tax level and the amount of front offce transactions. Distributed Generation Selection Distrbuted generation resources-CHP and standby generation-was selected in all the portfo- lios, and ranged from 95 MW in case 3 (medium load growth, no C02 tax, and high June 2008 gas price scenario) to 209 MW in case 6 (high load growth, $45 C02 tax, and low June 2008 gas price scenario). Standby generation, biomass CHP, and the Kern River Recovered Energy Generation projects were most commonly selected. Standby generation and biomass always appeared in the first year of availability (2009), while the Kern River REG units appeared between 2011 and 2015. The low biomass fuel price assumed for the CHP resource explains why it appears in all the portfo- lios. Quantities were tyically added in constant amounts each year until 2018. Kern River REG units were not selected under low load growth scenarios, or a combination of the $45 C02 tax and low gas price scenarios. Additions of reciprocating engine CHP were less common, and are sensitive to the gas prices assumed. System optimizer generally started adding this tye of CHP resource in the 2012-2013 time frame, with constant amounts (tyically 1 or 2 MW) appearing in each year. There is no single factor that accounts for the amount of distrbuted generation capacity selected; rather, a combination of low or medium gas price scenarios and higher C02 tax levels appear as- sociated with larger quantities added. Emerging Technology Resource Selection Emerging technologies-solar, energy storage, and fuel cells-were rarely selected by the model, and appear in no more than one portfolio. The portfolio for case 15 includes 500 MW of solar thermal with natual gas backup (250 MW in 2014 and 2015), added in response to a $45 C02 tax and high load growth and gas prices. Compressed air energy storage and battery storage 185 PacifCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result appear in case 12 as a response to a $45 CO2 tax combined with high load growth and medium gas prices. (CAES air compression is fueled by simple-cycle combustion turbines). These tech- nologies are added late in the simulation period, after 2025. Finally, fuel cells appear in the port- folio for case 6 in 2016 (40 MW in the east side), developed with high load growth, low gas prices, and the $45 CO2 tax. Transmission Option Selection PacifiCorp included thee transmission resource options in System Optimizer: . An Energy Gateway West expansion totaling 750 MW (Path C to West Main) available in 2015 . A Walla Walla to West Main transmission project available beginning in 2014, with ca- pacity options of 200 MW and 400 MW System Optimizer did not these trsmission options in any of the portfolios. Incremental Resource Selection under Alternative Load Growth Scenarios Observations concerning the incremental resources selected as load growth increases are as fol- lows: $45/ton CO2 Tax and Low Gas Prices · Moving from low to medium load growt, System Optimizer chose front office transactions as the dominant resource for meeting load. Mead and Mona FOT were relied on heavily be- gining in 2013 and 2017, respectively. Additionally, the model added an IC aero SCCT in 2016 (261 MW), a significant amount of east-side wid (750 MW by 2018, and another 450 MW by 2021), and a small quatity of east-side Class 2 DSM. · Moving from medium to high load growt, the model added a diverse mix of resource tyes. Incremental resources included: combined-cycle (1,100 MW by 2018 and another CCCT plant added in 2020); 123 MW of Class 1 DSM by 2014; 131 MW of Class 2 DSM by 2028, 40 MW of fuel cell capacity by 2016,50 MW of utility-scale biomass by 2016, and west-side front offce transactions in the out-years. No incremental wind capacity was added. $45/ton CO2 Tax and Medium Gas Prices · Moving from low to medium load growt, System Optimizer relied mostly on front office transactions and wind to serve the higher loads. The incremental resource mix included 600 MW of wind, CHP, distrbuted standby generation, west-side geothermal, and Class 2 DSM. · Moving from medium to high load growt, the optimal resource mix shifted to conventional thermal resources and fewer wind additions. A coal plant and IC aero SCCT plant were added in the east durng the first 10 years of the study period, with a consequent reduction in east-side wind (about 500 MW), while a combined cycle plant was added in the west. A sig- nificant amount of Class i DSM was also added (118 MW), along with Class 2 DSM. $45/ton CO2 Tax and High Gas Prices · Moving from low to medium load growth, the model chose wind and, despite the high gas prices, front office transactions, as the primar resources needed to serve load. By 2021, the 186 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results model added about 1,500 MW of wind. From 2017 through 2028, the model selected Mead front office transactions, averaging 460 MW per year. An IGCC plant was also added in 2025. . Moving from medium to high load growth, System Optimizer added 250 MW of solar in both 2014 and 2015, and added an east-side IC Aero SCCT in 2016. Other resource additions include: front office transactions (Mead and Mid-Columbia); 84 MW of Class 1 DSM by 2020; 96 MW of Class 2 DSM by 2025; over 300 MW of wind (400 MW added in the east- accelerated by two years-along with a 100 MW reduction in the west); 47 MW of distrb- uted standby generation, and; a 1,600 MW nuclear unit in 2015. $70/ton CO2 Tax and Low Gas Prices Moving from low to medium load growth, the dominant resources for meeting the higher loads are wind and front offce transactions. The model added 300 MW of wind by 2018. Selection of all available Mead and Mona front offce trnsactions began in 2018, while use of Mid-Columbia transactions ramped up from 2013 to full utilization by 2020 and beyond. Additional Class 2 DSM was also selected, reaching 86 MW by 2023. $70/ton C02 Tax and Medium Gas Prices Moving from low to medium load growth, the model chose a conventional pulverized coal plant in 2018 and additional wind. On the east-side, it added 911 MW of wind from 2018 through 2020, and deferred west-wide wind additions to 2019 and 2020. This wind resource timing sug- gests that the model's strategy was to dilute the coal plant's CO2 tax impact by adding wind. $ i OO/ton CO2 Tax and Medium Gas Prices Moving from low to medium load growt, System Optimizer relied on wind and front offce transactions to address the higher load growth. Unlike the $70/ton scenario, the model did not find it cost-effective to add a conventional coal resource and offset it with wind or other renew- abIes. In the out-years, the portfolio relied on both front offce transactions (primarly Mid- Columbia) and growt resources to meet load. $ 100/ton CO2 Tax and High Gas Prices Moving from low to medium load growth, System Optimizer depended heavily on wind re- sources to meet load, adding 1,351 MW in two years: 2019 and 2020. Additionally, the model increased reliance on front offce transactions, although this reliance was temporary in the east side (2018 through 2020). The model also chose addition DSM, including 110 MW of Class 1 DSM and 147 MW of Class 2 DSM. Thermal Resource Utilization Table 8.3 shows for gas and coal resources the average anual capacity factors for each portfolio, reflecting both existing and new resources. The capacity factors are reported for the entire simu- lation period, as well as for the following periods: 2009-2012 (captung plant operations before a CO2 tax goes into effect), 2013-2020, and 2021-2028. The impact of the C02 tax on plant dispatch is shown by comparng the capacity factors for the 2009-2012 and 2013-2020 periods for the varous gas price scenaros. Low gas prices cause the tax burden to fall on the coal plants, which realize a tyical 10-percentage-point utilization de- 187 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result crease under a $45 CO2 tax, a 20-percentage-point utilization decrease under a $70 CO2 tax, and a 50 percentage point decrease under the $100 CO2 tax. With a $100 CO2 tax, a number of coal plants become uneconomic to operate, dispatching with a capacity factor in the single digits. As gas prices increase in combination with a CO2 tax, the tax burden shifts to the gas plants, which see a large drop-off in utilization. Under a $100 CO2 tax and high gas price scenaros, coal plant utilization drops by 10 to 16 percentage points. 188 ............................................ ............................................ PaciffCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Table 8.3 - Average Annual Thermal Resource Capacity Factors by Portfolio 1 Low - June 2008 $0 33 39 61 47 86 87 88 872 Medium - June 2008 $0 30 30 40 34 86 87 88 873 High - June 2008 $0 34 17 16 20 86 87 88 875 Low - June 2008 $45 35 40 59 46 86 73 71 758 Medium - June 2008 $45 31 28 46 36 86 86 86 869 Low - Oct 2008 $45 42 40 64 50 86 76 73 7710 Medium - Oct 2008 $45 57 34 57 48 85 86 87 8611 High - Oct 2008 $45 38 14 18 21 86 86 85 8614 High - June 2008 $45 25 11 13 15 86 86 87 8617 Medium - June 2008 $70 30 29 48 37 86 72 68 7318 Low - Oct 2008 $70 42 42 75 55 86 54 46 5719 Medium - Oct 2008 $70 57 33 62 49 85 71 64 7120 High - Oct 2008 $70 37 12 14 18 86 82 77 8122 High - June 2008 $70 25 10 11 14 86 84 81 8324 Medium - June 2008 $ 100 28 31 48 37 86 52 37 5325 Low - Oct 2008 $100 41 43 69 53 86 34 29 4226 Medum - Oct 2008 $100 56 36 57 48 85 49 37 5127 High - Oct 2008 $100 36 13 10 16 86 71 60 6929 Hi!! - June 2008 $100 20 5 6 8 86 76 57 7146 Medium - Oct 2008 $8, C&T 35 35 58 44 86 87 88 8747 Medium - Oct 2008 $8, C&T 35 35 58 44 86 87 88 87Lo Lod Growt Core'Cases 0 ; 0 0 0 0 04 Low - June 2008 $45 34 39 63 48 86 71 68 737 Medium - June 2008 $45 30 24 38 31 86 86 86 8613 High - June 2008 $45 25 9 10 13 86 84 83 8416 Medum - June 2008 $70 29 24 41 32 86 70 64 7021 Hi!! - June 2008 $70 25 8 8 12 86 83 78 8223 Medium - June 2008 $ 100 27 28 40 33 86 48 32 4928 High - June 2008 $100 20 4 3 7 86 72 49 65Ilb Lod Grwt Core Ca 0 0 ' 006 Low - June 2008 I $45 36 40 55 45 86 73 7112 Medum - June 2008 I $45 32 27 42 34 86 86 87 15 High-June 2008 I $45 26 14 16 17 86 86 87 8ellvl ea. Rea C02 Cos EBælatin Wi Chaniiln Load Gntl 30 Medum-JUDe 2008 ~$4510$1791 31 31 58 42 86 83 53 31 High-JUDe 2008 I $45 to $179 1 28 14 21 19 86 86 66Sesii Case - HiIh Cos Onkme "0. 033 High - June 2008 I $100 I 24 8 9 11 85 85 868eiìllvi Ctes .:Clea BaLo Geern Avalbl " 034 Medium - JUDe 2008 $45 32 27 44 35 86 85 86 35 High-JUDe 2008 $45 30 17 16 19 86 86 8336 Medum - June 2008 $70 19 29 48 34 86 73 6737 High - June 2008 $70 25 10 6 12 86 82 73SeviCÍlse - Hih Pl CoiiCost o.d ' ",". "38 Medium - June 2008 I $45 I 33 32 48 38 86 87 8839 High - June 2008 I $45 I 24 10 11 13 85 80 84 8e1l Case. System-wie Orimii C02 Reduelon TaletB ' ""40 Medium - JUDe 2008 I Har Caii I 30 11 10 15 86 77 I 678enBilivi Ca -'planniDl Reserve Mari 1S"A. ' ' ,41 Medium - June 2008 I $45 I 31 26 I 41 33 86 86 8642 Medium - June 2008 I $70 1 29 27 43 34 86 72 6843 Medum - June 2008 I $100 I 28 31 48 37 86 52 36Seit Ctes - Alernatie Reewable Pol Â$$IUDÐtill rHiIh RPC exranl ;, 044 Medium - Oct 2008 I $8, C&T I 35 33 49 40 86 8745 Medium - Oct 2008 I $8, C&T I 34 33 I 58 43 85 86 8elÍvi Cae - Clss 3, DSM for Peak Loa Rednetn48 Medium - June 2008 I $45 I 32 I 29 I 47 37 I 86 ',' "" 75 86 86 , , 72 78 , 85." 86 85 73 79 87 82 88 88 75 , .1 86 73 52 ., 87 87 I86 I8686 ii All portolios include 1,520 MW of finn planed resoures, consisting of Lake Side 2, a 2012 eat PP A, 2009-2010 wind resours UDder development or contrt, coal plant tuine upgres, and Swift 1 hydr upgres. 189 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecon Results Sensitivity Case Results C02 Tax Real Cost Escalation and Demand Response Cases 30 and 31 were designed to test a real escalating CO2 tax and assumed decrease in load growth attbutable to the price response. The CO2 tax begins in 20 i 3 and is increased at a real straight-line escalation rate resulting in $7.86/ton increases per year staring in 2014. Load growth is maintained at a medium level through 2020, after which the growth converts to a low forecast for the remainder of the simulation period. For the two cases, all factors were held constat with the exception of the gas price forecast used: case 30 was based on the June 2008 medium gas price while case 31 was based on the June 2008 high gas price forecast. The case 30 portfolio included 5,498 MW of wind added by 2028, a nu- clear plant in 2025, and four carbon captue and sequestration plants in 2025, including an IGCC resource. The case 31 portfolio included more wind and front office trnsactions, but excluded the IGCC resource. The PVRR for case 3 i was $989 milion lower than case 30, an unintuitive result. Several factors contrbuted to this PVRR difference: · The 466 MW Utah IGCC with CCS unit added in the case 30 portfolio was not included in case 31. Instead, higher on-peak spot purchases and DSM programs costs were in- cured in case 31. · Case 31 included 750 MW more wind than case 30 in the first ten years. As a result of the additional wind, existing station fuel costs in case 31 were $1.1 bilion lower than in case 30. · While the capital costs for case 31 were $2.4 bilion higher than in case 30, the difference was offset by higher spot market sales in case 31. Normally the System Optimizer model wil build to the 12% plannng reserve margin level; however, it may exceed that if it is economic to add extr capacity and sell excess energy to the market. For example, in cases 30 and 31, the model added resources in excess of the planning reserve margin in 2025 through 2028 with the addition of a 3,200 MW nuclear plant. Significant excess energy is sold to market, contrbutig to $27.6 and $30.0 bilion PVR reductions for cases 30 and 31, respectively Early Clean Base-load Resource Availabilty Cases 34 through 37 were designed to test early availability of clean base-load generation re- sources by allowing System Optimizer to select such resources as early as 2020 rather than 2025 as specified for all other case definitions. Cases 34 and 35 were specified with a $45/ton CO2 tax and varing gas price forecasts (medium and high June 2008), while cases 36 and 37 were based on a $70 CO2 tax with the same gas price forecasts. For cases 34 and 35, no clean base-load technology was selected; however, the high gas price forecast used in case 35 caused the model to select about 1,000 MW of additional wind in the west and a 600 MW pulverized coal plant in Utah. Case 34 favored front offce transactions. 190 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results For cases 36 and 37 (both with the $70 CO2 tax), three clean coal resources were selected in 2020. For case 37, the model also selected a 3,200 MW nuclear station in 2020 as an alternative to market purchases in the out years. The PVRR for case 37 is about $2.3 bilion lower than case 36, and this cost relationship exists between cases 34 and 35 as well. As indicated above, the cost difference is attbutable to the model sellng excess energy to the market. High Construction Costs For cases 38 and 39, resource constrction costs were uniformly increased by 20 percent. Both were based on a $45 CO2 tax, medium load growth, and medium and high gas price forecasts, respectively. Comparing case 38 to case 8 (which used the same input assumptions except for constrction costs) indicates that the uniform percentage cost increase caused the model to select additional DSM programs along with dispatching existing units more often. Similarly, a comparison be- tween cases 39 and 14 indicate that the constrction cost increase, combined with a higher gas price forecast, caused the model to build about 3,000 MW less wind in case 39 than for case 14. The reduced wind build in case 39 was a major contrbutor to the lower PVRR relative to that for case 14 (a $5.16 bilion difference). In addition, the Utah IGCC unit picked in case 14 was not chosen in case 39. For case 39, the model preferred to buy from the market and relied more heav- ily on growth resources in the out years. In case 39, units were not dispatched as often as in case 14 and there was consequently less power to sell to the market. Carbon Dioxide Emissions Hard Cap Case 40 was designed to determine the optimal resource mix given a system-wide CO2 emissions hard cap patterned after the Oregon CO2 reduction targets from House Bil 3543 (10 percent be- low 1990 levels by 2020, and at least 75% below 1990 levels by 2050). The specific allowances per year reflected in the System Optimizer model are reported in Table 8.4. The cap is assumed to go into effect beginning in 2013. With these system emission constraints in place, the model optimizes the resource mix such that the system-wide average emissions stay at or below the an- nual caps. Table 8.4 - Hard Cap CO2 Emission Allowances 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 53.484 53.484 55.192 56.077 54.244 52.412 50.579 48.746 46.913 45.081 43.248 41.415 40.418 39.421 38.424 191 PaeifCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result 2024 2025 2026 2027 2028 37.427 36.430 35.433 34.436 33.439 For this sensitivity study, front offce transactions and growth resources were assigned a proxy CO2 emission rate. The rate is that for a Utah combined-cycle gas plant (F tye 2xl), reflecting a presumed long term reduction in the WECC CO2 footprint attbutable to the penetration of gas, wind and other renewable resources in the resource stack. Additionally, the June 2008 $0 CO2 tax forward price forecasts were used to ensure that the model's capacity expansion solution was constrained by the hard cap only, and not impacted by CO2 costs reflected in market prices. Table 8.5 compares the total emissions generated in case 40 to the three core cases with medium load, medium gas forecasts (Case 8, 17, and 24). The results indicate that the hard cap portfolio is most comparable to the $70 CO2 tax portolio, having total cumulative emissions of 896 and 931 milion tons, respectively. Table 8.5 - Portfolio Comparison, System Optimizer Total CO2 Emissions by Year 2009 54.0 54.5 54.4 54.4 2010 53.7 54.0 53.8 53.6 2011 54.5 54.1 54.0 53.6 2012 56.1 54.2 53.6 52.5 2013 54.2 54.1 51.46.3 2014 52.4 53.4 49.3 43.9 2015 50.6 54.3 47.8 38.3 2016 48.7 54.2 44.5 33.7 2017 46.9 55.3 47.6 35.7 2018 45.1 55.3 50.0 37.7 2019 43.2 55.7 50.5 37.7 2020 41.4 55.6 50.9 37.9 2021 40.4 54.1 50.0 37.6 2022 39.4 54.1 49.2 36.3 2023 38.4 54.0 47.9 32.6 2024 37.4 54.0 45.8 27.1 2025 36.4 53.6 36.2 12.3 2026 35.4 52.7 33.0 11.9 2027 34.4 52.3 30.8 11. 2028 33.4 51.9 29.8 10.8 Cumulative 896.4 1081.930.6 705.4Total 192 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results With the combination of medium June 2008 market prices and the hard cap, a significant reduc- tion in combined-cycle gas plant capacity factors happens from 2013 through 2015, followed by a gradual decrease through 2020. Figue 8.1 compares the average annual capacity factors for combined-cycle, coal, and simple-cycle combustion tubine resources reflected in the modeL. Ca- pacity factors for certain coal plants begin to drop off in 2015, while others are unaffected, re- flecting the relative dispatch cost differences among the plants. As noted earlier in the chapter, the impact of CO2 costs on plant dispatch cannot be assessed in isolation from fuel prices; utili- zation of thermal resource tyes in response to CO2 costs wil vary considerably based on the fuel price forecasts used for the simulations. Figure 8.1 - Average Annual Capacity Factors by Resource Type, CO2 Hard Cap Portfolio 90.0 ~'- ~ 80.0 .~-- Q,~;; E- ~ 70.0 ~~..==..~ 60.0 ..\'";;,J.. __ Combin-Cycle CTS 50.0 \....--Coal¡¡ € 40.0 \__ Simle-cyle CT..Q,.. ~ 30.0..~=== .. 20.0 ~..lO.... : 10.0.. 0.0 --..~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ A number of current IRP model limitations come into play for analyzing a hard cap scenario. First, the System Optimizer model does not allow emission rates to be assigned to spot market balancing transactions. This limitation is being addressed in an enhanced version of the model being developed for PacifiCorp by the model vendor. Second, the Plannng and Risk model is limited in that hard caps canot be directly enforced. To simulate the effect of a hard cap, the shadow cost for the last ton of incremental emissions calculated from System Optimizer can be entered into the Planing and Risk modeL. PacifiCorp is in the process of experimenting and validating this work-around approach. The test simulation resulted in anual CO2 emissions that were consistently below the hard cap. The stochastic costs results for the test simulation are as follows: mean PVRR of $41.0 bilion, upper-tail mean PVRR of $76.4 bilion, and production cost standard deviation of $ i 1.7 bilion. 193 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecon Result Alternative Renewable Policy Assumptions Case 44 is designed with a System Optimizer constraint that imposes a system-wide renewable generation requirement that reaches 25 percent of system load by 2028. Case 44 parallels case 8 in terms of other input assumptions; i.e., an $8 CO2 ta and medium June 2008 gas and electrc- ity prices. In order to satisfy the higher RPS requirement, the model selected a large amount of wind and some geothermal resources, especially in the mid and later years of the simulation period. With nearly 6,000 MW of wind resources built, this scenaro attbutes a relatively small PVRR to sales of clean energy to markets.47 The second alternative renewable policy scenaro was established to determine the best resource mix without the renewable production tax credit after 2012. Case 45 was created from case 44 with the base case RPS requirement, but the costs of resources qualifying for the PTC were ad- justed to remove the incentive after 2012. Without the PTC, the model selected: . No wind resources after 2012 . A west geothermal resource in 2023 . An IC Aero SCCT in 2016 intead of wind resources · More growth resource capacity in the out years This section presents stochastic cost, stochastic supply reliability risk, and capital cost perform- ance results for the 21 portfolios that constitute the group from which the preferred portolio was selected. For the stochastic cost measures, results are first shown for the thee individual C02 tax simulations, along with the straight average across the C02 tax results. The section concludes with tables that show the stochastic cost results as probability-weighted values. These values re- flect $5/ton increments of the expected value (EV) C02 tax, raging from $20/ton to $70/ton. Stochastic Mean PVRR Table 8.6 reports the stochastic mean PVRR for each of the candidate portfolios by C02 tax level, along with average values and associated rankngs. Cases 8, 5, and 9 ran the highest based on the average of the C02 tax results. 47 The cost results presume a regulatory world with both a $45/ton CO2 ta and an aggressive RPS requiement. In this sitution, the markets would be flooded with excess clean energy, drving market prices down. This dynamic is not captued in the scenario. Also, the reliability impacts and costs of such large amounts of wind being added to the system are not factored into the IR simulations. 194 ............................................. ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Table 8.6 - Stochastic Mean PVRR by Candidate Portolio 21,873 39,893 61,299 41,022 10 21,642 39,542 60,098 40,427 4 24,844 40,745 57,781 41,123 11 22,417 39,289 58,700 40,136 2 23,092 39,244 57,311 39,882 1 22,532 39,398 58,800 40,244 3 23,723 39,872 58,198 40,598 6 25,664 41,035 57,496 41,398 12 27,620 42,481 57,954 42,685 16 25,267 40,134 56,369 40,590 5 25,092 40,185 56,822 40,700 7 25,600 40,513 56,870 40,994 9 28,412 42,127 56,620 42,386 15 29,751 43,576 57,813 43,713 20 30,393 43,496 57,094 43,661 19 27,178 41,317 56,419 41,638 13 30,056 43,417 57,485 43,653 18 30,367 43,477 57,105 43,650 17 32,601 45,626 59,042 45,757 21 23,336 40,975 61,146 41,819 14 22,345 40,058 60,378 40,927 8 Table 8.7 reports the incremental mean PVR associated with imposing the $45/ton and $100/ton C02 taxes, as well as the average cost for the two tax levels. Table 8.8 reports the net power cost (variable cost less market sales revenue) and fixed cost by portolio for the three C02 tax simulations. Table 8.7 - Incremental Mean PVRR by CO2 Tax Level 18,019 17,900 15,901 16,872 16,152 16,866 16149 15,371 14,861 14,867 15,093 14,913 13,715 13,825 39,426 38,456 32,937 36,284 34,219 36,268 34,476 31,831 30,334 31,102 31,730 31,270 28,208 28,062 28,723 28,178 24,419 26,578 25,186 26,567 25,312 23,601 22,597 22,984 23,411 23,092 20,962 20,943 195 PadfiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result 13,103 14,139 13,361 13,110 13,025 17,639 17,713 26,700 29,241 27,429 26,738 26,440 37,811 38,032 19,902 21,690 20,395 19,924 19,733 27725 27,873 Table 8.8 - PVRR Net Power Costs and Fixed Costs by CO2 Tax Level 20.0 21 1.8 1 38.1 21 1.8 1 59.5 21 1.8 1 18.3 18 3.4 2 36.2 20 3.4 2 56.7 20 3.4 2 14.1 9 10.7 12 30.0 10 10.7 12 47.1 11 10.7 12 18.3 20 4.1 3 35.2 17 4.1 3 54.6 17 4.1 3 16.8 14 6.3 7 33.0 14 6.3 7 51.0 14 6.3 7 18.3 19 4.2 5 35.2 16 4.2 5 54.6 16 4.2 5 17.4 15 6.4 8 33.5 15 6.4 8 51.8 15 6.4 8 13.9 8 11.8 13 29.2 9 11.8 13 45.7 9 11.8 13 12.7 5 14.9 15 27.6 7 14.9 15 43.0 7 14.9 15 15.7 11 9.6 10 30.5 11 9.6 10 46.8 10 9.6 10 16.1 13 9.0 9 31.2 13 9.0 9 47.8 13 9.0 9 15.8 12 9.8 11 30.7 12 9.8 11 47.1 12 9.8 11 13.2 7 15.2 16 26.9 6 15.2 16 41.4 6 15.2 16 12.1 1 17.6 18 25.9 4 17.6 18 40.2 4 17.6 18 12.4 4 18.0 20 25.5 3 18.0 20 39.1 2 18.0 20 14.1 10 13.0 14 28.3 8 13.0 14 43.4 8 13.0 14 13.1 6 17.0 17 26.4 5 17.0 17 40.5 5 17.0 17 12.4 3 18.0 19 25.5 2 18.0 19 39.1 3 18.0 19 12.2 2 20.4 21 25.3 1 20.4 21 38.7 1 20.4 21 17.9 16 5.4 6 35.6 18 5.4 6 55.7 18 5.4 6 18.2 17 4.1 4 35.9 19 4.1 4 56.2 19 4.1 4 Risk-adjusted PVRR As discussed in Chapter 7, risk-adjusted PVR is calculated as the stochastic mean PVR plus five percent of the 95th percentile PVRR, with the latter term representing a cost premium re- flecting the tail risk for the portfolio. This measure constitutes 45 percent of the overall compos- ite portfolio preference score for each candidate portfolio. 196 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Table 8.9 reports the risk-adjusted PVRR values for each of the portolios by CO2 tax level, along with average values and associated rankngs. Cases 8, 5, and 9 rank the highest in line with the stochastic mean PVRR values reported in Table 8.3. Figue 8.2 shows the range of risk- adjusted PVRR for each portfolio by CO2 tax level, matched up with the amount of incremental wind capacity included. It is apparent from the char that the variation in risk-adjusted PVR across the CO2 tax levels generally decreases as the amount of portfolio wind capacity increases. Figues 8.3 through 8.7 show capacity by resource tye for each portfolio, ranked by risk- adjusted PVRR averaged across the CO2 tax simulations. The resource tyes include wind, en- ergy effciency, average annual front office transactions, clean base load coal, and IC aero SCCT resources. These charts indicate the correlation between the amount of primary resource tye added to the portfolios and the risk-adjusted cost. As can be seen from Figue 8.3, the positive correlation between risk-adjusted PVRR and amount of wind capacity added is clearly evident. Similarly the negative correlation between risk-adjusted PVRR and the volume of front offce transactions is evident in Figure 8.4. Table 8.9 - Risk-adjusted PVRR by Portfolio 23,992 43,093 66,090 44,392 12 23,506 42,492 64,586 43,528 4 26,610 43,555 61,952 44,039 9 24,365 42,270 63,154 43,263 2 24,942 42,138 61,628 42,903 1 24,489 42,387 63,261 43,379 3 25,676 42,815 62,585 43,692 6 27,472 43,856 61,646 44,324 11 29,422 45,340 62,046 45,603 16 27,173 43,021 60,574 43,589 5 27,009 43,093 61,077 43,726 7 27,533 43,427 61,111 44,024 8 30,314 44,957 60,666 45,312 15 31,599 46,442 61,886 46,642 20 32,292 46,363 61,088 46,581 18 29,107 44,193 60,544 44,615 13 31,986 46,290 61,528 46,602 19 32,251 46,338 61,087 46,559 17 34,596 48,571 63,133 48,767 21 25,255 43,973 65,681 44,970 14 24,233 43,022 64,885 44,047 10 197 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecon Result Figure 8.2 - Risk-adjusted PVRR Range and Wind Nameplate Capacity by Portfolio 7,000 70,000 6,000 ~ 5,000 .. ;5 ~ 4,000ui ~ 3,000 osZ 'C ~ 2,000 1,000 o I I I i I Ii i 1 T I I i J -f------ ..+1 +-++~++++++ + .. 60,000 ~ 8u~ 50,000 ~ __ ~ ElII = ~ .~ 40,000 ~ ~ ..ci '"= = ~ ~30,000 ~ i i: rr "C 20,000 ~=:s".:10,000 ¡ o 8 5 9 2 10 17 47 18 1 19 3 11 46 25 20 14 26 27 24 22 29 Case Numbr Figure 8.3 - Wind Capacity for Portfolios Ranked by Risk-adjusted PVRR 8,000 Portfolios rankedfromlollst to highest risk-iusted PVR (left to right) 7,000 ~6,000 ------ ....5,000 --f----'a..e"~4,000 --f---- ãl....3,000 -~-f-----(.."".."2,000 ----f----i:"U t'g 1,000 -e-tl -----f---tI~ 0 8 5 9 2 17 10 18 19 3 47 11 1 25 46 20 14 27 24 26 22 29 Case Number 198 ............................................ ............................................ PacifìCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Figure 8.4 - Energy Efficiency Capacity for Portfolios Ranked by Risk-adjusted PVRR 2,400 Portolios ranked from lowes t to highes t ris k -adjus ted PVRR (left to right) 2,200 'i 2,00 --------'C ~ ~~1,80 ------------~-= .... ...- .... -= i' ¡; e 1,60 -------------- .. ..i:Z.. '-=1,40 ----------~----¡; 1,200 -----~---- 1,00 8 5 9 2 17 10 18 19 3 47 11 1 25 46 20 14 27 24 26 22 29 Case Numbr Figure 8.5 - Annual Average Front Offce Transaction Capacity for Portfolios Ranked by Risk-adjusted PVRR 2,00 Portfolios ranked from lowst to highest risk-austedPVR (left to right) 1,800 ¡¡ 1,60 --- ~ ~ 1,40 ----- ~ ~;¡ J! ê I 1,200 -------- If .. ~ i 1,00 ---------- .. l! ~ ~800 --r-r------------- ~ :E .. .."" =60 f----, =--r----------- 1: =Q -i.. ~00 400 --f-------~------- 200 --f-----n -n f------ 0 8 5 9 2 17 10 18 19 3 47 11 1 25 46 20 14 27 24 26 22 29 Case Number 199 PacißCorp - 20081RP Chapter 8 - Modeling and Portolio Selecton Result Figure 8.6 - Clean Base Load Coal Capacity for Portolios Ranked by Risk-adjusted PVRR 1,60 Portfolios raned from lowest to highest risk-iusted PVR (left to right) ~ 1,40 $ 1,200.! eoS 1,00'"~ 'C 80 --~---~f-..'C'C 0(60 --I-----t-'i0u 40 --I--f----t-='"J/U 200 f-i--i--!-i- o I-, 8 5 9 2 17 10 18 19 3 47 11 1 25 46 20 14 27 24 26 22 29 Cae Numbr Figure 8.7 - IC Aeroderivative SCCT Capacity for Portolios Ranked by Risk-adjusted PVRR 'i 300=== ~ 250'i ~ ~ 200~ $; .!o eo ~ ~ 150~z ~ ~~ ¡ 100 .. 0(~ ~ 0(u.. Portfolios ranked from lowest to highes t ris k-austed PVR (left to rigbt) 50 o 8 5 9 2 17 10 18 19 3 47 11 ~46WMV24~22~ Case Numbr Customer Rate Impact The portfolio customer rate impacts for each CO2 tax simulation, and averaged across the simu- lations, are reported in Table 8.10. This measure is given a 20 percent weight for determining the overall portolio preference scores. 200 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result With no CO2 tax, the portfolios for cases i and 2 perform the best due to the lack of wind in- vestment. Case i, which has the lowest rate impact, has no wind additions other than the firm planned resources in 2009 and 20 i o. Case 2, which raned second, has only 338 MW of wind added by 20 i 8, but includes a 600 MW super-critical coal plant in 20 i 8. Under the $45 CO2 tax, the top performers are the portfolios for cases 9 and 5. Case 9 has slightly more wind resources than case 5 (by 230 MW) and less front offce transactions. Under the $100 CO2 tax, the top per- formers are cases 20 and 17. Case 20 relies on a nuclear plant in 2025 and more wind than for case i 7. When averaging the results across the CO2 tax levels, cases 9 and 5 fare the best; they rank first and second, respectively. Table 8.10 - Customer Rate Impacts by Portfolio 2.82 6.28 10.16 6.42 8 2.89 6.31 10.06 6.42 7 3.49 6.58 9.74 6.61 14 2.95 6.11 9.54 6.20 2 3.08 6.19 9.48 6.25 5 2.93 6.09 9.52 6.18 1 3.24 6.31 9.64 6.40 6 3.34 6.22 9.11 6.22 3 4.09 6.97 9.80 6.95 16 3.48 6.22 9.03 6.24 4 3.61 6.41 9.33 6.45 9 3.66 6.43 9.28 6.46 10 4.24 6.62 8.92 6.59 13 4.78 7.30 9.70 7.26 18 5.22 7.51 9.70 7.48 20 3.95 6.57 9.20 6.58 12 5.09 7.41 9.66 7.39 19 4.99 7.19 9.27 7.15 17 5.71 7.96 10.07 7.91 21 3.16 6.55 10.22 6.64 15 2.99 6.39 10.09 6.49 11 Cost Exposure under Alternative Carbon Dioxide Tax Levels As discussed in Chapter 7, cost exposure is the difference between a portfolio's risk-adjusted PVRR and the risk-adjusted PVR of the best-performing portfolio for a given CO2 tax leveL. Portfolio performance under this measure is gauged by the size of the worst loss that could be realized under the thre CO2 tax levels if the chosen portfolio turns out to not be the optimal one based on risk-adjusted PVRR. This measure was assigned a 15 percent weight for determining the overall portfolio preference scores. 201 PadfìCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Table 8.11 presents the cost exposure results for the CO2 tax simulations, with no probability weights applied. As indicated in the table, the potential cost exposure is large for portfolios built in response to an extreme C02 tax value, and where the realized CO2 tax tus out to be at the other extreme. The cost exposures range from $30 milion for case 17 under a realized $ i OO/ton tax, to $11 bilion for case 29 given no CO2 tax. (Note that portfolios with no cost exposure value reported have the lowest cost at that C02 tax leveL.) To be consistent with the probability-weighted approach used to ran portfolio performance, the maximum loss values are probability-weighted as well. Table 8.11 - Portfolio Cost Exposures for Carbon Dioxide Tax Outcomes 5,546 5,546 13 4,042 4,042 10 3,104 1,408 3,104 5 859 2,610 2,610 3 1,436 1,084 1,436 1 983 249 2,717 2,717 4 2,170 678 2,040 2,170 2 3,965 1,718 1,102 3,965 8 5,916 3,202 1,502 5,916 15 3,667 883 30 3,667 7 3,503 955 533 3,503 6 4,026 1,290 566 4,026 9 6,808 2,819 122 6,808 16 8,093 4,304 1,342 8,093 17 8,786 4,225 543 8,786 20 5,601 2,055 5,601 14 8,480 4,152 984 8,480 18 8,745 4,200 543 8,745 19 11,090 6,433 2588 11,090 21 1,749 1,835 5,137 5,137 12 727 885 4,341 4,341 11 Portfolio Capital Costs Figues 8.8 and 8.9 show the capital costs for each portfolio, expressed on a net present value basis for costs accrued for 2009-2018 and 2009-2028, respectively. (The 2009-2018 capital cost measure was assigned a five percent weight for determining the portfolio preference scores.) The portfolios with the lowest capital costs are for cases 1,2, and 5. Case 1, with a capital cost of $0.5 bilion, relies more heavily on market purchases, distrbuted generation, and Class 1 DSM than the other low capital cost portfolios, and reflects no incremental wind investment past 2010. 202 ............................................ ............................................ PacifìCorp - 2008 IRP Chapter 8 - Modeling and Portolio Seleaion Result In contrast, the high-cost portfolios-such as cases 29, 22, 27, and 24-reflect large investments in wind, clean coal, and nuclear plants to mitigate the CO2 tax liabilities. Figure 8.8 - Portfolio Capital Costs, 2009-2018 ..$6 .æ"~..$5=...,....i: l:$4Z,;.. ,-i: ~==e e $3~ Š~ e ..z $2...æ...,eU $1ii:"U $0 4R 4R 4.9 4.9 4.9 5.1 4.0 4.0 3.5 3.1 3.2 3.3 2.6 2.0 i.-e- L.2 05 0.6 V.I -~~ïli 2 47 5 9 46 10 8 18 19 17 3 11 25 20 24 26 27 29 14 22 Case Number Figure 8.9 - Portolio Capital Costs, 2009-2028 $18 ..1 .æ $16 ie e 15.7 15.8"~14.8..=..$14.,'J.J iJ.J ---....i:l:$12 11 e -----Z,;10.2.. ,- ~ ~$10 ------= =9.1 ;i ¡§8.1 82.. .i: e $8 "H ------ ~..Z $6..5.0 ------ .æ 4.9...," .e $4 --------U ~2.7 2.7 2.8 1.9i:$2 -----------": Iu $0 1 2 5 47 9 46 8 10 18 17 19 3 II 25 14 20 26 22 27 24 29 203 Paci~Corp - 2008 IRP Chapter 8 - Modeling and Portolio Selection Result The impact of such investments on capacity planing reserve margins, paricularly in the out years, is indicated in Figue 8.10. This figue shows average annual reserve margins for 20 i i to 2018 (reflecting the start of the system capacity short position) as well as for 2011 to 2028. The association between extensive clean generation investment and excess planning reserve marfins is clearly seen with margins far exceeding the 12 percent requirement reflected in the modei.4 Figure 8.10 - Average Annual Planning Reserve Margins 17.0% 165% ':16.%= =155%'5i..=15,0%~~145%....14.0%~'" ~135%-=13.0%===125%~~12,0%~=..11.5%~..~11.0% 105% 10,0% . Averae (2011-2018) a Averae (2011-2028) 2 3 4 5 8 9 10 11 14 17 18 19 20 22 24 25 26 27 29 46 47 Case Number 48 The 2011-2028 average anual planning resere margins for case 11, which was based on a $45/ton CO2 tax, is higher than for the other core cases with this ta leveL. Unlike the other $45 tax cases, case 1 i was modeled with high gas prices. This case experienced greater west-east transfers than the other cases for 2026-2028, supported by a relatively larger amount of growt resources and front offce transactions on the west side. 204 ............................................ ............................................. PacißCorp - 200BIRP Chapter B - Modeling and Portolio Selecton Results Figue 8.11 shows the impact on portfolio capital costs given a 20 percent increase in the per- kilowatt capital cost for all resources. Figure 8.11- Incremental Portfolio Capital Costs (20% increase from Base per-kW values) $3,500 $3,00 $2,500 ~~$2,00= ~$1,500~ $1,00 $500 $0 Incremental Portolio Constrction Cost (20% above base per-kW Resource Capital Costs) 1 2 5 47 9 46 8 10 18 17 19 3 11 25 20 14 26 24 27 22 29 Case Number Upper-tail Mean PVRR Table 8.12 reports the upper-tail mean PVRR results for the individual C02 tax simulations and the average. Cases 22 and 14 pedorm the best. Case 22 includes both pulverized coal and nuclear plants in response to a $70/ton CO2 tax and high gas/electrcity prices. Case 14 also includes pulverized coal as well as an IGCC plant in 2025. Both portolios featue heavy reliance on wind resoures (7,200 MW for case 22 and 6,300 MW for case 14), and consequently rely on less front offce transactions and gas plant dispatch. Table 8.12 - Upper-tail Mean PVRR by Portfolio 205 PaeifCorp - 2008 iRP Chapter 8 - Modeling and Portolio Selecton Result 53,047 74,487 106,969 78,168 19 49,843 70,581 101,048 73,824 14 53,347 74,736 107,163 78,415 20 52,335 72,023 102,956 75,771 15 44,638 65,642 94,453 68,244 6 44,778 65,453 93,021 67,751 2 49,328 68,766 96,941 71,678 11 50,209 69,834 98,591 72,878 13 50,320 69,705 98,022 72,682 12 46,767 66,084 92,486 68,446 7 45,569 65,404 91,170 67,381 1 46,980 65,939 91,142 68,020 4 48,112 66,967 94,182 69,754 10 47,587 66,665 92,520 68,924 8 46,732 65,701 90,907 67,780 3 48,734 67,670 92,365 69,590 9 52,224 74,442 107,516 78,061 18 51,559 73,905 107,252 77,572 17 The following charts present the megawatt capacities for the portfolios raned by upper-tail mean PVRR, focusing on the resource tyes most consequential for determning upper-tail cost risk. Figures 8.12 and 8.13 show the portolio wind and energy effciency capacities, indicating that upper-tail cost risk is inversely proportional to the amount of these resources added. Figues 8.14 and 8.15 show the front offce transactions (on an average anual basis) and peaking gas capacities, respectively. Portolios with more of these resource tyes tend to exhibit higher up- per-tail cost risk. 206 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Figure 8.12 - Wind Capacity for Portolios Ranked by Upper-tail Mean PVRR 8,000 Portolios ranked from lowest to highest upper-tall mean PVR (left to right) 7,000 ãl 6,000:g ~~ ~ 5,000.. ., ëi -= a. Q. 4,000OI .,U e 'g .; 3,000 ~ -- --- ---- ------- -------- ---------- ---------- I 22 14 27 24 3 11 20 26 29 25 17 19 18 8 10 2 47 46 5 9 1 Case Number 2,000 1,000 o Figure 8.13 - Energy Efficiency Capacity for Portfolios Ranked by Upper-tail Mean PVRR 2,400 Portfolios ranked from lowest to highest upper-tall mean PVR (left to tight) 2,200 ~ ~ :l 2,000 - ." .!-i il ~ ~ 1,800 -- j z ië g'¡¡ ; 1,600 -f--~ :-t" -i.. -c co 1,400¡¡ =~-f--f-- CCS 1,200 --f---- 1,000 22 14 27 24 3 11 20 26 29 25 17 19 18 8 10 2 47 46 5 9 1 Case Number 207 Paci~Corp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Figure 8.14 - Front Office Transaction Capacity for Portfolios Ranked by Upper-tail Mean PVRR 2,00 Portfolios ranked from lowest to highest uppr-tail mean PVR (left to right) 1,800 'ã I--~ ~ 1,600 ~ ~ 1,400 --I-- l l 1,200 '-f-- if .. ~ ~ 1,00 --'-l-I- ~ ~800 !-----l-f- Ë ::.. ..60 I-----l-I-f- =, = 1: =., ~40 -------.. "-'" 200 -------- 0 22 14 27 24 3 11 20 26 29 25 17 19 18 8 io 2 47 46 5 9 1 Case Number Figure 8.15 - Intercooled Aeroderivative SCCT Capacity for Portfolios Ranked by Upper- tail Mean PVRR 300 'l Portolios raked from lowest to blgbest uppr-tl mean PV (left to rigbt) ~ ~ 250 !3 ~.. " i =. 200 l-f-æ ..",i: !( r ~ 150 --l-e-.- I:.: "~ ..ci ~100'" ~---- ~ ;;= E =.. =50 ~--~ ~ U.. 0 22 14 27 24 3 11 20 26 29 25 17 19 18 8 10 2 47 46 5 9 1 Case Number Mean/Upper-Tail Cost Scatter Plots Figues 8.16 though 8.18 are scatter plots of portfolio cost (mean PVR) versus high-end cost risk as represented by the upper-tail mean PVR. These scatter plots show the trade-off between cost and risk at the different CO2 tax levels. 208 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Across the CO2 tax levels, there are no portfolios that dominate all others for both mean PVRR and upper-tail mean PVRR. For the $O/ton tax, the case 2 and 3 portfolios dominate all others for mean PVRR and upper-tail mean PVRR, respectively. For the $45/ton tax, the dominant (or nearly dominant) portfolios are represented by cases 8 and 5 for mean PVRR, and cases 22, 14, and 3 for the upper-tail mean. For the $100/ton tax, the dominating portfolios include cases 17 and 25 for mean PVRR, and 27,22, and 24 for upper-tail mean PVRR. Figure 8.19 is the scatter plot for the cost and risk measures expressed as averages across the C02 tax simulations. Cases 8 and 5 dominate on mean PVRR, while cases 22, 27, and 14 domi- nate on upper-tail mean PVRR. Figure 8.16 - Stochastic Cost versus Upper-tail Risk, $0 CO2 Tax 60,0 58.0 56, ..c0 54,0lIIII52,0~lL C...,::50.0 ~ 8-48.0Co:: 46, 44,0 $0 C~ Tax Level .Cas 1 I Cas v';"''' 5X ja:i 4~ ase 10 II A Case :¡Case 47 Crfl1\ C se 19 C:!eB I .I Case 29 (ase 17 Case 25 . Case 20 I IcasE 24X"..,.. Case 14 )lCase11.Case 2- A Cas 3 42.0 21,0 22.0 31,0 32,0 33.023,0 24,0 25,0 26,0 27.0 28.0 29.0 Stochastic Mean PVRR (BIllon $) 30,0 209 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecon Result Figure 8.17 - Stochastic Cost versus Upper-tail Risk, $45 CO2 Tax 82.0 80.0 78.0 ..76.0c ,gl 74,0 IIII::72.0iic..Gl .:E 70,0 ~Gl 68.0Q.Q.:: 66.0 64,0 62.0 39,0 39.5 $4 CO2 Tax Level case 1 40,0 40.5 41,0 41.5 42,0 42,5 43.0 43.5 44,0 44,5 45,0 45,5 46,0 Stostc Mean PVRR (Billon $) Figure 8.18 - Stochastic Cost versus Upper-tail Risk, $100 CO2 Tax 116.0 114,0 112.0 110,0 ..108,0c ,g 106.0a ~104,0 it 102,0c..Gl:I 100,0 ii ~98,0..Q.Q.96,0:: 94,0 92,0 $100 CQi Tax Level . ""'''' ¡ r."" ? Cæ 511."'"'".Â !I cae 7 ase46 va;: lU )10 se8 case 17 GaS:.ö .cae 9 case s~11 iiCæ 3. ~se ~D _~ca ¡29 Cà 14 "Case 2 XC!e22Case 2 90,0 56,0 56.5 57.0 57.5 58,0 58.5 59.0 59,5 60.0 60,5 61.0 61.5 62.0 Stoastc Mean PVRR (Billon $) 210 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Figure 8.19 - Stochastic Cost versus Upper-tail Risk, Average for CO2 Tax Levels 85,0 83,0 81.0 ..79,0c ,g !l noiiii;:iic 75... ~ ~no lQ.no:: 69,0 67,0 65. 39,0 Mean Across All C~ Tax Levels ($0, $45, $100 per ton) CaseS.+ Case 8 )I 39.5 40,0 40.5 41,0 41,5 42,0 42,5 43.0 43.5 44.0 44,5 45.0 45.5 46,0 Stochastic Mean PVRR (Bilion $) Fifth and Ninety-Fifth Percentile PVR Table 8.13 reports the 5th and 95th percentile PVRR results for each of the CO2 tax simulations. Straight averages across the simulations are also shown. The 95th percentile PVRRs are incorpo- rated into the risk-adjusted PVRR results shown above. Table 8.13 - 5th and 95th Percentile PVRR by Portfolio 12,783 42,378 25,788 64,012 37,447 95,821 25,339 67,404 13,242 37,288 26,367 58,989 38,006 89,768 25,872 62,015 16,195 35,313 28,995 56,205 39,187 83,429 28,126 58,316 13,824 38,965 26,143 59,619 36,667 89,078 25,544 62,554 15,227 37,008 25,594 57,877 36,925 86,354 25,916 60,413 13,845 39,135 26,254 59,775 36,833 89,222 25,644 62,711 15,530 39,069 26,786 58,877 37,377 87,726 26,564 61,890 16,042 36,143 29,664 56,410 38,989 83,010 28,232 58,521 18,323 36,047 31,913 57,172 39,748 81,853 29,995 58,357 17,939 38,113 27,689 57,738 37,331 84,101 27,653 59,984 17,497 38,334 27,366 58,161 37,552 85,095 27,472 60,530 18,038 38,656 27,945 58,283 37,923 84,818 27,968 60,586 19,002 38,039 31,958 56,595 38,589 80,918 29,849 58,518 20,516 36,950 32,172 57,320 39,783 81,455 30,823 58,575 211 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result 21,323 37,971 33,686 57,338 39,783 79,882 31,597 58,397 18,385 38,596 29,912 57,527 38,267 82,511 28,855 59,545 21,408 38,599 33,688 57,464 40,050 80,862 31,715 58,975 21,363 37,689 33,220 57,212 40,064 79,636 31,549 58,179 23,269 39,889 34,029 58,893 42,020 81,822 33,106 60,201 15,085 38,385 27,953 59,954 39,326 90,703 27,455 63,014 14,048 37,753 26,881 59,283 38,290 90,150 26,406 62,395 Production Cost Standard Deviation The standard deviation of stochastic production costs for each portfolio and the average is shown in table 8.14. (Probability-weighted average values based on alternative expected value C02 tax levels are reported in Table 8.27.) This risk measure was assigned a five percent weight for de- termination of the portolio preference scores. As expected, portfolios that rely on coal, wind, and nuclear resources exhibit the lowest levels of production cost variability. Table 8.14 - Production Cost Standard Deviation 10,486 12,939 18,966 14,130 21 8,795 11,312 17,234 12,447 18 6,484 8,845 14,129 9,819 9 9,067 11,549 17,422 12,679 19 8,083 10,534 16,156 11,591 14 9,104 11,565 17,412 12,694 20 8,552 10,733 16,424 11,903 15 6,499 8,778 13,958 9,745 8 6,106 8,256 13,205 9,189 6 7,438 9,799 15,133 10,790 11 7,655 10,033 15,439 11,042 13 7,566 9,906 15,238 10,904 12 6,336 8,460 13,255 9,350 7 5,860 7,854 12,459 8,724 2 5,904 7,955 12,530 8,796 4 6,808 9,041 14,090 9,980 10 6,094 8,201 12,880 9,058 5 5,893 7,909 12,434 8,745 3 5,920 7,844 12,242 8,669 1 8,628 11,142 17,029 12,266 16 8,708 11,251 17,188 12,382 17 212 ............................................ ............................................ PacifiCarp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Energy Not Served (ENS) Figures 8.20 and 8.21 below show, respectively, the average annual amount of Energy Not Served (ENS) for the periods 2009-2028 and 2009-2018. Figure 8.22 shows the upper-tail mean ENS by portfolio. As explained in Chapter 7, these are measures of high-end supply reliability risk. Portfolios with low ENS include coal and nuclear, as well as relatively large quantities of wind. Portfolios with relatively high amounts of ENS rely to a greater degree on front office transactions, and in the out-years, growth resources. Figure 8.20 - Average Annual Energy Not Served, 2009-2028 ($45 C02 Tax) Average Anual GWh for 2009 - 2028 280 240 200 -=160 - ~"120 --I-I----¡--- 80 ----I----I-I----I-~- 40 I-I--i--I---I----I-I--I-I-I--- 0 Ca Case Case Case Case Ca Case Ca Case Case Case Case Case Ca Case Case Ca Case Ca Case Ca 22 29 24 27 14 26 3 20 11 25 2 17 18 19 47 46 8 5 10 9 1 I. West 15 14 15 15 17 17 20 19 19 23 32 30 33 33 33 33 34 40 37 42 64 1I~ East 56 58 58 61 62 63 69 71 73 85 90 97 97 97 98 ios 109 ios 112 114 165 213 PadffCorp - 2008 iRP Chapter 8 - Modeling and Portolio Selecton Result Figure 8.21- Average Annual Energy Not Served, 2009-2018 ($45 CO2 Tax) Avemge Anual GWh for 2009 - 2018 100 90 80 70 60.= ~50 - 40 ----f--- 30 -r------------f--- 20 --f---f-----r-------f--- 10 -~f---f-----f-------f--- 0 Case Cas Case Case Case Ca Ca Ca Ca Ca Ca Case Ca Ca Ca Case Ca Case Case Case Case 14 22 24 29 3 27 II 25 20 26 17 19 18 8 2 5 9 10 47 46 I I_West 4 4 4 4 5 5 5 5 5 5 5 6 6 7 9 9 9 7 9 9 13 1~I East 23 23 25 25 25 26 28 28 29 29 29 31 32 33 30 31 31 34 35 40 37 Figure 8.22 - Upper-tail Energ Not Served, $45 C02 Tax Average Annual Amounts for 2009-2028 1,500 1,250 .c 1,000 ~ 750e" 500 250 o Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case Case22 29 24 14 27 26 03 20 11 25 17 18 19 02 47 46 08 10 05 09 01 Loss of Load Probabilty As discussed in Chapter 7, Loss of Load Probability (LOLP) is represented by the probability of an occurence of Energy Not Served. Table 8.15 displays the average LOLP for each of the can- 214 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selection Result didate portfolios durng the summer peak at various ENS event thresholds, modeled using the $45 CO2 tax assumption. 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. Table 8.16 displays the year-by-year results for the threshold value of 25,000 MWh. For each year, the LOLP value represents the proportion of the 100 simulation iterations where the July ENS was greater than 25,000 MWh. This is the equivalent of 2,500 megawatts for LO hours. The anual average LOLPs from Table 8.16 constitute one of the supply reliability risk measures used for overall portfolio preference scoring, and is given a five percent weight for this purose. Table 8.15 - Average Loss of Load Probabilty by Event Size During Summer Peak 44% 37% 25% 19% 14% 10% 3% 1% 215 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Table 8.16 - Year-by-Year Loss of Load Probabilty of ENS Event:; 25,000 MW in Jul 4%4%4%4%4%4%4%4%4%4% 14%12%10%12%12%12%12%11%9%11% 9%9%8%9%9%9%9%9%8%9% 7%7%5%7%7%7%7%7%5%7% 17%14%10%14%12%17%16%13%10%12% 18%17%8%17%17%19%17%10%8%16% 17%15%10%15%15%15%15%10%10%10% 11%11%13%11%15%11%15%13%11%13% 8%6%12%6%14%6%14%11%11%14% 23%19%19%20%23%20%23%19%17%21% 21%12%16%15%18%15%18%15%15%17% 22%15%19%19%23%19%23%19%19%22% 24%17%22%19%20%21%24%22%22%23% 26%12%15%17%16%17%22%16%15%21% 30%25%25%25%30%28%30%25%24%30% 30%23%21%22%23%25%27%23%21%24% 39%27%27%36%39%36%35%30%27%36% 30%25%25%27%29%26%29%26%25%29% 26%21%22%25%27%25%27%23%22%23% 35%25%25%26%29%29%31%20%23%28% 216 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results 18%18%13%8%8%13%13%10%9%17%17% 15%10%10%10%10%10%10%10%10%15%15% 13%13%13%13%13%13%13%13%13%16%15% 14%14%13%11%11%12%13%12%12%21%14% 21%21%21%17%20%20%21%21%19%26%23% 17%17%16%15%15%15%16%16%15%21%18% 22%22%21%19%21%21%21%21%21%24%23% 23%23%23%22%23%23%23%23%23%25%23% 20%21%17%15%16%19%17%18%17%20%18% 30%30%28%25%25%28%29%30%27%31%29% 25%24%24%21%21%22%22%24%21%24%24% 36%36%29%23%24%33%24%24%23%34%33% 29%31%27%25%24%29%24%24%24%29%28% 23%22%21%21%20%22%20%20%20%25%24% 29%28%23%22%22%28%22%18%20%27%26% Table 8.17 reports selected stochastic cost and risk results for the cases developed with low and high load growth assumptions. Comparable medium load growth cases are included for reference purposes. The results are also grouped by gas price scenaro to highlight the influence of gas and associated electricity prices on portfolio cost as load growth increases. One observation gleaned from Table 8.17 is that the mix of resource added in response to higher load growth reduces high-end cost risk and Energy Not Served. The System Optimizer model tended to add wind and base-load resources (or CCCT capacity under low gas price scenarios), which reduced upper-tail costs. Much of the cost reduction is seen in the form of net revenue gains from spot market balancing transactions. Table 8.17 - Stochastic Performance Results for Alternative Load Growth Scenario Cases Low - June 2008 Low - June 2008 Low - June 2008 Medium - June 2008 Medium - June 2008 Medium - June 2008 39,877 39,244 40,027 26,747 25,594 27,513 74,618 70,581 67,054 11,395 10,534 9,462 255.1 143.4 38.3 59,769 57,877 56,698 8,940 117.5 8,256 79.0 217 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results 94.0 72.1 22.2 PacifiCorp compared stochastic cost and risk measures for portfolios built to meet 12 percent and 15 percent capacity planning reserve margins. This comparative analysis also examined the im- pact of the resource mix as the cost of CO2 emission compliance increases, since resources added in response to high CO2 costs, such as wind and energy effciency programs, are not subject to fuel price volatility.49 The relevant comparsons are cases 8 and 41 ($45 CO2 tax), cases 17 and 42 ($70 CO2 tax), and cases 24 and 43 ($100 CO2 tax). Stochastic simulations were only con- ducted with the $45 CO2 tax since ENS is not materially affected by differences in emission cost. For the $45 CO2 tax cases, increasing the planning reserve margin from 12 percent to 15 percent resulted in additional wind (135 MW and east-side geothermal (35 MW) resources, as well as increased reliance on front offce trnsactions on both the east and west sides, prior to 2016. The System Optimizer model added an IC aero SCCT in 2016 (261 MW and subsequently cut back on additional wind resources and front offce trsactions. Table 8.18 shows the stochastic cost and risk results for the two case portfolios (cases 8 and 41), while Table 8.19 shows the detailed PVRR cost breakdown. Building to the 15-percent PRM level increased costs and high-end cost risk due to higher fuel and market purchase costs. Partially offsettg these higher operating costs was reduced system balancing costs and lower capital expenditues from the smaller wind investment. (The contrbu- tion of the ENS cost as a proportion of total variable costs is less than that reported in the 2007 IRP due to the tiered cost approach applied for this IRP. See the discussion on ENS in Chapter 7 for details.) 49 The IRP modeling of wind does not captue the stochastic behavior of wind generation, so related supply reliabil- ity risks are not captued in the stochastic analysis. 218 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results As expected, with the higher PRM, supply reliability is enhanced as measured by average annual ENS and significant-event LOLP during July. Dividing the incremental portfolio cost by the re- duced amount of ENS (487 GWh for 2009-2028) associated with adopting the I5-percent PRM portfolio results in a cost premium of $659/MWh for the ENS reduction. Table 8.18 - Cost versus Risk for 12% and 15% Planning Reserve Margin Portfolios Table 8.19 - PVRR Cost Details ($45/ton C02 Tax), 12% and 15% Planning Reserve Mar- gin Portfolios Variable Cost Total Fuel Cost 14,191,867 14,418,506 226,640 Varable O&M Cost 1,222,685 1,241,622 18,937 Total Emission Cost 14,691,301 14,751,942 60,641 Long Term Contrcts and Front Offce Transactions 8,978,705 9,650,090 671,386 DSM 3,015,434 3,019,019 3,586 Spot Market Balancin Sales (13,089,333)( 13,482,889)(393,557) Purchases 3,714,988 3,514,149 (200,839 Ener Not Served 184,495 152,058 (32,436) Dump Power (12,366 (10,982)1,384 Reserve Deficiency 73,920 63,886 (10,034) Total Variable Net Power Costs 32,971,694 33,317,402 345,707 Real Levelized Fixed Costs 6,272,174 6,247,502 (24,672) TotalPVR 39,243,869 39,564,904 321,036 219 PacifiCorp - 2008 iRP Chapter 8 - Modeling and Portolio Seleaion Result Table 8.20 - PVR Cost Details ($70/ton C02 Tax), 12% and 15% Planning Reserve Mar- gin Portfolios Variable Cost Total Fuel Cost 13,625,227 13,740,869 115,642 Varable O&M Cost 1,204,222 1,215,560 11,339 Total Emission Cost 13,469,668 13,455,115 (14,553) Long Term Contracts and Front Offce Transactions 8,669,522 9,330,643 661,121 DSM 3,186,054 3,180,545 (5,509) Spot Market Balancing Sales (13,388,006)(13,854,964)(466,958) Purchases 3,546,102 3,284,808 (261,294) Ener Not Served 168,279 130,139 (38,141) Du Power 21,406)(19,997 1,409 Reserve Deficiency 63,344 52,524 (10,820) Total Variable Net Power Costs 30,523,005 30,515,242 (7,764) Real Levelized Fixed Costs 9,610,984 9,651,213 40,229 Total PVR 40,133,989 40,166,454 32,465 Under a $70 CO2 tax, increasing the PRM results in a similar build pattern as that for the $45 CO2 tax cases-including the addition of an IC Aero SCCT in 2016-xcept that System Opti- mizer removes less wind and increases front offce transactions once the peaking resource is added. As can be seen from Table 8.20, the gap in cost and cost risk narrows between the two portfolios, while supply reliability improves slightly. Table 8.21 shows the PVRR cost detail comparison for the two portfolios. Fuel, net system balancing, and emission costs are reduced due to the extra wind included in the 15-percent PRM portfolio and decreased dispatch of ther- mal units. The cost premium associated with an ENS reduction of 569 GWh drops to $57/MWh. For the $100 CO2 tax cases, increasing the PRM to 15 percent results in a larger amount ofDSM (125 MW), partcularly Class 1 programs, and distrbuted standby generation (42 MW), and a slight increase in front offce trnsactions. No peakig gas resources were added in either portfo- lio. As indicated in Table 8.21, costs and cost risk actully decrease slightly due to this resource mix. 50 The supply reliability benefit is negligible, and there is effectively a positive cost benefit for reducing the 69 GWh of ENS. 50 The System Optimier's determistic PVR for case 43 was slightly grater than that for case 24: $60.905 bilion versus $60.693 bilion. The extrsic (or real option value) of generation units affected by stochastic varation in fuel and maket prices is not accounted in the deterministic capacity optimization solutions. 220 ............................................ ............................................ PacißCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Table 8.21- PVRR Cost Details ($100/ton C02 Tax), 12% and 15% Planning Reserve Margin Portfolios Variable Cost Total Fuel Cost 12,231,023 12,159,435 Varable O&M Cost 1,099,133 1,094,393 Total Emission Cost 12,068,839 12,009,121 Long Term Contracts and Front Office Transactions 7,533,865 8,332,267 DSM 3,342,009 3,443,037 S ot Market Balancing Sales (13,956,020)(14,423,822)(467,802) Purchases 3,073,137 2,851,243 (221,894) Energy Not Served 117,336 112,439 (4,897 Dump Power (27,096)27,081 15 Reserve Deficiency 35,439 32,499 (2,940) Total Variable Net Power Costs 25,517,664 25,583,531 65,866 Real Levelized Fixed Costs 17,978,326 17,902,669 (75,657) TotalPVR 43,495,990 43,486,200 (9,790) The main conclusions to be drawn from this analysis are as follows: · With low to moderately high CO2 tax assumptions (less than $70/ton), planning to a higher PRM results in a significant cost premium for avoiding unserved energy. Whether this cost premium is worth paying is a subjective determination. However, from a stochastic modeling perspective, it is not cost-effective to invest in incremental generating capacity for reserves given that the cost premium for such investment is above the assumed ENS cost. . In a high CO2 cost environment, the incremental resources acquired for the larger capacity reserve requirement shifts to low CO2-emitting options, which is beneficial from an overall stochastic cost perspective. However, the supply reliability improvement from adding these incremental resources appear to reach a point of diminishing retus between $70/ton and $IOO/ton. Tables 8.22 through 8.24 show the generation shares by fuel tye category for selected years (2013,2020, and 2028) for new resources in each of the 21 portfolios. The generation mix pro- fie for each portfolio changes over time reflecting the availabilty of conventional and emerging technologies over the 20-year study period. All the portfolios increase fuel diversity by reducing the generation share of the Company's coal- fired plants. This result is a consequence of the System Optimizer being allowed to select from a diverse range of resource tyes in response to various price scenarios that in some scenarios make investment in new conventional thermal generation less cost-effective in the futue. In this respect, each portfolio has the optimal fuel mix based on it associated input scenario. 221 PacifiCorp - 2008 iRP Chapter 8 - Modeling and Portolio Selecton Result While the portfolios increase overall generation fleet fuel and technology diversity, at the same time, concentration of anyone fuel or technology for new resource investment has been found to be suboptimal when considering risk and uncertinty. As an example, portfolios for cases 22 and 24 include relatively large investment in wind resources to mitigate correspondingly large CO2 compliance costs. Table 8.22 - Generation Shares for New Resources by Fuel Type for 2013 25% 36% 70% 36% 58% 36% 49% 67% 76% 68% 59% 65% 68% 77% 77% 68% 68% 73% 77% 41% 33% 58% 16% 14% 8% 14% 10% 14% 11% 8% 6% 8% 9% 9% 7% 6% 6% 7% 7% 6% 7% 23% 26% 11% 59% 50% 23% 50% 32% 50% 40% 25% 17% 24% 31% 26% 25% 17% 17% 25% 25% 21% 16% 36% 41% 31% Table 8.23 - Generation Shares for New Resources by Fuel Type for 2020 0%34%17%49% 16%41%14%29% 11%75%3%11% 0%57%11%33% 0%67%5%27% 0%58%10%32% 0%69%4%26% 7%79%3%11% 7%81%3%10% 0%76%4%21% 0%75%4%21% 0%76%3%20% 0%83%3%15% 6%84%2%8% 222 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selection Result 0% 0% 0% 0% 0% 14% 14% 4% 83% 81% 82% 83% 86% 50% 50% 70% 14% 16% 15% 14% 12% 25% 25% 20% Table 8.24 - Generation Shares for New Resources by Fuel Type for 2028 0%0%34%11%55% 10%0%47%8%35% 9%0%68%3%20% 5%0%50%7%38% 0%0%61%4%35% 5%0%50%7%38% 0%0%63%3%34% 6%0%71%2%21% 9%0%76%2%13% 9%0%61%2%28% 9%0%61%2%28% 8%0%62%2%28% 6%11%62%2%19% 11%12%70%2%6% 6%23%64%2%6% 7%0%69%2%22% 6%23%66%2%3% 5%20%56%2%17% 9%21%66%2%2% 9%0%51%7%33% 9%0%51%7%33% 7%6%60%4%23% Carbon Dioxide The portfolio cumulative generator CO2 emissions for the simulation period are presented in Ta- ble 8.25 by CO2 tax level and the average across tax levels. Figure 8.23 shows the emissions footprint in bar char form by tax level, with portfolios raned from lowest to highest emissions (left to right) for the $45 tax. The portfolios with the lowest cumulative CO2 emissions are those optimized in response to both the $100 CO2 tax and high gas price scenarios. At the other extreme, portfolios optimized with 223 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result no CO2 tax have the highest emissions. A notable exception is the portfolio for case 3. This port- folio was optimized with the high June 2008 gas price scenario, and as a consequence, includes both a pulverized coal plant in 2018 and about 3,900 MW of wind by 2028. This resource com- bination lowered the CO2 emissions to less than the amount produced by a number of portfolios optimized with the $45 CO2 tax; specifically, those for cases 5,8,9, and 10. Table 8.25 - Cumulative Generator Carbon Dioxide Emissions, 2009-2028 1,073,510 899,802 835,943 936,418 1,089,942 892,740 821,440 934,707 1,028,918 807,954 730,560 855,811 1,036,052 841,758 772,358 883,389 1,020,539 818,050 746,063 861,551 1,037,463 843,569 774,282 885,105 1,025,000 823,005 751,041 866,349 1,014,089 794,324 716885 841,766 997,347 768,352 688,991 818,230 969,127 759,332 687,261 805,240 977,559 769,036 696,885 814,493 973,843 764,943 692,880 810,555 928,315 715,884 643,360 762,520 944,887 722,610 647,183 771,560 897,912 686,454 615,226 733,197 948,159 733,850 660,573 780,861 909,892 699,942 628,852 746,228 895,656 686,694 616,273 732,874 899,919 686,052 615,523 733,831 1,080,785 882,033 810,307 924,375 1,081,815 883,284 811,541 925,547 224 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Figure 8.23 - Generator Carbon Dioxide Emissions by C02 Tax Level 1,200,000 1,100,000 ""..=~1,000,000="==.. ,-~ '"900,000'" == =.~ ..'" ...~ a- S .æ 800,000 f; rL.. =0=u ~700,000.... '- ,Sos..600,000..=..~ 500,000 400,000 .$0 El $45 ra $100 29 24 27 26 20 22 25 17 19 14 18 11 3 8 10 5 9 46 47 2 1 Case Numr Other Pollutants Table 8.26 reports for each case portfolio the emissions footprint for sulfu dioxide (S02), nitrous oxides (NOx), and mercur (Hg). On an average basis across each C02 tax level, the portfolio for case 24 has the lowest emissions of S02. For NOx, the lowest-emitting portfolio was for case 27, while for mercury, the lowest-emitting portfolio was case 14. Table 8.26 - Generator Carbon Dioxide Emissions by C02 Tax Level 917 1,214 14,190 735 979 11,665 670 905 10,652 922 1,207 14,149 717 947 11,330 647 865 10,244 877 1,148 13,648 653 865 10,531 580 776 9,440 900 1,191 14,266 698 933 11,591 629 851 10,535 883 1,171 13,719 676 908 10,831 606 825 9,752 900 1,192 14,281 699 934 11,616 630 853 10,564 886 1,175 13,766 679 912 10,898 609 829 9,821 869 1,142 13,473 649 863 10,400 577 775 9,322 856 1,124 13,329 630 836 10,168 558 746 9,089 852 1,143 13,971 642 865 11,356 574 779 10,382 859 1,151 14,086 649 874 11,476 580 789 10,495 855 1,147 14,037 646 870 11430 577 784 10,458 822 1,102 13,423 610 824 10,831 543 738 9,893 825 1,095 13,426 605 807 10,724 537 720 9780 225 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result 9,526 10,100 9,697 9,507 9,562 10,153 10,177 Chapter 7 outlined the portfolio preference scorig approach for selecting the top portfolios. Preference-scoring grids were prepared for 12 expected value CO2 tax levels, ranging from $15 to $70 at $5 increments. Table 8.27 shows the expected value CO2 tax levels and associated probabilities. Stochastic cost results for the thee CO2 tax production cost simulations were weighted with these probabilities. These probabilty-weighted results are reported in Appendix B, and include risk-adjusted PVRR customer rate impact, CO2 cost exposure, upper-tail mean PVRR, and standad deviation of production costs. The 12 preference-scoring grds are also re- ported in Appendix B. A preference-scoring grd sample-for the $45 expected value CO2 tax- is shown as Table 8.28. Table 8.27 - Probabilty Weights for Calculating Expected Value CO2 Tax Levels 66 55 45 40 35 30 25 20 15 10 5 o 34 45 55 55 55 55 55 55 55 55 55 55 o o o 5 10 15 20 25 30 35 40 45 226 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selection Results Table 8.28 - Measure Rankings and Preference Scores, $45/ton Expected-value CO2 Tax 2.7 2.0 1.0 2.7 10.0 10.0 3.6 3.2 1.6 2.1 13 1.6 7.2 3.9 2.1 1.2 2.8 32 6.7 2.8 2.8 2.0 3.0 2.4 1.3 L1 1.6 13 7.6 52 2.0 1.0 1.0 1.4 43 1.0 5.8 5.1 2.0 1.1 1.5 1.0 1.8 1.5 7.6 5.9 2.2 1.3 2.1 2.1 3.8 2.1 62 5.5 2.9 2.2 33 1.4 7.1 33 2.7 22 3.0 2.4 53 5.1 9.7 53 1.8 1.4 4.9 4.9 2.2 1.5 6.2.2 4.5 42 2.7 2.0 23 2.5 5.4 23 4.9 4.4 3.0 2.4 2.8 2.6 6.4 2.8 4.7 4.4 3.3 2.8 4.9 3.4 8.0 4.9 2.1 2.1 4.4 4.3 6.9 6,7 10.0 6.9 L1 1.0 6.1 6.6 6.8 7.8 9.6 6.8 1.2 L1 6.3 6.9 3.8 33 8.0 3.8 3.1 3.1 3.9 3.6 6.8 7.4 9.6 6.8 1.6 1.5 6.4 6.9 6.8 62 9.6 6.8 L1 13 6.1 6.5 10.0 10.0 9.7 10.0 1.0 1.0 8.7 10.0 3.7 32 2.7 3.7 6.9 4.8 4.1 3.8 2.4 2.4 1.5 2.4 7.1 4.5 2.9 2.3 Table 8.29 reports the portfolio preference scores for each of the 12 expected value C02 tax lev- els. When summing the normalized preference scores across the expected value CO2 tax levels, the portfolios for cases 5 and 8 have the best scores, followed by cases 9 and 2. (These portfolios are shown highlighted in the table.) These four portfolios were therefore selected as the candi- dates for preferred portfolio selection. Table 8.29 - Portfolio Preference Scores 2.75 236 3.07 30,9 3,27 2.17 2.20 31.8 538 4.88 5,08 61.2 3.9 1.53 1.00 270 3.46 2.12 1.90 32.23,5 2.49 2.22 36.7 5.56 3,71 2.81 53, 7,11 637 6.13 80.1 7.67 6.43 5,67 82.9 4,79 3.08 237 45.2 7.58 6,55 6.00 83.5 7.44 5,97 5,10 78,6 10.00 iooo iooo 120.0 3,14 05 7.13 50.7 1.95 3,06 5.15 32.7 Figue 8.24 shows the portfolio preference scores from Table 8.36 sorted from best to worst. 227 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Figure 8.24 - Portfolio Preference Scores, sorted from Best to Worst 10.010.0 9.0 :f ~8,0 .. ..8 ..t; ~6.8rI ..7.0.. 0 6.4 o.~~ \, .. .... =6.0 r---r-cæ ";~ ~¡: ."4.9 f-.. ~5.0 --r-.. .- 4.2e ..3.9= c:rI ~4.0 3.5 -f-f-r---f-." ..33.. i-== ~3.0 ~ ..i---f-----i-" ..e ..2.2 23 2.3 23 24.. II.. ..1.9Z fl 2.0 -f----f----f----r--ti1.0 --f----f----f----f-- 0.0 L. 8 5 2 9 17 10 11 18 3 47 19 1 25 46 20 14 27 22 24 26 29 Case Numbr Sensitivity of Portolio Preference Rankings to Measure Importance Weights To test the sensitivity of the preference scores to changes in measure importance weights- particularly for the top-performing portfolios-PacifiCorp constrcted a preference-scoring grd for the expected value $45 CO2 tax level with an alternate set of weights. The alternate weights reflect a combination of comments and recommendations made by parcipants at PacifiCorp's February 2, 2009 public meeting, and place more importce on risk-adjusted PVR and C02 cost risk, but none on capital costs. These alternative weights are shown in Table 8.30. Table 8.30 - Alternate Measure Importance Weights CO2 Cost Ex osure Production Cost Standard Deviation Avera e anual ENS Avera e Anual Probabili of ENS events for Jul The resulting measure rankngs and preference scores based on these alternate weightings are reported in Table 8.31. The alternate weights result in changes to scores of no more than two- tenths of a point. The score for case 8 registers a slight improvement relative to the score for case 5, resulting in a switch in ranking. However, portfolios 8, 5,2, and 9 remain the top ranked under 228 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result both weighting schemes. Based on this result, PacifiCorp concludes that the top-pedorming port- folios are robust choices given variations in the measure weighting schemes. Table 8.31- Measure Rankings and Preference Scores with Alternative Measure Impor- tance Weights, $45/ton Expected-value CO2 Tax 3.7 2.1 2.8 2.0 1.8 2.2 2.8 3.0 4.7 2.6 2.9 3.2 4.4 6.0 6.1 3.8 6.2 6.0 8.7 4.2 3.0 3.5 1.3 2.3 1. 1.0 1.5 2.3 2.5 4.8 2.0 2.4 2.8 4.4 6.56. 3.5 6.7 6.4 10.0 4.1 2.5 As indicated above, the portfolios developed under cases 2, 5, 8, and 9 pedormed the best ac- cording to the final preference scores. For selecting the preferred portfolio, of interest is how the preference scores for these portfolios vary across the CO2 tax levels. Figue 8.25 shows the scores at each expected value CO2 tax leveL. The case 2 portfolio scores the best with tax levels below $40, while the case 8 portfolio scores the best with tax levels at $50 and above. Case 5 appears to represent the "least-regrets" portfolio with respect to the range of preference scores, avoiding the highest scores like the case 2 and 8 portfolios, and always dominating the case 9 portfolio. 229 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selection Results Figure 8.25 - Preference Scores by Expected Value CO2 Tax, Top-performing Portfolios ~ 350=~ Q; ál 3.00e::Q;~ 2.50 = .~ 1: 2.00:. "C .; 1.50 .. S ; 1.00z 450 4.00 ~ Case 2 Portfolio __ Case 5 Portolio -. Case 8 Portfolio __ Case 9 Portolio 050 0.00 $15 $20 $25 $30 $35 $4 $45 $50 $55 $60 $65 $70 Expcted Value C02 Tax Based on the preference scores and the analysis above, PacifiCorp dropped cases 2 and 9 from further consideration as the preferred portolio. A discussion of the comparative advantages, dis- advantages, and risks for the two remaining portfolios is provided below. Case 5 versus Case 8 Portolio Assessment Both case 5 and case 8 are equally strong contenders to be the 2008 IRP preferred portfolio. The main difference between the two portfolios is that case 8 includes 1,150 MW more wind in the first 10 years (600 MW more overall), and lacks a gas peakng resource in 2016. Case 5 also in- cludes more east-side front offce transactions in the first 10 years than case 8. The assumed CO2 cost is the key determinant for overall portolio performance: case 8 out- performs case 5 with CO2 taxes at $45 and above, but the reverse is tre with CO2 taxes below $45. Noteworthy is that case 5 out-performs case 8 on customer rate impact for all CO2 tax lev- els. In terms of relative advantages independent of the operational cost impact of a CO2 price, case 5 has a smaller capital cost (by $2.2 bilion), as well as a lower probability of a major ENS event durng the system peak month. In contrast, case 8 has a lower upper-tail cost and upper-tail ENS, reflecting the variable operating cost savings benefits of the additional wind and its selected loca- tion in load areas that exhibit relatively higher ENS. 230 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result A disadvantage for case 8 is the amount of wind investment in the first 10 years, which reaches 2,600 MW. The average annual capacity added for 2012 through 2018 exceeds 300 MW, which is a concern from procurement, rate impact, constrction project management, and operational perspectives. This wind is not needed for RPS compliance puroses, and its economic desirabil- ity hinges on continuation of a production tax credit (or comparable financial incentive), a sig- nificant CO2 cost penalty benefiting clean energy alternatives, and a robust market for sales of excess energy, particularly durng off-peak hours. On the other hand, the incremental wind pro- vides added price hedge benefits due to the lack of fuel costs and exposure to future CO2 compli- ance costs. The respective wind expansion patterns for cases 5 and 8 suggest that the optimal wind strategy is to identify a wind capacity floor and upper value that are updated as aspects of futue federal CO2 compliance cost and renewable energy policies becomes clearer. This strategy takes advantage of the relatively short development lead-time and modular constrction of wind resources. PacifiCorp's action plan discusses this wind strtegy in more detaiL. Both portfolios have heavier reliance on market purchases relative to most other portfolios, which increases the risk of a high-end cost outcome. Case 8 does better than case 5, due to more renewable resources and east-side Class 2 DSM, but both appear in the bottom quartle of ran- ing results for upper-tail risk measures. This higher tail risk must be evaluated in the context of the timing of when the tail risk is most pronounced, and other risks that these portfolios help mitigate. For example, Table 8.32 compares the 95th percentile PVRRs for the case 5, 8 and 22 portfolios given a lO-year span (2009-2018) and 20-year span (2009-2028). The case 22 portfo- lio ranks at the top for upper-tail mean PVRR. Table 8.32 - Short- and Long-term 95th Percentile PVRR Comparisons 2,299 558 As the comparison shows, differences in upper-tail mean PVRR are significantly lower under the lO-year view. Case 8 actually performs better than case 22, owing primarily to the high capital costs associated with a pulverized coal plant and 4,500 MW of wind included in case 22. The portfolios that do well on the 20-year upper-tail cost measures rely on large amounts of wind re- sources, as well as base-load resources such as conventional pulverized coal and nuclear in the out-years-resources with their own significant risks. This comparison again ilustrates the trade- off between expected costs and high-end cost risk. As emphasized in PacifiCorp's 2007 IRP, PacifiCorp believes that firm market purchases benefit the preferred portfolio by increasing planning flexibilty and resource diversity at a time of con- siderable regulatory uncertainty. The curent economic recession, coupled with the Company's 231 PadfiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result need for grd infrastructue and clean air investments, magnifies the importance of such flexibil- ity for maintaining affordable customer rates. Nevertheless, PacifiCorp recognizes the risks asso- ciated with market reliance, and has in place a price hedging strategy to mitigate these risks. A description ofPacifiCorp's price hedging strtegy is provided in Chapter 9. Regarding fuel source diversity, the case 8 portfolio has a greater proportion of renewable gen- eration-and generation reduction in the case of Class 2 DSM-than for case 5, particularly in the near term. On the other hand, case 5 has a greater share of gas generation, and for the first 10 years, more reliance on generation from market purchases. By 2028, the generation mix for the two portfolios look similar. The significant difference is that case 5 includes a clean coal re- source in 2025, while case 8 depends on much earlier wind investment to meet C02 and RPS compliance requirements. Scenario Risk Assessment Risk Scenario Development In accordance with the Public Service Commission of Uta's acknowledgement order for Pacifi- Corp's last IRP, the Company followed the Commission's instrction to "examine the cost con- sequences of the superior portfolios with respect to uncertinty by subjecting them to evaluation under the initial set of relatively broad input assumptions".Sl PacifiCorp selected the three top- performing portfolios-eases 5, 8, and 9-for this analysis (Case 2 had a. were fixed in the Sys- tem Optimizer capacity expansion modeL. The model was then executed to solve for the determi- nistic PVRR under each selected input scenario. The input scenaros consisted of the following case assumptions: · Medium load growth forecast · June 2008 forward price cures and highlow varations · Varying CO2 tax levels: $0, $45, $70, and $100 The resulting ten risk scenarios, along with the represented cases, are listed in Table 8.33. A total of 30 deterministic PVRRs therefore represent the outcome of the scenario risk modeling. Table 8.33 - Scenario Risk Case Definitions 1 1 $0 Low Medium 2 2 $0 Medium Medium 3 3 $0 High Medium 4 5 $45 Low Medium 5 8 $45 Medium Medium 6 14 $45 High Medium 7 17 $70 Medium Medium 8 22 $70 High Medium 9 24 $100 Medium Medium 51 Public Service Commission of Utah, Report and Order, In the Matter of the PacifiCorp 2006 Integrated Resource Plan, Docket No. 07-2035-01, Februar 6, 2008, p. 40. 232 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result The analysis did not include alternative load growt scenarios because the portfolios were devel- oped with the same load growt forecast. Therefore, applying alternative load forecasts would have no value for cost comparson purposes. The selection of only the June 2008 price forecast assumptions reflects a practical decision to help limit the number of additional model rus to a manageable number. Risk Scenario Modeling Results Table 8.34 shows the deterministic PVRR results for the 30 System Optimizer rus, along with the PVRR average and the standard deviation for each portfolio across the risk scenarios. The portfolio for case 8 has both the lowest PVRR and the smallest PVRR variability across the risk scenarios. The case 8 and 5 portfolios are nearly equal with respect to both PVRR average and standard deviation, owing to the similarity of the portfolios. Table 8.34 - Scenario Risk PVRR Results 1 1 21,025 21,972 21,048 2 2 22,176 22,305 22,188 3 3 22,550 21,288 22,481 4 5 40,542 40,730 40,542 5 8 41,691 41,389 41,672 6 14 44,243 42,430 44,146 7 17 52,533 51,782 52,489 8 22 55,159 53,144 55,049 9 24 64,853 63,379 64,768 10 29 65,123 62,913 64,915 Average 42,990 42,133 42,930 Standard Devition 15,968 15,278 15,920 Table 8.35 reports the portfolio PVR rankings for each risk scenario. Case 8 rans first on the basis of having the lowest rank sum (16). Case 9 comes in second with a rank sum of 19, fol- lowed by case 5 with a rank sum of 24. Table 8.35 - Portfolio PVRR Rankings 233 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results 3 3 3 1 2 4 5 1 3 1 5 8 3 1 2 6 14 3 1 2 7 17 3 1 2 8 22 3 1 2 9 24 3 1 2 10 29 3 1 2 Rank Sum 24 16 19 Table 8.36 shows differences between the original deterministic PVRR and those obtained for the risk scenario runs. 52 Table 8.36 - PVRR Differences, Portolio Development Case less Risk Scenario Results 1 12 23 34 55 86 147 178 229 24 10 29 These results indicate that Portfolio 5 pedormed best in low gas/low CO2 tax scenarios and per- formed worst in high gas price and high CO2 ta cases. Portolio 8 pedormed best under the me- dium/igh gas price and medium/igh CO2 tax scenaros, but pedormed worst in low gas/low CO2 scenarios. Conclusions The scenaro risk assessment yielded findings similar to the stochastic mean cost analysis regard- ing the top-pedorming portolio, case 8. However, case 9 pedormed slightly ahead of case 5 in the scenaro risk analysis, whereas case 5 pedormed ahead of case 9 under the stochastic mean cost analysis. Given this outcome, the question is whether the risk scenao analysis, as formu- 52 Fixing of resources in System Optimizer for the risk scenaro TUS entailed roundig capacity values of the smaller resources, such as class 2 DSM amounts by topology bubble, price tier, and year. The result was a small PVRR dif- ference with respect to the PVRR obtained in the original portfolio development TU. 234 ............................................ ............................................ PacißCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result lated above, provides any added value for preferred portfolio selection over that provided by the stochastic analysis. PacifiCorp concludes that it does not. The reasons are as follows. First, the stochastic Monte Carlo simulations provide 100 combinations of input invariables, accounting for varable correlations. The scenario risk assessment is essentially a manually formulated and limited version of the Monte Carlo simulation. It is impractical to emulate this range of input variability using System Optimizer or the Planning and Risk model in deterministic mode. Second, the scenaro risk assessment introduces a confounding aspect to the preferred portfolio selection process given the situation where the analysis yields pedormance conclusions contra- dictory to those obtained from the stochastic analysis-such as with the case 5 and 9 portfolios. In summary, PacifiCorp believes that the stochastic risk analysis is sufficient for exploring port- folio cost outcomes given a range of input assumptions reflecting uncertainty and risk. The only value that the scenario risk assessment provides is to confirm the degree that stochastic and de- terministic costs are consistent for portfolio rankng puroses. On the other hand, the Company finds value with subjecting a portfolio to resource-specific scenarios as part of the acquisition path analysis, and using System Optimizer to determine the optimal resource mix under those alternate resource assumptions._I__I~I:,;, Based on the portfolio preference scores and consideration of relative resource risks, the Com- pany would have chosen the case 5 portfolio as the basis for its preferred portfolio. However, due to the Company's February 2009 decision to terminate the constrction contrct for the Lake Side II CCCT resource, PacifiCorp conducted additional portfolio analysis to determine a revised preferred portfolio that takes this decision into account, as well as new transmission and market assumptions that supported that decision. PacifiCorp conducted two tyes of portfolio studies reflecting the removal of Lake Side II as a planned resource in 2012. The first type involved fixing a combined-cycle gas plant in 2014 and running System Optimizer to select other resources using the case 5 input assumptions. Two portfolios were created: one had a 570 MW (July capacity) wet-cooled CCCT located at the Lake Side site in Utah North, while the second had a 536 MW dr-cooled CCCT located in the Cur- rant Creek site. This was followed by stochastic production cost modeling runs using the PaR model with $0, $45, and $100 CO2 tax levels. These two portfolios reflect a CCCT deferral strat- egy that assumes, conservatively, that CCCT capital costs do not change from the generic values assumed for the 2008 IRP, after adjusting for inflation.53 The rationale for fixing CCCTs in Sys- tem Optimizer is that this model does not account for resource optionality and reserve holding value captured through stochastic production cost modeling, and tends to favor SCCTs over CCCTs for meeting capacity planning reserve margins as a result. The second portfolio study tye consisted of the removal of the Lake Side II plant in the top eight portfolios selected on the basis of the preference scores (Table 8.36), and having System 53 PacifiCorp expects that lower commodity costs and the effects of the world-wide economic downtu should eventually sta to impact plant constrction prices. However, the Company did not see price reductions in the bids received in response to its 2008 All-Source RFP issued in October 2008. 235 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Optimizer select the portfolios to fill the resource gap using the case defmitions associated with these portfolios. Stochastic production cost simulations with multiple CO2 tax levels were also conducted for these 10 portfolios. The portfolios modeled without Lake Side II reflect a number of assumption changes docu- mented in Chapters 6 and 7. Table 8.37 profiles the 10 portfolios and the associated input as- sumptions. Table 8.37 - Additional Portfolios Modeled to Support a 2012 Gas Resource Deferral Strategy 2 5 5 5 8 9 10 17 18 47 . Lake Side II CCCT removed as a planed resource . West MainI est Main to Yakima topology updates (See Figure 7.2) . Mona to Uta South topology update (See Figue 7.2) . Mid-Columbia market depth updates for 2012 and 2013 (See Table 6.22) . Mona market depth updates for 2012 and 2013, including Nevad Utah Border (See Table 6.22) None None Dry-cooled CCCT fixed in 2014 Wet-cooled CCCT fixed in 2014 None None None None None None PacifiCorp developed a full set of performance measures for these portfolios and ranked them using the same preference-scoring scheme applied for the original 2 i portfolios. These additional portfolios are shown in Appendix A. The stochastic performance measures are reported in Ap- pendix B. Table 8.38 compares the cumulative nameplate capacities by major resource tye for the original and "B series" portfolios. The B series portfolios include more front office transaction and en- ergy effciency program capacity than their original portfolio counterparts, and-with the excep- tion of the two fixed CCCT portfolios (5B_CCCT_Dry and 5B_CCCT_Dry)-include more IC Aero SCCT capacity. On the other hand, just four of the 10 portfolios include more wind capac- ity (2B, lOB, 17B, and 47B), while two portfolios have less wind than the original portfolios (8B and 18B). Portfolio tables showing the resource capacity differences between the ten B series portfolios and the corresponding originals are included in Appendix A. Table 8.38 - Resource Capacity Comparisons, Original and B Series Portolios 236 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results 47B 2,383 0 609 797 1/ Anual average front offce transactions capacity for 2009-2018 shown. 2/ Distributed generation consists of customer standby generation and combined heat and power facilities. General findings for this additional portfolio analysis are as follows. . The combination of revised input assumptions and deferral of a 2012 gas resource resulted in lower PVRRs compared with those reported for the original portfolios. For example, as shown in Table 8.39, the stochastic mean PVRR of portfolio 5B (averaged across the three CO2 tax simulations) is $570 milion less than the PVRR for the original case 5 portfolio. 54 . The portfolio with a wet-cooled CCCT located at the Lake Side II site ("5B CCCT Wet") had the lowest risk-adjusted PVRR, CO2 cost exposure, and rate impact (Table 8.40). The other two case 5 portfolios ranked second and third. . The wet-cooled CCCT deferral portfolio also had the best overall preference score, rankng at the top for expected value CO2 tax levels of $20 through $60. Table 8.41 presents the portfo- lio preference scores for CO2 tax expected values from $15 to $70. . The three portfolios developed with the case 5 input assumptions had the highest preference scores (Table 8.4 1). This portfolio analysis strengthens the assertion that case 5 is relatively robust at producing the optimal portfolios on the basis of overall preference scoring. . Fixing a CCCT in 2014 rather than allowing System Optimizer to fully optimize resource selection resulted in improved stochastic costs. For example, fixing a wet-cooled CCCT in 2014 yielded a $115 milion improvement in risk-adjusted PVRR (averaged across the $0, 54 The PVRs for the original case 5 portfolio reported in Table 8.41 are adjusted to include 2012 CCCT capital costs for comparability with the gas resource deferral portfolios. Because the Lake Side II CCCT was treated as an existing resource in all the original portfolios, associated capital costs were not included in the PVR calculations. 237 Paci~Corp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result $45, and $100 CO2 tax simulations) relative to portfolio 5B, which has no CCCT. Fixing a dr-cooled CCCT in 2014 resulted in a $51 milion risk-adjusted PVRR improvement. . The tail risk (upper-tail mean PVRR) for the B series portolios is lower than that for the original portfolios, accounting for the capital cost of the Lake Side II resource (See footnote no 49). This is generally due to more wind, DSM, and distrbuted generation in these new portfolios. The two CCCT deferral portfolios had the highest upper-tail risk and production cost standard deviation among the B series portolios. Figue 8.26 is a scatter-plot graph of the stochastic mean PVRR versus upper-tail mean PVRR for the three CO2 tax levels. (Table B.23 in the appendix volume shows portfolio rankg results for an alternate importance weighting scheme that includes the upper-tail mean PVRR as a performance measure with a relatively large importnce weight: 20%.) Table 8.39 - Stochastic Mean PVRR for 2012 Gas Resource Deferral Strategy Portfolios 22,126 40,062 60,448 40,879 22,554 39,452 58,664 40,224 22,462 39,369 58,751 40,194 22,457 39,315 58,639 40,137 23,402 39,673 57,809 40,295 22,778 39,725 59,031 40,511 23,921 40,261 58,542 40,908 25,569 40,539 56,798 40,968 25,102 40,353 57136 40,864 22,658 40,507 60,872 41,346 11 The PVRRs for the original case 5 portolio are adjusted to include 2012 CCCT capital costs for comparabil- ity with the gas resource deferrl portfolios. Table 8.40 - Measure Rankings and Preference Scores for 2012 Gas Resource Deferral Strategy Portfolios, $45/ton Expected-value CO2 Tax 238 ............................................ ............................................ PacifìCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Table 8.41 - Measure Rankings and Preference Scores for 2012 Gas Resource Deferral Strategy Portfolios 4.6 4A 4.1 1.7 13 3A 3.5 4.4 4.8 4.7 6.8 7.1 8A 6.7 6.2 10.0 10.0 10.0 3.1 1. 8.9 8.9 9.0 3A 1.9 3.8 4.5 8.0 10.0 10. Figure 8.26 - Stochastic Cost versus Upper-tail Risk: $0, $45, and $100 C02 Tax Levels $0, $45, $100 COi Tax Levels 108 104 100 96 92 '"88".51l 84 ¡¡80;;.."..76i ~72t..68..¡; 64 60 56 52 48 20 :i c- I II 51 8B II -" 0 ':, ,~ I """"L ,"r:~il9~!JnB' ............- IIt:'1..'ii .18B ,...,.-,+I~: 8B~~II. 5B_Cet Wet : .....- .SB~ci..or.......T"... Ä )K98; 2B .. ..ŠB¡..~~...r.. Tl7B - I~I:88.. .......178 v I~775 829 821 820 811 829 820 796 808 797,_ 1~ f~ ,~ 1_ 1_ ,_ 2~ 2_ 1~ 1~ n 00 129 1~ 1B 1V 1V ~ .. ... 'I .. WI Gas FOT DSM Clas 2DlGen.n~un~nM~~~~~%~~~~~~~~ Stocbastic Mean PVR (Billion $) Based on the 2012 gas resource deferral modeling results, PacifiCorp chose the "5B _ CCCT _ Wet" portfolio as the basis for the preferred portfolio. An issue with this portfolio, and wind resource optimization in general, is that the capacity expansion model adds a large 239 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result amount of wind capacity in certain years and little or none in others. Such a pattern, while opti- mal from the model's perspective, is not desirable from a business planning perspective. As noted in Chapter 7, PacifiCorp applied annual wind capacity constraints to reflect realistic system limits. However, additional constrints are required to emulate a long-term procurement program that ideally accounts for rate stability/financial impacts, anticipated demand for con- strction and equipment resources, flexibility to respond to changing market and regulatory condi- tions, constrction management requirements, and location-specific considerations not factored into the IRP models. The Company believes that given the curent sophistication of capacity expansion optimization models, development of a suitable wind acquisition schedule that takes these various factors into account is best handled outside of the modeL. Consequently, PacifiCorp manually devel- oped a wind acquisition schedule based on the aggregate wind amount from the 5B _ CCCT _ Wet portfolio, and then ran System Optimizer with this fixed wind schedule and the 5B_CCCT_ Wet input assumptions. The resulting portolio, presented in the next section, constitutes PacifiCorp' s preferred portfolio. Table 8.42 shows the wind acquisition schedule and original wind additions from the 5B _CCCT _ Wet portfolio. Table 8.42 - Revised Wind Resource Acquisition Schedule The strategy behind this acquisition schedule is to distrbute wind quantities across all years of the business planning period (2009-2018) and though 2021, keeping anual amounts at 200 MW or less. Planning to relatively level annual wind additions provides the following customer and Company benefits: · Helps to support rate and capital spending stability · Strikes a balance between the risk of (1) front-loading wind development and then ex- periencing lower-than-expected CO2 costs, and (2) deferrng wind development and then experiencing higher-than-expected CO2 costs, termination of the PTC after 2012, or both · Reduces the risk of RPS compliance penalty costs stemming from procurement delays for projects needed to meet percentage-of-sales requirements in a given year · Helps in maintaining effciently sized constrction management, engineering, and sup- port teams The wind schedule also reflects the addition of 200 MW of west-side wind resources in 2011 to take advantage of regional wind diversity benefits that are not captured in the IRP models. 240 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selection Results The increasing mix of clean resources reflected in the 2008 IRP preferred portfolio-renewables and demand-side management-reduces the carbon intensîty of PacifiCorp' s generation fleet (Figure 8.27) and positions the Company well for meeting future climate change and renewable resource requirements. For example, the preferred portfolio exceeds curent jursdictional RPS requirements expressed on a system load basis, and would potentially meet a i 5-percent federal RPS requirement such as the one contained in draft legislation proposed by U.S. Representatives Waxman and Markey ("The American Clean Energy and Securty Act of 2009"). The addition of energy efficiency resources-reaching 4.2 milion kWh by 20 i 8-reduces the system coincident peak load from a 2.7% average annual growth rate (2009-2018) to 1.9%. The addition of flexible natural gas resources supports the aggressive expansion of intermittent renewable generation while meeting incremental base load and intermediate load needs. The role of new firm market purchases is to help replace expiring long-term power purchases, and, by ad.. justing volumes up or down, provide resource flexibility to manage the volatility and uncertainty in load forecasts, commodity prices, and capital costs. The increase in near-term front offce transactions takes advantage of the significant price drops in fuels and forward wholesale power in late 2008 and early 2009, providing the opportity to lower power supply costs before the Company needs to commit to a large new thermal power plant. If constrction markets continue to soften as several experts predict, this wil create additional cost-saving opportities through lower plant prices. Figure 8.27 - Carbon Dioxide Intensity of the 2008 IRP Preferred Portfolio 0,85 0.8 ........\- ;:0.75 \.i From2009/eve/s, CO2 intensity drops by 15% in 2018 and 32% by 2028 ~0,7 'y ""-- '"~='F -'"Q 0,65E-'\....0U 0.6 'F 'F "-~055 ~ 05 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 11 Generatio conists of the outp from therii renewable and hydro resources based on a $45/to C02 tax begi in 2013. 241 Paci~Corp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result Figure 8.28 - Renewable Portfolio Standard Compliance 2008 IRP Preferred Portfolio l 22%............_._...._-_.......__.......__._--_......._------_."_._----_.-_._---_.._........__...........__..................................................._......__................. ..20%e..A,-"~.A /--,.18%rI ,/,... '5 16%..--=~-.=14%f..~I......=-12%eo /'I'"eo 10% ~¡£I~8% J~6%......=r-4%Jl /.ceo ~2% =.-ø=0%~ 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 I -& 2008 IR PrfetTd Portoli ~ Sysæm-ed Renewa Portoli Stard Requiment I Relative to the preferred portfolio reported in the 2007 IR Update report (June 2008), the 2008 preferred portfolio relies on significantly less fi market purchases for the period covered in common (2009-2017). For gas resources, the major difference is the addition of a simple-cycle gas plant in 2016; with the acquisition of the Chehalis plant in 2008, there is negligible change in the amount of combined-cycle gas capacity. The 2008 IRP relies more heavily on distrbuted generation resources, while differences in wind and Class 2 DSM are minimaL. Table 8,43 shows the annual resource differences for the two preferred portfolios (2008 IRP less the 2007 IRP Up- date). 242 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Results Table 8.43 - Resource Differences, 2008 IRP Preferred Portfolio less 2007 IRP Update Pre- ferred 134 42 NA 509 (28 150 1008 8 (598) (572) (5)45 20 100 1042 2 2 2 3 3 3 3 25(40) (657) (677) (31) 30 (55) (100) (333) NA Energy Effciency (Class 2 DSM) 2 2 (2) (3) I 2 3 2 (55) 11 Acqusition of the Chehalis 509 MW combined-cycle plat in Washington, 11 For 2008. actu wind aditions totaled 545 MW, coniar to the planned amount of 370 MW in the 2007 IRP Upda 3/ Expansions of the existing Uta COL Keepe progr and dispatchable irgation progrs are treated as existing resources. Relative to the 2007 IR Updte quatities, the incrmental DSM planned expansions reach 525 MW by 2018. 41 For the 2007 IR Updte, Class 2 DSM was trated as a deeas to load rather tha as a resoure included in the prfered portfolio, Table 8.44 presents the detailed view of the preferred portfolio resources. This portfolio reflects the wind schedule described in the preceding section. Since Class i DSM other than the Utah Cool Keeper program was found to be cost-effective in all the portfolios modeled, the preferred portfolio includes up to 120 MW of additional cost-effective Class I DSM to be identified through competitive Requests for Proposals and procured in the 2009-2018 time frame. (For the non-CCCT "B series" cases, the capacity expansion model tyically selected 9 i MW of various Class 1 DSM programs in the east-predominantly irrigation load control and load curilment- and 34 MW in the west.) This amount is in line with the corporate objective of aggressively pur- suing DSM opportities, and exceeds the 2009 business plan goal by 15 MW. Acquiring the additional Class 1 DSM amounts would reduce the need for front offce transactions. Below are explanatory notes for the portfolio table. . Swift 1 Upgrdes - The three Swift upgrade projects (25 MW each) are shown under the year for which they enter commercial service (2012, 2013, and 2014); however, the planned in-service dates occur after the system peaks for these years. They are available to support the summer peak load in 2013,2014, and 2015, respectively. . High Plains and Duke PP A Wind Projects - The High Plains wind project has an October December 2009 in-service date, and is therefore shown under the year for which it enters commercial service (2009); the Duke project has a December 2009 in-servce date, but is modeled with a start date of January 1, 2010, and is therefore shown in the year it is available to support the summer peak load (2010). . Gas resource MW capacities reflect average anual capability rather than the generator nameplate. For the CCCT, the value shown approximates the July maximum capability. . Class 2 DSM resource capacities reflect summer peak values. . The capacities shown for the coal plant CCS (carbon captue and sequestration) retrofit resources represent replacement capacities for the existing units. The replacement capac- 243 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecton Result ity is smaller than the original unit size, which is due to a capacity penalty for captung the CO2. · Front offce transactions and growth resources reflect amounts acquired for the given year only, and are not cumulative. . For the 20-year totals column, growth resources are reported as an eight-year average from 2021-2028. · Short-term resource totals comprise the sum of front offce transactions and growth re- sources. Table 8.45 shows the resulting capacity load and resource balance for 2009-2018 with preferred portfolio resources included. Wind and Class 2 DSM resource additions are reported as the ca- pacity available at the time of the system coincident peak load hour, which is less than the in- stalled capacity reported in Table 8.44. Figues 8.29 and 8.30 consist of pie charts showing the energy and capacity mixes ofthe portfolio for 2009,2014, and 2018. (Note that for the capacity charts, the expected system peak capacity contrbution for wind resources is shown.) 244 ............................................ .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 8 - M o 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 8 . 4 4 - P r e f e r r e d P o r t f o l i o , D e t a i l L e v e l CC S H u n t e r . U n i t 3 ( R e n l a c e s O r CC C T F 2 x l 57 0 57 0 IC A e r 8C C T 26 1 26 1 Ea t P P A 20 1 20 1 Co a l P l a n t T u i n e U D 2 l a d e s 3 44 33 25 2 1 4 8 12 8 .l u n d e U G e o t h e n l 3 35 35 Win d , D u e E n e n r P P A 99 99 Win d . H i l Z h P l a i n s 99 99 Wi n d , W Y S W , 3 5 % C a p a c i t y F a c t o 15 0 10 0 1 0 0 1 0 0 1 5 0 10 0 10 0 50 20 0 2 0 0 15 0 85 0 il T o t a l W I n d 99 2 4 9 . 10 0 10 0 1 0 0 1 5 0 1 0 0 10 0 50 20 0 2 0 0 15 0 . . . . . 1,0 4 8 CH P - B i o m a s s 2 2 2 2 2 2 2 2 2 2 20 !C H P - R o c _ n . E n . . n e 1 1 1 2 2 2 2 2 2 2 2 2 2 10 Di s t i b u S t b y G e e r t i o n 4 4 4 4 4 4 4 4 4 4 38 DS M C l a s s i U t a h - C o o l K e e 25 50 40 30 10 10 10 1 0 1 0 10 20 5 10 8 M , C l a s s 1 , O t e r . . . . . . . . . . DS M O a s s 2 G o s h e n 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 D8 M , C l a s s 2 , U t a 40 46 42 4 2 4 5 45 46 45 47 48 4 7 4 8 4 9 51 52 52 5 9 55 5 7 5 5 DS M , C l a s s 2 , W y o m i n J l 3 6 8 8 8 8 9 9 9 9 9 9 9 10 10 1 0 1 0 1 0 1 0 !D 8 M , C l a s s 2 T o t a l 42 5 1 49 52 5 5 55 56 56 58 59 5 8 5 9 6 0 6 2 64 64 71 67 69 6 7 FO T U t a 3 r d O t t H L H 44 5 0 2 28 7 5 0 5 0 50 50 50 FO T M e a d , 3 r d O t H L H 51 7 60 0 6 0 0 6 0 0 60 0 60 0 60 0 60 0 6 0 0 6 0 0 60 0 6 0 0 FO T M o n a I e v d a U t a B o r d e r , 3 r d Q t H L H 75 50 1 5 0 35 0 44 3 20 0 2 0 0 20 0 2 0 0 2 0 0 2 0 0 20 0 Fo r E a s t T o t a l 75 5 0 iS O 39 4 49 3 20 0 20 2 22 8 71 7 8 0 0 8 0 0 8 0 7 6 5 0 65 0 65 0 65 0 60 0 60 0 65 0 60 0 Gr w t R e s o u r e - G o s h e n 20 4 18 7 1 9 8 21 9 19 2 Gr w t R e u r e . U t a N o r t h 21 2 3 0 8 2 3 8 2 4 2 Gr R e u r e . W v o m i m r . 73 79 12 6 1 6 7 19 6 Co P l a t T u r b i n e U o r z e s 9 9 12 1 2 42 42 Sw i f t H v d r o U n Ø T a d e s 25 2 5 25 75 75 Wi n d _ P P A 45 20 65 6 5 Wi n d Y a k , 2 9 % C a D a c i t v F a c t r P P A 10 0 10 0 1 0 0 Win d , W a l l a W a l a , 2 9 % C a n a i t v F a c r P P A 10 0 10 0 10 0 To l a l W l n d 45 2 0 20 0 . . . . . . . . . 26 5 2 6 5 Ut i l i t y B i o m s 25 25 50 lI . B i o m a s s 1 1 I I 1 I 1 1 1 I 12 1 2 CH P - R e c i n m a t i n g E n t r n e 1 1 1 1 1 1 1 1 I 1 4 6 Di s t i b u t e d S t a d b y G e n e r a t o n 1 1 I I I I 1 I 1 I 12 1 2 DS M , C l a s I , O t h e r . . . . . . . . . . D8 M c i a s s 2 . _ ~ L l A l . i 2 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 DS M , C l a s 2 W e s t M a n 28 2 8 3 0 3 0 30 31 3 1 3 1 3 1 20 2 0 20 20 2 0 20 20 2 0 2 0 2 0 DS M , C l a s 2 , Y a k i m a 5 6 5 5 5 5 6 5 5 6 6 6 6 6 6 6 6 6 6 ID 8 M , C i l i s s 2 T o t a l 35 3 6 39 3 9 38 3 9 3 9 39 39 29 29 2 9 30 29 29 30 29 30 30 FO T C O B , F l a A n n a l 59 3 8 9 38 9 28 9 23 9 2 3 9 23 9 3 3 8 3 3 8 33 8 33 8 3 3 8 33 8 33 8 3 3 8 3 3 8 FO T C O B 3 r d O t H L H 38 9 FO T M i d - C o l n m b i a F l A n u a l 17 1 22 8 22 8 37 67 71 63 FO T M i d - C l u m h i . 3 r d O t H L H 40 0 4 0 0 3 0 0 4 0 0 40 0 12 1 1 0 5 1 6 0 7 FO T W e s t M a i n , 3 r d Q t H L H 50 5 0 50 5 0 50 5 0 5 0 5 0 5 0 5 0 5 0 50 50 II O T W e s t T o t l . S9 83 9 83 9 7 3 9 73 9 6 8 9 28 9 58 2 72 1 77 6 4 2 4 4S 4 45 9 45 7 9G w t h R e s o r c - W a l l a W a l l a 10 6 97 13 4 1 3 5 Gr o w t R e s o u r e - W e s t M a n Gr w t R e s u r . Y a k m a * U p t o 1 2 0 M W o f a d d i t i o n a l c o s t - e f f e c t i v e C l a s s 1 D S M p r o g r a m s ( 9 0 M W e a s t , 3 0 M W w e s t ) t o b e i d e n t i f i e d t h r o u g h c o m p e t i t i v e R e q u e s t s f o r P r o p o s a l s a n d p h a s e d i n as a p p r o p r i a t e f r o m 2 0 0 9 - 2 0 1 8 . F i r m m a r k e t p u r c h a s e s ( 3 r d q u a r e r p r o d u c t s ) w o u l d b e r e d u c e d a c c o r d i n g l y 24 5 ..PaciCorp - 2008 IRP Chapter 8 - Modeling and Portfolio Selecon Result .. Table 8.45 - Preferred Portfolio Load and Resource Balance (2009-2018). Calendar Year 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 .tili(.)ff;(l.1L,:,:",::::,::::J*,¡fJIl~t::!¡11:¡¡:¡l:1111__811181111. I N~'L i II ,U IUf :JI__I,I"::~~,,~i'lIFi"81I*¡li~tiT:II1r"Thermal 5,983 5,99 6,025 6,066 6,06 6,078 6,079 6,087 6,088 5,863 .Hydroelectric Generation 135 135 135 135 135 135 135 135 135 135 Demand-side Management 345 395 435 465 475 485 495 505 515 525 Renewable 157 157 157 157 157 157 154 154 154 154 .Purchase 751 54 541 341 341 341 341 320 320 320 Qualifyng Facilities 151 151 151 151 151 151 151 151 151 151 .Interruptible Contracts 237 237 237 237 237 237 237 237 237 237 Transfers 854 914 794 685 737 565 769 737 231 519 .East Existing Resources 8,614 8,534 8,476 8,238 8,30 8,149 8,361 8,326 7,831 7,905 Combined Heat and Power 2 4 6 9 11 14 18 22 26 30 .Distributed Standby Generation 4 8 12 15 19 23 27 31 35 38 DSM, Class 2 36 79 119 160 205 249 294 338 384 431 .Front Offce Transactions 75 50 150 394 493 200 202 228 717 800 Gas 0 0 0 201 201 771 771 1,032 1,032 1,032 .Geothermal 0 0 0 0 35 35 35 35 35 35 Wind 9 12 12 15 17 20 23 26 28 29 .Growh Resource 0 0 0 0 0 0 0 0 0 0East Planned Resourc 126 153 299 79 980 1,310 1,369 1,711 2,255 2,395 .East Total Resourcs 8,740 8,687 8,774 9,032 9,280 9,46 9,730 10,037 10,086 10,300 .Load (Coincident Peak)6,757 6,949 7,150 7,40 7,643 7,779 8,029 8,303 8,491 8,696 Sale 781 768 758 747 745 745 745 745 659 659 .East Obligation 7,538 7,717 7,90 8,151 8,38 8,524 8,774 9,04 9,150 9,355 Planning reserves (12%)731 769 771 786 797 841 865 890 837 845 . Non-owned reserves 70 70 70 70 70 70 70 70 70 70 .East Reserves 802 84 841 857 867 912 935 961 908 915 East Obligation + Reserves 8,339 8,556 8,749 9,007 9,255 9,436 9,709 10,009 10,058 10,271 . East Position 401 131 25 25 25 24 21 28 29 29 East Reserve Margin 17.3%13.7%12.3%12.3%12.3%12.3%12.2%12.3%12.3%12.3%.. Hydroelectric Generation 1,315 1,218 1,216 98 1,00 1,04 1,157 1,150 1,149 1,146 .Demand-side Management 0 0 0 0 0 0 0 0 0 0 Renewable 90 96 96 90 90 90 90 90 90 90 .Purchase 1,310 1,203 753 115 144 111 111 111 111 139 Qualifing Facilties 120 120 120 120 120 120 120 120 120 120 .Transfers (855)(914)(795)(68)(738)(565)(769)(737)(231)(520)West Existing Resources 4,530 4,281 3,958 3,198 3,217 3,392 3,300 3,325 3,815 3,551 Combined Heat and Power 1 2 4 5 7 9 10 12 14 16 . Distributed Standby Generation 1 2 4 5 6 7 8 9 11 12 .DSM, Class 1 0 0 0 0 0 0 0 0 0 0 DSM, Class 2 26 54 83 112 140 169 199 228 257 279 .Front Ofce Transactions 0 0 59 839 839 739 739 689 289 582 Other 0 0 0 0 0 0 0 0 0 0 .Wind 0 0 8 8 8 8 8 8 8 8 Growth Resource 0 0 0 0 0 0 0 0 0 0 West Planned Resources 29 58 157 969 1,00 933 965 947 580 896 . West Total Resources 4,559 4,34 4,115 4,167 4,217 4,325 4,265 4,272 4,395 4,44 . Load (Coincident Peak)3,393 3,422 3,490 3,587 3,638 3,722 3,769 3,824 3,893 3,978 .Sale 499 490 290 258 258 258 158 108 108 108 West Obligation 3,892 3,912 3,780 3,84 3,896 3,98 3,927 3,932 4,001 4,086 .Planning reserves (12%)307 319 346 334 333 355 345 348 401 370 .Non-owned reserves 7 7 7 7 7 7 7 7 7 7 West Reserves 313 325 353 34 339 362 352 355 408 377 West Obligation + Reserves 4,199 4,230 4,126 4,179 4,229 4,335 4,272 4,280 4,402 4,456 . West Position 360 110 (11)(12)(12)(10)(7)(8)(7)(9).West Reserve Margin 21.1%14.6%11.5%11.5%11.5%11.6%11.7%11.6%11.7%11.6%_I ._il!'Ui . . Total Resources 13,299 13,027 12,889 13,199 13,497 13,785 13,995 14,30 14,481 14,747~(.Obligation 11,430 11,628 11,687 11,99 12,284 12,504 12,701 12,980 13,151 13,441Reseres1,115 1,165 1,194 1,197 1,206 1,274 1,287 1,316 1,315 1,292 Obligation + Reserves 12,54 12,793 12,882 13,192 13,490 13,777 13,988 14,296 14,466 14,733 .System Position 754 234 7 7 6 7 8 13 15 14 .. 246 ... ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portfolio Selection Result Figure 8.29 - Current and Projected PacifiCorp Resource Energy Mix 2009 Resource Energ Mix with Preferred Portolio Resources ($45 C02 Tax) Interruptible 0.10/. Front Offce Transactions 1.1% CUP 0.03% Class 1 DSM 0.00% DSG 0.00% Existing Purchases 7.1% Hydroelectric 8.9% Coal 58.0% 2014 Resource Energy Mix with Preferred Portolio Resources ($45 C02 Tax) Class 2 DSM 3.4% Front Offce Transactions 6.6% Class ID8M 0.02% Renewable 8.5% Coal 43.2% Existing Purchases 7.9% Gas-CCCT 21.5% 247 248 ............................................ PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portolio Selecon Result 2018 Resource Energy Mix with Preferr Portolio Resources ($45 C02 Tax) Gas-CCT 1.2% Interruptible 0.1% CHP 0.5%Class 1 DSM 0.02% Front Offce Transactions 7.7% Renewable 9.7% Existig Purchases 7.80/. Gas-CCT 19.7% Figure 8.30 - Current and Projected PacifiCorp Resource Capacity Mi 2009 Resource Capacity Mix with Preferr Portolo Resurces ($45 C02 Tax) Hydrolectric 10.90/0 D8 0.0% Gacr 2.8-;. Cl 1 DSM 2.6% E:dtig Purchases 12.7% COO 461% Gas-ccr 15.30/. ............................................ PacifiCorp - 2008 iRP Chapter 8 - Modeling and Portfolio Selection Result 2014 Resource Capacity Mix with Preferred Portolio Resources ($45 CO2 Tax) Interruptile 1."/0 Hydroelectric 8.6% Coal 45.5% Gas-CCT 2.6% Class IDSM 3.5% Class2DSM 3.0% Exitig Purchases 5.2% Front Ofce Transactions 6.8% 2018 Resource Capacity Mi with Preferred Portolio Resources ($45 C02 Tax) CI..IDSM 3.60/. Existing Purchases 4.90/. Coal 42.6% Hydrolectric 8.7% Front Ofce Transacton 9.4% GaH:CCT 19.0% 249 PacifiCorp - 2008 IRP Chapter 8 - Modeling and Portfolio Selection Result PacifiCorp prepared a new load forecast in February 2009 after reviewing actual loads through January 2009. This forecast is being used to support corporate planning efforts including the ac- quisition path analysis outlined in the next Chapter, as well as recent regulatory filings. Table 8.46 compares the coincident peak loads for the two load forecasts. For the 2009 business plan, the load forecast was adjusted to include the expected impact of historical Class 2 DSM programs, which are assumed to contrbute incremental load reductions in the futue as equip- ment and appliances are replaced with higher-effciency alternatives. This load forecast adjust- ment was not included in previous IRP modeling, but is factored into the portfolio modeling us- ing the February 2009 load forecast. As with the federal lighting standards adjustment described in Chapter 5, this DSM adjustment has the effect of increasing the load forecast for capacity ex- pansion modeling only, so that the model can select additional DSM to fill the load gap. Includ- ing this adjustment also ensures that suffcient resource capacity is added in case the full amount of estimated future load reductions from existing Class 2 DSM programs is not realized. This adjustment, which partially offsets the recession-related load reductions, ranges from 34 MW in 2009 to 337 MW by 2018. Appendix E reports the detailed February 2009 forecast net of ex- pected future load reductions attbutable to existing Class 2 DSM programs and federal lighting standards. Table 8.46 - Coincident Peak Load Forecast Comparison Although the Company could not accommodate a comprehensive portfolio evaluation based on the February 2009 load forecast without contravening certin state IRP fiing requirements, PacifiCorp was nevertheless able to conduct a preferred portfolio sensitivity analysis with it. PacifiCorp developed a portfolio using this new DSM-adjusted load forecast and the case 5 input assumptions ($45/ton CO2 tax and low June 2008 forward price cures) with the CCCT fixed in 2014. As indicated in table 8.45, the peak load reductions are not sufficient to eliminate or defer a gas combined-cycle plant. 250 ............................................ ............................................ PacifìCorp - 2008 IRP Chapter 8 - Modeling and Portfolio Selection Results The resource impacts of applying the new load forecast with the DSM adjustment described above, relative to the 5B _ CCCT _ Wet portfolio, are as follows: . The IC aero SCCT originally added in 2016 is no longer needed . Front offce transactions are deferred in both the east and west, and decrease overall by about 100 MW by 2020; the east experiences a net increase of about 90 MW while the west experiences a net decrease of 185 MW in line with the lower loads . To make up for the loss of the IC aero SCCT and front offce transactions, the model added 41 MW of customer standby generation (30 MW in the east; 12 MW in the west), 50 MW of utility-scale biomass capacity in 2015-2016, and moved up 243 MW of wind from 2019 to 2017 Table 8.47 shows the resource capacity differences through 2020 between the portfolio produced using the new load forecast and the wet-cooled CCCT portfolio (5B_CCCT_ Wet). Table 8.47 - Resource Capacity Differences, February 2009 Load Forecast Portfolio less Wet-Cooled CCCT Portfolio 243 (243) 1 4 4 4 4 4 4 4 4 (2.1) 03 1.9 0.6 0.8 0.4 30 17 5 50 47 50 64 trHLH (7 (74 25 25 1 2 2 2 2 2 2 2 2 1.9 1.0.5 55 26 (17)(22)19) (44)71 (58)64 54 (42) Since the relative resource impact of the DSM-adjusted February 2009 load forecast is minimal until 2016, PacifiCorp decided to retain the IC aero SCCT in the preferred portfolio. Also sup- porting this decision is the uncertainty over the timing and pace of an economy recovery, com- bined with the short lead-time for a gas peaking resource and the potential need for such re- sources to support wind integration. Consideration of the timing and tye of gas resources and other resource changes wil be handled as par of a comprehensive assumptions update and port- folio analysis to be conducted for the next business plan and 2008 IRP update. 251 ............................................ PacifiCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management 9. ACTION PLAN AND RESOURCE RISK MANAGEMENT PacifiCorp's 2008 IRP action plan identifies the steps the Company wil take during the next two to four years to implement the plan, covering the 10-year resource acquisition time frme, 2009- 2018. Associated with the action plan is an acquisition path analysis that anticipates potential major regulatory actions expected during the action plan time horizon and other events that could materially impact resource acquisition strategies. The resources included in the 2008 IRP preferred portfolio were used to help define the actions included in the action plan, focusing on the size, timing, and tye of resources needed to meet load obligations and curent and potential future state regulatory requirements. The preferred portfolio resource combination was determined to be the lowest cost on a risk-adjusted basis ac- counting for cost, risk, reliability, and regulatory uncertainty. The 2008 IRP action plan is based upon the latest and most accurate information available at the time of portfolio study completion The Company recognizes that the preferred portfolio upon which the action plan is based reflects a snapshot view of the future that accounts for a wide range of uncertainties. The current volatile economic and regulatory environment wil likely re- quire near-term alteration to resource plans as a response to specific events and improved clarity concerning the direction of the economy and governent energy and environmental policies. For example, the economic stimulus package enacted in February 2009 ("The American Recovery and Reinvestment Act of 2009") introduced a number of provisions affecting resource planning, including extension and expansion of renewable and distrbuted energy technology tax benefits, fuding of grid infrastrcture improvements, and block grants for energy efficiency improve- ments. Provisions of the economic stimulus package, other than the renewable PTC extension, require more analysis to determine how they impact the Company and should be addressed within the IRP analytical framework. On the climate change mitigation front, the Waxman- Markey CO2 cap-and-trade provisions are under investigation, but the Company is not able to determine the impact on resource plans until the legislation is finalized. Complicating the pictue are state environmentaVenergy legislative proposals, such as Oregon's Senate Bil 80, that estab- lish a state CO2 cap-and-trade system. Resource information used in the 2008 IRP, such as capital and operating costs, is consistent with that used to develop the Company's business plan completed in December 2008. However, it is important to recognize that the resources identified in the plan are proxy resources and act as a guide for resource procurement. Resources evaluated as par of procurement initiatives may vary from the proxy resource identified in the plan with respect to resource tye, timing, size, cost, and location. Evaluations wil be conducted at the time of acquiring any resource to justify such acquisition. In addition to the action plan and acquisition path analysis, this chapter addresses a number of topics associated with resource risk management. These topics include the following: · Managing carbon risk for existing plants 253 PacifCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management · The use of physical and financial hedging for electrcity price risk . Managing gas supply risk · The treatment of customer and investor risks for resource planing Table 9.1 is a summary of the annual MW capacity and timing for the resources contained in the 2008 IRP preferred portfolio. A more comprehensive sumary of portolio resources can be found in Chapter 8. Table 9.1 - Preferred Portfolio, Summary Level 200 44 33 25 2 14 35 99 249 100 100 100 150 100 100 50 2 2 2 3 3 3 4 4 4 4 4 4 4 4 4 4 4 4 4 4 25 50 40 30 10 10 10 10 10 10 42 51 49 52 55 55 56 56 58 59 75 50 150 394 493 200 202 228 717 800 Coal Plant Turbine U 9 9 12 12Swift Hydro U gres 21 25 25 25Wind 45 20 200CHP 1 1 1 2 2 2 2Distrbuted Stadb Genemtion 1 1 1 1 1 1 1 DSM,Class 1DSM, Class 2 35 36 39 39 38 39 39 39 39 29Front Offce Tmnsaction 59 839 839 739 739 689 289 582 1/ The 99 MW amount in 2009 is t1e High Pla prject; th 249 MW in 2010 include t1e 99 MW Th Butt wind PPA 21 The Swift 1 hydro upds ar shown in t1e ye th th ente into coia seice, . Up to 120 MW of additional cot-effective Clas 1 DSM prgr (100 MW ea 30 MW west) to be idetified lhugh comptitive Reests for Propsals and pha in as appropriate frm 200-2018. Finn ma pur (3rd qua prct) would be re by roughly compable amounts. 42 75 265 16 12 U t030 372 The 2008 IRP action plan, detailed in Table 9.2, provides the Company with a road map for moving forward with new resource acquisitions, including major transmission projects needed to support the preferred portfolio and other Company objectives. (More detail on transmission ex- pansion action items is provided in Chapter 10.) 254 ............................................ .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t Ta b l e 9 . 2 - 2 0 0 8 I R P A c t i o n P l a n 1 Re n e w a b l e s Ac q u i r e a n i n c r e m e n t a l 1 , 4 0 0 M W o f re n e w ab I e s b y 2 0 1 8 , i n a d d i t i o n t o t h e a l r e a d y p l a n e d 7 5 M W o f ma j o r hy d r o e l e c t r i c u p g r a d e s i n 2 0 1 2 - 2 0 1 4 ; P a c i f i C o r p ' s p r o j e c t e d r e n e w a b l e r e s o u r c e i n v e n t o r y b y 2 0 1 8 e x c e e d s 2, 5 4 0 M W w i t h t h e s e r e s o u r c e a d d i t i o n s . S u c c e s s f u l l y a d d 1 4 4 M W o f w i n d r e s o u r c e s i n 2 0 0 9 t h a t a r e c u r e n t l y i n t h e p r o j e c t p i p e l i n e , i n c l u d i n g Pa c i f i C o r p ' s 9 9 M W H i g h P l a i n s f a c i l i t y i n W y o m i n g , a n d 4 5 M W o f po w e r p u r c h a s e a g r e e m e n t ca p a c i t y . S u c c e s s f u l l y a d d 2 6 9 M W o f w i n d r e s o u r c e s i n 2 0 1 0 t h a t a r e c u r r e n t l y i n t h e p r o j e c t p i p e l i n e , i n c l u d i n g 1 1 9 M W o f p o w e r p u r c h a s e a g r e e m e n t c a p a c i t y a l r e a d y c o n t r a c t e d . P r o c u r e u p t o a n a d d i t i o n a l 5 0 0 M W o f c o s t - e f f e c t i v e r e n e w a b l e r e s o u r c e s f o r c o m m e r c i a l o p e r a t i o n , su b j e c t t o t r a n s m i s s i o n a v a i l a b i l t y , s t a r t i n g i n t h e 2 0 0 9 t o 2 0 1 1 t i m e f r a m e u n d e r t h e c u r r e n t l y a c t i v e 20 0 9 _ 2 0 1 8 I r e n e w a b l e r e s o u r c e R F P ( 2 0 0 8 R - l ) a n d t h e n e x t r e n e w a b l e r e s o u r c e R F P ( 2 0 0 9 R ) e x p e c t e d t o b e i s s u e d in t h e s e c o n d q u a r e r o f 2 0 0 9 Th e C o m p a n y i s e x p e c t e d t o s u b m i t c o m p a n y r e s o u r c e s ( s e l f bu i l d o r o w n e r s h i p t r a n s f e r s ) i n th e 2 0 0 9 R R F P . P r o c u r e u p t o a n a d d i t o n a l 5 0 0 M W o f c o s t - e f f e c t i v e r e s o u r c e s f o r c o m m e r c i a l o p e r a t i o n , s u b j e c t t o tr a n s m i s s i o n a v a i l a b i l t y , s t a r t i n g i n t h e 2 0 1 2 t o 2 0 1 8 t i m e f r a m e v i a R F P s o r o t h e r o p p o r t u n i t i e s Pr o c u r e a t l e a s t 3 5 M W o f v i a b l e a n d c o s t - e f f e c t i v e g e o t h e r m a l o r o t h e r b a s e - l o a d r e n e w a b l e s . M o n i t o r s o l a r a n d e m e r g i n g t e c h n o l o g i e s , g o v e r n m e n t f i n a n c i a l i n c e n t i v e s , a n d p r o c u r e s o l a r o r o t h e r co s t - e f f e c t i v e r e n e w a b l e r e s o u r c e s d u r i n g t h e 1 0 - y e a r i n v e s t m e n t h o r i z o n . C o n t i n u e t o e v a l u a t e t h e p r o s p e c t s a n d i m p a c t s o f R e n e w a b l e P o r t f o l i o S t a n d a r d r u l e s a t t h e s t a t e a n d fe d e r a l le v e l s , a n d a d j u s t t h e r e n e w a b l e a c q u i s i t o n t i m e l i n e a c c o r d i n g l y Im p l e m e n t a b r i d g i n g s t r a t e g y t o s u p p o r t a c q u i s i t i o n d e f e r r a l o f l o n g - t e r m i n t e r m e d i a t e l b a s e - l o a d r e s o u r c e ( s ) i n th e e a s t c o n t r o l a r e a u n t i l n o s o o n e r t h a n t h e b e g i n n i n g o f s u m m e r 2 0 1 4 . A c q u i r e t h e f o l l o w i n g r e s o u r c e s : Up t o 1 , 4 0 0 M W o f e c o n o m i c f r o n t o f f c e t r a n s a c t i o n s o n a n a n n u a l b a s i s a s n e e d e d t h r o u g h 20 0 9 - 2 0 1 3 I 2 0 1 3 , t a k i n g a d v a n t a g e o f f a v o r a b l e m a r k e t c o n d i t i o n s At l e a s t 2 0 0 M W o f l o n g - t e r m p o w e r p u r c h a s e s Co s t - e f f e c t i v e i n t e r r p t i b l e c u s t o m e r l o a d c o n t r a c t o p p o r t i t i e s ( f o c u s o n o p p o r t i t i e s i n Ut a h ) . R e s o u r c e s w i l b e p r o c u r e d t h o u g h m u l t i p l e m e a n s : ( 1 ) r e a c t i v a t i o n o f th e s u s p e n d e d 2 0 0 8 A l l - S o u r c e 2 Fi r m M a r k e t Pu r c h a s e s 25 5 Pa c i f i C o r p - 2 0 0 8 I R P C h a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t 5 Cl a s s 1 D S M 20 0 9 - 2 0 1 8 RF P i n l a t e 2 0 0 9 , w h i c h s e e k s t h i r d q u a r t e r s u m m e r p r o d u c t s a n d c u s t o m e r p h y s i c a l c u r t a i l m e n t co n t r a c t s a m o n g o t h e r r e s o u r c e t y e s , ( 2 ) p e r i o d i c m i n i - R F P s t h a t s e e k r e s o u r c e s l e s s t h a n f i v e y e a r s i n te r m , a n d ( 3 ) b i l a t e r a l n e g o t i a t i o n s . C l o s e l y m o n i t o r t h e n e a r - t e r m n e e d f o r f r o n t o f f c e t r a n s a c t i o n s a n d r e d u c e a c q u i s i t i o n s a s a p p r o p r i a t e i f lo a d f o r e c a s t s i n d i c a t e r e c e s s i o n a r y i m p a c t s g r e a t e r t h a n a s s u m e d f o r t h e F e b r u a r y 2 0 0 9 lo a d f o r e c a s t . A c q u i r e i n c r e m e n t a l t r a n s m i s s i o n t h r o u g h T r a n s m i s s i o n S e r v i c e R e q u e s t s t o s u p p o r t r e s o u r c e ac q u i s i t i o n Pr o c u r e l o n g - t e r m f i r m c a p a c i t y a n d e n e r g y r e s o u r c e s f o r c o m m e r c i a l s e r v i c e i n t h e 2 0 1 2 - 2 0 1 6 t i m e f r a m e . T h e p r o x y r e s o u r c e s i n c l u d e d i n t h e p r e f e r r e d p o r t f o l i o c o n s i s t o f ( l ) a U t a h w e t - c o o l e d g a s c o m b i n e d - cy c l e p l a n t wi t h a s u m m e r c a p a c i t y r a t i n g o f 5 7 0 M W , a c q u i r e d b y t h e s u m m e r o f 2 0 1 4 , a n d ( 2 ) a 2 6 1 MW e a s t - s i d e i n t e r c o o l e d a e r o d e r i v a t i v e s i m p l e - c y c l e g a s p l a n t a c q u i r e d b y t h e s u m e r o f 2 0 1 6 . P r o c u r e t h r o u g h a c t i v a t i o n o f th e s u s p e n d e d 2 0 0 8 a l l - s o u r c e R F P i n l a t e 2 0 0 9 Th e C o m p a n y p l a n s t o s u b m i t C o m p a n y r e s o u r c e s ( s e l f - b u i l d o r o w n e r s h i p t r a n s f e r s ) o n c e t h e su s p e n s i o n i s r e m o v e d . I n r e c o g n i t i o n o f th e u n s e t t l e d U . S . e c o n o m y , e x p e c t e d c o n t i n u e d v o l a t i l t y i n n a t u r a l g a s m a r k e t s , a n d re g u l a t o r y u n c e r t a i n t y , c o n t i n u e t o s e e k c o s t - e f f e c t i v e r e s o u r c e d e f e r r a l a n d a c q u i s i t i o n o p p o r t u n i t i e s i n li n e w i t h n e a r - t e r m u p d a t e s t o l o a d / p r i c e f o r e c a s t s , m a r k e t c o n d i t i o n s , t r a n s m i s s i o n p l a n s , a n d re g u l a t o r y d e v e l o p m e n t s . Pu s u e e c o n o m i c p l a n t u p g r a d e p r o j e c t s - s u c h a s t u r b i n e s y s t e m i m p r o v e m e n t s a n d r e t r o f i t s - a n d u n i t av a i l a b i l t y i m p r o v e m e n t s t o l o w e r o p e r t i n g c o s t s a n d h e l p m e e t t h e C o m p a n y ' s f u t u e C O 2 a n d o t h e r en v i r o n m e n t a l c o m p l i a n c e r e q u i r e m e n t s . S u c c e s s f u l l y c o m p l e t e t h e d e n s e - p a c k c o a l p l a n t t u r b i n e u p g r a d e p r o j e c t s b y 2 0 1 6 , w h i c h a r e e x p e c t e d to a d d 1 2 8 M W o f i n c r e m e n t a l i n t h e e a s t a n d 4 2 M W i n t h e W e s t w i t h z e r o i n c r e m e n t a l e m i s s i o n s . S e e k t o m e e t t h e C o m p a n y ' s a g g r e g a t e c o a l p l a n t n e t h e a t r a t e i m p r o v e m e n t g o a l o f 2 1 3 B t u / k W h b y 20 1 8 5 5 . M o n i t o r t u r b i n e a n d o t h e r e q u i p m e n t t e c h n o l o g i e s f o r c o s t - e f f e c t i v e u p g r a d e o p p o r t u n i t i e s t i e d t o f u t u r e pl a n t m a i n t e n a n c e s c h e d u l e s Ac q u i r e a t l e a s t 2 0 0 - 3 0 0 M W o f c o s t - e f f e c t i v e C l a s s 1 d e m a n d - s i d e m a n a g e m e n t p r o g r a m s f o r i m p l e m e n t a t i o n in t h e 2 0 0 9 - 2 0 1 8 t i m e f r a m e . P u r s u e u p t o 2 0 0 M W o f e x p a n d e d U t a h C o o l K e e p e r p r o g r a m p a r t i c i p a t i o n b y 2 0 1 8 . P u r s u e U l J t o 1 3 0 M W o f ad d i t i o n a l c o s t - e f f e c t i v e c l a s s 1 D S M l J r o d u c t s ( 9 0 M W i n t h e e a s t s i d e a n d 3 0 3 Pe a k i n g I In t e r m e d i a t e I Ba s e - l o a d Su p p l y - s i d e Re s o u r c e s 20 1 2 - 2 0 1 6 4 Pl a n t Ef f c i e n c y Im p r o v e m e n t s 20 0 9 - 2 0 1 8 55 P a c i f i C o r . E n e r g y H e a t R a t e I m p r o v e m e n t P l a n , M a r c h 3 1 , 2 0 0 9 . 25 6 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f C o r p - 2 0 0 8 I R P C h a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t MW i n t h e w e s t s i d e ) t o h e d g e a g a i n s t t h e r i s k o f hi g h e r g a s p r i c e s a n d a f a s t e r - t h a n - e x p e c t e d r e b o u n d in l o a d g r o w t h r e s u l t i n g f r o m e c o n o m i c r e c o v e r y P r o c u r e t h r o u g h t h e c u r r e n t l y a c t i v e 2 0 0 8 D S M R F P an d s u b s e q u e n t D S M R F P s . F o r 2 0 0 9 - 2 0 1 0 , i m p l e m e n t a s t a n d a r d i z e d C l a s s i D S M s y s t e m b e n e f i t e s t i m a t i o n m e t h o d o l o g y f o r pr o d u c t s m o d e l e d i n t h e I R P . T h e m o d e l i n g w i l c o m p l i m e n t t h e s u p p l y c u r v e w o r k b y p r o v i d i n g ad d i t i o n a l r e s o u r c e v a l u e i n f o r m a t i o n t o b e u s e d t o e v o l v e c u r e n t C l a s s i p r o d u c t s a n d e v a l u a t e n e w pr o d u c t s w i t h s i m i l a r o p e r a t i o n a l c h a r a c t e r i s t i c s t h a t m a y b e i d e n t i f i e d b e t w e e n p l a n s . Ac q u i r e 9 0 0 - 1 , 0 0 0 M W o f c o s t - e f f e c t i v e C l a s s 2 p r o g r a m s b y 2 0 1 8 ( p e a k c a p a c i t y ) , e q u i v a l e n t t o a b o u t 4 3 0 t o 20 0 9 - 2 0 1 8 I 4 8 0 M W a . P r o c u r e t h r o u g h t h e c u r r e n t l y a c t i v e D S M R F P a n d s u b s e q u e n t D S M R F P s Ac q u i r e c o s t - e f f e c t i v e C l a s s 3 D S M p r o g r a m s b y 2 0 1 8 . P r o c u r e p r o g r a m s t h r o u g h t h e c u r r e n t l y a c t i v e D S M R F P a n d s u b s e q u e n t D S M R F P s . C o n t i n u e t o e v a l u a t e p r o g r a m a t t r i b u t e s , s i z e / d i v e r s i t y , a n d c u s t o m e r b e h a v i o r p r o f i l e s t o d e t e r m i n e th e e x t e n t t h a t s u c h p r o g r a m s p r o v i d e a s u f f c i e n t l y r e l i a b l e f i r m r e s o u r c e f o r l o n g - t e r m p l a n n i n g . P o r t f o l i o a n a l y s i s w i t h C l a s s 3 D S M p r o g r a m s i n c l u d e d a s r e s o u r c e o p t i o n s i n d i c a t e d t h a t a t l e a s t 10 0 M W m a y b e c o s t - e f f e c t i v e ; c o n t i n u e t o e v a l u a t e p r o g r a m s p e c i f c a t i o n a n d c o s t - e f f e c t i v e n e s s i n th e c o n t e x t o f I R P p o r t f o l i o m o d e l i n g 6 Cla s s 2 DS M 7 cl a s s 3 D S M 20 0 9 - 2 0 1 8 8 Di s t r i b u t e d Ge n e r a t i o n 20 0 9 - 2 0 1 8 9 Pl a n n i n g Pr o c e s s 20 0 9 - 2 0 1 0 Pu r s u e a t l e a s t 1 0 0 M W o f d i s t r i b u t e d g e n e r a t i o n r e s o u r c e s b y 2 0 1 8 . P r o c u r e a t l e a s t 5 0 M W o f c o m b i n e d h e a t a n d p o w e r ( C H P ) g e n e r a t i o n : 3 0 M W f o r t h e e a s t s i d e an d 2 0 M W f o r t h e w e s t s i d e , t o i n c l u d e p u r c h a s e o f f a c i l t y o u t p u t p u r s u a n t t o P U R P A r e g u l a t i o n s su p p l y - s i d e R F P s ( r e n e w a b l e s h e l f R F P s a n d A l l S o u r c e R F P s , w h i c h p r o v i d e f o r Q F s w i t h a ca p a c i t y o f 1 0 M W o r g r e a t e r ) , a n d o t h e r o p p o r t u n i t i e s ; f o c u s o n r e n e w a b l e f u e l a n d o t h e r " c l e a n " fa c i l t i e s t o t h e e x t e n t t h a t fe d e r a l a n d s t a t e R e n e w a b l e P r o d u c t i o n T a x c r e d i t r u l e s p r o v i d e ad d i t i o n a l R e n e w a b l e E n e r g y C r e d i t v a l u e t o s u c h f a c i l t i e s . P r o c u r e a t l e a s t 5 0 M W o f c o s t - e f f e c t i v e c u s t o m e r s t a n d b y g e n e r a t i o n : 3 8 M W f o r t h e e a s t s i d e (s u b j e c t t o a i r p e r m i t t i n g r e s t r i c t i o n s a n d o t h e r i m p l e m e n t a t i o n c o n s t r a i n t s ) a n d 1 2 M W f o r t h e w e s t si d e . P r o c u r e m e n t t o b e h a n d l e d b y c o m p e t i t i v e R F P f o r d e m a n d r e s p o n s e n e t w o r k s e r v i c e a n d / o r in d i v i d u a l c u s t o m e r a g r e e m e n t s · S e e k u p t o a n a d d i t i o n a l 4 0 M W o f c u s t o m e r s t a n d b y g e n e r a t i o n i f t h e e c o n o m i c r e c e s s i o n a n d ma r k e t c o n d i t i o n s c o n t i n u e t o s u p p o r t e l i m i n a t i o n o f s i m p l e - c y c l e g a s u n i t s o r o t h e r p e a k i n g re s o u r c e s a s i n d i c a t e d b y I R p o r t f o l i o m o d e l i n g f o r t h e 2 0 1 0 b u s i n e s s p l a n / 2 0 0 8 I R P u p d a t e Po r t f o l i o m o d e l i n g i m p r o v e m e n t s . C o m o l e t e t h e i m o l e m e n t a t i o n o f S 25 7 Pa d ~ C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t Im p r o v e m e n t s 10 Tr a n s m i s s i o n 11 Tr a n s m i s s i o n 12 Tr a n s m i s s i o n 20 0 9 - 2 0 1 1 20 1 0 20 1 2 im p r o v e d r e p r e s e n t a t i o n o f C O 2 a n d R P S r e g u l a t o r y r e q u i r e m e n t s a t t h e j u r i s d i c t i o n a l l e v e l · C o n t i n u e t o i m p r o v e w i n d r e s o u r c e m o d e l i n g b y r e f i n i n g t h e r e p r e s e n t a t i o n o f i n t e r m i t t e n t w i n d re s o u r c e s ; a t t r i b u t e s t o c o n s i d e r i n c l u d e i n c r e m e n t a l r e s e r v e r e q u i r e m e n t s a n d o t h e r c o m p o n e n t s t i e d t o sy s t e m i n t e g r a t i o n , g e o g r a p h i c a l d i v e r s i t y i m p a c t s , a n d p e a k l o a d c a r r i n g c a p a b i l i t y e s t i m a t i o n · R e f i n e m o d e l i n g t e c h n i q u e s f o r D S M s u p p l y c u r e s / p r o g r a m v a l u a t i o n , a n d d i s t r i b u t e d g e n e r a t i o n · I n v e s t i g a t e a n d i m p l e m e n t , i f be n e f i c i a l , t h e L o s s o f Lo a d P r o b a b i l i t y ( L O L P ) r e l i a b i l i t y c o n s t r a i n t fu c t i o n a l i t y i n t h e S y s t e m O p t i m i z e r c a p a c i t y e x p a n s i o n m o d e l . C o n t i n u e t o c o o r d i n a t e w i t h P a c i f i C o r p ' s t r a n s m i s s i o n p l a n n i n g d e p a r t m e n t o n i m p r o v i n g t r a n s m i s s i o n in v e s t m e n t a n a l y s i s u s i n g t h e I R P m o d e l s . C o n t i n u e t o i n v e s t i g a t e t h e f o r m u l a t i o n o f s a t i s f a c t o r y p r o x y i n t e r m e d i a t e - t e r m m a r k e t p u r c h a s e re s o u r c e s f o r p o r t f o l i o m o d e l i n g , c o n t i n g e n t o n a c q u i r i g s u i t a b l e m a r k e t d a t a Es t a b l i s h a d d i t i o n a l p o r t f o l i o d e v e l o p m e n t s c e n a r o s f o r t h e b u s i n e s s p l a n t h a t w i l b e c o m p l e t e d b y t h e e n d o f 20 0 9 , a n d w h i c h w i l s u p p o r t t h e 2 0 0 8 I R P u p d a t e . A f e d e r a l C O 2 c a p - a n d - t r a d e p o l i c y s c e n a r i o a l o n g t h e l i n e s o r i g i n a l l y p r o p o s e d f o r t h i s I R P · C o n s i d e r d e v e l o p i n g o n e o r m o r e s c e n a r i o s i n c o r p o r a t i n g p l u g - i n e l e c t r i c v e h i c l e s a n d S m a r G r i d te c h n o l o g i e s Ob t a i n C e r t i f i c a t e s o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r U t a h / y o m i n g l N o r t h w e s t s e g m e n t s o f th e E n e r g y Ga t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f i C o r p l o a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o ma r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . O b t a i n C e r t i f i c a t e o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r a 5 0 0 k V l i n e b e t w e e n M o n a T o O q u i r r h · O b t a i n C e r t i f i c a t e o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r 2 3 0 k V a n d 5 0 0 k V l i n e b e t w e e n W i n d s t a r an d Po p u l u s · O b t a i n C e r t i f i c a t e o f Pu b l i c C o n v e n i e n c e a n d N e c e s s i t y f o r a 5 0 0 k V l i n e b e t w e e n P o p u l u s a n d He m i n g w a y Pe r m i t a n d b u i l d U t a h d a h o l N e v a d a s e g m e n t s o f th e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t Pa c i f i C o r p l o a d g r o w t , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n re l i e f . P e r m i t a n d c o n s t r u c t a 3 4 5 k V l i n e b e t w e e n P o p u l u s t o T e r m i n a l Pe r m i t a n d b u i l d U t a h s e g m e n t o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f C o r p l o a d g r o w t h , re g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . P e r m i t a n d c o n s t r u c t a 5 0 0 k V l i n e b e t w e e n M o n a a n d O q u i r r h 25 8 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t 13 Tr a n s m i s s i o n 20 1 4 14 Tr a n s m i s s i o n 20 1 6 15 Tr a n s m i s s i o n 20 1 7 Pe r m i t a n d b u i l d s e g m e n t s o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f C o r p l o a d g r o w t h , re g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . P e r m i t a n d c o n s t r u c t 2 3 0 k V a n d 5 0 0 k V l i n e b e t w e e n W i n d s t a r a n d P o p u l u s . P e r m i t a n d c o n s t r u c t a 3 4 5 k V l i n e b e t w e e n S i g u r d a n d R e d B u t t e Pe r m i t a n d b u i l d N o r t h w e s t / U t a h / N e v a d a s e g m e n t s o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t Pa c i f C o r p l o a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n re l i e f . P e r m i t a n d c o n s t r u c t a 5 0 0 k V l i n e b e t w e e n P o p u l u s a n d H e m i n g w a y Pe r m i t a n d b u i l d W y o m i n g / U t a h s e g m e n t o f t h e E n e r g y G a t e w a y T r a n s m i s s i o n P r o j e c t t o s u p p o r t P a c i f C o r p lo a d g r o w t h , r e g i o n a l r e s o u r c e e x p a n s i o n n e e d s , a c c e s s t o m a r k e t s , g r i d r e l i a b i l t y , a n d c o n g e s t i o n r e l i e f . P e r m i t a n d c o n s t r u c t a 5 0 0 k V l i n e b e t w e e n A e o l u s a n d M o n a 25 9 PacifiCorp - 200BIRP Chapter 9 - Acton Plan and Resource Risk Management This section describes progress that has been made on previous active action plan items docu- mented in the 2007 Integrated Resource Plan Update report fied with the state commissions on June 11,2008. Most of these action items have been superseded in some form by items identified in the current IRP action plan. Action Item 1: Acquire 2,000 MW of renew abIes by 2013, including the 1,400 MW outlned in the Renewable Plan. Seek to add trnsmission infrastrctue and flexible generating resources, such as natural gas, to integrate new wind resources. Status: PacifCorp is on pace to exceed the 2,000 MW target by 2013. Since 2005, the Com- pany's projected renewable resource inventory has grown by 1,405 MW accountingfor existing resources and those under construction, contract, or included in a capital budget. The incre- mental renewables identifed in the 2008 IRP preferred portfolio and action plan bring the target to about 2,040 MW by 2013. The projected inventory exceeds 2,540 MW by 2018. Action Item 2: Acquire the base Class 2 DSM (Pacific Power and Energy Trust of Oregon com- bined, including energy savings in Oregon beyond that fuded by the ETO) of 300 MWa and 200 MWa or more of additional Class 2 DSM if risk-adjusted cost-effective initiatives can be identified. Wil work with the ETO to identify such new energy effciency initiatives and fie the necessary tariffs with the Public Utility Commission of Oregon. PacifiCorp wil reassess Class 2 objectives upon completion of system-wide DSM potential study. Wil incorporate potentials study findings into the 2007 IRP update and 2008 integrated resource planing processes, includ- ing developing supply cures, modeling them as portolio options that compete with supply-side options, and analyzing cost and risk reduction benefits. Modeling also wil take into account the benefits of conservation in reducing the costs of complying with Renewable Portfolio Standards. Status: This action item has been superseded by Action Item no. 6 in Table 9.2. PacifCorp issued a DSM RFP in November 2008 to help meet Class 1 DSM acquisition goals. Action Item 3: Targets were established though potential study work performed for the 2007 IRP. Acquire 100 MW or more of additional Class 1 resources if risk-adjusted cost-effective ini- tiatives can be identified. A new potential study was completed June 2007, and associated find- ings wil be incorporated into the 2007 update and the 2008 integrated resource planing proc- esses, including developing supply cures, modeling them as portfolio options that compete with supply-side options, and analyzing cost and risk reduction benefits. Status: This action item has been superseded by Action Item no. 5 in Table 9.2. Pacif- Corp developed Class 1 DSM supply curves using the DSM potentials study data, and in- corporated them into the portfolio modeling for this IRP. Action Item 4: Although not curently in the base resource stack, the Company wil seek to lev- erage Class 3 and 4 resources to improve system reliability durng peak load hours. PacifiCorp 260 ............................................ ............................................ Paci~Corp - 20081RP Chapter 9 - Acton Plan and Resource Risk Management wil incorporate potential study findings into the 2007 update and/or 2008 integrated resource planning processes. Status: This action item has been superseded by Action Item no. 7 in Table 9.2. Pacif- Corp developed Class 3 DSM supply curves using the DSM potentials study data, and in- corporated them into the portfolio modeling for this IRP. The all-source DSM RFP seeks price-responsive product proposals. Action Item 5: Pursue at least 75 MW of combined heat and power generation for the west-side and 25 MW for the east-side, to include purchase of combined heat and power output pursuant to PURP A regulations and from supply-side RFPs. The potential study results wil be incorporated into the 2007 update and 2008 integrated resource planing processes. Status: This action item has been superseded by Action Item no. 8 in Table 9.2. Pacif- Corp has about 75 MW online ofCHPlother distributed generation resources and 30-40 MW in the project pipeline. Action Item 6: (Distrbuted Generation) Wil incorporate potential study findings into the 2007 update and 2008 integrated resource planning processes. Status: This action item has been successfully completed Chapter 6 describes how PacifCorp incorporated distributed generation resources in the 2008 IRP portfolio mod- eling process. Action Item 7: Procure base load / intermediate load / summer peak resources system-wide by the summer of 2012 through 2016. This is part of the requirement included in the 2012 Base Load RFP and the 2008 All Source RFP. Status: This action item has been superseded by Action Item no. 3 in Table 9.2. Pacif- Corp wil reactivate the suspended 2008 All-Source RFP in late 2009 to assist in procur- ing the needed resources Action Items 8 through 12: Status: These action items are no longer active. Action Item 13: Pursue the addition of transmission facilities or wheeling contracts as identified in the IRP to cost-effectively meet retail load requirements, integrate wind and provide system reliability. Work with other transmission providers to facilitate joint projects where appropriate. Status: This action item has been superseded by Action Item nos. 10 through 15 in Table 9.2. Chapter 4 and Chapter 10 outline the Company's transmission expansion plans. Action Item 14: Continue to have dialogue with stakeholders on Global Climate Change issues. Status: PacifCorp continues to participate in numerous forums that address these issues. PacifCorp's Environmental Policy and Strategy department and Government Affairs de- 261 PacifìCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Rik Management partment are among the lead organizations within the Company that participate in ongo- ing policy dialogues. Action Item 15: Evaluate technologies that can reduce the carbon dioxide emissions of the Company's resource portfolio in a cost-effective manner, including but not limited to, clean coal, sequestration, and nuclear power. For the 2008 IRP, include integrated gasification combined cycle (IGCC) plants with carbon captue and sequestrtion as a resource option for selection. Status: A variety of clean generating technologies were evaluated in this IRP, including a range of renewables, nuclear plants, and coal plants with carbon capture and sequestra- tion (IGCC and conventional coal plant CCS retrofits). Action Item 16: Continue to investigate implications of integrting at least 2,000 MW of wind to PacifiCorp's system. Status: This action item has been superseded by Action Item Nos. 1 and 9 in Table 9.2. PacifCorp is currently updating its wind integration cost estimates, and wil include the results as Appendix F in the separate appendix volume for the May 29 IRP filing. Pacif- Corp is also pursuing operational improvements for integrating wind resources. This ac- tivity is briefly described in the Resource Procurement Strategy section below. Action Item 17: Update modeling tools and assumptions to reflect policy changes in the area of renewable portfolio standards and carbon dioxide emissions. Status: This action item has been superseded by Action Item no. 9 in Table 9.2. Pacif- Corp has successfully updated modeling assumptions, including detailed representation of state RPS requirements as system load-based constraints. See Chapter 7 for details on the modeling approach for representing RPS compliance and CO2 costs. Action Item 18: Work with states to gain acknowledgement or acceptance of the 2008 integrated resource plan and action plan. To the extent state policies result in different acknowledged plans, work with states to achieve state policy goals in a manner that results in full cost re.covery of prudently incured costs. Status: Activity under this action item wil commence after filing of the 2008 IRP with the state commissions. Action Item 19: In the next IRP, evaluate intermediate-term market purchases, modeling them as portfolio options that compete with other resource options, and analyze cost and risk. Status: This action item has been superseded by Action Item no. 9 in Table 9.2. In formu- lating market purchase options for the IRP models, the Company lacked information with which to discriminate such purchases from the proxy front offce transaction (FaT) re- sources already modeled in this IRP. Lacking such information, the Company anticipated using bid information from the 2008 All-Source RFP to inform the development of inter- mediate-term market purchase resources for modeling purposes. The Company received 262 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 9 - Action Plan and Resource Risk Management no intermediate-term market purchase bids; therefore, such resources could not be rea- sonably modeled for this IRP. (See Chapter 6, "Resource Options") PacifCorp wil con- tinue to investigate the formulation of satisfactory intermediate-term market purchases for portfolio modeling contingent on acquiring suitable market data. Action Item 20: For the 2008 IRP, develop a scenario to meet the CO2 emissions reduction goals in Oregon HB 3543, including development of a compliant portfolio that meets the Commis- sion's best cost/risk standard. Status: This action item was successfully completed. PacifCorp designed a portfolio analysis to address this requirement, estimating a system-wide hard cap based on Ore- gon's HE 3543 emission reduction goals. A description of this portfolio scenario ("case 40") is provided in Chapter 7; modeling results are provided in Chapter 8. Action Item 21: For the 2008 IRP, fuher develop with stakeholders, use of loss of load prob- abilty (LOLP) and energy not served (ENS). Fully develop cost and risk metrics of various LOLP and ENS criteria. Status: This action item has been superseded by Action Item no. 9 in Table 9.2. The Company wil investigate functionality in the System Optimizer model that allows the ap- plication of an LOLP constraint for capacity planning. Action Item 22: For the 2008 IRP, consider the impact of forced early retirements of existing coal plants, or retrofits necessary to reduce their CO2 emissions, under strngent carbon regula- tion scenarios. Status: This action item has been successfully completed. PacifCorp incorporated exist- ing plant retrofits with carbon capture and sequestration technology as capacity expan- sion model resource options. Additionally, portfolios were developed to simulate the ef- fect of forced coal plant back-down through high CO2 costs and emissions hard cap con- straints. The associated analysis is provided in Chapter 8. Action Item 23: Pursue refinement of CO2 emissions modeling to improve treatment of compli- ance under varous regulatory schemes, including assignent of emission rates to short-term market transactions. Status: This action item has been superseded by Action Item no. 9 Table 9.2, which high- lights the CO2 modeling enhancements that PacifCorp is currently in the process of im- plementation with its model software vendor, Ventyx Energy, LLC. Completion of the software enhancements are expected in the summer of 2009. The IRP is not only a regulatory requirement, but is also a primary tool for PacifiCorp's business planning. As indicated in Chapter 2, the Company has made a concerted effort to fuher align 263 Paci~Corp - 20081RP Chapter 9 - Acton Plan and Resource Risk Management these two planing processes durng this IRP cycle. The business planning process addresses the impacts of resources on the Company's financial health, electrcity rates, and the prospects for successful recovery of shareholder investments. Considerations such as resource affordability and financeability thus serve as checks to make sure that the IRP's long-term planning perspec- tive comports with prudent utility business practices under today's commercial and regulatory environments. For IRP and business planning alignent puroses, major resource differences between the 2008 preferred portfolio and the 2009 business plan approved in December 2008 were analyzed by PacifiCorp Energy's finance departent for rate and financial impacts. This analysis also sup- ported credit rating agency review of the business plan. The major resource changes included deferral of the CCCT to 2014 from 2012, deferrl of the IC Aero SCCT to 2016 from 2013, and a modified wind acquisition schedule. (The preferred portfolio includes an additional 450 MW from 2009 though 2018.) To acquire resources outlined in the 2008 IRP action plan, PacifiCorp intends to continue using competitive solicitation processes in accordance with the then-curent law, rules, and/or guide- lines in each of the states in which PacifiCorp operates. PacifiCorp wil also continue to pursue opportnistic acquisitions identified outside of a competitive procurement process that provide clear economic benefits to customers. Regardless of the method for acquiring resources, the Company wil use its IRP models to support resource evaluation as part of the procurement proc- ess, with updated assumptions including load forecasts, commodity prices, and regulatory re- quirement information available at time that the resource evaluations occur. This wil ensure that the resource evaluations account for a long-term system benefit view in alignent with the IRP portfolio analysis framework as directed by state procurement regulations, and with business planning goals in mind. The sections below profile the general procurement approaches for the key resource categories covered in the action plan: renewables, demand-side management, thermal plants, distrbuted generation, and market purchases. Renewable Resources The renewables 2008R-l shelf RFP is representative of the mechanism under which the Company wil issue subsequent RFPs to meet most of the renewable resource acquisition goals over the ten- year business planing horizon. The 2008R-I shelfRFP, to be re-issued on a periodic basis, wil al- low the Company to react effectively to power supply market developments and changes in the status of RPS requirements, the production tax credit, other financial incentives, and CO2 legislation. The Company wil seek both cost-effective conventional and emerging renewable technologies through the RFP process, including those coupled with energy storage. Qualifying Facilities under the Public Utilities Regulatory Policy Act (PURP A), at least 10 MW in size, are also treated as eligible re- sources under this particular RFP program. The Company wil also pursue renewable resources through means other than the shelf RFP in recognition that strong competition for renewable projects, and the dynamic natue of renewable 264 ............................................ ............................................ Paci~Corp - 2008 IRP Chapter 9 - Aaion Plan and Resource Risk Management constrction and equipment markets, wil require the Company to respond quickly and effi- ciently as resource opportities arise. Other procurement strategies that PacifiCorp wil pursue in parallel include bilateral negotiations, PURP A contracting, and self~development. In addition to supply-side resource acquisition, the Company wil add transmission infrstrctue and flexible generating resources to support and integrate wind generation. PacifiCorp wil also work to improve its understanding of how to integrate large amounts of wind into its portfolio in a reliable and cost-effective manner. Areas of focus include wind forecasting, scheduling prac- tices, curtailment tools, and regional coordination activities. Demand-side Management PacifiCorp uses a variety of business processes to implement DSM programs. The outsourcing model is preferred where the supplier takes the performance risk for achieving DSM results (such as the Cool Keeper program). In other cases, PacifiCorp manages the program and con- tracts out specific tasks (such as the Energy FinAswer program). A third method is to operate the program completely in-house as was done with the Idaho Irrgation Load Control program. The business process used for any given program is based on operational expertise, pedormance risk and cost-effectiveness. With some RFP's, PacifiCorp developed a specific program design, and put that design out to competitive bid. In other cases, as with the currently active 2008 DSM RFP issued in November 2008, PacifiCorp opened up bidding to many tyes of Class 1,2, and 3 programs and design options. To support the DSM procurement program, the IRP models are used for resource valuation pur- poses to gauge the cost-effectiveness of programs identified for procurement shortlists. In the case of the 2008 DSM RFP, system benefit valuation estimates wil be provided for both Class i and 2 programs. For Class 2 programs, PacifiCorp wil pedorm a "no cost" load shape decre- ment analysis to derive program values, similar to what was done for the 2007 IRP. (Although the supply cure modeling approach used for Class i and Class 2 DSM programs can provide a gross-level indication of program value, an avoided-cost tye of study is necessary to pinpoint precise values suitable for cost-effectiveness assessment.) Thermal Plants and Power Purchases Prior to the issuance of any supply-side RFP, PacifiCorp wil determine whether the RFP should be "all-source" or if the RFP wil have limitations as to the amount, proposal strctue(s), fuel type, or other resource attbutes. The Company has lately turned to all-source RFPs in support of IRP fuel-type and technology diversity goals. For example, the 2008 all-source RFP does not specify fuel type requirements, and seeks a range of resources including renewables (greater than i 0 MW), power purchase agreements, load curailment, and QFs. Company benchmark resources wil also be determined prior to an RFP being issued and may consist of a self-build option or ownership transfer arrangement. As with other resource catego- ries, the IRP models wil be used for bid evaluation, and wil reflect the latest market prices, load forecasts, regulatory policies, and other updated information as appropriate. 265 PaciCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management Distributed Generation Distrbuted generation, such as CHP and distrbuted standby generators, were found to be cost- effective resources in the context of IRP portfolio modeling. PacifiCorp's procurement process wil continue to provide an avenue for such new or existing resources to participate. These re- sources wil be advantaged by being given a minimum bid amount (MW) eligibility that is ap- propriate for such an alternative, but that is also consistent with PacifiCorp's then-curent and applicable tariff filings (QF tariffs for example). As noted in the action plan, QFs of 10 MW or greater are considered eligible resources in the Company's curently active renewables RFP (2008R-l) and the 2008 All Source RFP, which was suspended in February 2009, but is expected to be reactivated later in 2009. PacifiCorp wil continue to participate with regulators and advocates in legislative and other regulatory activities that help provide ta or other incentives to renewable and distributed gen- eration resources. The Company wil also continue to improve representation of distrbuted gen- eration resource in the IRP models. As the Company acquires new resources, it wil need to determine whether it is better to own a resource or purchase power from another par. While the ultimate decision wil be made at the time resources are acquired, and wil primarly 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 futue, 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 it remains economic. In addition, by owning a plant, the Company can hedge itself from the uncer- tainty of relying on purchasing power from others. On the negative side, owning a facility sub- jects 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 facilty's life. Purchasing power from another par can help mitigate the risk of cost overrs durng constrc- tion and operation of the plant, can mitigate some cost and performance risks, and can avoid any liabilities associated with closure of the plant. Short-term purchased power contracts could allow the Company to defer a long term resource acquisition. On the negative side, a long-term pur- chase power contract relinquishes control of constrction cost, schedule, ongoing costs and com- pliance to a third par, and exposes the buyer to default events and contract remedies that wil not likely cover the potential negative impacts. For example, a purchase power contract could terminate prior to the end of the term, requiring the Company to replace the output of the con- tract at then curent market prices. In addition, the Company and customers do not receive any of the savings that result from management of the asset, nor do they receive any of the value that arise from the plant after the contrct has expired. Finally, credit rating agencies impute debt as- sociated with long-term resource contrcts that may result from a competitive procurement proc- ess, and such imputation can affect the Company's credit ratios and credit rating. 266 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management The acquisition path analysis conducted for the 2008 IRP focuses on four risk areas: regulatory events, load growth, natural gas prices, and procurement delays. The sections below present con- tingency resource strategies for the Company to consider given signficant changes in resource planning conditions tied to these four risk areas. The decision mechanism for pursuing resource strategies is the outcome of the business planning process, which wil be informed by portfolio modeling using the IRP models and updated input assumptions. Regulatory Events Table 9.3 outlines a set of resource acquisition strategies tied to regulatory "trgger" events that have been analyzed for the 2008 IRP via input assumption scenarios developed for portolio analysis. These trgger events include (1) a fairly strngent federal RPS is enacted, (2) the federal renewable production tax credit expires or is phased out in the next 10 years, and (3) federal CO2 regulation is enacted that results in CO2 cost above and below PacifiCorp's assumed C02 trigger point, which is the CO2 cost that yields significant changes in the resource mix. Table 9.3 also lists major risks and implementation constraints for each acquisition strategy. The Public Utility Commission of Oregon IRP guidelines require PacifiCorp to "provide its as- sessment of whether a CO2 regulatory future that is equally or more strngent than the identified trigger point wil be mandated.,,56 For the 2008 IRP, PacifiCorp dermed a trgger point of $45/ton (modeled as a CO2 tax) to demarcate the point at which large changes to futue resource acquisitions, and significant changes to existing fossil fuel resource operations, take place. Rela- tive to the 2008 IRP preferred portfolio, defined with the $45/ton CO2 cost, PacifiCorp defined a trgger point of $70/ton that indicates a reasonable point at which fuher significant changes to futue resource acquisition, as well as major changes to existing fossil fuel resource operations, take place. The Company developed numerous portfolios based on these CO2 cost trgger points, along with portfolios defined with even higher costs: a $100 CO2 tax, and a $45 CO2 tax with real escalation that reaches over $160 by 2028. (Chapter 8 provides expected cost and risk per- formance results as required by the Oregon IRP guidelines.) PacifiCorp also developed portfolios with no C02 tax for estimation of the portfolio cost of C02 regulations. The likelihood that CO2 prices would reach or exceed $70/ton depends on the confluence of both federal and state policies that have yet to be determined regarding overall strategic goals, pro- gram design, and economic sector/industr responsibilities for helping to attain long-term C02 reduction objectives. Specifically, governents wil need to determine if policies are needed to severely restrct the use of existing fossil fuel resources, and not just discourage new coal plants from being built. Until that policy question is answered, PacifiCorp has no basis to predict whether C02 costs wil exceed any particular leveL. Even when this policy question is answered, there are many uncertainties that complicate the task of predicting how high CO2 prices wil go at this time. For example, assuming that the U.S. adopts a cap-and-trade system like the Waxman-Markey proposal, such open issues as the trjec- tory of annual CO2 caps, free allowance and offset policies, state/federal interjursdictional coor- 56 Public Utility Commission of Oregon, Order No. 08-339, "Investigation into the Treatment of C02 Risk in the Integrated Resource Planning Process", Guideline 8d, June 30, 2008. 267 PacißCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management dination, safety valve provisions, linkages to potential federal RPS requirements, and many other factors, wil ultimately determine if CO2 costs exceed $70/ton. Adding to the uncertainty are the following factors: · The perceived affordability of aggressive C02 reduction policies in today's economic en- vironment, which could result in a "take it slow" regulatory track . The pace of technology advancements · Public policies towards clean coal, advanced nuclear, and other emerging technologies that are curently controversial · Commitments to reaching international climate change mitigation goals Load Growth and Gas Prices Figure 9.1 shows different resource acquisition paths based on combinations of relative de- creases and increases in load growth and gas price projections given the 2008 IRP preferred port- folio input assumptions as the staring point. The acquisition paths shown are necessarily high- level, reflecting resource tyes rather than quantities and timing. The figure also highlights the connection with CO2 regulations, the uncertinty of which greatly complicates any type of con- tingency resource planning involving other planning varables. 268 ............................................ .. . . . . . . . . . . . . . . . . . . . . 1 . . . . . . . . . . . . . . . . . . . . . . . Pa c i ~ C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t Ta b l e 9 . 3 - R e s o u r c e A c q u i s i t i o n P a t h s T r i g g e r e d b y M a j o r R e g u l a t o r y A c t i o n s Fe d e r a l R e n e w a b l e Po r t f o l i o S t a n d a r d en a c t e d Fe d e r a l r e n e w a b l e pr o d u c t i o n t a x cr e d i t e x p i r a t i o n o r cu t b a c k . A f e d e r a l R P S i s i n s t i t u t e d r e q u i r i n g i 5 % o f l o a d t o b e m e t w i t h q u a l i f y - in g r e n e w a b l e s b y 2 0 2 0 , 2 0 % b y 20 2 0 , a n d 2 5 % b y 2 0 2 5 . . T h e f e d e r a l r e n e w a b l e s P T C e x p i r e s wi t h i n t h e 2 0 1 3 - 2 0 1 8 p e r i o d f o r wi n d , o r l e s s l i k e l y , a l l r e n e w a b l e r e - so u r c e s . . T h e f e d e r a l r e n e w a b l e s P T C i s ph a s e d o u t o v e r a m u l t i - y e a r p e r i o d . . C u m u l a t i v e w i n d c a p a c i t y t o t a l s o f 1 , 6 0 0 M W an d 3 , 5 0 0 M W a r e n e e d e d b y 2 0 2 0 a n d 2 0 2 5 , re s p e c t i v e l y , b a s e d o n t h e p o r t f o l i o d e v e l o p e d fo r t h e h i g h R P S r e q u i r e m e n t s c e n a r i o ( c a s e 44 ) . . S p r e a d i n c r e m e n t a l r e n e w a b l e s a c q u i s i t i o n a c - co r d i n g t o a n a n u a l s c h e d u l e f o r p r o c u r e m e n t fl e x i b i l i t y , a c c e l e r a t i n g a s n e c e s s a r t o a c c o u n t fo r n e a r - t e r m R P S r e q u i r e m e n t s a n d t o t a k e a d - va n t a g e o f c o s t - e f f e c t i v e s i t e a v a i l a b i l i t y , tr a n s m i s s i o n a c c e s s , a n d g o v e r n e n t f i n a n c i a l in c e n t i v e s . . A g g r e s s i v e l y d i v e r s i f y t h e r e n e w a b l e s p o r t f o l i o wi t h o t h e r t e c h n o l o g i e s ( g e o t h e r m a l , s o l a r , a n d bi o m a s s ) a s d i c t a t e d b y m a r k e t c o n d i t i o n s a n d th e a v a i l a b i l i t y o f s u i t a b l e c o s t - e f f e c t i v e p r o - je c t s . . C o n t i n u e t o i s s u e r e n e w a b l e R F P s u n d e r Pa c i f i C o r p ' s s h e l f R F P p r o g r a m , a n d s t e p u p co n s i d e r a t i o n o f un s o l i c i t e d p r o p o s a l s a n d mu l t i - p a r t i c i p a n t p r o j e c t s a s o p p o r t n i t i e s a r s e . . S t e p u p a c q u i s i t i o n o f d e m a n d - s i d e m a n a g e - me n t p r o g r a m s a n d d i s t r b u t e d r e n e w a b l e s g e n - er a t i o n t o m i t i g a t e c o s t a n d p r o c u r e m e n t r i s k s of ut i l t y - s c a l e s u p p l y - s i d e p r o j e c t s . . A d j u s t t r a n s m i s s i o n c o n s t r c t i o n p l a n s a n d in c r e a s e r e g i o n a l t r a n s m i s s i o n c o o r d i n a t i o n e f - fo r t s t o f a c i l t a t e p r o j e c t d e v e l o p m e n t a c t i v i t y . . A c c e l e r a t e r e n e w a b l e s a c q u i s i t i o n t o o b t a i n a s mu c h a s p o s s i b l e b e f o r e t h e f e d e r a l P T C e x p i r a - ti o n d a t e ; r e n e w a b l e a d d i t i o n s w e r e n o t f o u n d t o be c o s t - e f f e c t i v e w i t h o u t t h e f e d e r a l P T C d u r i n g th e 2 0 1 3 - 2 0 1 8 p e r i o d , g i v e n r e l a t i v e l y l o w C O 2 co s t s . . R a t e p a y e r a f f o r d a b i l i t y a n d C o m - pa n y f i n a n c i a l i m p a c t s a s s o c i a t e d wi t h a l a r g e a n d p r o t r a c t e d r e n e w - ab I e s a c q u i s i t i o n p r o g r a m . . D e m a n d / s u p p l y i m b a l a n c e f o r w i n d tu r b i n e s a n d l a b o r r e s u l t s i n p r o j e c t de l a y s a n d h i g h e r c o n s t r c t i o n c o s t s . . L o c a l e n v i r o n m e n t a l a n d l a n d u s e co n c e r n s / r e s t r i c t i o n s b e g i n t o a d - ve r s e l y i m p a c t r e n e w a b l e p r o j e c t pl a n s b y i n c r e a s i n g r e s o u r c e c o s t s an d f o r c i n g c o n s t r c t i o n d e l a y s . . T r a n s m i s s i o n c o n s t r c t i o n d e l a y s . . I n c r e a s e d e x p o s u r e t o w i n d i n t e g r a - ti o n i s s u e s a n d i n c r e a s e d n e e d f o r fl e x i b l e r e s o u r c e s . . C o m p l i a n c e b u r d e n a n d c o s t s a s s o - ci a t e d w i t h m u l t i - j u r s d i c t i o n a l R P S re q u i r e m e n t s . . A c c e p t a b i l i t y o f a s s o c i a t e d r a t e i n - cr e a s e s d u e t o t h e a c c e l e r a t e d r e - ne w a b l e s a c q u i s i t i o n c o m b i n e d w i t h ot h e r g e n e r a t i o n a n d t r a n s m i s s i o n re s o u r c e a c q u i s i t i o n s . . N e a r - t e r m i m p a c t o n t h e C o m p a n y ' s fi n a n c i a l s i t u t i o n . . R e g u l a t o r y r e q u i r e n i e n t s ( s i t i n g a n d ro c u r e n i e n t ) t h a t c o u l d i e o D a r d i z e 26 9 Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t CO 2 e m i s s i o n co m p l i a n c e : l o w t o me d i u m c o s t i m - pa c t CO 2 e m i s s i o n co m p l i a n c e : h i g h co s t i m p a c t . A f e d e r a l c a p - a n d - t r a d e p r o g r a m o r CO 2 t a x i s i m p l e m e n t e d w i t h a n e f - fe c t i v e p r o d u c t i o n c o s t i m p a c t o f up to $ 7 0 / t o n . . A f e d e r a l c a p - a n d - t r a d e p r o g r a m o r CO 2 t a i s i m p l e m e n t e d w i t h a n e f - fe c t i v e p r o d u c t i o n c o s t o f $ 7 0 / t o n o r gr e a t e r . . T h e p r e f e r r e d p o r t f o l i o i s c o n s i d e r e d a r e a s o n - ab l e p l a n n i n g s t a r t i n g p o i n t f o r a n u n c e r t a i n CO 2 c o s t u p t o $ 7 0 / t o n . . T h e 2 0 0 8 I R P p r e f e r r e d p o r t f o l i o w o u l d b e mo d i f i e d a s a n o u t c o m e o f bu s i n e s s p l a n / I R P po r t f o l i o m o d e l i n g t o r e f l e c t u p d a t e d a s s e s s - me n t s o f CO 2 r e g u l a t i o n s ( s t a r t a n d t r a j e c t o r y of CO 2 c o s t s ) , o t h e r e n e r g y p o l i c i e s a f f e c t i n g re n e w a b l e e n e r g y a c q u i s i t i o n a n d e c o n o m i c s , an d f o r w a r d g a s p r i c e s . ( N a t u a l g a s p r i c e s a f - fe c t t h e q u a n t i t y o f w i n d i n c l u d e d i n t h e r e - so u r c e p o r t f o l i o . F o r e x a m p l e , c o m p a r i n g t h e pr e f e r r e d p o r t o l i o a n d t h e p o r t f o l i o f o r c a s e 8B , a 2 0 % i n c r e a s e i n g a s p r i c e s w a s f o u n d t o re s u l t i n a 7 0 0 M W i n c r e a s e i n w i n d s e l e c t e d by t h e c a p a c i t y e x p a n s i o n m o d e L . ) . D e p e n d i n g o n e x p e c t e d C O 2 c o s t s a n d g a s pr i c e s , s t e p u p a c q u i s i t i o n o f d e m a n d - s i d e m a n - ag e m e n t p r o g r a s a n d h i g h - e f f c i e n c y d i s t r i b - ut e d g e n e r a t i o n t o h e l p m i n i m i z e t h e c a r b o n fo o t p r i n t , c o n t i n u e t o d i v e r s i f y t h e r e s o u r c e mi x , a n d t a e a d v a n t a g e o f a n y C O 2 c o m p l i - an c e c r e d i t s t h a t m a y b e g i v e n t o t h e s e r e s o u r c e ty p e s . . M o d i f y t h e b i d e v a l u a t i o n p r o c e s s ( w h i c h i s ba s e d o n t h e I R p o r t f o l i o m o d e l i n g f r a m e - wo r k ) t o r e f l e c t u p d a t e d C O 2 r e g u l a t o r y e x p e c - ta t i o n s . . A c q u i r e a t l e a s t a n a d d i t i o n a l 2 , 5 0 0 M W o f wi n d a n d a t l e a s t 7 0 M W o f g e o t h e r m a l c a p a c - it y o r o t h e r b a s e - l o a d r e n e w a b l e r e s o u r c e s , w i t h th e t i m i n g a n d a n n u a l a m o u n t s t i e d t o t h e s t a r t of C O 2 r e g u l a t i o n s a n d t r a j e c t o r y o f C O 2 c o s t s . Th e s e m i n i m u m t a r g e t s a r e s u g g e s t e d b y t h e po r t f o l i o g e n e r a t e d f r o m c a s e 1 7 B , o p t i m i z e d us i n g a $ 7 0 / t o n C O 2 c o s t . . C o n s i d e r e m i s s i o n o f f s e t D o s s i b i l i t i e s t o a m e - me e t i n g r e q u i r e d i n - s e r v i c e d a t e s . . R a t e p a y e r a f f o r d a b i l t y a n d C o m - pa n y f i n a n c i a l i m p a c t s a s s o c i a t e d wi t h C O 2 c o s t s t h a t a p p r o a c h t h e up p e r e n d o f t h e c o s t r a n g e ( $ 4 0 t o $7 0 / t o n ) . . C o m p l i a n c e b u r d e n a n d c o s t s a s s o - ci a t e d w i t h m u l t i - j u r i s d i c t i o n a l C O 2 re g u l a t o r y r e q u i r e m e n t s . . C u s t o m e r a f f o r d a b i l t y a n d C o m - pa n y f i n a n c i a l i m p a c t s a s s o c i a t e d wi t h n e c e s s a r r e s o u r c e a c q u i s i t i o n s (i n c l u d i n g t h o s e n e e d e d t o p o t e n - ti a l l y r e p l a c e l e s s e f f i c i e n t f o s s i l f u e l pl a n t s ) . . C o m p l i a n c e s a f e t y v a l u e o r e m e r - ge n c y o f f - r a m p p r o v i s i o n s k i c k i n du e t o h i g h c o m D l i a n c e c o s t s . 27 0 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t li o r a t e r e s o u r c e a c q u i s i t i o n a n d c o s t r i s k s . . S t e p u p a c q u i s i t i o n o f hi g h e r - c o s t d e m a n d - s i d e ma n a g e m e n t p r o g r a m s a n d h i g h - e f f c i e n c y d i s - tr i b u t e d g e n e r a t i o n t o f u r t h e r m i n i m i z e t h e c a r - bo n f o o t p r i n t . . C o n s i d e r a d v a n c e d h i g h - e f f c i e n c y g a s g e n e r a - ti o n t e c h n o l o g i e s , e v a l u a t i n g t h e t r a d e - o f f be - tw e e n g r e a t e r e f f i c i e n c y a n d h i g h e r c a p i t a l co s t s a n d p r o j e c t r i s k s . . A g g r e s s i v e l y p u r u e e f f c i e n c y i m p r o v e m e n t s fo r P a c i f i C o r p ' s e x i s t i n g f o s s i l f u e l a n d h y d r o - po w e r p l a n t s . . F o r l o n g - t e r m r e s o u r c e n e e d s a n d t o p o t e n t i a l l y re p l a c e e x i s t i n g f o s s i l f u e l p l a n t s , c o n t i n u e t o re e v a l u a t e c l e a n c o a l t e c h n o l o g i e s , a d v a n c e d nu c l e a r , a n d e m e r g i n g r e n e w a b l e a n d e n e r g y st o r a g e t e c h n o l o g i e s . . M o d i f y t h e b i d e v a l u a t i o n p r o c e s s t o r e f l e c t uo d a t e d C O 2 r e g u l a t o r y e x o e c t a t i o n s . . D e m a n d / s u p p l y i m b a l a n c e f o r w i n d tu r b i n e s a n d l a b o r r e s u l t s i n p r o j e c t de l a y s a n d h i g h e r c o n s t r u c t i o n c o s t s . . L o c a l e n v i r o n m e n t a l a n d l a n d u s e co n c e r n s / r e s t r i c t i o n s b e g i n t o a d - ve r s e l y i m p a c t r e n e w a b l e p r o j e c t pl a n s b y i n c r e a s i n g r e s o u r c e c o s t s an d f o r c i n g c o n s t r u c t i o n d e l a y s . . T r a n s m i s s i o n c o n s t r c t i o n d e l a y s . . I n c r e a s e d e x p o s u r e t o w i n d i n t e g r a - ti o n i s s u e s a n d i n c r e a s e d n e e d f o r fl e x i b l e r e s o u r c e s . . C o m p l i a n c e b u r d e n a n d c o s t s a s s o - ci a t e d w i t h m u l t i - j u r i s d i c t i o n a l r e - qu i r e m e n t s o r p o o r l y d e s i g n e d i m - pl e m e n t a t i o n . 27 1 Pa c i f i C o r p - 2 0 0 8 I R P Ch a p t e r 9 - A c t i o n P l a n a n d R e s o u r c e R i s k M a n a g e m e n t Fi g u r e 9 . 1 ~ R e s o u r c e A c q u i s i t i o n P a t h s T i e d t o L o a d G r o w t h a n d N a t u r a l G a s P r i c e s . P r i o r i t y i s t o r e d u c e . P r i o r i t y i s t o r e d u c e an d d e f e r a s i g n i f i c a n t an d d e f e r s o m e w i n d am o u n t o f pl a n n e d re s o u r c e s , s u b j e c t t o wi n d r e s o u r c e s , s u b j e c t ex p e c t e d R P S - r e l a t e d to e x p e c t e d R P S - co n s t r a i n t s re l a t e c o n s t r i n t s . R e d u c e a n d / o r d e f e r (L e s s w i n d r e s o u r c e s ga s - f i r e d c a p a c i t y co n t r b u t e t h e m o s t t o PV R R r e d u c t i o n s u n d e r . R e d u c e f i r m m a k e t lo w e r l o a d g r o w t pu r c h a s e s sc e n a r o s ) . I n c r e a e d i s t r i b u t e d . R e d u c e f i r m m a r k e t ge n e r a t i o n a n d D S M pu r c h a s e s ( F O T o r ad d i t i o n s t o h e l p o f f s e t PP A s ) , a n d d e f e r g a s wi n d r e d u c t i o n s a n d re s o u r c e s i f c a p a c i t y i s ot h e r h i g h e r - c o s t no t ne e e d re s o u r c e s . M o d e r t e l y i n c r e a s e di s t r b u t e d g e n e r a t i o n an d D S M a d d i t i o n s t o he l p o f f s e t w i n d re d u c t i o n s a n d o t h e r hi g h e r - c o s t r e s o u r c e s . P r i o r i t y i s t o r e d u c e . P r i o r i t y i s t o i n c r e a s e . P r i o r i t y i s t o i n c r e s e . P r i o r i t y i s t o a d d pl a n e d g a s c a p a c i t y , ga s - f i r e d c a p a c i t y , wi n d r e s o u r c e a n d sig n i f i c a n t q u a t i t i e s o f of f s e t g w i t h st a n g w i t h a C C C T in c r e s e / a c c e l e r t e g a s wi n d r e s o u r c e s a n d ad d i t i o n a l w i n d a n d an d a c e l e r a t i n g / a d d i n g re s o u r c e c a p a c i t y ba s e - l o a d r e n e w a b l e s ; ba s e - l o a r e e w a b l e s si m p l e - c y c l e u n i t s i f . S e e k c o s t - e f f e c t i v e so l a r t e c h n o l o g i e s . R e d u c e f i r m m a r k e t ne e d e d t o m e e t c a p a c i t y ba s e - l o a d r e n e w a b l e s be g i n t o l o o k pu r c h a s e s re s e r v e m a r g i n s pr o m i s i n g , a s s u m i n g . I n c r e a s e C l a s s 2 D S M th e P T C o r o t h e r . I n c r e e D S M a n d . M o d e r a t e l y i n c r a s e an d c u s t o m e r s t a d b y fi n a n c i a l i n c e n t i v e s di s t r b u t e d g e n e r a t i o n DS M ge n e r a t i o n re m a n a v a i l a b l e to h e l p o f f s e t r e d u c e d . M o d e r a t e l y i n c r e a s e . S e e k m o d e r a t e . I n c r e a s e C l a s s 2 D S M re l i a n c e o n g a s fi r m m a r k e t p u r c h a s e s in c r e a s e s i n f i r m an d s t a d b y g e n e r a t i o n re s o u r c e s a n d f i r m (F O T o r P P A s ) ma r k e t p u r c h a s e s ma r k e t p u r c h a s e s . P u l v e r z e d c o a l . S e e k c o s t - e f f e c t i v e pa r t i c u l a r l y i n t h e n e a r co m b u s t i o n t e c h n o l o g y ba s e - l o a d r e n e w a b l e s te r m i f P a c i f i C o r p co u l d b e c o m e c o s t - . M o n i t o r f u e l c e I l ju r i s d i c t i o n s e x p e r i e n c e ef f e c t i v e d e p e n d i n g o n te c h n o l o g i e s f o r a s t r o n g e r e c o n o m i c C0 2 c o s t s a n d s t a t e po s s i b l e d i s t r b u t e d re c e s s i o n r e b o u n d t h a t re g u l a t i o n s ; e x a m i n e ap p l i c a t i o n i n l a t e r ex p e c t e d th e p o t e n t i a l f o r c l e a n ye a r o f th e l O - y e a r co a l t e c h n o l o g y f o r o u t - in v e s t m e n t p l a n i n g ye a r a c q u i s i t i o n ho r i z o n 27 2 .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............................................ PacifiCorp - 2008 IRP Chapter 9 - Aaion Plan and Resource Risk Management Procurement Delays The main procurement risk is an inability to procure resources in the required time frame to meet the need. There are various reasons why a particular proxy resource cannot be procured in the time frame identified in the 2008 IRP. There may not be any cost-effective opportities avail- able through an RFP, the successful RFP bidder may experience delays in permittng and/or de- fault on their obligations, or a material change in the market for fuels, materials, electrcity, or environmental or other electrc utility regulations, may change the Company's entire resource procurement strategy. Possible paths PacifiCorp could take if there was either a delay in the on-line date of a resource or, if it was no longer feasible or desirable to acquire a given resource, include the following: · Consider alternative bids if they haven't been released under a curent RFP . Issue an emergency RFP for a specific resource · Move up the delivery date of a potential resource by negotiating with the supplier/developer · Rely on near-term purchased power and transmission until a longer-term alternative is identi- fied, acquired through PacifiCorp's mini-RFPs or sole source procurement · Install temporar generators to address some or all of the capacity needs · Temporarly drop below the 12 percent planing reserve margin · Implement load control initiatives, including calls for load curailment via existing load cur- tailment contracts Carbon dioxide reduction regulations at the federal and state levels would prompt the Company to continue to look for measures to lower CO2 emissions of existing thermal plants through cost- effective means. The cost, timing, and compliance flexibility afforded by C02 reduction rules wil impact what tyes of measures would be cost-effective and practical from operational and regulatory perspectives. For a cap-and-trde system, examples of factors include the allocation of free allowances, the cost of allowances in the market, and any flexible compliance mechanisms such as carbon offsets, allowance/offset banng and borrowing, and safety valve mechansms. To lower the emission levels for existing thermal plants, options include changing the fuel tye, repowering with more efficient generation equipment, lowering the plant heat rate so it is more efficient, and. adoption of new technologies such as CO2 capture with sequestration when com- mercially proven. Indirectly, plant carbon risk can be addressed by acquiring offsets in the form of renewable generation and energy effciency programs. Under an aggressive CO2 regulatory environment, early coal plant retirement becomes a tenable option. Such coal plant retirement decisions would also depend on market conditions and technological advancements that would enable cost-effective base-load power replacement or retrofit opportities. High C02 costs would shift technology preferences both for new resources and existing re- sources to those with more efficient heat rates and also away from coal, unless carbon is seques- tered. There may be opportnities to repower some of the existing coal fleet with a different less carbon-intensive fuel such as natual gas, but as a general rule, coal units wil continue to use the existing coal technology until it is more cost-effective to replace the unit in total. A major issue 273 PacifiCorp - 200BIRP Chapter 9 - Acton Plan and Resource Risk Management is whether new technologies wil be available that can be exchanged for existing coal economi- cally. Fuel switching and dual-fueling provide some limited opportities to address emissions, but wil require both capital investment and an understading of the trade-offs in operating costs and risks. While these options would provide the Company a means to lower its emission profile, such options would be extremely expensive to implement unless there is a high carbon emission penalty to justify them. _~Il.~':~",~);d~:~'y:::,~1¡", ,_~ .",ifdd'"', if ~__d ¥!i_~ d "=$="" ~ ~ il W ,,/';; JA "'".~ ",1- * ""',, "ø W The Company proposes to continue to hedge the price risk inherently carred due to volume mismatches between sales obligations and economic resources by purchasing or selling fixed- price energy in the forward market. These transactions mitigate the Company's financial expo- sure to the short-term markets, which historically have much greater price volatility than the longer-term markets. Specifically, purchasing to cover a short position in the forward market re- duces the Company's financial exposure to increasing prices, albeit these transactions also re- duce the Company's financial opportty ifprices decrease. Sellng to cover a long position has a similar effect. The Company also proposes to contiue to hedge the physical delivery risk inherently carried due to the volume mismatch between physical resources and physical obligations by purchasing or selling physical products in the forward though real-time markets. The purose of purchases is to ensure adequate resources to maintain reliable delivery to the Company's obligations such as retail load. The purpose of sales is to ensure the Company's ability to economically generate and deliver electrcity to wholesale purchasers. Adding natual gas generating resources to PacifiCorp' s system requires an understanding of the fuel supply risks associated with such resources, and the application of prudent risk management practices to ensure the availability of suffcient physical supplies and limit price volatility expo- sure. The risks discussed below include price, availability, and deliverability. Price Risk PacifiCorp manages price risk through a documented hedging strategy. This strategy involves fully hedging price risk in the nearest 12-month period and hedging less of the exposure each year beyond that through year four. Near-term prices are fully hedged to add price certinty to near term planning horizons, budgets, and rate case fiings. Further out, where plans and budgets are less certain, PacifiCorp considers its most recent ten-year business plan, curent market fu- damentals, credit risk, collateral fuding, and regulatory risk in makng hedging decisions. PacifiCorp balances the benefit of hedging that plan's price assumptions with prudent risk man- agement for its ratepayers and shareholders. PacifiCorp hedges price risk though the use of fi- nancial swap transactions and/or physical trsactions. These transactions are executed with various counterparies that meet PacifiCorp's credit and contractual requirements. 274 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management Availabilty Risk Availability risk refers to the risk associated with having natual gas supply in the vicinity of contemplated generating assets. PacifiCorp purchases physical supply on a forward basis achiev- ing contractual commitments for supply. The Company also relies on its ability to purchase physical supplies in the future to meet requirements. This second approach subjects PacifiCorp to price risk resulting from swings in supply-demand balances, as well as the risk that natural gas production in a producing region ceases regardless of price. It is reasonable that a region-wide cease in production, given reserve estimates, could only be brought about by extreme and un- foreseen events such as natual disaster or regulatory moratoriums on the production or con- sumption of natual gas--vents that long-term supply commitments would not counteract. In- dex prices are designed to reflect the prevailing cost of supply at various delivery locations. As described above, PacifiCorp hedges its exposure to changes in those index prices, thereby allow- ing for procurement of supply at floating index prices or waiting to acquire supply when re- quirements estimates are more accurate and the premiums for longer-term commitments are no longer demanded by suppliers. Deliverabilty Risk Deliverability risk refers to the risk associated with transporting natual gas supply from supply locations to generating facilities. The 2008 IRP accounts for the cost of natual gas transporttion service required to fuel gas plants, and uses existing tarff pipeline-defined transportation capac- ity and transportation costs in evaluating the need, timing, and location of new natual gas-fired generating plants. More specifically, the 2008 IRP uses existing maximum tariff rates for de- mand charges, volumetric costs, and reimbursement of fuel and lost/unaccounted natual gas. These tariff rates are developed through cost of service fiings with appropriate regulators-the FERC for interstate pipelines and relevant state regulators for intrastate pipelines. By definition, rates are developed based on cost of service of existing operations, without consideration for maintenance and operations of futue expansions. The result of this is that the 2008 IRP assumes that the economics of a new natural gas fired generator reflect the curent cost of service for ex- isting natual gas transportation facilities; whereas, the cost of any new natual gas transportation capacity is dependent on the volumetrc size of the new capacity, and prevailing costs of con- strction, maintenance, and operations (e.g. steel, labor, financing). Also, the 2008 IRP accounts for the availability of natual gas transporttion service required to fuel new electricity generating facilities. In selecting a gas-fired resource, the implicit assump- tion is made that natual gas transportation infrastrctue exists or wil be built. This is a reason- able assumption if one further assumes that the constrction of new pipeline facilities is a fuc- tion of cost, which is addressed above. PacifiCorp manages this transportation cost through two transaction tyes: transportation service agreements and delivered natual gas purchases: . PacifiCorp enters into transportation service agreements that offer PacifiCorp the right to ship natual gas from prolific production basins or liquidly traded "hubs" to generating assets. Natul gas hubs exist where a large volume of production is gathered and deliv- ered into a large interstate pipeline or where large pipelines intersect. These hubs lead to 275 PacifiCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Rik Management liquidly traded markets as the movement of gas from one transporting pipeline to another lead to a large number of wiling buyers and sellers. . PacifiCorp purchases natual gas delivered to generating plants and/or hubs. This ap- proach pushes the deliverability risk to the supplier by contrctually committing it to making necessary supply and/or trnsporttion arangements. PacifiCorp is confident that the risks associated with fueling curent and prospective natural gas fueled generation can be effectively managed. Risk management involves ongoing monitoring of the factors that affect price, availability, and deliverability. While prudence warrants the moni- toring of many factors, some issues that PacifiCorp needs to pay particular attention to, given today's market, include the following: . Potential counterparties need to be continually monitored for their creditworthiness and long-term viability, especially given the curent economic downtu. . Environmental concerns could impact natual gas prices, particularly given the prospects of a C02 cap-and-trade or tax program. PacifiCorp continues to monitor the regulatory environment and its potential impact on natual gas pricing. . As production grows in the Rocky Mountains, so does the transportation infrastrctue. PacifiCorp continues to monitor this activity for risks and opportities that new pipeline infrastructure may yield. The IRP standards and guidelines in Uta require that PacifiCorp "identify which risks wil be borne by ratepayers and which wil be borne by shareholders." This section addresses this re- quirement. Three tyes of risk are covered: stochastic risk, capital cost risk, and scenario risk. Stochastic Risk Assessment Several of the uncertain varables that pose cost risks to different IRP resource portolios are quantified in the IRP production cost model using stochastic statistical tools. The variables ad- dressed with such tools include retail loads, natul gas prices, wholesale electrcity prices, hy- droelectrc generation, and thermal unit availabilty. Changes in these variables that occur over the long-term are tyically 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 investors unless specific regulatory mechansms provide otherwise. Conse- quently, 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 incured costs wil be re- flected in rates and customers wil bear the risk. Capital Cost Risks The actual cost of a generating or transmission asset is expected to vary from the cost assumed in the 2008 IRP. Capital expenditues continue to increase, drven by the need for infrastrcture in- vestment to support load growth and maintain reliable electrcity supplies, and the effects of cost inflation. State commissions may determine that a portion of the cost of an asset was imprudent 276 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 9 - Acton Plan and Resource Risk Management and therefore should not be included in the determination of rates. The risk of such a determina- tion is borne by investors. To the extent that capital costs vary from those assumed in this IRP for reasons that do not reflect imprudence by PacifiCorp, the risks are borne by customers. Scenario Risk Assessment Scenario risk assessment pertains to abrupt or fundamental changes to varables that are appro- priately handled by scenario analysis as opposed to representation by a statistical process or ex- pected-value forecast. The single most important scenario risk of this tye facing PacifiCorp con- tinues to be governent actions related to CO2 emissions. This scenario risk relates to the uncer- tainty in predicting the scope, timing, and cost impact of CO2 emission compliance rules. Chap- ter 3 frames this issue in terms of the impacts of CO2 policy and cost uncertainty on natual gas and wholesale electricity prices, and consequent dramatic cost impacts to consumers. To address this risk, the Company decided in 2007 that acquiring a coal plant was not a viable resource option until regulatory clarity concerning CO2 costs and technology/fuel policies is ob- tained. While coal plants are allowed as eligible resources for competitive procurements that so- licit base~load resources, PacifiCorp evaluates all bid resources using a range of CO2 prices con- sistent with the scenario analysis methodology adopted for the Company's IRP portfolio evalua- tion process. Further, coal resources must comply with applicable existing state CO2 compliance regulations. The risk of potential futue CO2 costs is therefore fully accounted for in resource planning and procurement decision-making. The Company's efforts to acquire wind and DSM resources also serve as effective CO2 risk mitigation measures. 277 ............................................ PacifiCorp - 2008 IRP Chapter 10 - Transmission Expansion Action Plan 10. TRASMISSION EXPANSION ACTION PLAN Since the original announcement of Energy Gateway in May 2007 and as discussed fuher in Chapter 4, PacifiCorp has emphasized that significant infrastrcture of new transmission capac- ity is needed to adequately serve PacifiCorp's existing and futue loads. The Company's position has not changed in this regard and stil requires 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South) of new trnsmission capacity to adequately serve its customers load and growth needs for the long-term. PacifiCorp also recognized in its original announcement the need and benefits of potentially "up- sizing" the Energy Gateway Program to increase transmission capacity by two-fold (6,000 MW). This upsizing would potentially provide a number of local and regional benefits such as: maxi- mizing the use of new proposed corrdors, potential to reduce environmental impacts, provide economies of scale needed for large infrastrctue, lower cost per megawatt of transport capacity made available, and improved opportity for third paries to obtain new long-term firm trans- mission capacity. PacifiCorp stil believes there are short-term and long-term benefits for upsizing Energy Gate- way and has vigorously pursued other paricipants the past year and a half. To this point, signifi- cant barrers stil exist preventing PacifiCorp and other third partes from making a business de- cision to upsize the Energy Gateway Program without taking significant financial and delivery risk. PacifiCorp is proceeding with efforts regarding planing, rating, and permitting require- ments for the Energy Gateway Program that facilitates a planned ultimate transmission capacity of 3,000 MW for Gateway West and 3,000 MW for Gateway South (6,000 MW total). In order to achieve the ratings while meeting customer requirements, PacifiCorp plans to achieve the rat- ings in stages or phases based on need and constrction timing. PacifiCorp is moving forward with the expansion plan that wil constrct transmission lines and substations required to provide 1,500 MW on Gateway West and 1,500 MW on Gateway South (3,000 MW total) transmission capacity required to meet PacifiCorp's long-term regulatory re- quirement to serve loads. In addition, several main grid reinforcement projects that are complementar to the Energy Gateway program are scheduled for completion over the next several years. They are described after the Energy Gateway segments. High-level descriptions of the Energy Gateway segments and Company planning activities are outlined below. In-service dates are based on optimal timing of transmission needs and best ef- forts to complete constrction. The dates reflect the most recent Gateway planning assessment, which occured after the completion of IRP modeling described in the preceding chapters. Gate- way plan modifications wil be incorporated in PacifiCorp's 2010 business plan and the 2008 IRP update. In-service dates are subject to timing shifts based on permitting, environmental ap- provals, and construction schedules. 279 PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Aaion Plan Walla Walla to McNary - Segment A Originally planned as a single circuit 230 kV trnsmission line approximately 56 miles in length between Wall Walla, Washington and Umatila, Oregon that connects existing substations at Walla Walla, Wallula, and McNary. The initial target completion date was 2010; however, addi- tional information became available in early 2009 that prompted the decision to defer moving forward with the curent project scope in 2009. PacifiCorp acquired the Chehalis generation plant in late 2008 and on February 13, 2009 redi- rected 470 MW of transmission rights to the Mid Columbia area. Existing transmission rights between Yakima and Walla Walla allow a porton of the Chehalis resources to cover any Walla Walla short resource position. This minimizes any net power costs benefits from the prior eco- nomics that showed Hermiston generation located in Oregon displacing Mid-Columbia pur- chases and serving Yakima and Walla Walla loads durng short supply periods. Over the next six to twelve months, PacifiCorp is actively participating in transmission plans and system rating processes impacting the Nortwest, and these plans are expected to mature and possibly influence PacifiCorp's Westside Plan. At that time, the Company wil determine any additional transmission needed in the Walla Walla / McNar area. PacifiCorp wil continue to evaluate the project and incorporate the analysis with regional trnsmission needs. Populus to Terminal - Segment B A double circuit 345 kV line that wil ru approximately 135 miles from a new substation (Popu- lus) near Downey, Idaho to the existing Terminal Substation near Salt Lake International Airport west of Salt Lake City, Utah. When completed in 2010, this segment wil improve reliability along a critical transmission corrdor (Path C) and provide additional transfer capability of en- ergy resources both south bound and north bound. It wil also provide a vital link for Energy Gateway path ratings. Mona to Limber to Oquirrh - Segment C A single circuit 500 kV line that will ru approximately 65 miles between the existing Mona Substation in central Utah to a futue substation called Limber in the Tooele Valley, west of Salt Lake City, Utah. It wil also include a double circuit 345 kV line that wil ru approximately 21 miles between the future Limber Substation to an existing substation called Oquirrh in the Salt Lake valley. When completed in 2012, it provides a critical northbound path for additional re- source whether internally generated or purchased through market transactions. It wil also pro- vide a vital link for reliability and Energy Gateway path ratings. Oquirrh to Terminal A double circuit 345 kV line that wil ru approximately 14 miles between the Oquirrh Substa- tion to an existing Terminal Substation near Salt Lake International Airport west of Salt Lake City, Utah. When completed in 2012, it wil add operational flexibility to the bulk electrcal sys- tem, improved reliability and wil provide a vital link for Energy Gateway path ratings. 280 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Acton Plan Windstar to Aeolus to Bridger to Populus - Segment D Part of Energy Gateway West, it is comprised of two single circuit 230 kV lines that wil ru ap- proximately 82 and 72 miles respectively between the recently constrcted Winds tar Substation in eastern Wyoming to a new substation called Aeolus near Medicine Bow, Wyoming. It wil continue as a 500 kV single circuit line that wil ru approximately 141 miles from Aeolus Sub- station to a new annex substation near the existing Bridger Substation near Jim Bridger Power Plant in western Wyoming. The last section wil connect the new annex substation located near Bridger Substation to the Populus Substation that is being constrcted as part of the Populus to Terminal segment. When completed in 2014, the entire segment wil move wind or other resources from eastern Wyoming to a critical hub (Populus) located near Downey, Idaho. The Populus Substation is the intersec- tion substation for Gateway West and Gateway Central. Populus to Hemingway - Segment E Two single circuit 500 kV lines .that wil ru approximately 135 and 149 miles respectively be- tween the Populus Substation and the existing Midpoint Substation. One of the lines wìl also connect the existing Borah Substation between Populus and Midpoint. The segment wil con- tinue as a single circuit 500 kV line for approximately 126 miles from Midpoint Substation to a new Hemingway Substation located south of Boise on the south side of the Snake River between the towns of Melba and Murhy. When completed in 2016 the segment wil connect resources located in eastern Wyoming and Gateway Central to load centers further west. It wil also allow the Company to maintain reliable electrc service in the Western Interconnection. Aeolus to Mona - Segment F A single-circuit 500 kV line that rus approximately 395 miles between the Aeolus Substation (constrcted as part of Gateway West) and the Mona Substation (expanded as part of Gateway Central). When completed in 2017 the segment wil connect Gateway West and Gateway Central providing operational flexibility for the bulk electrc network, reliability and supports path rat- ings for each segment. Sigurd to Red Butte - Segment G A single circuit 345 kV line that rus approximately 160 miles connecting the existing Sigud Substation located in central Utah to another existing substation called Red Butte Substation lo- cated in southwest Utah. When completed in 2014, it provides a critical path to meet load obliga- tions, increase export capability and to maintain trsmission capacity on TOT2C for contracted point to point service. Specific routing alternatives are curently being considered in the permit- ting and ratings processes. Segment G originally included a single circuit 500 kV line from Red Butte Substation in Utah to Crystal Substation in Nevada. The transmission line is being deferred for fuher review due to the fact that existing customer forecasted needs are anticipated to be met without its constrction. Studies show bi-directional flows to markets are met by installng upgrades at Har Allen Sub- station in Nevada and other system reinforcements in 2014. Although the segment is not needed at this time for the 1,500 MW Gateway South expansion plan, the line segment and related sub- 281 PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Acton Plan station upgrades wil be required for Energy Gateway South to obtain the next incremental rating of3,000 MW total. Constrction of the planned trnsmission segments by estimated in-service dates and additional megawatt capacity are shown in the following sequence of maps. Delivery of the segments by the calendar years shown are particularly critical for Gateway West from Windstar to Populus, Gateway Central from Mona to Terminal, and Gateway South from Sigud to Red Butte, due to the IRP preferred portfolio reliance on available transmission. Maintaining sufficient trnsmission capacity for southwest Utah loads and maintaining con- tracted point-to-point transmission service prior to the Sigud to Red Butte - Segment G addition in 2014 wil require several substation upgrdes. The Sigud to Red Butte project is being con- sidered with other alternatives to meet the requirements in SW Utah. In 2010, PacifiCorp is planning to install additional station equipment at Har Allen Substation, Pinto Substation and Three Peaks Substation and in 2011 additional station equipment is being installed at Red Butte Substation. Additional main grid reinforcement projects also includes upgrades to TOT2C path at Harr Al- len Substation in Nevada, which wil increase bi-directional flows to markets in the Desert Southwest needed in 2014. 282 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Action Plan Figure 10.1- Energy Gateway 2010 Additions Energy Gateway Transmission Expansion Plan 2010 . Parp se ar - 50 kV I1nìmm volte .. 345 kV mîìmm vo .. 230 kV 11ní vo o Trasi hu. Suta. Gera pltati Note: This sees of maps generally reflect the expansion necessary to adequately sere PacifiCorp's existing and futue loads, which require 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South). PacifiCorp is proceeding with effort regarding planng, rang, and perttng for an ultimate Energy Gateway capacity of 6,000 MW (3,000 MW on Gateway West and 3,000 MW on Gateway South). 283 PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Acton Plan Figure 10.2 - Energy Gateway 2012 Additions Energy Gateway Transmission Expansion Plan 2012 .. 50 kV mini vo .. 345 kV mini vo .. 230 kV mini volt €) Transisio hub. SunII Gen plwl Note: This seres of maps generally reflect the expansion necessa to adequately sere PacifiCorp's existing and futue load, which requires 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South). PacifiCorp is proceedg with efforts regarding plang, rating, and perittng for an ultimate Energy Gateway capacity of6,000 MW (3,000 MW on Gateway West and 3,000 MW on Gateway South). c Mona - Limber Limber - 0 uirh o uirh - TerminalOther 500 kV single circuit! 345 kV double circuit 345 kV double circuit 700MW 1500MW 700MW 1500MW 284 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Acton Plan Figure 10.3 - Energy Gateway 2014 Additions Energy Gateway Transmission Expansion Plan 2014 - 50 IN minim YO .. 345 kV min YO .. 23 kV mini volt o Trans hu. Su. Gen platl Note: This seres of maps generally reflect the expansion necessar to adequately serve PacifiCorp's existing and futue loads, which requires 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South). PacifiCorp is proceeding with efforts regarding planng, rating, and perttng for an ultimate Energy Gateway capacity of 6,000 MW (3,000 MW on Gateway West and 3,000 MW on Gateway South). D Windstar - Aeolus Aeolus -Bridger Brid er - Po ulus Si d - Red Butte Various upgrades at Har Allen to in- crease capacity to the Desert Southwest G Varous 2-230 kV single circuits 500 kV single circuit 500 kV sin Ie circuit 345 kV sin Ie circuit TOT2CPath 700MW 1500MW 1500MW 600MW 600MW 700MW 700MW 700MW 600MW 600MW 285 PacifìCarp - 2008 IRP Chapter 10 - Transmission Expansion Acton Plan Figure 10.4 - Energy Gateway 2016 Additions Energy Gateway Trasmission Expansion Plan 2016 - sa kV miimumvo - 345 kV miimum vo - 230 kV miimum vo o Tramisîo hub. Suti II GeraÎoo plant/sta Note: This series of maps generally reflect the expansion necessar to adequately serve PacifiCorp's existing and futue loads, which requires 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South). PacifiCorp is proceedig with effort regarding planng, rating, and pertting for an ultimate Energy Gateway capacity of 6,000 MW (3,000 MW on Gateway West and 3,000 MW on Gateway South). E Populus - Borah - 500 kV single circuit Mid oint Populus - Midpoint - 500 kV single circuit Hemin wa 700MW 1500MW E 700MW 1500MW 286 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Action Plan Figure 10.5 - Energy Gateway 2017 Additions E.nergy Gateway Transmission Expansion Plan 2017 . Parp se ar Plne trnsio lin - so kV minimu vo -- 34S kV minimum vo "" 230 kV minimu vo o Trasmis hu . Stíon II Geera plst Note: This seres of mas generally reflect the expansion necessary to adequately sere PacifiCorp's existing and futue loads, which requires 3,000 MW (1,500 MW on Gateway West and 1,500 MW on Gateway South). PacifiCorp is proceeding with effort regarding planng, rang, and perittg for an ultimate Energy Gateway capacity of 6,000 MW (3,000 MW on Gateway West and 3,000 MW on Gateway South). 287 PacifiCorp - 2008 IRP Chapter 10 - Transmission Expansion Acton Plan Westside Plan / Red Butte - Crystal The west side of PacifiCorp's system (Washington, Oregon and California) is well integrated with A vista Energy, Bonnevile Power Administration, Portland General Electric, and, to a lesser degree, interconnections to the California Independent System Operator. Additionally, several regional projects have been proposed to interconnect in the northwest (California to Canada Transmission, Boardman to Hemingway, Southern Crossing, West of McNary, 1-5 reinforce- ment, Devils Gap, Northern Lights and others). PacifiCorp's Walla Walla to McNary single circuit 230 kV line and Hemingway to Captain Jack single circuit 500 kV line will be planned and coordinated with other regional projects to provide the best solution for customers and the region. Ultimate configuation and timing ofPacifiCorp's Walla Walla to McNary and Hemingway to Captain Jack projects is an action item resulting from this IRP. The Red Butte to Crystal single circuit 500 kV line was originally planned for 2012 but was de- ferred due to other Energy Gateway/system reinforcement projects providing sufficient transmis- sion capacity to meet customer requirements. The line wil be reevaluated as futue needs are identified. The map shown below shows the geographic context of the segments described above. 288 ............................................ ............................................ PacifiCorp - 2008 IRP Chapter 10- Transmission Expansion Aaion Plan Figure 10.6 - Westside Plan / Red Butte - Crystal Energy Gateway Transmission Expansion Plan (Under review) Pa sece ar Plne trissi lin - sa kV mím vo -- 345 kV mi volt -- 230 kV mi volte (¡ Traîsìo hu. SutìII Ge platlta Note: This map generally reflects key expasion segments under review. It does not reflect all the segments that are necessar to for an ultimate Energy Gateway capacity of 6,000 MW (3,000 MW on Gateway West and 3,000 MW on Gateway South). 230 kV sin Ie circuit 500 kV sin Ie circuit 500 kV sin Ie circuit 289