April 30, 2013

Let’s turn the answers on.

Integrated

Resource

Plan

Volume 1

2013
This 2013 Integrated Resource Plan Report is based upon the best available information at the time of

preparation. The IRP action plan will be implemented as described herein, but is subject to change as new

information becomes available or as circumstances change. It is PacifiCorp’s intention to revisit and

refresh the IRP action plan no less frequently than annually. Any refreshed IRP action plan will be

submitted to the State Commissions for their information.

For more information, contact:

PacifiCorp

IRP Resource Planning

825 N.E. Multnomah, Suite 600

Portland, Oregon 97232

(503) 813-5245

irp@pacificorp.com

http://www.pacificorp.com

This report is printed on recycled paper

Cover Photos (Top to Bottom):

Transmission: Sigurd to Red Butte Transmission Segment G

Hydroelectric: Lemolo 1 on North Umpqua River

Wind Turbine: Leaning Juniper I Wind Project

Thermal-Gas: Chehalis Power Plant

Solar: Black Cap Photovoltaic Solar Project
PACIFICORP – 2013 IRP TABLE OF CONTENTS

i

TABLE OF CONTENTS

TABLE OF CONTENTS ..............................................................................................................I

INDEX OF TABLES ................................................................................................................ VII

INDEX OF FIGURES ................................................................................................................IX

CHAPTER 1 – EXECUTIVE SUMMARY................................................................................ 1

2013 IRP HIGHLIGHTS ..............................................................................................................................1

MODELING AND PROCESS IMPROVEMENTS..............................................................................................3

RESOURCE NEED ......................................................................................................................................5

FUTURE RESOURCE OPTIONS AND PORTFOLIO MODELING......................................................................7

THE 2013 IRP PREFERRED PORTFOLIO...................................................................................................11

THE 2013 IRP ACTION PLAN ..................................................................................................................14

CHAPTER 2 – INTRODUCTION............................................................................................ 21

2013 INTEGRATED RESOURCE PLAN COMPONENTS...............................................................................22

THE ROLE OF PACIFICORP’S INTEGRATED RESOURCE PLANNING.........................................................23

PUBLIC PROCESS.....................................................................................................................................23

CHAPTER 3 – THE PLANNING ENVIRONMENT ............................................................. 27

INTRODUCTION .......................................................................................................................................27

WHOLESALE ELECTRICITY MARKETS ....................................................................................................28

Natural Gas Uncertainty....................................................................................................................29

THE FUTURE OF FEDERAL ENVIRONMENTAL REGULATION AND LEGISLATION ....................................32

Timing of Environmental Protection Agency (EPA) Regulation........................................................32

Federal Climate Change Legislation .................................................................................................33

EPA REGULATORY UPDATE – GREENHOUSE GAS EMISSIONS...............................................................33

New Source Review / Prevention of Significant Deterioration (NSR / PSD).....................................33

Guidance for Best Available Control Technology (BACT)................................................................34

New Source Performance Standards (NSPS) for Greenhouse Gases ................................................34

EPA REGULATORY UPDATE – NON-GREENHOUSE GAS EMISSIONS......................................................35

Clean Air Act Criteria Pollutants – National Ambient Air Quality Standards..................................35

Clean Air Transport Rule...................................................................................................................35

Regional Haze ....................................................................................................................................36

Mercury and Hazardous Air Pollutants.............................................................................................37

Coal Combustion Residuals ...............................................................................................................38

Water Quality Standards....................................................................................................................38

Cooling Water Intake Structures...................................................................................................................38

Effluent Limit Guidelines..............................................................................................................................39

STATE CLIMATE CHANGE REGULATION ................................................................................................39

California ...........................................................................................................................................39

Oregon and Washington.....................................................................................................................40

Greenhouse Gas Emission Performance Standards...........................................................................40

RENEWABLE PORTFOLIO STANDARDS ...................................................................................................41

California ...........................................................................................................................................42

Oregon................................................................................................................................................44

Utah....................................................................................................................................................45

Washington.........................................................................................................................................46

Federal Renewable Portfolio Standard..............................................................................................46

HYDROELECTRIC RELICENSING..............................................................................................................47
PACIFICORP – 2013 IRP TABLE OF CONTENTS

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Potential Impact .................................................................................................................................48

Treatment in the IRP ..........................................................................................................................48

PacifiCorp’s Approach to Hydroelectric Relicensing........................................................................48

RATE DESIGN INFORMATION..................................................................................................................48

ENERGY IMBALANCE MARKET...............................................................................................................50

RECENT RESOURCE PROCUREMENT ACTIVITIES....................................................................................50

All-Source Request for Proposals ......................................................................................................51

Demand-side Resources.....................................................................................................................51

Oregon Solar Request for Proposal ...................................................................................................52

Natural Gas Transportation Request for Proposals ..........................................................................52

Natural Gas Request for Proposals....................................................................................................53

Natural Gas Transportation Request for Proposals ..........................................................................53

Renewable Energy Credit (REC) Request for Proposals...................................................................53

Renewable Energy Credit (REC) Request for Proposals – Oregon...............................................................54

Renewable Energy Credit (REC) Request for Proposals - Washington ........................................................54

Renewable Energy Credit (REC) Request for Proposals - California ...........................................................54

Short-term Market Power Request for Proposals..............................................................................54

CHAPTER 4 – TRANSMISSION............................................................................................. 55

INTRODUCTION .......................................................................................................................................56

REGULATORY REQUIREMENTS ...............................................................................................................56

Open Access Transmission Tariff.......................................................................................................56

Reliability Standards..........................................................................................................................57

IRP Feedback .....................................................................................................................................57

SYSTEM OPERATIONAL AND RELIABILITY BENEFITS TOOL...................................................................58

Background ........................................................................................................................................58

Benefits Evaluated..............................................................................................................................59

Operational Cost Savings (economic driven)................................................................................................59

Segment Loss Savings (energy and capacity) ...............................................................................................59

System Reliability Benefits...........................................................................................................................60

Customer and Regulatory Benefits................................................................................................................61

Avoided Capital Cost ....................................................................................................................................61

Improved Generation Dispatch (reliability driven) .......................................................................................62

Wheeling Revenue Opportunity ....................................................................................................................62

REQUEST FOR ACKNOWLEDGEMENT OF SIGURD TO RED BUTTE...........................................................62

FACTORS SUPPORTING ACKNOWLEDGEMENT........................................................................................63

Improved Transmission System Capacity...........................................................................................63

Enhanced Transfer Capability to Promote Energy Transfers............................................................63

Improved Transmission System Reliability ........................................................................................64

Sigurd to Red Butte Cost Benefit Analysis .........................................................................................64

GATEWAY WEST – CONTINUED PERMITTING.........................................................................................65

Windstar to Populus...........................................................................................................................66

Preliminary SBT Analysis – Windstar to Populus (Segment D).........................................................66

Plan to Continue Permitting Gateway West.......................................................................................67

EVOLUTION OF THE ENERGY GATEWAY TRANSMISSION EXPANSION PLAN .........................................67

Introduction........................................................................................................................................67

Background ........................................................................................................................................67

Planning Initiatives............................................................................................................................68

Energy Gateway Configuration..........................................................................................................70

Energy Gateway’s Continued Evolution ............................................................................................71

EFFORTS TO MAXIMIZE EXISTING SYSTEM CAPABILITY .......................................................................75

CHAPTER 5 – RESOURCE NEEDS ASSESSMENT............................................................ 79

INTRODUCTION .......................................................................................................................................80
PACIFICORP – 2013 IRP TABLE OF CONTENTS

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SYSTEM COINCIDENT PEAK LOAD FORECAST........................................................................................80

EXISTING RESOURCES ............................................................................................................................80

Thermal Plants...................................................................................................................................81

Renewables.........................................................................................................................................83

Wind..............................................................................................................................................................83

Geothermal....................................................................................................................................................84

Biomass / Biogas...........................................................................................................................................84

Renewables Net Metering .............................................................................................................................84

Hydroelectric Generation...................................................................................................................85

Hydroelectric Relicensing Impacts on Generation ........................................................................................86

Demand-side Management.................................................................................................................87

Class 1 Demand-side Management ...............................................................................................................89

Class 2 Demand-side Management ...............................................................................................................89

Class 3 Demand-side Management ...............................................................................................................89

Class 4 Demand-side Management ...............................................................................................................90

Power Purchase Contracts.................................................................................................................91

LOAD AND RESOURCE BALANCE............................................................................................................92

Capacity and Energy Balance Overview............................................................................................92

Load and Resource Balance Components..........................................................................................92

Existing Resources........................................................................................................................................93

Obligation......................................................................................................................................................94

Reserves ........................................................................................................................................................95

Position..........................................................................................................................................................95

Reserve Margin .............................................................................................................................................95

Capacity Balance Determination .......................................................................................................96

Methodology .................................................................................................................................................96

Load and Resource Balance Assumptions.....................................................................................................96

Capacity Balance Results..............................................................................................................................97

Energy Balance Determination........................................................................................................101

Methodology ...............................................................................................................................................101

Energy Balance Results....................................................................................................................102

Load and Resource Balance Conclusions........................................................................................105

CHAPTER 6 – RESOURCE OPTIONS................................................................................. 107

INTRODUCTION .....................................................................................................................................107

SUPPLY-SIDE RESOURCES.....................................................................................................................107

Derivation of Resource Attributes....................................................................................................108

Handling of Technology Improvement Trends and Cost Uncertainties...........................................109

Resource Options and Attributes......................................................................................................111

Distributed Generation ................................................................................................................................124

Resource Option Description ...........................................................................................................128

Coal .............................................................................................................................................................128

Coal Plant Efficiency Improvements...........................................................................................................129

Natural Gas..................................................................................................................................................129

Wind............................................................................................................................................................131

Other Renewable Resources........................................................................................................................132

Distributed Supply Side Resources .............................................................................................................137

Nuclear........................................................................................................................................................139

Energy Storage ............................................................................................................................................139

DEMAND-SIDE RESOURCES ..................................................................................................................140

Resource Options and Attributes......................................................................................................140

Source of Demand-side Management Resource Data .................................................................................140

Demand-side Management Supply Curves .................................................................................................140

TRANSMISSION RESOURCES .................................................................................................................151

MARKET PURCHASES............................................................................................................................154
PACIFICORP – 2013 IRP TABLE OF CONTENTS

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CHAPTER 7 – MODELING AND PORTFOLIO EVALUATION APPROACH............. 157

INTRODUCTION .....................................................................................................................................157

PORTFOLIO MODELING: SYSTEM OPTIMIZER.......................................................................................159

Modeling Capital Costs and Addressing “End-Effects”..................................................................160

Modeling Front Office Transactions................................................................................................160

Modeling Wind and Solar Resources...............................................................................................161

Modeling Coal Unit Environmental Investments.............................................................................161

Reserve Margin Requirement...........................................................................................................162

Modeling Energy Gateway Transmission Scenarios........................................................................162

Modeling Energy Storage Technologies ..........................................................................................163

GENERAL ASSUMPTIONS AND PRICE INPUTS .......................................................................................163

Study Period and Date Conventions ................................................................................................163

Escalation Rates and Other Financial Parameters..........................................................................164

Inflation Rates.............................................................................................................................................164

Discount Factor ...........................................................................................................................................164

Federal Renewable Resource Tax Incentives..............................................................................................164

Asset Lives..................................................................................................................................................164

Transmission System Representation ...............................................................................................165

CARBON DIOXIDE REGULATORY COMPLIANCE SCENARIOS................................................................167

Carbon Dioxide Scenarios...............................................................................................................167

Zero CO2 Price Scenario .............................................................................................................................167

Medium CO2 Price Scenario .......................................................................................................................167

High CO2 Price Scenario.............................................................................................................................167

U.S. Hard Cap, Medium Natural Gas CO2 Price Scenario ..........................................................................167

U.S. Hard Cap, High Natural Gas CO2 Price Scenario ...............................................................................168

Oregon Environmental Cost Guideline Compliance........................................................................170

PHASE (1) CASE DEFINITION ................................................................................................................171

Case Specifications ..........................................................................................................................171

PHASE (2) SCENARIO PRICE FORECAST DEVELOPMENT.......................................................................176

Gas and Electricity Price Forecasts ................................................................................................178

Price Projections Tied to the High Forecast ................................................................................................181

Price Projections Tied to the Medium Forecast...........................................................................................182

Price Projections Tied to the Low Forecast.................................................................................................184

PHASE (3) OPTIMIZED PORTFOLIO DEVELOPMENT: NO RPS CASES....................................................185

PHASE (4) ESTABLISHING A RENEWABLE RESOURCE FLOOR ..............................................................186

PHASE (5) OPTIMIZED PORTFOLIO DEVELOPMENT: RPS CASES..........................................................187

PHASE (6) MONTE CARLO PRODUCTION COST SIMULATION ...............................................................187

The Stochastic Model .......................................................................................................................188

Stochastic Model Parameter Estimation..........................................................................................188

Monte Carlo Simulation ...................................................................................................................191

Stochastic Portfolio Performance Measures....................................................................................195

Stochastic Mean PVRR...............................................................................................................................196

Risk-adjusted Mean PVRR .........................................................................................................................196

Ten-year Customer Rate Impact..................................................................................................................197

Upper-Tail Mean PVRR..............................................................................................................................197

95th and 5th Percentile PVRR.......................................................................................................................197

Production Cost Standard Deviation ...........................................................................................................197

Average and Upper-Tail Energy Not Served ..............................................................................................197

Loss of Load Probability (LOLP)................................................................................................................198

Fuel Source Diversity..................................................................................................................................198

PHASE (7) TOP-PERFORMING PORTFOLIO SELECTION..........................................................................198

Initial Screening ...............................................................................................................................198

Final Screening ................................................................................................................................200

PHASE (8): PRELIMINARY AND FINAL PREFERRED PORTFOLIO SELECTION.........................................200
PACIFICORP – 2013 IRP TABLE OF CONTENTS

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CHAPTER 8 – MODELING AND PORTFOLIO SELECTION RESULTS..................... 201

INTRODUCTION .....................................................................................................................................202

PREFERRED PORTFOLIO SELECTION .....................................................................................................202

Core Case Portfolio Results.............................................................................................................202

Carbon Dioxide Emissions..........................................................................................................................210

Pre-Screening Results......................................................................................................................212

Initial Screening Results...................................................................................................................216

Final Screening Results....................................................................................................................218

Risk-adjusted PVRR ...................................................................................................................................218

Cumulative Carbon Dioxide Emissions ......................................................................................................219

Supply Reliability........................................................................................................................................220

Preferred Portfolio Selection ...........................................................................................................221

Deliverability of Accelerated Class 2 DSM and Resource Constraints.......................................................222

Resource Diversity ......................................................................................................................................222

Preliminary Selection ..................................................................................................................................224

Final Selection.............................................................................................................................................224

THE 2013 IRP PREFERRED PORTFOLIO.................................................................................................226

Summary Reports .............................................................................................................................226

Preferred Portfolio Compliance with Renewable Portfolio Standard Requirements ......................232

Preferred Portfolio Carbon Dioxide Emissions...............................................................................233

SENSITIVITY ANALYSES .......................................................................................................................234

System Optimizer Sensitivity Cases..................................................................................................234

Load Sensitivities (S01, S02, and S03) .......................................................................................................235

Extension of PTC and ITC (S05 and S06) ..................................................................................................237

Endogenous Selection of Resources to Meet RPS Requirements (S07)......................................................237

2013 Business Plan Portfolio (S08).............................................................................................................238

Resurgence of Renewable Resources (S09) ................................................................................................239

Class 3 DSM (S10)......................................................................................................................................239

ADDITIONAL ANALYSIS........................................................................................................................239

Trigger Point Analysis......................................................................................................................239

Oregon Greenhouse Gas Goals .......................................................................................................240

CHAPTER 9 – ACTION PLAN .............................................................................................. 243

INTRODUCTION .....................................................................................................................................244

THE INTEGRATED RESOURCE PLAN ACTION PLAN ..............................................................................244

THE 2013 IRP ACTION PLAN ................................................................................................................245

PROGRESS ON PREVIOUS ACTION PLAN ITEMS ....................................................................................252

Action Item 1: Renewable / Distributed Generation 2021-2020......................................................252

Action Item 2: Intermediate/ Base-load Thermal Supply-side Resources 2014-2016......................255

Action Item 3: Firm Market Purchases 2011-2020..........................................................................256

Action Item 4: Plant Efficiency Improvements 2011-2020...............................................................256

Action Item 5: Class 1 DSM 2011-2020...........................................................................................257

Action Item 6: Class 2 DSM 2011-2020...........................................................................................257

Action Item 7: Class 3 DSM 2011-2020...........................................................................................259

Action Item 8: Planning Process Improvements Process Improvement..........................................261

Action Item 9: Coal Resource Actions..............................................................................................261

Action Item 10: Transmission...........................................................................................................263

Action Item 11: Planning Reserve Margin.......................................................................................263

ACQUISITION PATH ANALYSIS .............................................................................................................264

Resource Strategies..........................................................................................................................264

Acquisition Path Decision Mechanism.............................................................................................265

PROCUREMENT DELAYS .......................................................................................................................268

IRP ACTION PLAN LINKAGE TO BUSINESS PLANNING.........................................................................269

RESOURCE PROCUREMENT STRATEGY.................................................................................................271
PACIFICORP – 2013 IRP TABLE OF CONTENTS

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Renewable Energy Credits...............................................................................................................272

Demand-side Management...............................................................................................................272

Distributed Generation.....................................................................................................................272

ASSESSMENT OF OWNING ASSETS VERSUS PURCHASING POWER........................................................273

MANAGING CARBON RISK FOR EXISTING PLANTS...............................................................................273

PURPOSE OF HEDGING ..........................................................................................................................274

Risk Management Policy and Hedging Program.............................................................................274

Cost Minimization ............................................................................................................................276

Portfolio ...........................................................................................................................................276

Effectiveness Measure ......................................................................................................................277

Instruments.......................................................................................................................................277

External Review................................................................................................................................277

Commission Review..........................................................................................................................280

TREATMENT OF CUSTOMER AND INVESTOR RISKS ..............................................................................281

Stochastic Risk Assessment ..............................................................................................................281

Capital Cost Risks............................................................................................................................281

Scenario Risk Assessment.................................................................................................................281
PACIFICORP – 2013 IRP INDEX OF TABLES

vii

INDEX OF TABLES

Table ES.1 – PacifiCorp 10-year Capacity Position Forecast (Megawatts) .................................................5

Table ES.2 – 2013 IRP Resource Options* ..................................................................................................8

Table ES.3 – 2013 IRP Preferred Portfolio.................................................................................................11

Table ES.4 – 2013 IRP Action Plan............................................................................................................14

Table 2.1 – 2013 IRP Public Meetings.......................................................................................................24

Table 3.1 – State RPS Requirements..........................................................................................................41

Table 3.2 – California Compliance Period Requirements ..........................................................................42

Table 3.3 – California Balanced Portfolio Requirements...........................................................................43

Table 3.4 – PacifiCorp’s Request for Proposal Activities ..........................................................................50

Table 4.1 – SBT-Derived Values for Sigurd to Red Butte .........................................................................65

Table 4.2 – Windstar to Populus Benefits Calculation ...............................................................................67

Table 5.1 – Forecasted System Coincidental Peak Load in Megawatts, Prior to Energy Efficiency 

Reductions..........................................................................................................................................80

Table 5.2 – 2013 Capacity Contribution at System Peak for Existing Resources......................................81

Table 5.3 – Coal Fired Plants......................................................................................................................81

Table 5.4 – Natural Gas Plants....................................................................................................................82

Table 5.5 – PacifiCorp-owned Wind Resources.........................................................................................83

Table 5.6 – Wind Power Purchase Agreements and Exchanges.................................................................83

Table 5.7 – Hydroelectric Contracts - Load and Resource Balance Capacities..........................................85

Table 5.8 – PacifiCorp Owned Hydroelectric Generation Facilities - Load and Resource Balance 

Capacities...........................................................................................................................................85

Table 5.9 – Estimated Impact of FERC License Renewals and Relicensing Settlement Commitments on 

Hydroelectric Generation ...................................................................................................................86

Table 5.10 – Existing DSM Summary, 2013-2022.....................................................................................90

Table 5.11 – Old IRP Format: System Capacity Loads and Resources without Resource Additions........98

Table 5.12 – Updated Format: System Capacity Loads and Resources without Resource Additions.......99

Table 6.1 - 2013 Supply Side Resource Table (2012$) ............................................................................112

Table 6.1 - 2013 Supply Side Resource Table (2012$) (Continued)........................................................113

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax .................................114

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax (Continued) .............115

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax (Continued) .............116

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax (Continued).............117

Table 6.3 – Total Resource Cost for Supply-Side Resource Options, $16 CO2 Tax ................................118

Table 6.3 – Total Resource Cost for Supply-Side Resource Options, $16 CO2 Tax (Continued)............119

Table 6.3 – Total Resource Cost for Supply-Side Resource Options, $16 CO2 Tax (Continued)............120

Table 6.4- Glossary of Terms from Supply Side Resource Table ............................................................121

Table 6.5 – Glossary of Acronyms Used in the Supply Side Resource Table..........................................122

Table 6.6 – Total Resource Cost, Natural Gas-fired plants at varying Capacity Factors (2012$)............123

Table 6.7- Distributed Generation Resource Supply-Side Options..........................................................125

Table 6.8 – Distributed Generation Total Resource Cost, $0 CO2 Tax ....................................................126

Table 6.9 – Distributed Generation Total Resource Cost, $16 CO2 Tax ..................................................127

Table 6.10 – Cumulative Wind Selection Limits by Year and Energy Gateway Scenario.......................132

Table 6.11 – 2010 Geothermal Study Results...........................................................................................133

Table 6.12 – 2012 Geothermal Study Results...........................................................................................134

Table 6.13 – Distributed Generation Resource Attributes........................................................................138

Table 6.14 –HDR Energy Storage Study Summary Cost and Capacity Results (2011$).........................139

Table 6.15 –HDR Storage Study, Normalized Battery Cost Comparison (2011$)...................................140

Table 6.16 – Class 1 DSM Program Attributes West Control Area .........................................................143

Table 6.17 – Class 1 DSM Program Attributes East Control Area...........................................................143
PACIFICORP – 2013 IRP INDEX OF TABLES

viii

Table 6.18 – Class 3 DSM Program Attributes, West Control Area ........................................................144

Table 6.19 – Class 3 DSM Program Attributes, East Control area...........................................................145

Table 6.20 – Class 2 DSM MWh Potential by Cost Bundle.....................................................................148

Table 6.21 – Class 2 DSM Adjusted Prices by Cost Bundle ....................................................................149

Table 6.22 – Transmission Upgrades by Supply-Side Resource and Location ........................................152

Table 6.22 – Transmission Upgrades by Supply-Side Resource and Location (Continued)....................153

Table 6.23 – Maximum Available Front Office Transaction Quantity by Market Hub ...........................154

Table 7.1 Resource Costs, Existing and Associated Gas Conversion Alternatives...............................162

Table 7.2 – Resource Book Lives.............................................................................................................165

Table 7.3 CO2 Price Scenarios...............................................................................................................168

Table 7.4 Carbon Reduction under U.S. Hard Cap Scenarios...............................................................170

Table 7.5 – Energy Gateway Scenario Definitions...................................................................................172

Table 7.6 – Core Case Definitions............................................................................................................174

Table 7.7 – Sensitivity Case Definitions...................................................................................................175

Table 7.8 – Underlying Henry Hub Natural Gas Price Forecast Summary (Nominal $/MMBtu)............181

Table 7.9 – Short Term Load Stochastic Parameter Comparison, 2013 IRP vs. 2011 IRP ......................189

Table 7.10 Price Correlations................................................................................................................190

Table 7.11 - Hydro Short Term Stochastic Parameter Comparison, 2011 IRP vs. 2013 IRP...................191

Table 8.1 Portfolio Comparison, Risk-adjusted PVRR .........................................................................219

Table 8.2 –Portfolio Comparison, Cumulative CO2 Emissions for 2013-2032 ........................................219

Table 8.3 – Portfolio Comparison, Stochastic Mean Energy Not Served.................................................220

Table 8.4 – Portfolio Comparison, Energy Not Served - Upper Tail........................................................221

Table 8.5 – Percentage Share of Generation of New Resources by Category ..........................................223

Table 8.6 – Impact of Washington Situs Assigned Wind Generation Resources.....................................225

Table 8.7 – PacifiCorp’s 2013 IRP Preferred Portfolio ............................................................................227

Table 8.8 – Preferred Portfolio Capacity Load and Resource Balance (2013-2022)................................228

Table 8.9 – Preferred Portfolio Demand Side Management Energy (2013-2022)....................................232

Table 8.10 – PVRR of Sensitivity Cases and the Comparative Core Cases.............................................235

Table 8.11 – Renewable Resources in Case S07 and Case C03 ...............................................................238

Table 8.12 – 2013 Business Plan Resource Portfolio ...............................................................................239

Table 8.13 – Comparison of Trigger Point Portfolios to the Preferred Portfolio......................................240

Table 8.13 – Cost/Risk Comparison of Compliance Portfolios and the Preferred Portfolio, with Medium 

CO2 Prices........................................................................................................................................241

Table 9.1 – 2013 IRP Action Plan ............................................................................................................245

Table 9.2 – Near-term and Long-term Resource Acquisition Paths.........................................................267

Table 9.3 – Portfolio Comparison, 2013 Preferred Portfolio versus 2011 IRP Update Portfolio.............270

Table 9.4 – Portfolio Comparison, 2013 Business Plan versus 2013 Preferred Portfolio ........................271
PACIFICORP – 2013 IRP INDEX OF FIGURES

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INDEX OF FIGURES

Figure ES.1 – Load Forecast Comparison among Recent IRPs....................................................................1

Figure ES.2 – Power and Natural Gas Price Comparison among Recent IRPs............................................2

Figure ES.3 – PacifiCorp Capacity Resource Gap........................................................................................6

Figure ES.4 – Economic System Dispatch of Existing Resources in Relation to Monthly Load.................7

Figure ES.5 – Comparison of Resource Types in Top Performing Portfolios............................................10

Figure ES.6 – Addressing PacifiCorp’s Peak Capacity Deficit, 2013 through 2022..................................12

Figure ES.7 Annual State and Federal RPS Position Forecasts...............................................................13

Figure 3.1 – Henry Hub Day-ahead Natural Gas Price History..................................................................29

Figure 3.2 - U.S. Dry Natural Gas Production (TCF) by Source................................................................30

Figure 3.3 – Shale Plays in Lower 48 States...............................................................................................31

Figure 4.1 – Energy Gateway Transmission Expansion Plan .....................................................................74

Figure 5.1 – Contract Capacity in the 2013 Load and Resource Balance...................................................91

Figure 5.2 – System Capacity Position Trend...........................................................................................100

Figure 5.3 – West Capacity Position Trend ..............................................................................................100

Figure 5.4 – East Capacity Position Trend ...............................................................................................101

Figure 5.5 – System Average Monthly and Annual Energy Positions......................................................103

Figure 5.6 – West Average Monthly and Annual Energy Positions.........................................................104

Figure 5.7 – East Average Monthly and Annual Energy Positions ..........................................................105

Figure 6.1 – World Carbon Steel Pricing by Type....................................................................................110

Figure 6.2 – Historic Carbon Steel Pricing...............................................................................................110

Figure 6.3 - Commercially Viable Geothermal Resources near PacifiCorp’s Service Territory..............135

Figure 7.1 – Modeling and Risk Analysis Process ...................................................................................159

Figure 7.2 – Transmission System Model Topology................................................................................166

Figure 7.3 – Carbon Dioxide Price Scenario Comparison........................................................................169

Figure 7.4 – Future Energy Gateway Transmission Expansion Plan........................................................172

Figure 7.5 – Modeling Framework for Commodity Price Forecasts........................................................177

Figure 7.6 – Comparison of Base Henry Hub Gas Price Forecasts used for Recent IRPs .......................179

Figure 7.7 –Palo Verde Electricity Price Forecasts used in Recent IRPs.................................................179

Figure 7.8 – Mid Columbia Electricity Price Forecasts used in Recent IRPs...........................................180

Figure 7.9 – Underlying Henry Hub Natural Gas Price Forecast Summary (Nominal $/MMBtu) ..........181

Figure 7.10 – Henry Hub Natural Gas Prices Derived from the High Underlying Forecast ....................182

Figure 7.11 – Western Electricity Prices from the High Underlying Gas Price Forecast.........................182

Figure 7.12– Henry Hub Natural Gas Prices Derived from the Medium Underlying Forecast................183

Figure 7.13 – Western Electricity Prices from the Medium Underlying Gas Price Forecast ...................184

Figure 7.14– Henry Hub Natural Gas Prices from the Low Underlying Forecast....................................185

Figure 7.15 – Western Electricity Prices Derived from the Low Underlying Gas Price Forecast............185

Figure 7.16 – Frequency of Western (Mid-Columbia) Electricity Market Prices for 2013 and 2022 ......192

Figure 7.17 – Frequency of Eastern (Palo Verde) Electricity Market Prices, 2013 and 2022 ..................192

Figure 7.18 – Frequency of Western Natural Gas Market Prices, 2013 and 2022....................................192

Figure 7.19 – Frequency of Eastern Natural Gas Market Prices, 2013 and 2022.....................................193

Figure 7.20 – Frequencies for Idaho (Goshen) Loads...............................................................................193

Figure 7.21 – Frequencies for Utah Loads................................................................................................193

Figure 7.22 – Frequencies for Washington Loads....................................................................................194

Figure 7.23 – Frequencies for California and Oregon Loads....................................................................194

Figure 7.24 – Frequencies for Wyoming Loads .......................................................................................194

Figure 7.25 – Frequencies for System Loads............................................................................................195

Figure 7.26 – Hydroelectric Generation Frequency, 2013 and 2022........................................................195

Figure 7.27 – Illustrative Pre-Screening to Remove Outliers...................................................................199

Figure 7.28 – Illustrative Stochastic Mean vs. Upper-tail Mean PVRR Scatter-plot ...............................200
PACIFICORP – 2013 IRP INDEX OF FIGURES

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Figure 8.1 – Total Cumulative Capacity under Energy Gateway Scenario 1, 2013 through 2032...........203

Figure 8.2 – Total Cumulative Capacity under Energy Gateway Scenario 2, 2013 through 2032...........203

Figure 8.3 – Total Cumulative Capacity under Energy Gateway Scenario 3, 2013 through 2032...........203

Figure 8.4 – Total Cumulative Capacity under Energy Gateway Scenario 4, 2013 through 2032...........204

Figure 8.5 – Total Cumulative Capacity under Energy Gateway Scenarios 5, 2013 through 2032 .........204

Resource Selection by Resource Type......................................................................................................204

Figure 8.6 – Front Office Transaction Addition Trends by Portfolio, EG-2 ............................................206

Figure 8.7 – PVRR Difference in System Costs between Like Portfolios in Energy Gateway Scenario 2 

and Energy Gateway Scenario 1 (System Optimizer)......................................................................207

Figure 8.8– PVRR Difference in System Costs between Like Portfolios in Energy Gateway Scenario 3 

and Energy Gateway Scenario 1 (System Optimizer)......................................................................208

Figure 8.9 – PVRR Difference in System Costs between Like Portfolios in Energy Gateway Scenario 4 

and Energy Gateway Scenario 1 ......................................................................................................208

Figure 8.10 – PVRR Difference in System Costs between Like Portfolios in Energy Gateway Scenario 5 

and Energy Gateway Scenario 1 ......................................................................................................208

Summary of Portfolios among Core Case Themes...................................................................................208

Figure 8.11 – Annual CO2 Emissions: Reference Cases...........................................................................211

Figure 8.12 – Annual CO2 Emissions: Environmental Policy ..................................................................211

Figure 8.13 – Annual CO2 Emissions: Targeted Resources .....................................................................212

Figure 8.14 Remove Outliers, Energy Gateway Scenario 1 with Zero CO2 Prices ..............................213

Figure 8.15 Remove Outliers, Energy Gateway Scenario 1 with Medium CO2 Prices.........................213

Figure 8.16 Remove Outliers, Energy Gateway Scenario 1 with High CO2 Prices...............................214

Figure 8.17 Remove Outliers, Energy Gateway Scenario 2 with Zero CO2 Prices ..............................214

Figure 8.18 Remove Outliers, Energy Gateway Scenario 2 with Medium CO2 Prices.........................215

Figure 8.19 Remove Outliers, Energy Gateway Scenario 2 with High CO2 Prices...............................215

Figure 8.20 Stochastic mean PVRR versus Upper-tail Risk with Zero CO2 Prices ..............................217

Figure 8.21 Stochastic mean PVRR versus Upper-tail Risk with Medium CO2 Prices ........................217

Figure 8.22 Stochastic mean PVRR versus Upper-tail Risk with High CO2 Prices..............................218

Figure 8.23 Stochastic Mean Annual CO2 Emissions with Medium CO2 Prices ..................................220

Figure 8.24 Stochastic Mean Annual ENS with Medium CO2 Prices...................................................221

Figure 8.25 Resource Types among Top Performing Portfolios...........................................................223

Figure 8.26 Stochastic Mean PVRR versus Upper-tail Risk with Zero CO2 Prices..............................224

Figure 8.27 Increase/(Decrease) in Annual Nominal Revenue Requirement with Wind Removed from 

the EG2-C07 Portfolio .....................................................................................................................226

Figure 8.28 – Current and Projected PacifiCorp Resource Capacity Mix for 2013 and 2022..................229

Figure 8.29 – Current and Projected PacifiCorp Resource Energy Mix for 2013 and 2022.....................230

Figure 8.30 – Addressing PacifiCorp’s Peak Capacity Deficit, 2013 through 2022 ................................231

Figure 8.31 – Energy Contribution of the Preferred Portfolio Resources to Load Growth, PacifiCorp 

System (2013-2022).........................................................................................................................231

Figure 8.32 Annual State and Federal RPS Position Forecasts using the Preferred Portfolio...............233

Figure 8.33 – Carbon Dioxide Emission Trend ........................................................................................234

Figure 8.34– Total Cumulative Capacity of Sensitivity Cases, 2032 .......................................................235

Figure 8.35 – Sensitivity Case Coincidental Peak Load Forecasts...........................................................236

Figure 8.36 – Sensitivity Case Load Forecasts.........................................................................................236

Figure 8.37 – Cumulative Wind Additions, No RPS................................................................................237

Figure 8.38 – Cumulative Wind Addition, with RPS ...............................................................................237
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

1

CHAPTER 1 – EXECUTIVE SUMMARY

PacifiCorp’s 2013 Integrated Resource Plan (2013 IRP), representing the 12

th plan submitted to 

state regulatory commissions, presents a framework for future actions that PacifiCorp will take to 

provide reliable, reasonable-cost service with manageable risks to its customers. It was 

developed with participation from numerous public stakeholders, including regulatory staff, 

advocacy groups, and other interested parties.

The key elements of the 2013 IRP include (1) a finding of resource need, focusing on the 10-year 

period 2013-2022, (2) the preferred portfolio of incremental supply-side and demand-side 

resources to meet this need, and (3) an action plan that identifies the steps the Company will take 

during the next two to four years to implement the plan. The process and outcome of the IRP—

the preferred portfolio and action plans—meet applicable state IRP standards and guidelines. 

PacifiCorp continues to plan on a system-wide basis while accommodating state resource 

acquisition mandates and policies.

2013 IRP Highlights

Development of the 2013 IRP involved balanced consideration of cost, risk, uncertainty, supply 

reliability/deliverability, and long-run public policy goals. Key drivers to the 2013 IRP preferred 

portfolio and associated action plan include the following:

As shown in Figure ES.1, the Company’s load forecast in the 2013 IRP is down in 

relation to projected loads used in the 2011 IRP and 2011 IRP Update. The lower load 

forecast is driven significantly by industrial self generation taking advantage of low 

natural gas prices, as well as by load request cancellations in Utah and Wyoming and 

postponements prompted by prolonged recessionary impacts and permitting issues. The 

reduced load forecast has greatly mitigated, but not eliminated the need for resources in 

the front ten years of the planning horizon, and is a significant driver in resource portfolio 

modeling performed for the 2013 IRP.

Figure ES.1 – Load Forecast Comparison among Recent IRPs

60,000

62,000

64,000

66,000

68,000

70,000

72,000

74,000

76,000

78,000

80,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Forecasted Annual System Load

(GWh)

2013 IRP 2011 IRP Update 2011 IRP

9,000

9,500

10,000

10,500

11,000

11,500

12,000

12,500

13,000

13,500

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Forecasted Annual System Coincident Peak

(MW)

2013 IRP 2011 IRP Update 2011 IRP
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

2

Figure ES.2 shows that base case wholesale power prices and natural gas prices used in 

the 2013 IRP are significantly lower than the base case market prices used in the 2011 

IRP and 2011 IRP Update. The decline in forward natural gas prices has largely been 

influenced by continued growth in prolific shale gas plays in North America. With 

continued declines in natural gas prices and reduced regional loads, forward power prices 

have also declined significantly over the past two years. Given these favorable market 

conditions, front office transactions play a critical role in meeting coincident peak loads 

throughout the front ten years of the planning horizon.

Figure ES.2 – Power and Natural Gas Price Comparison among Recent IRPs

In all portfolios evaluated in the 2013 IRP, energy efficiency resources play an important 

role in meeting load growth throughout the front ten years of the planning horizon. In the 

2013 IRP preferred portfolio, the accumulated acquisition of incremental energy 

efficiency resources meets 67 percent of currently forecasted load growth from 2013 

levels by 2022, and the 2013 IRP action plan identifies steps the Company will take in 

the next two to four years to accelerate acquisition of cost-effective energy efficiency 

resources.

Policy and market developments have contributed to higher renewable resource costs and 

reduced benefits. On the policy front, policy makers continue to debate Federal budget 

deficits, and deep philosophical differences have thus far proven to be a barrier to 

budgetary compromise, making the long-term outlook for federal tax incentives that have 

traditionally benefited new renewable resources highly uncertain. Policy makers have 

also not succeeded in passing federal greenhouse gas legislation for consideration by the 

President. While the U.S. Environmental Protection Agency (EPA) has proposed new 

source performance standards to regulate greenhouse gas emissions from new sources, it 

has not finalized those standards, nor has it established a schedule to promulgate rules 

applicable to existing sources. With higher after-tax costs, lower power prices, and 

continued greenhouse gas regulation uncertainty, the need for new renewable resources 

will be driven by state-specific renewable portfolio standard (RPS) regulations. To 

mitigate the cost of RPS compliance, analyses in the 2013 IRP supports the use of 

unbundled renewable energy credits (RECs) to meet state RPS obligations through the 

first ten years of the planning period.

 $-

 $1

 $2

 $3

 $4

 $5

 $6

 $7

 $8

 $9

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Henry Hub Natural Gas Prices

($/MMBtu)

2013 IRP (Sep 2012) 2011 IRP Update (Aug 2011)

2011 IRP (Sep 2010)

 $-

 $10

 $20

 $30

 $40

 $50

 $60

 $70

 $80

 $90

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Average of MidC/Palo Verde Flat Power Prices

($/MWh)

2013 IRP (Sep 2012) 2011 IRP Update (Aug 2011)

2011 IRP (Sep 2010)
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

3

On March 15, 2013, the Utah Public Service Commission approved the Company’s 

application for a Certificate of Public Convenience and Necessity (CPCN) for the Sigurd 

to Red Butte transmission project. The Company began construction of the Sigurd to 

Red Butte transmission project in April, 2013 with a scheduled in-service date of June, 

2015. For the 2013 IRP, the Company has completed preliminary analysis of the 

Windstar to Populus transmission project (Energy Gateway Segment D) that supports ongoing permitting activities. Permitting activities for other Energy Gateway transmission 

segments will continue in parallel with the on-going development of analytical tools that 

can be used to evaluate transmission benefits that are not traditionally captured in the 

resource portfolio modeling process used in the IRP.

The Company has analyzed in the 2013 IRP environmental investments required to meet 

known and prospective compliance obligations across PacifiCorp’s existing coal fleet. 

Supported by analyses performed as part of the 2013 IRP and analyses performed in 

recent regulatory filings, the Company plans to convert Naughton Unit 3 to a natural gasfired facility and to install environmental investments required to meet near term 

compliance obligations at the Hunter Unit 1, Jim Bridger Unit 3, and Jim Bridger Unit 4

generating units. Installation of emission control equipment at these facilities will reduce

emissions of nitrous oxides (NOX) and sulfur dioxide (SO2) and contribute to improved 

visibility in the region. The Company plans to continue to evaluate environmental 

investments required to meet known and prospective environmental compliance 

obligations at existing coal units in future IRPs and future IRP Updates.

Modeling and Process Improvements

In developing the 2013 IRP, the Company has significantly advanced its analytical methods and 

portfolio development approach. The notable improvements that are summarized below have 

very much influenced the 2013 IRP and establish a sound foundation for analysis in future IRPs.

Energy Gateway Transmission

In contrast to the 2011 IRP, where analysis of Energy Gateway transmission investments 

preceded resource portfolio modeling, Energy Gateway transmission investments have 

been integrated into the portfolio modeling process for the 2013 IRP. This was achieved 

by replicating the development of resource portfolios among five different Energy 

Gateway transmission scenarios. Consequently, 94 unique core case resource portfolios 

were produced in the 2013 IRP, nearly five times the number of core case portfolios 

developed for the 2011 IRP.

In addition to incorporating Energy Gateway transmission investments into the resource 

portfolio modeling process, the 2013 IRP introduces the System Operational and 

Reliability Benefits Tool (SBT), which identifies and quantifies transmission benefits that 

are not captured using production cost dispatch models traditionally used for IRP 

analyses. In this way, the SBT identifies, measures, and monetizes benefits that are 

incremental to those identified in the resource portfolio modeling process. Analysis 

using the SBT supports investment in the Sigurd to Red Butte transmission project and 

preliminary application of the SBT to the Windstar to Populus transmission project 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

4

supports continued permitting of Energy Gateway Segment D. The SBT will continue to 

be developed and will be applied to additional Energy Gateway transmission projects for 

analysis in future IRPs.

Existing Coal Resources

Building upon modeling techniques developed in the 2011 IRP and 2011 IRP Update, 

environmental investments required to achieve compliance with known and prospective 

regulations at existing coal resources have been integrated into the portfolio modeling 

process in the 2013 IRP. Potential alternatives to environmental investments associated 

with known and prospective compliance obligations tied to Regional Haze rules, Mercury 

and Air Toxics Standards (MATS), regulation of coal combustion residuals (CCR), and 

regulation of cooling water intakes are considered in the development of all resource 

portfolios developed for the 2013 IRP. Integrating potential environmental investment 

decisions into the portfolio development process allows each portfolio to reflect potential 

early retirement and resource replacement and/or natural gas conversion as alternatives to 

incremental environmental investment projects on a unit-by-unit basis. In addition to 

integrating coal unit environmental investment decisions into the portfolio development 

process, the Company has completed detailed financial analysis of near-term investment 

decisions in Confidential Volume III of the 2013 IRP.

Energy Efficiency

PacifiCorp continues to evaluate energy efficiency as a resource that competes with 

traditional supply-side resource alternatives when developing resource portfolios that are 

compared under a range of cost and risk metrics. The 2013 IRP includes for the first time 

core case resource portfolios developed assuming accelerated acquisition of energy 

efficiency resources. While the assumptions developed for these cases require further 

validation and review, cost and risk analysis of these portfolios have led to action items in 

the 2013 IRP action plan to accelerate acquisition of cost-effective energy efficiency 

resources.

In addition to evaluating acceleration of energy efficiency resources in the 2013 IRP, the 

Company greatly expanded its representation of energy efficiency resource attributes that 

influence selection in any given portfolio. Energy efficiency resources were modeled 

with additional cost granularity by increasing the number of cost steps that delineate

groupings of different energy efficiency measures. In the 2011 IRP, energy efficiency 

resources for a given state were grouped into nine different cost levels, whereas the 2013 

IRP modeling was performed using 27 different cost levels to represent energy efficiency 

resource opportunities in each state. Implementation of this modeling refinement 

deteriorated model performance, and the Company has developed an action item to study 

trade-offs between resource selections and model run-times at different levels of 

granularity.

Renewable Portfolio Standards

The 2013 IRP includes portfolios with and without renewable portfolio standard (RPS) 

requirements to isolate how system costs and portfolio risks are affected when new 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

5

renewable resources are added to a portfolio for the sole purpose of meeting state-specific 

RPS compliance targets. In those cases where RPS compliance targets are assumed and 

incremental renewable resources are needed for the sole purpose of achieving RPS 

targets, the RPS Scenario Maker model was introduced into the 2013 IRP. The RPS 

Scenario Maker model was used to establish a minimum level of new renewable 

resources needed to meet RPS compliance targets while considering compliance 

flexibility mechanisms such as “banking” unique to each state RPS program.

Public Process

The involvement of stakeholders is a critical element of the IRP process. Over the course 

of developing the 2013 IRP, the Company expanded its open and collaborative approach 

to resource planning by increasing opportunities for stakeholder participation. The 

Company hosted 15 public input meetings, more than twice the number of public input 

meetings held for the 2011 IRP, supplemented communications with stakeholder 

conference calls, and held five state meetings. In addition, the Company made available 

to stakeholders a website used to provide data and to communicate Company responses 

to stakeholder questions received throughout the public process.

Resource Need

PacifiCorp’s need for new resources is determined by developing a capacity load and resource 

balance that considers the coincident system peak load hour capacity contribution of existing 

resources, forecasted loads and sales, and reserve requirements. For capacity expansion planning, 

the Company uses a 13 percent planning reserve margin, which is applied to PacifiCorp’s 

obligation net of offsetting “load resources” such as dispatchable load control capacity.

1

 

Table ES.1 shows the Company’s annual capacity position for 2013 through 2022, and Figure 

ES.3 graphically highlights the capacity resource gap in relation to currently owned and 

contracted east and west-side resources. Without new resources, the system experiences a 

capacity deficit of 824 megawatts in 2013, down by 57 percent as compared to the 2011 IRP and 

down by 39 percent as compared to the 2011 IRP Update. By 2022, the system capacity deficit 

reaches 2,308 megawatts. Over the 2013 to 2022 timeframe, the system peak load is forecasted 

to grow at a compounded annual rate of 1.2 percent (prior to forecasted load reductions from 

energy efficiency). On an energy basis, PacifiCorp expects system-wide average load growth of 

1.1 percent per year.

Table ES.1 – PacifiCorp 10-year Capacity Position Forecast (Megawatts)

 

1The 13 percent planning reserve margin is supported by a stochastic loss of load probability study that is 

summarized in Volume II, Appendix I of the 2013 IRP.

System 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Total Resources 10,010 10,065 9,996 9,602 9,556 9,553 9,487 9,488 9,864 9,803

Obligation 9,588 9,780 9,933 9,797 9,950 10,125 10,254 10,409 10,571 10,718

Reserves (Based on 13% Target) 1,246 1,271 1,291 1,274 1,294 1,316 1,333 1,353 1,374 1,393

Obligation + 13% Planning Reserves 10,834 11,051 11,224 11,071 11,244 11,441 11,587 11,762 11,945 12,111

System Position (824) (986) (1,228) (1,469) (1,688) (1,888) (2,100) (2,274) (2,081) (2,308)

Reserve Margin 4.4% 2.9% 0.6% (2.0%) (4.0%) (5.6%) (7.5%) (8.8%) (6.7%) (8.5%)
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

6

Figure ES.3 – PacifiCorp Capacity Resource Gap

The capacity position shows how existing resources and loads balance during the coincident 

peak load hour of the year inclusive of a planning reserve margin. Outside of the peak hour, the 

Company economically dispatches its resources to meet changing load conditions taking into 

consideration prevailing market conditions. In those periods when system resource costs are less 

than the prevailing market price for power, the Company can dispatch resources that in aggregate 

exceed then-current load obligations, facilitating off system sales that reduce customer costs. 

Conversely, at times when system resource costs fall below prevailing market prices, system 

balancing market purchases can be used to meet then-current system load obligations to reduce 

customer costs. The economic dispatch of system resources is critical to how the Company 

manages net power costs. 

Figure ES.4 provides a snapshot of how existing system resources could be used to meet 

forecasted load across on-peak and off-peak periods given current planning assumptions and 

current wholesale power and natural gas prices.2 The figure shows expected monthly energy 

production from system resources during on-peak and off-peak periods in relation to load

assuming no additional resources are added to PacifiCorp’s system. At times, system resources 

are economically dispatched above load levels facilitating net system balancing sales. This 

occurs more often in off-peak periods than in on-peak periods. At other times, economic 

conditions result in net system balancing purchases, which occur more often during on-peak 

 

2 On-peak hours are defined as hour ending 7 AM through 10 PM, Monday through Saturday, excluding NERCobserved holidays. All other hours define off-peak periods.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Megawatts

Obligation + 13% Planning Reserves

Obligation 

East Existing Resources

2022 Resource Gap

2,308 MW 2013 Resource Gap

824 MW

West Existing Resources

13% Reserves 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

7

periods. Figure ES.4 also shows how much system energy is available from existing resources at 

any given point in time. Those periods where all available resource energy falls below 

forecasted loads are highlighted in red, and are indicative of short energy positions absent the 

addition of incremental resources to the portfolio. During on-peak periods, the first energy 

shortfall appears in July 2018, and by 2022 available system energy falls short of monthly loads 

in January, July, August, and October. During off-peak periods, there are no energy shortfalls 

through the 2022 timeframe.

Figure ES.4 – Economic System Dispatch of Existing Resources in Relation to Monthly Load

Future Resource Options and Portfolio Modeling

In line with state IRP standards and guidelines, PacifiCorp included a wide variety of resource 

options in portfolio modeling covering generation, demand-side management and transmission. 

Cost and performance assumptions for resource alternatives were developed using multiple 

sources, including: third party estimates, data from actual and projected PacifiCorp or utility 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

On-Peak Energy Balance

System Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall System Energy Available Load

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

Off-Peak Energy Balance

System Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall System Energy Available Load
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

8

industry installations, and data from recent request for proposals and requests for information. 

Table ES.2 summarizes the wide range of resource alternatives evaluated in the 2013 IRP.

Table ES.2 – 2013 IRP Resource Options*

Natural Gas Other 

Thermal Renewable Energy Storage

Distributed 

Generation

Class 1 

DSM 

(Direct 

Load 

Control)

Class 2 

DSM 

(Energy 

Efficiency)

Class 3 

DSM 

(Demand 

Response)

SCCT Aero

Intercooled 

SCCT Aero

SCCT Frame

IC Recip. 

Engine

CCCT (2x1) 

F-class

CCCT (2x1) 

G/H-class

CCCT (1x1) 

G/H-class

CCCT (1x1) 

J-class

CCCTs with 

and without 

duct firing

IGCC with 

carbon 

capture and 

sequestration

Nuclear 

fission

Geothermal 

(PPAs)

Wind

Solar PV 

(fixed tilt & 

tracking)

Biomass

Pumped 

Storage

SodiumSulfur 

Battery

Advanced 

Fly Wheel

Compressed 

Air Energy 

Storage

Reciprocating 

Engines

Gas Turbine

Microturbine

Fuel Cell

Commercial 

Biomass, 

Anaerobic 

Digester

Industrial 

Biomass, 

Waste

Rooftop 

Solar PV

Solar Water 

Heaters

Residential 

Central Air & 

Water 

Heating

Small 

Commercial 

Central Air & 

Water 

Heating

Irrigation 

Load 

Curtailment

Commercial 

Curtailment

Industrial 

Curtailment

Residential, 

Commercial, 

Industrial, 

Irrigation, 

and Street 

Lighting 

Measures 

27 measure 

bundles 

grouped by 

cost among 

five states

Energy Trust 

of Oregon 

Energy 

Efficiency 

Measures as

Applicable 

for Oregon

Residential 

time-of-use 

rates

Commercial 

Critical Peak 

Pricing

Commercial 

and Industrial 

Demand 

Buyback

Voluntary 

Irrigation 

Time-of-Use

*SCCT = simple cycle combustion turbine; CCCT = combined cycle combustion turbine; IGCC = integrated 

gasification combined cycle, PPA = power purchase agreement; PV = photo voltaic, DSM = demand side 

management

PacifiCorp’s IRP modeling approach seeks to determine the comparative cost, risk, and 

reliability attributes of resource portfolios, and consists of eight phases:

Define input scenarios for portfolio development

Price forecast development (natural gas and wholesale electricity by market hub)

Optimize portfolio development using PacifiCorp’s System Optimizer capacity expansion 

model for cases without RPS requirements

Develop a renewable resource floor, reflecting renewable resource additions chosen in 

optimized portfolios from cases that exclude RPS requirements needed to achieve 

compliance for cases that do include RPS assumptions

Optimize portfolio development using PacifiCorp’s System Optimizer capacity expansion 

model for cases with RPS requirements

Stochastic Monte Carlo production cost simulation of optimized portfolios

Selection of top-performing portfolios using a three-phase screening process that 

incorporates stochastic portfolio cost and risk assessment measures

Preliminary preferred portfolio selection, followed by additional analysis and 

determination of the final preferred portfolio
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

9

PacifiCorp worked with stakeholders to define 19 input scenarios, or “core cases”, which were 

applied across five different Energy Gateway transmission scenarios totaling 94 different 

variations of resource portfolios.3The 19 different core cases were categorized into four 

different themes:

(1) Reference: There are three different core cases developed for the Reference Theme. 

Each case relied upon base case assumptions for market prices, environmental policy 

inputs, energy efficiency assumptions, and load projections. RPS assumptions 

differentiate the three cases in the Reference Theme, with one case assuming no state 

or federal RPS requirements, one case assuming only state RPS requirements, and 

one case assuming both state and federal RPS requirements must be met.

(2) Environmental Policy: There are 11 different core cases developed for the 

Environmental Policy Theme. Five of the 11 cases reflect base case assumptions for 

Regional Haze requirements on existing coal units, and six of the 11 cases assume 

more stringent Regional Haze requirements. Differentiating the sets of cases with 

different Regional Haze compliance requirements are varying assumptions for market 

prices (low, medium, and high), CO2 prices (zero, medium, and high), RPS 

requirements (with and without state and federal RPS), and energy efficiency.

(3) Targeted Resources: There are four different core cases developed for the Targeted 

Resource Theme. Each of the cases is characterized by alternative assumptions for 

specific resource types to understand how these assumptions influence resource 

portfolios, costs, and risk. One of the four cases prevents combined cycle resources 

from being added to the resource portfolio and assumes energy efficiency resources 

can be acquired at an accelerated rate. The second of the four cases in this theme 

assumes that geothermal power purchase agreement resources will be used to meet 

RPS requirements. The third of four cases in this theme assumes a spike in power 

prices over the period 2017 through 2022 and assumes natural gas prices will rise 

above base case levels over the entirety of the planning horizon. The fourth case in 

this theme targets clean energy resources and assumes CO2 prices rise consistent with 

a federal hard cap scenario, that natural gas prices rise above those assumed in the 

base case, that federal tax incentives for renewable resources are extended through 

2019, and that energy efficiency resources can be acquired at an accelerated rate.

(4) Transmission: The Transmission Theme included one core case, which assumes that 

third party transmission can be purchased from a newly built line as an alternative to 

the Company’s Gateway Segment D project. This case was only analyzed in four of 

the five Energy Gateway scenarios that include the Gateway Segment D project.

PacifiCorp selected top-performing portfolios on the basis of system costs using Monte Carlo 

simulations of each portfolio over a twenty year planning horizon. The Monte Carlo runs capture 

stochastic behavior of electricity prices, natural gas prices, loads, thermal unit availability, and 

hydro availability. The relative average cost among portfolios and the upper tail cost among 

portfolios are used to evaluate cost and risk metrics among candidate portfolios and are used to 

identify top performing resource portfolios that inform the Company’s selection of the preferred 

 

3 One of the input scenarios is applicable to four out of the five Energy Gateway transmission scenarios.
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

10

portfolio. In making its preferred portfolio selection, the Company considers measures of riskadjusted portfolio costs, customer rate impacts, CO2 emissions, and supply reliability.

In the 2013 IRP, some portfolios developed under the assumption that acquisition of demand 

side management (DSM) resources can be accelerated performed well on a risk adjusted cost 

basis. However, given uncertainties in incentive and administrative costs and delivery risks 

associated with accelerating acquisition of DSM resources, these portfolios were not selected as 

the preferred portfolio. Nonetheless, the potential benefits of accelerating acquisition of DSM

resources has prompted the Company to develop action items in 2013 IRP Action Plan targeting 

accelerated acquisition of cost effective DSM resources. 

Figure ES.5 summarizes the nameplate capacity of cumulative resource selections through 2022 

among top performing portfolios developed under base case DSM acquisition ramp rate 

assumptions. With reduced load expectations and market prices, resource selections among the

top performing portfolios over the first 10 years of the planning horizon are dominated by energy 

efficiency and front office transaction (FOT) resources, and there are no new CCCT resources 

required over this timeframe. Among these cases, renewable resources are added in different 

quantities and at different times for the sole purpose of meeting west side state RPS 

requirements. The variability in quantity, type, and timing of new renewable resources is 

dependent on whether the Windstar to Populus transmission project is built.

Figure ES.5 – Comparison of Resource Types in Top Performing Portfolios

In the final screening stage of the 2013 IRP portfolio analysis, the Company evaluated an 

alternative strategy to meet Washington RPS requirements with unbundled RECs. This analysis 

shows that a compliance strategy focused on acquiring unbundled RECs is favorable on a cost 

and risk basis, and supports 2013 IRP action items to issue competitive market solicitations for 

unbundled REC products over the next two to four years.

-500

0

500

1,000

1,500

2,000

2,500

3,000

3,500 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Cumulative Capacity (MW)

DSM FOTs CCCT Peaking Gas Renewable Retirement Other
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

11

The 2013 IRP Preferred Portfolio

Table ES.3 lists the resource types and annual nameplate megawatt capacity additions over the 

period 2013 through 2032. Figure ES.4 shows how the preferred portfolio, along with existing 

resources, meets capacity requirements at the time of system peak through 2022. The drop in 

obligation and reserves in 2016 and 2021 coincides with termination of two exchange contracts.

With reduced loads and favorable market conditions, incremental resource needs in the front 10 

years of the planning horizon are met largely with cost-effective energy efficiency acquisitions 

and firm market purchases. 

As informed by portfolio modeling completed for the 2013 IRP, the Company’s action plan 

focuses on accelerating acquisition of cost effective DSM measures, to take advantage of the risk 

mitigation benefits of DSM resources by reducing the need for new firm market purchases in the 

near-term. With policy and market drivers contributing to unfavorable economics for new 

renewable resources, renewable resource additions in the 2013 IRP preferred portfolio reflect a 

near-term unbundled REC compliance strategy. Near-term renewable resources include small 

scale utility solar resources needed to meet Oregon requirements and distributed solar resources 

associated with the Utah Solar Incentive Program. Over the long-term, the 2013 IRP preferred 

portfolio includes additional wind resources, totaling 650 megawatts in the 2024 to 2025 

timeframe, which contribute to meeting long-term state and assumed RPS obligations.

Table ES.3 – 2013 IRP Preferred Portfolio

Summary Portfolio Capacity by Resource Type and Year, Installed MW

Installed Capacity, MW

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Total

Gas - CCCT - 645 - - - - - - - - - 423 - - - 661 - 1,084 - - 2,813

Gas- Peaking - - - - - - - - - - - - - - - 181 - - - 181 362

DSM - Energy Efficiency 115 117 103 101 97 92 90 81 80 82 68 70 67 67 69 66 63 54 57 56 1,593

DSM - Load Control - - - - - - - - - - - - - - 85 19 88 - - - 193

Renewable - Wind - - - - - - - - - - - 432 218 - - - - - - - 650

Renewable - Utility Solar 4 3 3 - - - - - - - - - - - - - - - - - 10

Renewable - Distributed Solar 7 11 14 16 18 14 14 14 15 15 15 15 15 15 15 15 15 15 15 15 293

Combined Heat & Power 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 21

Front Office Transactions 650 709 845 983 1,102 1,209 1,323 1,420 1,191 1,333 1,427 1,112 1,304 1,425 1,469 1,464 1,472 1,231 1,281 1,246 n/a

Coal Early Retirement/Conversions - - (502) - - - - - - - - - - - - - - - - - (502)

Thermal Plant End-of-life Retirements - - - - - - - - - - - - - - - (760) - (701) (74) - (1,535)

Coal Plant Gas Conversion Additions - - 338 - - - - - - - - - - - - - - - - - 338

Turbine Upgrades 14 - - - - - - - - - - - - - - - - - - - 14

Total 791 1,486 802 1,102 1,218 1,315 1,427 1,515 1,287 1,431 1,511 2,054 1,606 1,509 1,640 1,648 1,639 1,685 1,281 1,500

Resource

Expansion Options

Existing Unit Changes
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

12

Figure ES.6 – Addressing PacifiCorp’s Peak Capacity Deficit, 2013 through 2022

Figure ES.7 shows PacifiCorp’s forecasted RPS compliance position for the California, Oregon, 

and Washington4programs, along with a federal RPS program scenario5, covering the period 

2013 through 2022 based on the preferred portfolio. Utah’s RPS goal is tied to a 2025 

compliance date, so the 2013 to 2022 position is not shown below. However, PacifiCorp meets 

the Utah 2025 state target of 20 percent based on eligible Utah RPS resources, and has 

significant levels of banked RECs to sustain continued future compliance. PacifiCorp anticipates 

utilizing flexible compliance mechanisms such as banking and/or tradable RECs where allowed, 

to meet RPS requirements.

 

4 The Washington RPS requirement is tied to January 1st of the compliance year.

5 The assumed federal RPS requirements are applied to retail sales, with a target of 4.5 percent beginning in 2018, 

7.1 percent in 2019-2020, 9.8 percent in 2021-2022, 12.4 percent in 2023-2024, and 20 percent in 2025

8,000

9,000

10,000

11,000

12,000

13,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Megawatts

New Firm Market Purchases New - DSM + CHP + Wind + Solar **

Existing - Long Term Contracts and PPA's 2014 Lake Side 2 CCCT (under construction)

Existing - Physical Assests and DSM *** Obligation + Reserves *

Existing - Physical Assets and DSM ***

Existing - Long Term Contracts and PPA's

New - DSM, CHP, and Solar **

New Firm Market Purchase

Obligation + Reserves *

* Includes 13% Planning Reserves, Sales and Non-Owned Reserves

** Solar resources peak contribution is 8 MW by 2022 and Combined Heat and Power (CHP) contributes 12 MW.

*** Includes retirements, turbine upgrades, and gas repower. DSM includes both Class 1 and 2.

2014 Lake Side 2 CCCT (under construction)
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

13

Figure ES.7 Annual State and Federal RPS Position Forecasts

0

2,000

4,000

6,000

8,000

10,000

12,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

Oregon RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement

0

100

200

300

400

500

600

700

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

Washington RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement

0

50

100

150

200

250

300

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

California RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement

0

2,000

4,000

6,000

8,000

10,000

12,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

Federal RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

14

The 2013 IRP Action Plan

The 2013 IRP Action Plan identifies specific actions the Company will take over the next two to four years. Action items are based on 

the type and timing of resources in the preferred portfolio, findings from analysis completed over the course of portfolio modeling, and 

feedback received by stakeholders in the 2013 IRP process. Table ES.4 details specific 2013 IRP action items by category.

Table ES.4 – 2013 IRP Action Plan

Action 

Item 1. Renewable Resource Actions

1a.

Wind Integration

Update the wind integration study for the 2015 IRP. The updated wind integration study will consider the 

implications of an energy imbalance market along with comments and feedback from the technical review committee 

and IRP stakeholders provided during the 2012 Wind Integration Study.

1b.

Renewable Portfolio Standard Compliance

With renewable portfolio standard (RPS) compliance achieved with unbundled renewable energy credit (REC) 

purchases, the preferred portfolio does not include incremental renewable resources prior to 2024. Given that the 

REC market lacks liquidity and depth beyond one year forward, the Company will pursue unbundled REC requests 

for proposal (RFP) to meet its state RPS compliance requirements. 

– Issue at least annually, RFPs seeking then current-year or forward-year vintage unbundled RECs that will 

qualify in meeting Washington renewable portfolio standard obligations.

– Issue at least annually, RFPs seeking historical, then current-year, or forward-year vintage unbundled RECs 

that will qualify for Oregon renewable portfolio standard obligations. As part of the solicitation and bid 

evaluation process, evaluate the tradeoffs between acquiring bankable RECs early as a means to mitigate 

potentially higher cost long-term compliance alternatives.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage unbundled RECs that will 

qualify for California renewable portfolio standard obligations.

1c. Renewable Energy Credit Optimization

On a quarterly basis, issue reverse RFPs to sell RECs not required to meet state RPS compliance obligations. 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

15

1d.

Solar

Issue an RFP in the second quarter of 2013 soliciting Oregon solar photovoltaic resources to meet the Oregon small 

solar compliance obligation (Oregon House Bill 3039). Coordinate the selection process with the Energy Trust of 

Oregon to seek 2014 project funding. Complete evaluation of proposals and select potential winning bids in the 

fourth quarter of 2013. 

Issue a request for information 180 days after filing the 2013 IRP to solicit updated market information on utility scale 

solar costs and capacity factors. 

1e.

Capacity Contribution

Track and report the statistics used to calculate capacity contribution from wind resources and available solar 

information as a means of testing the validity of the peak load carrying capability (PLCC) method. 

Action 

Item 2. Distributed Generation Actions

2a.

Distributed Solar

Manage the expanded Utah Solar Incentive Program to encourage the installation of the entire approved capacity. 

Beginning in June 2014, as stipulated in the Order in Docket No. 11-035-104, the Company will file an Annual 

Report with program results, system costs, and production data. These reports will also provide an opportunity to 

evaluate and improve the program as the Company will use this opportunity to recommend changes. Interested parties 

will have an opportunity to comment on the report and any associated recommendations.

2b.

Combined Heat & Power (CHP)

Pursue opportunities for acquiring CHP resources, primarily through the Public Utilities Regulatory Policies Act

PURPA Qualifying Facility contracting process. For the 2013 IRP Update, complete a market analysis of CHP 

opportunities that will: (1) assess the existing, proposed, and potential generation sites on PacifiCorp’s system; (2) 

assess availability of fuel based on market information; (3) review renewable resource site information (i.e. permits, 

water availability, and incentives) using available public information; and (4) analyze indicative project economics 

based on avoided cost pricing to assist in ranking probability of development.

Action 

Item 3. Firm Market Purchase Actions

3a.

Front Office Transactions

Acquire economic front office transactions or power purchase agreements as needed through the summer of 2017. 

– Resources will be procured through multiple means, such as periodic market RFPs that seek resources less than 

five years in term, and bilateral negotiations. 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

16

– Include in the 2013 IRP Update a summary of the progress the Company has made to acquire front office 

transactions over the 2014 to 2017 forward period.

Action 

Item 4. Flexible Resource Actions

4a.

Energy Imbalance Market (EIM)

Continue to pursue the EIM activities with the California Independent System Operator and the Northwest Power 

Pool to further optimize existing resources resulting in reduced costs for customers.

Action

Item 5. Hedging Actions

5a.

Natural Gas Request for Proposal

Convene a workshop for stakeholders by October 2013 to discuss potential changes to the Company’s process in 

evaluating bids for future natural gas RFPs, if any, to secure additional long-term natural gas hedging products.

Action 

Item 6. Plant Efficiency Improvement Actions

6a.

Plant Efficiency Improvements

Production efficiency studies have been conducted to satisfy requirements of the Washington I-937 Production 

Efficiency Measure that have identified categories of cost effective production efficiency opportunity.

– By the end of the first quarter of 2014, complete an assessment of the plant efficiency opportunities identified in 

the Washington I-937 studies that might be applicable to other wholly owned generation facilities.

– Prior to initiating modeling efforts for the 2015 IRP, determine a multi-state “total resource cost test” evaluation 

methodology to address regulatory recovery among states with identified capital expenditures.

– Prior to initiating modeling efforts for the 2015 IRP, present to IRP stakeholders in a public input meeting the 

Company’s recommended approach to analyzing cost effective production efficiency resources in the 2015 IRP.

Action 

Item 7. Demand Side Management (DSM) Actions

7a.

Class 2 DSM

Acquire 1,425 – 1,876 GWh of cost-effective Class 2 energy efficiency resources by the end of 2015 and 2,034 –

3,180 GWh by the end of 2017. 

– Collaborate with the Energy Trust of Oregon on a pilot residential home comparison report program to be offered 

to Pacific Power customers in 2013 and 2014. At the conclusion of the pilot program and the associated impact 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

17

evaluation, assess further expansion of the program.

– Implement an enhanced consolidated business program to increase DSM acquisition from business customers in 

all states excluding Oregon. 

 Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd quarter 2013.

 Washington base case schedule is 4th quarter 2014, with an accelerated target of 1st quarter 2014.

 Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with an accelerated target of 2nd

quarter 2014.

– Accelerate to the 2nd quarter of 2014, an evaluation of waste heat to power where generation is used to offset 

customer requirements – investigate how to integrate opportunities into the DSM portfolio. 

– Increase acquisitions from business customers through prescriptive measures by expanding the “Trade Ally 

Network”.

 Base case target in all states is 3rd quarter 2014, with an accelerated target of 4th quarter 2013

– Accelerate small-mid market business DSM acquisitions by contracting with third party administrators to facilitate 

greater acquisitions by increasing marketing, outreach, and management of comprehensive custom projects by 1st

quarter 2014. 

– Increase the reach and effectiveness of “express” or “typical” measure offerings by increasing qualifying 

measures, reviewing and realigning incentives, implementing a direct install feature for small commercial 

customers, and expanding the residential refrigerator and freezer recycling program to include commercial units.

 Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd quarter 2013.

 Washington base case schedule is 4th quarter 2014, with an accelerated target of 1st quarter 2014.

 Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with an accelerated target of 2nd

quarter 2014.

– Increase the reach of behavioral DSM programs: 

 Evaluate and expand the residential behavioral pilot.

 Utah base case schedule is 2nd quarter 2014, with an accelerated target of 4th quarter 2013.

 Accelerate commercial behavioral pilot to the end of the first quarter 2014.

 Expand residential programs system-wide pending evaluation results.

 System-wide target is 3rd quarter 2015, with an accelerated target of 3rd quarter 2014.

– Increase acquisition of residential DSM resources:

 Implement cost effective direct install options by the end of 2013.

 Expand offering of “bundled” measure incentives by the end of 2013.

 Increase qualifying measures by the end of 2013.

 Review and realign incentives.

 Utah schedule is 1st quarter 2014
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

18

 Washington base case schedule is 2nd quarter 2014, with accelerated target of 1st quarter 2014.

 Wyoming, California, and Idaho base case schedule is 3rd quarter 2014, with an accelerated 

target of 2nd quarter 2014

– Accelerate acquisitions by expanding refrigerator and freezer recycling to incorporate retail appliance distributors 

and commercial units – 3

rd quarter 2013. 

– By the end of 2013, complete review of the impact of accelerated DSM on Oregon and the Energy Trust of 

Oregon, and re-contract in 2014 for appropriate funding as required. 

– Include in the 2013 IRP Update Class 2 DSM decrement values based upon accelerated acquisition of DSM 

resources.

– Include in the 2014 conservation potential study an analysis testing assumptions in support of accelerating 

acquisition of cost-effective Class 2 DSM resources, and apply findings from this analysis into the development of 

candidate portfolios in the 2015 IRP. 

7b.

Class 3 DSM

Develop a pilot program in Oregon for a Class 3 irrigation time-of-use program as an alternative approach to a Class 1 

irrigation load control program for managing irrigation loads in the west. The pilot program will be developed for the 

2014 irrigation season and findings will be reported in the 2015 IRP.

Action 

Item 8. Coal Resource Actions

8a.

Naughton Unit 3

Continue permitting and development efforts in support of the Naughton Unit 3 natural gas conversion project. The 

permit application requesting operation on coal through year-end 2017 is currently under review by the Wyoming 

Department of Environmental Quality, Air Quality Division.

Issue a request for proposal to procure gas transportation for the Naughton plant as required to support compliance 

with the conversion date that will be established during the permitting process.

Issue an RFP for engineering, procurement, and construction of the Naughton Unit 3 natural gas retrofit as required to 

support compliance with the conversion date that will be established during the permitting process.

8b.

Hunter Unit 1

Complete installation of the baghouse conversion and low NOX burner compliance projects at Hunter Unit 1 as 

required by the end of 2014.

8c.

Jim Bridger Units 3 and 4

Complete installation of selective catalytic reduction (SCR) compliance projects at Jim Bridger Unit 3 and Jim 

Bridger Unit 4 as required by the end of 2015 and 2016, respectively.
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

19

8d.

Cholla Unit 4

Continue to evaluate alternative compliance strategies that will meet Regional Haze compliance obligations, related to 

the U.S. Environmental Protection Agency’s Federal Implementation Plan requirements to install SCR equipment at 

Cholla Unit 4. Provide an update of the Cholla Unit 4 analysis regarding compliance alternatives in the 2013 IRP 

Update.

Action 

Item 9. Transmission Actions

9a.

System Operational and Reliability Benefits Tool (SBT)

60 days after filing the 2013 IRP, establish a stakeholder group and schedule workshops to further review the System 

Benefit Tool (SBT).

– For the 2013 IRP Update, complete additional analysis of the Energy Gateway West Segment D that evaluates 

staging implementation of Segment D by sub-segment.

– In preparation for the 2015 IRP, continue to refine the SBT for Energy Gateway West Segment D and develop 

SBT analyses for additional Energy Gateway segments.

9b.

Energy Gateway Permitting

Continue permitting for the Energy Gateway transmission plan, with near term targets as follows:

– Segment D, E, and F, continue funding of the required federal agency permitting environmental consultant as 

actions to achieve final federal permits. 

– Segment D, E, and F, continue to support the federal permitting process by providing information and 

participating in public outreach projected through the next 2 to 4 years. 

– Segment H Cascade Crossing, complete benefits analysis in 2013.

– Segment H Boardman to Hemingway, continue to support the project under the conditions of the Boardman to 

Hemingway Transmission. Project Joint Permit Funding Agreement, projected through 2015. 

9c.

Sigurd to Red Butte 345 kilovolt Transmission Line

Complete project construction per plan.

Action 

Item 10. Planning Reserve Margin Actions

10a.

Planning Reserve Margin

Continue to evaluate in the 2015 IRP the results of a System Optimizer portfolio sensitivity analysis comparing a 

range of planning reserve margins considering both cost and reliability impacts of different levels of planning reserve 
PACIFICORP – 2013 IRP CHAPTER 1 – EXECUTIVE SUMMARY

20

margin assumptions. Complete for the 2015 IRP an updated planning reserve margin analysis that is shared with 

stakeholders during the public process.

Action 

Item 11. Planning and Modeling Process Improvement Actions

11a.

Modeling and Process

Within 90 days of filing the 2013 IRP, schedule an IRP workshop with stakeholders to discuss potential process 

improvements that can more efficiently achieve meaningful cost and risk analysis of resource plans in the context of 

the IRP and implement process improvements in the 2015 IRP.

11b.

Cost/Benefit Analysis of DSM Resource Alternatives

Complete a cost/benefit analysis on the level of detail used to evaluate prospective DSM resources in the IRP. The 

analysis will consider the tradeoffs between model run-time and resulting resource selections, will be shared with 

stakeholders early in the 2015 IRP public process, and will inform how prospective DSM resources will be aggregated 

in developing resource portfolios for the 2015 IRP.
PACIFICORP – 2013 IRP CHAPTER 2 - INTRODUCTION

21

CHAPTER 2 – INTRODUCTION

PacifiCorp files an Integrated Resource Plan (IRP) on a biennial basis with the state utility 

commissions of Utah, Oregon, Washington, Wyoming, Idaho, and California. This IRP, the 12th

plan submitted, fulfills 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 through a 

collaborative public process with involvement from regulatory staff, advocacy groups, and other 

interested parties. As the owner of the IRP and its action plan, all policy judgments and decisions 

concerning the IRP are ultimately made by PacifiCorp in light of its obligations to its customers, 

regulators, and shareholders.

This IRP also builds on PacifiCorp’s prior resource planning efforts and reflects continued 

advancements in portfolio modeling and analytical methods. These advancements include:

Implementation of the Enterprise Production Model (EPM) interface, combining the 

functionality of System Optimizer and Planning and Risk components into a single 

model;

Integration of Energy Gateway transmission investments into the portfolio modeling 

process;

Introduction of the System Operational and Reliability Benefits Tool (SBT) to 

complement IRP modeling for a more complete picture of transmission costs and benefits 

of each IRP scenario;

Enhancements to new resource modeling in System Optimizer resulting in improvement 

to resource selection, including modeling of environmental investments required to 

achieve compliance with known and prospection environmental regulations at existing 

coal resources, and increased granularity in the definition of bundle price breakpoints for 

energy efficiency measures;

Addition of core case resource portfolios that assume accelerated acquisition of energy 

efficiency resources; and

Use of the Renewable Portfolio Standard Scenario Maker, a new Excel spreadsheet tool 

for developing RPS-compliant renewable resource schedules.

Significant studies conducted to support the IRP include:

An update of the 2010 demand-side management (DSM) and dispersed generation 

potentials study;

An update of the 2011 loss of load study for determining an adequate capacity planning 

reserve margin for load and resource balance development;

A state-of-the-art wind integration study;

Market reliance scenario analysis; and

Evaluation of price hedging strategies.

Finally, this IRP reflects continued alignment efforts with the Company’s annual ten-year 

business planning process. The purpose of the alignment, initiated in 2008, is to:
PACIFICORP – 2013 IRP CHAPTER 2 - INTRODUCTION

22

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 capital budgeting; and

Improve the overall transparency of PacifiCorp’s resource planning processes to public 

stakeholders.

The planning alignment strategy also follows the 2008 adoption of the IRP portfolio modeling 

and analysis approach for requests for proposals (RFP) bid evaluation. This latter initiative was 

part of PacifiCorp’s effort to unify planning and procurement under the same analytical 

framework. The Company used this analytical framework for bid evaluation in support of the allsource RFP reactivated in December 2009.

This chapter outlines the components of the 2013 IRP, summarizes the role of the IRP, and 

provides an overview of the public process.

2013 Integrated Resource Plan Components

The basic components of PacifiCorp’s 2013 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 

(this chapter).

An assessment of the planning environment, market trends and fundamentals, legislative 

and regulatory developments, and current procurement activities (Chapter 3).

A description of PacifiCorp’s transmission planning efforts and description of IRP 

modeling studies conducted to support Energy Gateway transmission financial evaluation 

(Chapter 4).

A resource needs assessment covering the Company’s load forecast, status of existing 

resources, and determination of the load and energy positions for the 10-year resource 

acquisition period (Chapter 5).

A profile of the resource options considered for addressing future capacity and energy 

deficits (Chapter 6).

A description of the IRP modeling, risk analysis, and portfolio performance assessment 

processes (Chapter 7).

Presentation of IRP modeling results, and selection of top-performing resource portfolios 

and PacifiCorp’s preferred portfolio (Chapter 8).

An IRP action plan linking the Company’s preferred portfolio with specific 

implementation actions, including an accompanying resource acquisition path analysis 

and discussion of resource risks (Chapter 9).

The IRP appendices, included as a separate volume, comprised of a detailed load forecast report 

(Appendix A), fulfillment of IRP regulatory compliance requirements, (Appendix B), the public 
PACIFICORP – 2013 IRP CHAPTER 2 - INTRODUCTION

23

input process (Appendix C), energy efficiency modeling (Appendix D), conservation voltage 

reduction and voltage optimization projects update (Appendix E), flexible resource needs 

assessment (Appendix F), historical plant water consumption data (Appendix G), 2012 wind 

integration cost study (Appendix H), 2012 stochastic loss of load study (Appendix I), an 

assessment of resource adequacy for western power markets, including a market reliance “stress” 

scenario analysis (Appendix J), detailed capacity expansion tables (Appendix K), stochastic 

simulation results (Appendix L), case study fact sheets (Appendix M), DSM decrement studies 

(Appendix N), and wind, and solar peak contributions (Appendix O).

The Role of PacifiCorp’s Integrated Resource Planning

PacifiCorp’s IRP mandate is to assure, on a long-term basis, an adequate and reliable electricity 

supply at a reasonable cost and in a manner “consistent with the long-run public interest.”6The 

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 RFP bid evaluation efforts. As an external communications tool, 

the IRP engages numerous stakeholders in the planning process and guides them through the key 

decision points leading to PacifiCorp’s preferred portfolio of generation, demand-side, and 

transmission resources.

While PacifiCorp continues to plan on a system-wide basis, the Company recognizes that new 

state resource acquisition mandates and policies add complexity to the planning process and 

present challenges to conducting resource planning on this basis.

Public Process

The IRP standards and guidelines for certain states require PacifiCorp to have a public process 

allowing stakeholder involvement in all phases of plan development. The Company held 26

public meetings/conference calls during 2012 and early 2013 designed to facilitate information 

sharing, collaboration, and expectations setting for the IRP. The topics covered all facets of the 

IRP process, ranging from specific input assumptions to the portfolio modeling and risk analysis 

strategies employed. Table 2.1 lists the public meetings/conferences and major agenda items 

covered.

 

6 The Public Utility Commission of Oregon and Public Service Commission of Utah cite “long run public interest” 

as part of their definition of integrated resource planning. Public interest pertains to adequately quantifying and 

capturing for resource evaluation any resource costs external to the utility and its ratepayers. For example, the Public 

Service Commission of Utah cites the risk of future internalization of environmental costs as a public interest issue 

that should be factored into the resource portfolio decision-making process.
PACIFICORP – 2013 IRP CHAPTER 2 - INTRODUCTION

24

Table 2.1 – 2013 IRP Public Meetings 

Meeting Type Date Main Agenda Items

General Meeting 5/7/2012 2013 IRP kickoff meeting

General Meeting 6/20/2012 Demand-side management; portfolio development; wind integration

State Meeting 7/11/2012 Idaho state stakeholder comments

State Meeting 7/12/2012 Wyoming state stakeholder comments

General Meeting 7/13/2012 Portfolio case development; transmission scenarios and benefit analysis

State Meeting 7/19/2012 Oregon state stakeholder comments

State Meeting 7/20/2012 Washington state stakeholder comments

General Meeting 8/2/2012 Conservation voltage reduction; resource adequacy workshop; portfolio 

case development

General Meeting 8/13/2012 Supply-side resources; renewable portfolio standards; wind integration 

study

State Meeting 8/14/2012 Utah state stakeholder comments

General Conference Call 8/24/2012 Distributed generation resource assumptions

General Meeting 9/14/2012 Environmental compliance; load forecast; capacity load and resource 

balance; portfolio case development

General Conference Call 9/24/2012 Planning reserve margins; price curve scenarios and modeling 

methodology

General Conference Call 10/3/2012 Solar photovoltaic resources

General Meeting 10/24/2012 Utility-scale resource options; wind integration study; planning reserve 

margin

General Meeting 11/5/2012 Transmission benefit evaluation; stochastic modeling; preferred portfolio 

selection

General Meeting 11/27/2012 Planning reserve margin; methodology update overview

General Conference Call 12/6/2012 US Environmental Protection Agency and impacts on IRP modeling

General Conference Call 12/14/2012 Smart Grid

General Conference Call 12/18/2012 IRP filing schedule; core case fact sheet and price curve scenario updates

General Meeting 1/31/2013 Core case portfolio results; wind integration study

General Meeting 2/27/2013 Transmission system benefits tool; IRP modeling results update; class 2 

DSM supply curves

General Meeting 3/21/2013 Modeling update; draft preferred portfolio

General Meeting 4/5/2013 Draft preferred portfolio; draft action plan

General Meeting 

(Confidential) 4/17/2013 2013 IRP Confidential Volume 3

General Meeting 4/17/2013 Draft IRP document; sensitivity analysis results

Appendix C provides more details concerning the public meeting process and individual 

meetings.

In addition to the public meetings, PacifiCorp used other channels to facilitate resource planningrelated information sharing and consultation throughout the IRP process. The Company 

maintains a public website (http://www.pacificorp.com/es/irp.html), an e-mail “mailbox” 

(irp@pacificorp.com), and a dedicated IRP phone line (503-813-5245) to support stakeholder 

communications and address inquiries by public participants. In response to stakeholder 
PACIFICORP – 2013 IRP CHAPTER 2 - INTRODUCTION

25

requests, PacifiCorp has also introduced an additional IRP comments website intended for 

PacifiCorp’s IRP public participants only (http://www.pacificorp.com/es/irp/irpcomments.html)
PACIFICORP – 2013 IRP CHAPTER 2 - INTRODUCTION

26
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

27

CHAPTER 3 – THE PLANNING ENVIRONMENT

Introduction 

This chapter profiles the major external influences that impact PacifiCorp’s long-term resource 

planning as well as recent procurement activities. External influences include events and trends 

affecting the economy, wholesale power and natural gas prices, and public policy and regulatory 

initiatives that influence the environment in which PacifiCorp operates.

Sluggish economic growth continues to influence load growth expectations throughout the 2013 

IRP planning cycle. In light of current economic conditions, the Company continues to evaluate 

capital projects for least cost adjusted for risk resources based on known and measurable 

compliance requirements.

Concerning the power industry marketplace, the major issues addressed include capacity 

resource adequacy and associated standards for the Western Electricity Coordinating Council 

(WECC). As discussed elsewhere in the IRP, future natural gas prices and the role of gas-fired 

generation and market purchases are some of the critical factors impacting the determination of 

the preferred portfolio that best balances low-cost and low-risk planning objectives.

On the government policy and regulatory front, a significant issue facing PacifiCorp continues to 

be planning for an eventual, but highly uncertain, 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 

overview of the Electric Power Research Institute’s study on carbon dioxide price impacts on 

CHAPTER HIGHLIGHTS

Significantly lower wholesale power prices and natural gas prices in the 2013 IRP 

than market prices in the 2011 IRP, caused mainly by a decline in forward natural 

gas prices as a result of the continued growth in prolific shale gas plays in North 

America and reduced regional loads. Loss of momentum in federal efforts to 

develop comprehensive federal energy and climate change compliance requirements, 

leading to continued uncertainty regarding the long-term investment climate for 

clean energy technologies. 

The U.S. Environmental Protection Agency (EPA) has promulgated new source 

performance standards to regulate greenhouse gas emissions from new sources, it 

has not established a schedule to promulgate rules applicable to existing sources. 

Nevertheless, public and legislative support for clean energy policies at the state 

level remains robust.

Aggressive efforts by the EPA to regulate electric utility plant emissions, including 

greenhouse gases, criteria pollutants and other emissions.

Near-term procurement activities related to natural gas supply and transportation and 

Oregon solar resources.
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

28

western power markets, follows. This chapter also reviews the significant policy developments 

for currently-regulated pollutants

Other topics covered in this chapter include regulatory updates on the Environmental Protection 

Agency, regional and state climate change regulation, the status of renewable portfolio standards, 

and resource procurement activities. 

Wholesale Electricity Markets 

PacifiCorp’s system does not operate in an isolated market. Operations and costs are tied to a 

larger electric system known as the Western Interconnection which functions, on a day-to-day 

basis, as a geographically dispersed marketplace. Each month, millions of megawatt-hours of 

energy are traded in the wholesale electricity market. These transactions yield economic 

efficiency by assuring that resources with the lowest operating cost are serving demand in a 

region and by providing reliability benefits that arise from a larger portfolio of resources. 

PacifiCorp participates in the wholesale market in this fashion, making purchases and sales to 

keep its supply portfolio in balance with customers’ constantly varying needs. This interaction 

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 construct or own an 

unnecessarily large margin of supplies that would go unutilized in all but the most unusual 

circumstances and would substantially diminish its capability to cost effectively 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 destruction and rapid price declines in the second half of 2008, 

have underscored. Unanticipated paradigm shifts in the market place can also cause significant 

changes in market prices as evidenced by advancements in the ability of natural gas producers to 

cost-effectively access abundant shale gas supplies over the past several years. 

As with all markets, electricity markets are faced with a wide range of uncertainties. However, 

some uncertainties are easier to evaluate than others. Market participants are routinely studying 

demand uncertainties driven by weather and overall economic conditions. Similarly, there is a 

reasonable amount of data available to gauge resource supply developments. For example, 

WECC publishes an annual assessment of power supply and any number of data services are 

available that track the status of new resource additions. A review of the WECC power supply 

assessments is provided in Appendix J. The latest assessment, published in October 2012, 

indicates that with the exception of Northern and Southern California, US WECC has adequate 

resources through 2022. If only existing units and those under construction are considered, then 

Northern and Southern California will need capacity in 2015 and 2017, respectively. 

There are other uncertainties that are more difficult to analyze and that possess heavy influence 

on the direction of future prices. One such uncertainty is the evolution of natural gas prices over 

the course of the IRP planning horizon. Given the increased role of natural gas-fired generation, 

gas prices have become a critical determinant in establishing western electricity prices, and this 

trend is expected to continue over the term of this plan’s decision horizon. Another critical 

uncertainty that weighs heavily on this IRP, as in past IRPs, is the prospect of future greenhouse 

gas policy. A broad landscape of federal, regional, and state proposals aiming to curb 

greenhouse gas emissions continues to widen the range of plausible future energy costs, and 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

29

consequently, future electricity 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 twelve years, North American natural gas markets have demonstrated exceptional 

price volatility. Figure 3.1 shows historical day-ahead prices at the Henry Hub benchmark from 

April 2, 2001 through December 28, 2012. Over this period, day-ahead gas prices settled at a 

low of $1.72 per million British thermal units (MMBtu) on November 16, 2001 and at a high of 

$18.41 per MMBtu on February 25, 2003. During the fall and early winter of 2005, prices 

breached $15 per MMBtu after a wave of hurricanes devastated the gulf region in what turned 

out to be the most active hurricane season in recorded history. Prices later topped $13 per 

MMBtu in the summer of 2008 when oil prices began their epic climb above $140 per barrel in 

the months preceding the global credit crisis. By early 2009 slow economic growth coupled with 

abundant shale gas supplies pressured natural gas prices to dip below $5 per MMBtu; day-ahead 

prices averaged $3.92 per MMBtu for 2009. Prices rose modestly and then ticked down with 

day-ahead natural gas prices averaging $4.37, $3.99, and $2.75 per MMBtu for 2010 through 

2012, respectively. Today’s natural gas prices are not adequate to incent new drilling; the 

continued supply of natural gas is a result of improvements in well productivity, production from 

wells being “held by production”, and large amounts of price insensitive dry gas produced as a 

byproduct in wet gas and shale oil plays.

Figure 3.1 – Henry Hub Day-ahead Natural Gas Price History

Source: Intercontinental Exchange (ICE), Over the Counter Day-ahead Index

Beyond the geopolitical, extreme weather, and economic events that spawned day-ahead prices 

above $13 per MMBtu, as recently as summer 2008, natural gas prices have exhibited an upward 

trend from approximately $3 per MMBtu in 2002 to nearly $9 per MMBtu in 2008 followed by a 

downward trend starting 2009. Over much of the former period, declining volumes from 

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

4/2/20018/2/2001

12/2/2001

4/2/20028/2/2002

12/2/2002

4/2/20038/2/2003

12/2/2003

4/2/20048/2/2004

12/2/2004

4/2/20058/2/2005

12/2/2005

4/2/20068/2/2006

12/2/2006

4/2/20078/2/2007

12/2/2007

4/2/20088/2/2008

12/2/2008

4/2/20098/2/2009

12/2/2009

4/2/20108/2/2010

12/2/2010

4/2/20118/2/2011

12/2/2011

4/2/20128/2/2012

12/2/2012

$/MMBtu

Day Ahead Index Average Annual Price

*Decreased 

demand from 

economic 

down turn

*Technological 

advancements 

yield growth in 

shale gas 

supply

*Epic rise in 

oil prices and 

general rush 

to 

commodities

*Fear of 

storage 

shortfalls 

going into the 

heating 

*Most active 

hurricane season 

in recorded history

*Katrina, Rita, and 

Wilma cause 

significant shutins and eventual 

production losses 

in the Gulf Region
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

30

conventional, mature producing regions largely offset growth from unconventional resources. 

However, prices in 2009 through 2012 reflect reduced demand and significant production gains 

from unconventional domestic supplies such as tight and shale gas. Figure 3.2 shows a 

breakdown of U.S. supply; Figure 3.3 illustrates the shale plays in the lower 48 states. 

Figure 3.2 - U.S. Dry Natural Gas Production (TCF) by Source

Source: U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2013, Early 

Release, December 5, 2012.

0

5

10

15

20

25

30

35

1990 2000 2010 2020 2030 2040

History 2011 Projections

Shale gas

Nonassociated offshore

Coalbed methane

Tight gas

Alaska

Associated with oil Nonassociated onshore

0

5

10

15

20

25

30

35

1990 2000 2010 2020 2030 2040

0

5

10

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20

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35

1990 2000 2010 2020 2030 2040

History 2011 Projections

Shale gas

Nonassociated offshore

Coalbed methane

Tight gas

Alaska

Associated with oil Nonassociated onshore
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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Figure 3.3 – Shale Plays in Lower 48 States

Source: U.S. Department of Energy, Energy Information Administration

The supply/demand balance began to shift in 2007 and 2008 thanks to an unprecedented and 

unexpected burst of growth from unconventional domestic supplies across the lower 48 states. 

With rapid advancements in horizontal drilling and hydraulic fracturing technologies, producers 

began drilling in geologic formations such as shale. Some of the most prominent contributors to 

the rapid growth in unconventional natural gas production have been the Barnett Shale located 

beneath the city of Fort Worth, Texas, the Woodford Shale located in Oklahoma and the 

Marcellus Shale located in Pennsylvania. Strong growth also continued in the Rocky Mountain 

region. 

Prior to 2009, forecasters expected that a gradual restoration of improved supply/demand balance 

would be achieved largely with growth in liquefied natural gas (LNG) imports. Indeed, there has 

been tremendous growth in global liquefaction facilities located in major producing regions. 

This expectation led to significant investments in regasification capacity to accommodate the 

need for future LNG imports. However, the evolution of unconventional supplies and 

continually growing estimates of shale gas reserves has significantly changed the need for LNG 

imports. Today, liquefaction, not regasification, facilities are being proposed with one having 

already been approved. As such, the U.S. is anticipated to export 0.6 billion cubic feet per day 

(BCF/D) by 2016 reaching 4.5 BCF/D by 2027. Several factors contribute to a wide range of 

price uncertainty in the mid- to long-term. Supporting downside price risk, technological 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

32

advancements underlying the recent expansion of unconventional supplies opens the door to 

tremendous growth potential in both production and proven reserves from shale formations 

across North America. Increasing well productivity, technological innovations, and large 

volumes of price insensitive associated gas have flattened the supply curve. In the long-term, 

moderated oil prices from large oil shale finds could dampen demand for LNG exports and for 

oil-to-gas substitution in the transportation sector. Supporting upside price risk, the next 

generation of unconventional supplies may prove to be more difficult or costly to extract with the 

possibility of drilling restrictions due to environmental concerns associated with hydraulic 

fracturing, which would raise marginal costs, and consequently, raise prices. In addition, high oil 

prices could incent increased LNG exports and increased oil-to-gas substitution in the 

transportation sectors. 

Western regional natural gas markets are likely to remain well-connected to overall North 

American natural gas prices. Rocky Mountain region production has caused prices at the Opal 

hubs to transact at a discount to the Henry Hub benchmark in recent years. Major pipeline 

expansions to the mid-west and east coupled with further pipeline expansion plans to the west 

have provided price support for Opal; however, prices remain discounted to Henry Hub. In the 

Northwest, where natural gas markets are influenced by production and imports from Canada, 

prices at Sumas have traded at a premium relative to other hubs in the region. This has been 

driven in large part by declines in Canadian natural gas production and reduced imports into the 

U.S. In the near-term, Canadian imports from British Columbia are expected to remain below 

historical levels lending support for basis differentials in the region; however, in the mid- to 

long-term, production potential from regional shale formations will have the opportunity to 

soften the Sumas basis.

The Future of Federal Environmental Regulation and Legislation

PacifiCorp faces a continuously-changing environment with regard to electricity plant emission 

regulations. Although the exact nature of these changes remains uncertain, they are expected to 

impact the cost of future resource alternatives and the cost of existing resources in PacifiCorp’s 

generation portfolio. PacifiCorp monitors these regulations to determine the potential impact on 

the company’s generating assets and participates in the rulemaking process by filing comments 

on various proposals and participating in scheduled hearings to provide the company’s 

assessment on such proposals.

Timing of Environmental Protection Agency (EPA) Regulation

The U.S. EPA has undertaken a multi-pronged approach to minimize air, land, and water-based 

environmental impacts. Many environmental regulations from the EPA are in various parallel 

stages of development. Even in cases where the EPA has established deadlines for proposal or 

finalization of a rule, these deadlines are frequently extended, making it difficult to determine 

not only the final outcome of a rule, but when it may ultimately impact the Company. 

Aside from potential greenhouse gas regulations, few of the environmental regulations under 

consideration are likely to materially impact the industry in isolation; in aggregate, however, 

they are expected to have a significant impact – especially on the coal-fueled generating units 

that supply approximately 42 percent of the nation’s electricity. As such, each of these 

regulations will have a significant impact on the utility industry and could affect environmental 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

33

control requirements, limit operations, change dispatch, and could ultimately determine the 

economic viability of PacifiCorp’s coal-fueled generation assets.

Federal Climate Change Legislation

PacifiCorp continues to evaluate the potential impact of climate change legislation at the federal 

level. The impact of a given legislative proposal varies significantly depending on its selection of 

key design criteria (i.e., level of emissions cap, rate of decline of the cap, the use of carbon 

offsets, allowance allocation methodology, the use of safety valves, and etc.) and macroeconomic assumptions (i.e., electricity load growth, fuel prices – especially natural gas, 

commodity prices, new technologies, etc.).

To date, no federal legislative climate change proposal has successfully been passed by both the 

U.S. House of Representatives and the U.S. Senate for consideration by the President. The two 

most prominent legislative proposals introduced for attempted passage through Congress have 

been the Waxman-Markey bill in 2009 and the Kerry-Lieberman bill in 2010; neither measure 

was able to accumulate enough support to pass.

In the 112th Congress, several bills were introduced designed to limit, remove, or suspend EPA’s 

asserted regulatory authority over greenhouse gases, none of which were successful. In the 

President’s State of the Union Address, the 113th Congress was challenged by the President to 

pursue a bipartisan, market-based solution to climate change, indicating if Congress did not act 

soon, the President would direct his Cabinet to implement executive action to reduce greenhouse 

gas emissions. On February 14, 2013, Senators Bernie Sanders and Barbara Boxer introduced 

climate legislation, the Climate Protection Act of 2013, which would, among other things, 

impose a carbon fee of 20 dollars per ton on coal, petroleum and natural gas producers beginning 

in 2014. 

EPA Regulatory Update – Greenhouse Gas Emissions

In conjunction with its greenhouse gas endangerment finding in 2009, the EPA has aggressively 

pursued the regulation of greenhouse gas (GHG) emissions. Key recent initiatives include the 

following:

New Source Review / Prevention of Significant Deterioration (NSR / PSD)

On May 13, 2010, the EPA issued a final rule that addresses GHG emissions from stationary 

sources under the Clean Air Act (CAA) permitting programs, known as the “tailoring” rule. This 

final rule sets thresholds for GHG emissions that define when permits under the New Source 

Review (NSR) / Prevention of Significant Deterioration (PSD) and Title V Operating Permit 

programs are required for new and existing industrial facilities. This final rule “tailors” the 

requirements of these CAA permitting programs to limit which facilities will be required to 

obtain PSD and Title V permits. The rule also establishes a schedule that will initially focus 

CAA permitting programs on the largest sources with the most CAA permitting experience. 

Finally, the rule expands to cover the largest sources of GHGs that may not have been previously 

covered by the CAA for other pollutants. 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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Guidance for Best Available Control Technology (BACT) 

On November 10, 2010, the EPA published a set of guidance documents for the tailoring rule to 

assist state permitting authorities and industry permitting applicants with the Clean Air Act PSD 

and Title V permitting for sources of GHGs. Among these publications was a general guidance 

document entitled “PSD and Title V Permitting Guidance for Greenhouse Gases,” which 

included a set of appendices with illustrative examples of Best Available Control Technology 

(BACT) determinations for different types of facilities, which are a requirement for PSD 

permitting. The EPA also provided white papers with technical information concerning available 

and emerging GHG emission control technologies and practices, without explicitly defining

BACT for a particular sector. In addition, the EPA has created a “Greenhouse Gas Emission 

Strategies Database,” which contains information on strategies and control technologies for 

GHG mitigation for two industrial sectors: electricity generation and cement production.

The guidance does not identify what constitutes BACT for specific types of facilities, and does 

not establish absolute limits on a permitting authority’s discretion when issuing a BACT 

determination for GHGs. Instead, the guidance emphasizes that the five-step top-down BACT 

process for criteria pollutants under the CAA generally remains the same for GHGs. While the 

guidance does not prescribe BACT in any area, it does state that GHG reduction options that 

improve energy efficiency will be BACT in many or most instances because they cost less than 

other environmental controls (and may even reduce costs) and because other add-on controls for 

GHGs are limited in number and are at differing stages of development or commercial 

availability. Utilities have remained very concerned about the NSR implications associated with 

the tailoring rule (the requirement to conduct BACT analysis for GHG emissions) because of 

great uncertainty as to what constitutes a triggering event and what constitutes BACT for GHG 

emissions.

New Source Performance Standards (NSPS) for Greenhouse Gases 

On December 23, 2010, in a settlement reached with several states and environmental groups in 

New York v. EPA, the EPA agreed to promulgate emissions standards covering GHGs from both 

new and existing electric generating units under Section 111 of the CAA by July 26, 2011 and 

issue final regulations by May 26, 2012.7 NSPS are established under the CAA for certain 

industrial sources of emissions determined to endanger public health and welfare and must be 

reviewed every eight years. While NSPS were intended to focus on new and modified sources 

and effectively establish the floor for determining what constitutes BACT, the emission

guidelines will apply to existing sources as well. In April 2012, the EPA proposed a NSPS for 

new fossil-fueled generating facilities that would limit emissions of carbon dioxide to 1,000 

pounds per megawatt hour (MWh). The proposal exempted simple cycle combustion turbines 

from meeting the standards. The public comment period closed in June 2012 and a final rule is 

expected by April 2013. While the EPA is also under a consent decree obligation to establish 

GHG NSPS for modified and existing sources, EPA has indicated it has not established a 

schedule for doing so. 

 

7 The deadlines for EPA to take proposed and final actions have since been extended. EPA also entered into a 

similar settlement the same day to address greenhouse gas emissions from refineries with proposed regulations by 

December 15, 2011 and final regulations by November 15, 2012.
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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The emissions guidelines issued by the EPA will be used by states to develop plans for reducing 

emissions and include targets based on demonstrated controls, emission reductions, costs and 

expected timeframes for installation and compliance, and may be less stringent than the 

requirements imposed on new sources. States must submit their plans to the EPA within nine 

months after the guidelines’ publication unless the EPA establishes a different schedule. States 

have the ability to apply less stringent standards or longer compliance schedules if they 

demonstrate that following the federal guidelines is unreasonably cost-prohibitive, physically 

impossible, or that there are other factors that reasonably preclude meeting the guidelines. States 

may also impose more stringent standards or shorter compliance schedules.

EPA Regulatory Update – Non-Greenhouse Gas Emissions

Several categories of EPA regulations for non-GHG emissions are discussed below:

Clean Air Act Criteria Pollutants – National Ambient Air Quality Standards

Currently, PacifiCorp’s generation units must comply with the federal CAA, which is 

implemented by the States subject to EPA approval and oversight. The CAA requires the EPA to 

set National Ambient Air Quality Standards (NAAQS) for certain pollutants considered harmful 

to public health and the environment. For a given NAAQS, the EPA and/or a state identifies 

various control measures that once implemented are meant to achieve an air quality standard for 

a certain pollutant, with each standard rigorously vetted by the scientific community, industry, 

public interest groups, and the general public. 

Particulate matter (PM), sulfur dioxide (SO2), ozone (O3), nitrogen dioxide (NO2), carbon 

monoxide (CO), and lead are often grouped together because under the CAA, each of these 

categories is linked to one or more National Ambient Air Quality Standards (NAAQS). These 

“criteria pollutants”, while undesirable, are not toxic in typical concentrations in the ambient air. 

Under the CAA, they are regulated differently from other types of emissions, such as hazardous 

air pollutants and greenhouse gases.

Within the past few years, the EPA established new standards for particulate matter, sulfur 

dioxide, and nitrogen dioxide. While the EPA had proposed to implement new ozone standards 

in 2011, it was determined that the standards should be deferred until the next regularly 

scheduled review in 2013. 

Clean Air Transport Rule

In July 2009, EPA proposed its Clean Air Transport Rule (Transport Rule), which would require 

new reductions in SO2 and nitrogen oxide (NOX) emissions from large stationary sources, 

including power plants, located in 31 states and the District of Columbia beginning in 2012. The 

Transport Rule was intended to help states attain NAAQS set in 1997 for ozone and fine 

particulate matter emissions. The rule replaced the Bush administration’s Clean Air Interstate 

Rule (CAIR), which was vacated in July 2008 and rescinded by a federal court because it failed 

to effectively address pollution from upwind states that is hampering efforts by downwind states 

to comply with ozone and PM NAAQS. While the rule was finalized as the Cross-State Air 

Pollution Rule (CSAPR) in July 2011, litigation in the D.C. Circuit Court of Appeals resulted in 

a stay on the implementation of the CSAPR in December 2011; Ultimately, in August 2012, the 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

36

D.C. Circuit Court of Appeals vacated the CSAPR in a 2-1 decision after it determined the rule 

exceeded the EPA’s statutory authority. The EPA sought a full review of the CSAPR ruling by 

the entire D.C. Circuit; however, in January 2013, the court denied the request. Until a 

replacement rule is adopted and implemented, the CAIR remains in place.

PacifiCorp does not own generating units in states identified by the CAIR or CSAPR and thus 

will not be directly impacted; however, the Company intends to monitor amendments to these 

rules closely in the event that the scope of a replacement rule extends the geographic scope of 

impacted states. 

Regional Haze 

EPA’s rule to address Regional Haze visibility concerns will drive additional NOx reductions 

particularly from facilities operating in the Western United States, including the states of Utah 

and Wyoming where PacifiCorp operates generating units and Arizona, where PacifiCorp owns a 

generating unit subject to the Regional Haze Rule. Unlike CAIR or CSAPR, which have no 

direct impact on PacifiCorp’s states with generation, the finalized Regional Haze regulatory 

activity will have an impact.

On June 15, 2005, EPA issued final amendments to its July 1999 Regional Haze rule. These 

amendments apply to the provisions of the Regional Haze rule that require emission controls 

known as Best Available Retrofit Technology (BART), for industrial facilities meeting certain 

regulatory criteria that with emissions that have the potential to impact visibility. These 

pollutants include PM2.5, NOX, SO2, certain volatile organic compounds, and ammonia. The 

2005 amendments included final guidelines, known as BART guidelines, for states to use in 

determining which facilities must install controls and the type of controls the facilities must use. 

States were given until December 2007 to develop their implementation plans, in which states 

were responsible for identifying the facilities that would have to reduce emissions under BART 

as well as establishing BART emissions limits for those facilities. 

The state of Utah issued a regional haze state implementation plan (SIP) requiring the installation 

of SO2, NOx and particulate matter (PM) controls on Hunter Units 1 and 2 and Huntington Units 

1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah Regional Haze SIP 

and disapproved the NOx and PM portions. Certain groups have appealed the EPA’s approval of 

the SO2 SIP. The date for appealing the disapproval of the NOx and PM portions of the SIP is 

March 25, 2013. In addition, and separate from the EPA’s approval process and related 

litigation, the Utah Division of Air Quality is undertaking an additional BART analysis for each 

of Hunter Units 1 and 2 and Huntington Units 1 and 2, which will be provided to the EPA as a 

supplement to the existing Utah SIP. It is unknown whether and how the Utah Division of Air 

Quality’s supplemental analysis will impact the EPA’s approval and disapproval of the existing 

SIP.

In Wyoming, the state issued two regional haze SIPs requiring the installation of SO2, NOx and 

PM controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA 

approved the SO2 SIP in December 2012, but initially proposed to disapprove portions of the 

NOx and PM SIP and instead issue a federal implementation plan (FIP). The EPA proposed to 

approve the installation of selective catalytic reduction (SCR) equipment and a baghouse at 

Naughton Unit 3 by December 31, 2014; to approve the installation of SCR equipment at Jim 

Bridger Unit 3 by December 31, 2015; and to approve the installation of SCR equipment at Jim 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

37

Bridger Unit 4 by December 31, 2016. The EPA proposed to disapprove the NOx and PM SIP for 

Jim Bridger Units 1 and 2 and instead accelerate the installation of SCR equipment to 2017 from 

2021 and 2022, but agreed to accept comment on maintaining the original schedule as the state 

proposed. In addition, the EPA proposed to reject the SIP for the Wyodak facility and Dave 

Johnston Unit 3 and require the installation of selective non-catalytic reduction (SNCR) 

equipment within five years, as well as require the installation of low-NOx burners and overfire 

air systems at Dave Johnston Units 1 and 2. Since the EPA’s initial proposal, which was to have 

been final in October 2012 and was extended to December 2012, the EPA has withdrawn its 

proposed action on the SIP and its proposed FIP and has indicated its intent to re-propose action 

on the Wyoming NOx and PM SIP by March 29, 2013, and take final action by September 27, 

2013. In the meantime, certain groups have appealed the EPA’s approval of the Wyoming SO2

SIP which, consistent with the Utah SO2 SIP, required emission reductions of SO2 to be enforced 

through a three-state milestone and backstop trading program. 

In Arizona, the state issued a Regional Haze SIP requiring, among other things, the installation 

of SO2, NOx and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by 

Arizona Public Service. The EPA approved in part, and disapproved in part, the Arizona SIP and 

issued a FIP for the disapproved portions. PacifiCorp filed an appeal in the Ninth Circuit Court 

of Appeals regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of 

Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it 

relates to their interests. 

Other cases are pending before the Tenth Circuit Court of Appeals with regard to similar appeals 

of FIPs issued by the EPA in New Mexico and Oklahoma.

Mercury and Hazardous Air Pollutants 

In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to permanently limit and 

reduce mercury emissions from coal-fired power plants under a market-based cap-and-trade 

program. However, the CAMR was vacated in February 2008, with the court finding the mercury 

rules inconsistent with the stipulations of Section 112 of the CAA.

The vacated CAMR was replaced by EPA with the more extensive Mercury and Air Toxics 

Standards (MATS) with an effective date of April 16, 2012. The MATS rule requires that new 

and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other 

non-mercury hazardous air pollutants. Existing sources are required to comply with the new 

standards by April 16, 2015. Individual sources may be granted up to one additional year, at the 

discretion of the Title V permitting authority, to complete installation of controls or for 

transmission system reliability reasons. While the final MATS requirements continue to be 

reviewed by PacifiCorp, the Company believes its emission reduction projects completed to date 

or currently permitted or planned for installation, including the scrubbers, baghouses and 

electrostatic precipitators required under other EPA requirements, are consistent with achieving 

the MATS requirements and will support PacifiCorp’s ability to comply with the final standards 

for acid gases and non-mercury metallic hazardous air pollutants. PacifiCorp will be required to 

take additional actions to reduce mercury emissions through the installation of controls or use of 

sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the 

standards. 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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PacifiCorp currently anticipates that retiring the Carbon plant in early 2015 will be least-cost 

alternative to comply with the MATS and other environmental regulations. PacifiCorp continues 

to assess other issues, such as potential transmission system impacts, that could impact its 

ultimate decision regarding the Carbon plant, including the timing of retirement and 

decommissioning.

Coal Combustion Residuals 

Coal Combustion Residuals (CCRs), including coal ash, are the byproducts from the combustion 

of coal in power plants. 

CCRs are currently considered exempt wastes under an amendment to the Resource 

Conservation and Recovery Act (RCRA); however, EPA proposed in 2010 to regulate CCRs for 

the first time. EPA is considering two possible options for the management of CCRs. Both 

options fall under the RCRA. Under the first option, EPA would list these residual materials as 

special wastes subject to regulation under Subtitle C of RCRA with requirements from the point 

of generation to disposition including the closure of disposal units. Under the second option, 

EPA would regulate coal combustion residuals as nonhazardous waste under Subtitle D of 

RCRA and establish minimum nationwide standards for the disposal of coal combustion 

residuals. Under either option for regulation, surface impoundments utilized for coal combustion 

byproducts would have to be closed unless they could meet more stringent regulatory 

requirements. PacifiCorp operates 16 surface impoundments and six landfills that contain coal 

combustion byproducts. 

While the public comment period on EPA’s proposal to regulate coal combustion byproducts 

closed in November 2010, the EPA has not indicated when the rule will be finalized, and the 

substance of the final rule is not known. In briefs filed in litigation pending in the D.C. Circuit 

Court of Appeals to force the EPA to meet a deadline to issue final coal combustion byproduct 

rules, the EPA indicated it needs until at least 2014 to review comments, formulate a risk 

assessment and coordinate the rule with the effluent limit guidelines discussed herein.

Water Quality Standards

Cooling Water Intake Structures

The federal Water Pollution Control Act (“Clean Water Act”) establishes the framework for 

maintaining and improving water quality in the United States through a program that regulates, 

among things, discharges to and withdrawals from waterways. The Clean Water Act requires that 

cooling water intake structures reflect the “best technology available for minimizing adverse 

environmental impact” to aquatic organisms. In July 2004, the EPA established significant new 

technology-based performance standards for existing electricity generating facilities that take in 

more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse 

environmental impacts of cooling water intake structures by reducing the number of aquatic 

organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in 

January 2007, the Court of Appeal for the Second Circuit remanded almost all aspects of the rule 

to the EPA without addressing whether companies with cooling water intake structures were 

required to comply with these requirements. On appeal from the Second Circuit, in April 2009, 

the U.S. Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in 

setting the national performance standards regarding best technology available for minimizing 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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adverse environmental impact at cooling water intake structures and in providing for cost-benefit 

variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The 

Supreme Court remanded the case back to the Second Circuit Court of Appeals to conduct 

further proceedings consistent with its opinion.

In March 2011, the EPA released a proposed rule under §316(b) of the Clean Water Act to 

regulate cooling water intakes at existing facilities. The proposed rule establishes requirement for 

electric generating facilities that withdraw more than two million gallons per day, based on total 

design intake capacity, of water from waters of the U.S. and use at least 25 percent of the 

withdrawn water exclusively for cooling purposes. PacifiCorp’s Dave Johnston generating 

facility withdraws more than two million gallons per day of water from waters of the U.S. Jim 

Bridger, Naughton, Gadsby, Hunter, Carbon and Huntington generating facilities currently 

utilize closed cycle cooling towers but withdraw more than two million gallons of water per day. 

The proposed rule includes impingement (i.e., when fish and other aquatic organisms are trapped 

against screens when water is drawn into a facility’s cooling system) mortality standards to be 

met through average impingement mortality or intake velocity design criteria and entrainment 

(i.e., when organisms are drawn into the facility) standards to be determined on a case-by-case 

basis. The standards are required to be met as soon as possible after the effective date of the final 

rule, but no later than eight years thereafter. While the rule was required to be finalized by the 

EPA by July 2012, the deadline for finalizing the rule was extended to June 2013. Assuming the

final rule is issued by June 2013, PacifiCorp’s generating facilities impacted by the final rule will 

be required to complete impingement and entrainment studies in 2014.

Effluent Limit Guidelines

EPA first issued effluent guidelines for the Steam Electric Power Generating Point Source 

Category (i.e., the Steam Electric effluent guidelines) in 1974 with subsequent revisions in 1977 

and 1982. The EPA is currently under a deadline of April 19, 2013 to propose revised effluent 

limit guidelines and sent the proposed rulemaking package to the Office of Management and 

Budget for interagency review in January 2013. The EPA is required, under the terms of a 

stipulated extension to a consent decree, to finalize the rule by May 2014. While the EPA has 

indicated that the growing use of flue-gas desulfurization systems has increased the amount of 

toxic metals discharged from power plants, until the required technology-based effluent 

limitations and standards are proposed and finalized, PacifiCorp cannot determine the potential 

impact of the rules on its facilities. In addition, the effluent limit guidelines will apply to gasfired generation.

State Climate Change Regulation

While national greenhouse gas legislation has yet to be successfully adopted, state initiatives

continue with the active development of climate change regulations that will impact PacifiCorp.

California

An executive order signed by California’s governor in June 2005 would reduce greenhouse gas 

emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 

levels by 2050. In 2006, the California Legislature passed and Governor Schwarzenegger signed 

Assembly Bill 32, the Global Warming Solutions Act of 2006, which set the 2020 greenhouse 

gas emissions reduction goal into law. It directed the California Air Resources Board to begin 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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developing discrete early actions to reduce greenhouse gases while also preparing a scoping plan 

to identify how best to reach the 2020 limit. 

Pursuant to the authority of the Global Warming Solutions Act, in October 2011, the California 

Air Resources Board adopted a greenhouse gas cap-and-trade program with an effective date of 

January 1, 2012; compliance obligations were imposed on regulated entities beginning in 2013. 

The first auction of greenhouse gas allowances was held in California in November 2012 and the 

second auction in February 2013. PacifiCorp is required to sell, through the auction process, its 

directly allocated allowances, and purchase the required amount of allowances necessary to meet 

its compliance obligations. 

Oregon and Washington

In 2007, the Oregon Legislature passed HB 3543 Global Warming Actions which establishes 

greenhouse gas reduction goals for the state that (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 2009, the Legislature passed SB 101 which requires the Public Utility Commission of Oregon 

(OPUC) to report to the Legislature before November 1 of each even-numbered year on the 

estimated rate impacts for Oregon’s regulated electric and natural gas companies associated with 

meeting the greenhouse gas reduction goals of 10 percent below 1990 levels by 2020 and 15 

percent below 2005 levels by 2020. The OPUC submitted its most recent report November 1, 

2012.

During the 2013 session, the Oregon Legislature is considering a number of bills relating to the 

implementation of a carbon tax; it is unknown whether those bills will be passed. In addition, 

Oregon is considering the viability of establishing a voluntary greenhouse gas emission program 

that would allow utilities to consider alternative forms of regulation designed to lower 

greenhouse gas emissions.

In 2008, the Washington State Legislature approved the Climate Change Framework E2SHB 

2815, which establishes state greenhouse gas emissions reduction limits. Washington’s emission 

limits are 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. In the 2013 session, the 

Washington Legislature is considering a bill that would develop recommendations to achieve the 

state’s greenhouse gas emission limits.

Greenhouse Gas Emission Performance Standards

California, Oregon and Washington have all adopted greenhouse gas emission performance 

standards applicable to all electricity generated within the state or delivered from outside the 

state that is no higher than the greenhouse gas emission levels of a state-of-the-art combinedcycle natural gas generation facility. The standards are currently set at 1,100 pounds of carbon 

dioxide equivalent per MWh, which is defined as a metric measure used to compare the 

emissions from various greenhouse gases based upon their global warming potential. The 

Washington Department of Commerce is pursuing a rulemaking process to lower the emissions 

performance standard; while the rulemaking is not yet final, the Department of Commerce most 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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recently proposed an emission performance standard of 970 pounds of carbon dioxide per MWh. 

Efforts are also underway in Oregon to effectuate changes to the state’s emission performance 

standard to broaden its applicability. 

Renewable Portfolio Standards

A renewable portfolio standard (RPS) requires each retail seller of electricity to include in its 

resource portfolio a certain amount of electricity from renewable energy resources, such as wind, 

geothermal and solar energy. The retailer can satisfy this obligation by using renewable energy 

from its own facility, purchasing renewable energy from someone else's facility, using renewable 

energy credits (RECs) which certify renewable energy has been created, or a combination of all 

of these.

RPS policies are currently implemented at the state level and vary considerably in their 

requirements with respect to timeframe, resource eligibility, applicability of existing plants and 

contracts, arrangements for enforcement and penalties, and whether they allow REC trading. By 

the end of 2012, twenty-nine states, the District of Columbia and two territories had adopted a 

mandatory RPS, eight states and two territories had adopted RPS goals.8

Within PacifiCorp’s service territory, California, Oregon, and Washington have adopted a 

mandatory RPS and Utah has adopted an RPS goal. Each of these states’ legislation and 

requirements are summarized in Table 3.1, with additional discussion below.

Table 3.1 – State RPS Requirements

 

8 Database of State Incentives for Renewables & Efficiency (DSIRE) CA OR WA UT

Legislation • Senate Bill 1078 (2002)

• Assembly Bill 200 

(2005)

• Senate Bill 107 (2006)

• Senate Bill 2 First 

Extraordinary Session 

(2011)

• Senate Bill 838, Oregon 

Renewable Energy Act 

(2007)

• House Bill 3039 (2009)

• Initiative Measure 

No. 937 (2006)

• Senate Bill 202 (2008)

Requirement

or Goal

• 20% by 2010

• Average of 20% through 

2013

• 25% by December 31, 

2016

• 33% by December 31, 

2020 and beyond

• Based on the retail load 

for that compliance 

period

• At least 5% of load by 

December 31, 2014

• At least 15% by 

December 31, 2019

• At least 20% by 

December 31, 2024

• At least 25% by 

December 31, 2025 

and thereafter

• Based on the retail 

load for that year

• Invest in 20 MW solar 

by January 1, 2020 --

PGE, PacifiCorp and 

Idaho Power combined

• At least 3% of load 

by January 1, 2012

• At least 9% by 

January 1, 2016

• At least 15% by 

January 1, 2020

• Annual targets are 

based on the 

average of the 

utility’s load for the 

previous two years

• Goal of 20% by 2025 

(must be cost 

effective)

• Annual targets are 

based on the adjusted 

retail sales for the 

calendar year 36 

month prior to the 

target year 

• Adjustments for 

generated or 

purchased from 

qualifying zero carbon 

emissions and carbon 

capture sequestration 

and DSM
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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California

California originally established its RPS program with passage of Senate Bill 1078 in 2002. 

There have been several bills that have since been passed into law to amend the program. In the 

2011 1st Extraordinary Special Session, the California Legislature passed Senate Bill 2

9

(SB 2 

(1x)) to increase California’s RPS to 33 percent by 2020. SB 2 (1x) also expanded the RPS 

requirements to all retail sellers of electricity and publicly owned utilities, and established the 

following targets for renewable procurement based on retail load:

Extends the current 2010 mandate of procuring 20 percent of electricity from renewable 

resources out to December 31, 2013;

Requires 25 percent of electricity to come from renewable resources by December 31, 

2016; and,

Requires 33 percent of electricity to come from renewable resources by December 31, 

2020, and each year thereafter.

Qualifying renewable resources include solar thermal electric, photovoltaic, landfill gas, wind, 

biomass, geothermal, municipal solid waste, energy storage, anaerobic digestion, small 

hydroelectric, tidal energy, wave energy, ocean thermal, biodiesel, and fuel cells using renewable 

fuels. The RECs must be certified as eligible for the California RPS by the California Energy 

Commission and tracked in the Western Renewable Energy Generation Information System 

(WREGIS).

In addition to increasing the target from 20 percent in 2010 to 33 percent in 2020 and each year 

thereafter, SB 2 (1x) also created multi-year compliance periods. The California Public Utilities 

Commission approved the methodology for calculating the multi-year compliance periods and 

years thereafter; this is provided below in Table 3.2.

Table 3.2 – California Compliance Period Requirements

California RPS Compliance Period Procurement Quantity Requirement Calculation

Compliance Period 1: 2011-2013 20% * 2011 Retail Sales + 20% * 2012 Retail 

Sales + 20% * 2013 Retail Sales

Compliance Period 2: 2014-2016 21.7% * 2014 Retail Sales + 23.3% * 2015 

Retail Sales + 25% * 2016 Retail Sales

Compliance Period 3: 2017-2020 27% * 2017 Retail Sales + 29% * 2018 Retail 

Sales + 31% * 2019 Retail Sales + 33% * 2020 

Retail Sales

2021 and Beyond 33% * Annual Retail Sales

SB 2 (1x) also established new “portfolio content categories” for RPS procurement, which 

delineated the type of renewable product that may be used for compliance and also set minimum 

 

9

http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-0050/sbx1_2_bill_20110412_chaptered.pdf
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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and maximum limits on certain procurement content categories that can be used for compliance. 

The portfolio content categories pursuant to SB 2 (1x) are described below:

Portfolio Content Category 1 includes energy and RECs that meet either of the following criteria 

(a) have a first point of interconnection with a California balancing authority, have a first point 

of interconnection with distribution facilities used to serve end users within a California 

balancing authority area, or are scheduled from the eligible renewable energy resource into a 

California balancing authority without substituting electricity from another source. The use of 

another source to provide real-time ancillary services required to maintain an hourly or subhourly import schedule into a California balancing authority shall be permitted, but only the 

fraction of the schedule actually generated by the eligible renewable energy resource shall count 

toward this portfolio content category; or (b) have an agreement to dynamically transfer 

electricity to a California balancing authority.

Portfolio Content Category 2 includes firmed and shaped eligible renewable energy resource 

electricity products providing incremental electricity and scheduled into a California balancing 

authority.

Portfolio Content Category 3 includes eligible renewable energy resource electricity products, or 

any fraction of the electricity, including unbundled10 renewable energy credits that do not qualify 

under the criteria of Portfolio Content Category 1 or Portfolio Content Category 2.

Additionally, the California Public Utilities Commission established the balanced portfolio 

requirements for contracts executed after June 1, 2010. The balanced portfolio requirements set 

minimum and maximum levels for the Procurement Content Category products that may be used

in each compliance period. 

Table 3.3 – California Balanced Portfolio Requirements

California RPS Compliance Period Balanced Portfolio Requirement

Compliance Period 1: 2011-2013 Category 1 – Minimum of 50% of Requirement

Category 3 – Maximum of 25% of Requirement

Compliance Period 2: 2014-2016 Category 1 – Minimum of 65% of Requirement

Category 3 – Maximum of 15% of Requirement

Compliance Period 3: 2017-2020 Category 1 – Minimum of 75% of Requirement

Category 3 – Maximum of 10% of Requirement

In December 2011, the California Public Utilities Commission adopted a decision confirming 

that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits 

within the three portfolio content categories. PacifiCorp is required to file annual compliance 

reports with the California Public Utilities Commission and annual procurement reports with the 

California Energy Commission. 

 

10 A REC can be sold either "bundled" with the underlying energy or "unbundled", as a separate commodity from 

the energy itself, into a separate REC trading market.
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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The California Public Utilities Commission is in the process of an extensive rulemaking to 

implement the remaining requirements under SB 2 (1x).

The full California RPS statute is listed under Public Utilities Code Section 399.11-399.32. 

Additional information on the California RPS can be found on the California Public Utilities 

Commission and California Energy Commission websites.

Oregon

Oregon established the Oregon RPS with passage of Senate Bill 838 in 2007. The law, called the 

Oregon Renewable Energy Act11 was adopted in June 2007 and provides a comprehensive 

renewable energy policy for Oregon. Subject to certain exemptions and cost limitations 

established in the Oregon Renewable Energy Act, PacifiCorp and other qualifying electric 

utilities must meet minimum qualifying electricity requirements for electricity 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 

Electricity Coordinating Council geographic area, and a limited amount of unbundled renewable 

energy credits can be used toward the annual compliance obligation. 

Eligible renewable resources include electricity generated from wind, solar photovoltaic, solar 

thermal, wave, tidal, ocean thermal, geothermal, certain types of biomass and biogas, municipal 

solid waste, and hydrogen power stations using anhydrous ammonia. Electricity generated by a 

hydroelectric facility is eligible, if the facility is not located in any federally protected areas 

designated by the Pacific Northwest Electric Power and Conservation Planning Council as of 

July 23, 1999, or any area protected under the federal Wild and Scenic Rivers Act, P.L. 90-542, 

or the Oregon Scenic Waterways Act, ORS 390.805 to 390.925; or if the electricity is 

attributable to efficiency upgrades made to the facility on or after January 1, 1995, and up to 50 

average megawatts of electricity per year generated by a certified low-impact hydroelectric 

facility owned by an electric utility and up to 40 average megawatts of electricity per year 

generated by certified low-impact hydroelectric facilities not owned by electric utilities.

Utilities can bank RECs from qualifying resources beginning January 1, 2007 for the purpose of 

carrying them forward for future compliance. The RECs must be certified as eligible for the 

Oregon RPS by the Oregon Department of Energy and tracked in WREGIS.

In 2009, Oregon passed House Bill 3039, also called the Oregon Solar Initiative, requiring that 

on or before January 1, 2020, the total solar photovoltaic generating nameplate capacity must be 

at least 20 megawatts from all electric companies in the state. Qualifying solar photovoltaic 

systems must be at least 500 kilowatts in capacity with no single project greater than five 

megawatts of alternating current. Any qualifying solar photovoltaic systems that are online 

before January 1, 2016 will be credited with two megawatt-hours for every one megawatt-hour 

generated. The Oregon Public Utility Commission determined that PacifiCorp’s share of the 

Oregon Solar Initiative is 8.7 megawatts. 

 

11 http://www.leg.state.or.us/07reg/measpdf/sb0800.dir/sb0838.en.pdf
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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PacifiCorp files an annual RPS compliance report by June 1 of every year and in every odd year 

by January 1 PacifiCorp files a renewable implementation plan. PacifiCorp’s compliance reports 

and implementation plans are made available on PacifiCorp’s website12.

The full Oregon RPS statute is listed in Oregon Revised Statutes (ORS) Chapter 469A and the 

solar capacity standard is listed in ORS Chapter 757. The Public Utility Commission of Oregon 

rules are included within Oregon Administrative Rules (OAR) Chapter 860 Division 083 for the 

RPS and OAR Chapter 860 Division 084 for the solar photovoltaic program. The Oregon 

Department of Energy rules are under OAR Chapter 330 Division 160. 

Utah

In March 2008, Utah’s governor signed Utah Senate Bill 20213, “Energy Resource and Carbon 

Emission Reduction Initiative;” legislation. Among other things, this law 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 electric sales will be adjusted by 

deducting the amount of generation from sources that produce zero or reduced carbon emissions, 

and for sales avoided as a result of energy efficiency and demand-side management programs. 

Qualifying renewable energy sources can be located anywhere in the Western Electricity 

Coordinating Council areas, and unbundled renewable energy credits can be used for up to 20 

percent of the annual qualifying electricity target.

Eligible renewable resources include electricity generation or a generation facility from a facility 

or upgrade that becomes operational on or after January 1, 1995 that derives its energy from 

wind, solar photovoltaic, solar thermal electric, wave, tidal or ocean thermal, certain types of 

biomass and biomass products, landfill gas or municipal solid waste, geothermal, waste gas and 

waste heat capture or recovery, and efficiency upgrades to hydroelectric facilities if the upgrade 

occurred after January 1, 1995. Up to 50 average megawatts from a certified low impact hydro 

facility and in state geothermal and hydro generation without regard to operational online date 

may also be used toward the target. To assist solar development in Utah, solar facilities located 

in Utah receive credit for 2.4 kilowatt-hours of qualifying electricity for each kWh of generation. 

Under the Carbon Reduction Initiative, PacifiCorp is required to file a progress report by January 

1 of each of the years 2010, 2015, 2020 and 2024. PacifiCorp filed a progress report on 

December 31, 2009. The Utah Division of Public Utilities is required to provide the Legislature 

with a summary report on the progress made by these electrical corporations by January 1 of the 

years 2011, 2016, 2021, 2025. In the Utah Division of Public Utilities’ report to the Legislature, 

it was stated that, “Given PacifiCorp’s projections of its loads and qualifying electricity for 2025, 

PacifiCorp is well positioned to meet a target of 20 percent renewable energy by 2025.”

PacifiCorp’s next Carbon Reduction Progress Report is expected to be filed by January 1, 2015.

In 2027, the legislation requires a commission report to the Utah Legislature which may contain 

any recommendation for penalties or other action for failure to meet the 2025 target. The 

legislation requires that any recommendation for a penalty must provide that the penalty funds be 

used for demand-side management programs for the customers of the utility paying the penalty.

 

12 www.pacificpower.net/ORrps

13 http://le.utah.gov/~2008/bills/sbillenr/sb0202.pdf
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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The Energy Resource and Carbon Emission Reduction Initiative is codified in Utah Code Title 

54 Chapter 17.

Washington

In November 2006, Washington voters approved Initiative 937,14 a ballot measure establishing 

the Energy Independence Act, which is an RPS and energy efficiency requirement applied to

qualifying electric utilities, including PacifiCorp. The law requires that qualifying utilities 

procure at least three percent of retail sales from eligible renewable resources or RECs by 

January 1, 2012 through 2015, nine percent of retail sales by January 1, 2016 through 2019 and 

15 percent of retail sales by January 1, 2020 and every year thereafter. 

Eligible renewable resources include electricity produced from water, wind, solar energy, 

geothermal energy, landfill gas, wave, ocean, or tidal power, gas from sewage treatment 

facilities, biodiesel fuel with limitation, and biomass energy based on organic byproducts of the 

pulp and wood manufacturing process, animal waste, solid organic fuels from wood, forest, or 

field residues, or dedicated energy crops. Qualifying renewable energy sources must be located 

within the Pacific Northwest or delivered into Washington on a real-time basis without shaping, 

storage, or integration services. Moreover, the only hydroelectric resource eligible for 

compliance is electricity associated with efficiency upgrades to hydroelectric facilities. Utilities 

may use eligible renewable resources, RECs or a combination of both to meet the RPS 

requirement.

PacifiCorp is required to file an annual RPS compliance report demonstrating compliance with 

the Energy Independence Act by June 1 of every year with the Washington Utilities and 

Transportation Commission. PacifiCorp’s compliance reports are made available on PacifiCorp’s 

website15.

The Washington Utilities and Transportation Commission adopted final rules to implement the 

initiative; the rules are listed in the Revised Code of Washington (RCW) 19.285 and the 

Washington Administrative Code (WAC) 480-109.

Federal Renewable Portfolio Standard

The United States Congress has considered a federal RPS or a national clean energy standard in 

the past several years. This type of national policy could increase investment in a broad range of 

renewable energy resources and advanced technologies. Proponents of a national clean energy 

standard argue that it would provide a range of benefits including fostering the creation of clean 

energy industries, creating clean energy jobs, enabling the advancement of new technologies, 

diversifying energy portfolio, and providing positive public health and environmental impacts. If 

a national clean energy standard is considered, several key challenges exist including but not 

limited to how a national clean energy standard can be harmonized with existing state RPS 

programs, balancing the benefits of the policy with the costs of such policy. However, Congress 

has not yet adopted a national clean energy standard. 

 

14 http://www.secstate.wa.gov/elections/initiatives/text/I937.pdf

15 www.pacificpower.net/WArps
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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Hydroelectric Relicensing

The issues involved in relicensing hydroelectric facilities are multifaceted. They involve 

numerous federal and state environmental laws and regulations, and participation of numerous 

stakeholders including agencies, Indian tribes, non-governmental organizations, and local 

communities and governments.

The value to relicensing hydroelectric facilities is continued availability of hydroelectric 

generation. 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 

intermittent renewable resources such as wind. In addition to operational flexibility, 

hydroelectric generation does not have the emissions concerns of thermal generation. With the 

exception of the Klamath River and Wallowa Falls hydroelectric projects, all of PacifiCorp’s 

applicable generating facilities now operate under contemporary licenses from the Federal 

Energy Regulatory Commission (FERC). The 169 MW Klamath River hydroelectric project 

continues to operate under its existing license while PacifiCorp works with parties to implement 

a 2010 settlement agreement that would result in removal of the project. The assumed date of 

the removal in the IRP is January 1, 2021. The 1.1 MW Wallowa Falls project is currently 

undergoing the FERC relicensing process. 

FERC hydroelectric relicensing is administered within a very complex regulatory framework and 

is an extremely political and often controversial public process. The process itself requires that 

the project’s impacts on the surrounding environment and natural resources, such as fish and 

wildlife, be scientifically evaluated, followed by development of proposals and alternatives to 

mitigate for those impacts. Stakeholder consultation is conducted throughout the process. If 

resolution of issues cannot be reached in this process, litigation often ensues which can be costly 

and time-consuming. The usual alternative to relicensing is decommissioning. Both choices, 

however, can involve significant costs.

The FERC has sole jurisdiction under the Federal Power Act to issue new operating licenses for 

non-federal hydroelectric projects on navigable waterways, federal lands, and under other certain 

criteria. The FERC must find that the project is in the broad public interest. This requires 

weighing, with “equal consideration,” the impacts of the project on fish and wildlife, cultural 

resources, recreation, land-use, and aesthetics against the project’s energy production benefits. 

However, because some of the responsible state and federal agencies have the ability to place 

mandatory conditions in the license, the FERC is not always in a position to balance the energy 

and environmental equation. For example, the National Oceanic and Atmospheric 

Administration Fisheries agency and the U.S. Fish and Wildlife Service have the authority within 

the relicensing process to require installation of fish passage facilities (fish ladders and screens) 

at projects. This is often the largest single capital investment that will be considered in 

relicensing and can significantly impact project economics. Also, because a myriad of other state 

and federal laws come into play in relicensing, most notably the Endangered Species Act and the 

Clean Water Act, agencies’ interests may compete or conflict with each other leading to 

potentially contrary, or additive, licensing requirements. PacifiCorp has generally taken a 

proactive approach towards achieving the best possible relicensing outcome for its customers by 

engaging in settlement negotiations with stakeholders, the results of which are submitted to the 

FERC for incorporation into a new license. The FERC welcomes settlement agreements into the 

relicensing process, and with associated recent license orders, has generally accepted agreement 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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terms. Recently, the FERC has promoted that project owners seeking a new license do so 

through the Integrated Licensing Process (ILP). The ILP involves the FERC at early stages of the 

relicensing and seeks to resolve stakeholder issues in a timely manner.

Potential Impact

Relicensing hydroelectric facilities involves significant process costs. The FERC relicensing 

process takes a minimum of five years and may take longer, depending on the characteristics of 

the project, the number of stakeholders, and issues that arise during the process. As of December 

31, 2012, PacifiCorp had incurred approximately $49 million in costs for license implementation 

and ongoing hydroelectric relicensing, which are included in Construction work-in-progress on 

PacifiCorp's Consolidated Balance Sheet. As current or upcoming relicensing and/or settlement 

efforts continue for the Klamath River, Wallowa Falls, and other hydroelectric projects, 

additional process costs are being or will be incurred that will need to be recovered from 

customers. Also, new requirements from contemporary FERC orders and expected requirements 

from ongoing or new relicensing processes could amount to over $978 million over the 30 to 50 

year terms of these orders. Such costs include capital investments, and related operations and 

maintenance costs 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 aquatic resources resulting in lost generation. 

The majority of these relicensing and settlement costs relate to PacifiCorp’s three largest 

hydroelectric projects: Lewis River, Klamath River and North Umpqua.

Treatment in the IRP

The known or expected operational impacts related to FERC orders and settlement commitments 

are incorporated in the projection of existing hydroelectric resources discussed in Chapter 5.

PacifiCorp’s Approach to Hydroelectric Relicensing

PacifiCorp continues to manage this process by pursuing interest-based resolutions and/or 

negotiated settlements as part of relicensing. PacifiCorp believes this proactive approach, which 

involves meeting agency and others’ interests through creative solutions is the best way to 

achieve environmental improvement while managing costs. PacifiCorp also has reached 

agreements with licensing stakeholders to decommission projects where that has been the most 

cost-effective outcome for customers. 

Rate Design Information

Current rate designs in Utah have evolved over time based on orders and direction from the 

Public Service Commission in Utah and settlement agreements between parties during general 

rate cases. Most recently, current rates and rate design changes were adopted in Docket No. 11-

035-200. Generally, the goals for rate design are to reflect the costs to serve customers and to 

provide price signals to encourage economically efficient usage. This is consistent with resource 

planning goals that balance consideration of costs, risk, and long-run public policy goals. The 

Company currently has a number of rate design elements that take into consideration these 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

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objectives, in particular, rate designs that reflect cost differences for energy or demand during 

different time periods and that support the goals of acquiring cost-effective energy efficiency.

Residential Rate Design – Residential rates in Utah are comprised of a customer charge and 

energy charges. The customer charge is a monthly charge that provides limited recovery of 

customer-related costs incurred to serve customers regardless of usage. All other remaining costs 

are recovered through volumetric-based energy charges. Energy charges for residential 

customers are designed with an inclining tier rate structure such that high usage during a billing 

month is charged a higher rate than low usage. In this way, customers face a price signal to 

encourage reduced consumption. Additionally, energy charges are differentiated by season with 

higher rates in the summer when the costs to serve are higher. Residential customers also have 

an option for time-of-day rates. Time-of-day rates have a surcharge for usage during the on-peak 

periods and a credit for usage during the off-peak periods. This rate structure provides an 

additional price signal to encourage customers to use less energy during the daily on-peak 

periods when energy costs are higher. Currently, less than one percent of customers have opted 

to participate in the time-of-day rate option. 

Changes in residential rate design that might facilitate IRP objectives include deploying a 

mandatory time-of-day rate design that reflects the higher costs of on-peak usage to all 

residential customers rather than a self-selected few. Time-of-day rates are discussed in more 

detail in Chapter 6 (Resource Options). Any changes in residential rate design to support energy 

efficiency or time-differentiated usage should be balanced with the recovery of fixed costs in 

order to ensure the price signals are economically efficient. 

Commercial and Industrial Rate Design – Commercial and industrial rates in Utah are 

comprised of customer charges, facilities charges, power charges (for usage over 15 kW) and 

energy charges. As with residential rates, customer charges and facilities charges are intended to 

recover costs that don’t vary with usage. Power charges are applied to a customer’s monthly 

demand on a kW basis and are intended to recover the costs associated with demand or capacity 

needs. Energy charges are applied to the customer’s metered usage on a kWh basis. All 

commercial and industrial rates employ seasonal variations in power and/or energy charges with 

higher rates in the summer months to reflect the higher costs to serve during the summer peak 

period. Additionally, for customers with load 1,000 kW or more, rates are further differentiated 

by on-peak and off-peak periods for both power and energy charges. For commercial and 

industrial customers with load less than 1,000 kW, the Company offers two optional time-of-day 

rates—one that differentiates energy rates for on- and off-peak usage and one that differentiates 

power charges by on- and off-peak usage. Currently, approximately 15 percent of the eligible 

customers are on the energy time-of-day option and less than one percent are on the power timeof-day option. 

Changes in rate design that might facilitate IRP objectives include evaluating current rates in 

light of the growing interest in self generation by commercial and industrial customers, which is 

captured in the load forecast in IRP. Ensuring that partial requirements rates for customers with 

self generation that better reflect the costs of providing backup service to these customers is 

expected to be addressed in the Company’s next general rate case. Partial requirements rate 

design is important so that customers face a true economic price as they make decisions 

regarding self generation.
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

50

Irrigation Rate Design – Irrigation rates in Utah are comprised of an annual customer charge, a 

monthly customer charge, seasonal power charge and energy charges. The annual and monthly 

customer charges provide some recovery of customer-related costs incurred to serve customers 

regardless of usage. All other remaining costs are recovered through a seasonal power charge 

and energy charges. Power charge is for the irrigation season only and is designed to recover 

demand-related costs and to encourage irrigation customers to control and reduce their power 

consumption. Energy charges for irrigation customers are designed with two options. One is a 

time-of-day program with higher rates for on-peak consumption than for off-peak consumption. 

In this way, customers face a price signal to encourage reduced consumption during the on-peak 

period when energy costs are higher. Irrigation customers also have an option to participate in a 

third party operated Irrigation Load Control Program. Customers are offered a financial incentive 

to participate in the program and give the Company the right to interrupt the service to the 

participating customers when energy costs are higher. 

Energy Imbalance Market

PacifiCorp signed a memorandum of understanding with the California Independent System 

Operator Corporation (ISO) February 12, 2013 to outline terms for the implementation of an 

energy imbalance market (EIM) by October 2014. A benefit study was completed by Energy 

and Environmental Economics which shows a range of benefits to PacifiCorp and the ISO in 

2017 from $21.4m to $128.7m per year. The Company’s cost payable to the CAISO is a $2.1m 

one-time start-up and $1.3m per year on-going, in addition to internal Company costs for items 

such as metering, software and additional staffing. 

An energy imbalance market is a five-minute market administered by a single market operator 

using an economic dispatch model to issue instructions to generating resources to meet the load 

for the entire footprint of the EIM. Market participants voluntarily bid their resources into the 

EIM. The market operator, in addition to providing dispatch instructions, provides five-minute 

locational marginal prices to the market participants to be used for settlement of the energy 

imbalance. Energy imbalance is the difference between the forecast load or generation and the 

actual load or generation. The benefits of an EIM include economic efficiency of an automated 

dispatch, savings due to diversity of loads and variable resources in the expanded footprint, and 

favorable impacts to reliability or operational risk.

Recent Resource Procurement Activities

PacifiCorp issued and will issue multiple requests for proposals (RFP) to secure resources and / 

or transact on various energy and environmental attribute products. Table 3.4 summarizes 

current RFP activities.

Table 3.4 – PacifiCorp’s Request for Proposal Activities

RFP RFP Objective Status Issued Completed

All Source RFP for 2016 

Resource

600MW Canceled January 2012 October 2012
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

51

RFP RFP Objective Status Issued Completed

Demand-side Resources

Oregon Solar 2010S 2 MW Closed October 2012

Oregon Solar 2013S 6.7 MW Pending 1

st Quarter 2013 December 2014

Natural Gas Long-term physical 

and financial 

products

Open May 2012 May 2013

Natural Gas Transportation Firm natural gas 

supply to Naughton 

starting 2015

Pending 2

nd Quarter 2013 December 2013

Natural Gas Transportation Long-term gas 

transportation for 

Lake Side II resource

Complete July 2011 May 2013

Renewable energy credits (Sale) Excess system RECs Open Quarterly Ongoing

Renewable energy credits 

(Purchase)

Oregon compliance 

needs

Open Based on 

specific need

Ongoing

Renewable energy credits 

(Purchase)

Washington 

compliance needs

Open Based on 

specific need

Ongoing

Renewable energy credits 

(Purchase)

California 

compliance needs

Open Based on 

specific need

Ongoing

Short-term Market (Sales) System balancing Open Quarterly Ongoing

All-Source Request for Proposals

PacifiCorp issued an all source RFP for a 2016 resource up to 600 megawatts on a system-wide 

basis in four categories: base load, intermediate, renewable and summer peaking, which are 

required to be on-line by June 2016. The RFP was issued to market in January 2012 for Utah and 

April 2012 for Oregon with a bid due date in May 2012. The bidders on the initial shortlists were 

notified in July 2012 and best and final pricing received in August 2012. As part of the all source 

RFP process, PacifiCorp filed an updated needs assessment in Oregon and Utah in September 

2012, which included an update to the load and resource balance. For 2016, the load and 

resource balance was reduced, resulting in no significant resource need in 2016. As a result, 

PacifiCorp provided notice to terminate the all source RFP in Utah and withdrew PacifiCorp’s 

all source RFP application in Oregon. A technical conference was held in October 2012 to 

explain the cancellation of the RFP. 

Demand-side Resources

The comprehensive demand-side management RFP (2008 DSM RFP) released in November 

2008 produced several proposals that at the time the 2011 Integrated Resource Plan (2011 IRP) 

was filed were still under consideration. Since that time the Company successfully implemented 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

52

two proposals from the 2008 DSM RFP; a small business project facilitator proposal designed to 

simplify and improve participation in the Company’s business programs for small business 

customers, and a home energy report program (HER Program). The HER program is currently 

available to select residential customers in the states of Utah and Washington16. A third proposal, 

a commercial and industrial curtailment program (Class 1 load control proposal), was pursued to 

the point of executing a contract but was cancelled in 2012 following preliminary 2013 IRP 

modeling results, used to inform the 2012 All Source Supply-Side Request for Proposals, which 

indicated the Company would not have the need for new Class 1 DSM until at least 2018. 

A revised 2011 IRP Action Plan (Action Plan) was provided in January, 2012, as part of the state 

acknowledgement process. A new procurement in that Action Plan called for the Company to 

issue a system-wide request for proposal (excluding Oregon) for specific direct install/direct 

distribution programs targeting savings from the residential and small commercial sectors, 

program savings that could be delivered beginning in 2013 and help defer the need of the 2016 

resource identified in the 2011 IRP. The RFP was issued in March, 2012; however, as a result of 

the Company’s revised load and resource position, final evaluation of the short-listed proposals 

was suspended in the third quarter of 2012, pending the outcome of the 2013 IRP’s Preferred 

Portfolio and revised valuation of demand side resources (updated decrement values). 

Other key procurements in 2011 and 2012 included the re-procurement of delivery for the 

Company’s residential Home Energy Savings program, Utah New Homes program, refrigerator 

recycling program, Idaho irrigation Energy Savers program, Utah and Wyoming Self-Direction 

Credit programs, Utah and Washington energy education programs, and Utah and Idaho 

irrigation load management programs17. 

The Company also issued a request for proposals in December, 2012, for the re-procurement of 

delivery services for Utah’s Cool Keeper air conditioner load management program. 

Oregon Solar Request for Proposal

PacifiCorp secured a 2.0 MW solar photovoltaic project in 2012 located in Lakeview, Oregon as 

a result of its 2010 solar RFP to meet Oregon Statute ORS 757.370 pertaining to the solar 

photovoltaic generating capacity standard, which requires Oregon utilities to acquire at least 20 

MW (alternating current). PacifiCorp’s share of the total is 8.7 MW. A second solar RFP is 

proposed to be issued in second quarter 2013 with resources required to be on line by December 

31, 2014. The RFP will seek a total of 6.7 MW to meet PacifiCorp’s remaining share of the 

standard. Due to the 5.0 MW limit per project under the Statute, the Company is seeking 

multiple projects through the RFP.

Natural Gas Transportation Request for Proposals 

PacifiCorp issued a natural gas transportation RFP to secure firm natural gas transportation 

service to its Lake Side II power plant on July 5, 2011. The request for proposals bids were 

 

16 Home energy reports began being delivered in August, 2012, and following performance evaluations scheduled by 

June 2014 may be expanded to other company jurisdictions. The Energy Trust of Oregon in collaboration with the 

Company is launching a pilot in Pacific Power’s service area beginning in August, 2013. 

17 The Utah and Idaho procurement included pricing for program delivery in the west, Oregon, Washington and 

California, pending the resource selections results of the 2013 integrated resource plan, 
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

53

delivered August 15, 2011. As a result of the RFP bid evaluation, Questar Gas and Questar 

Pipeline Company were selected. Agreements were executed by both gas parties February 15, 

2012 and submitted to the regulatory authorities for preapproval. The Questar Gas agreement 

was approved June 20, 2012, by the Utah Public Service Commission. On March 13, 2013, the 

Federal Energy Regulatory Commission issued an order and certificate, approving Questar 

Pipeline Company’s application, subject to a condition that Questar Pipeline Company executes 

transportation agreements prior to commencing construction. The transportation agreements are 

on track to be signed by May 15, 2013 to meet the construction schedule.

Natural Gas Request for Proposals

Stakeholder feedback in the hedging collaborative indicated that the Company should investigate 

hedging some portion of its natural gas requirements for a term longer than the 36-month 

hedging window, as natural gas prices were perceived to be historically low. In response, the 

Company issued the 2012 Natural Gas RFP on May 14, 2012 for natural gas hedging and supply 

products ranging from four to ten years. The market response was robust, with the Company 

receiving hundreds of bids in a range of physical and financial products. The bids were analyzed 

by determining expected value to customers based on the Company’s forward price and volatility 

curves.

Favorable bids that were Fixed-price bids or collars with terms of six years or less were selected 

for the initial shortlist. Credit cost was then determined for these bids. The final shortlist was 

then created by selecting the most favorable physical and financial bids comprising four-to-six 

year fixed-price bids, four-to-six year collar bids, and seven-to-ten year fixed price bids. The 

final shortlists showed the most benefit for customers, and were ultimately selected for refreshed 

pricing. On April 4, 2013, both bids were refreshed. The final shortlist was evaluate and was not 

favorably to the Company’s forward price curves, and no deals were executed. The Company 

therefore entered a six-month predefined “market-monitoring window,” during which the 

Company could continue to request refreshed bids if market movements suggest it worthwhile. 

Based on the experience of this RFP process, subsequent similar RFPs are expected in the future.

Natural Gas Transportation Request for Proposals 

PacifiCorp will issue a natural gas transportation RFP to secure firm natural gas supply to its 

Naughton Unit 3 power plant after the planned plant conversion to natural gas in April 2015. The 

RFP is expected to be released in second quarter 2013. Final RFP schedule will be dependent 

upon the terms and the schedule of the plant conversion. 

Renewable Energy Credit (REC) Request for Proposals 

PacifiCorp issued multiple REC RFPs in 2011 and 2012 for two purposes; (i) the sale of RECs in 

excess of compliance needs to market and, (ii) purchase of RPS-eligible RECs to fulfill specific 

short-term needs to PacifiCorp’s RPS obligation in Oregon, Washington, and California. The 

REC sale RFPs are typically issued on a quarterly basis and will continue in that format for 

2013. The RPS-eligible REC purchase RFPs are issued specific to address a state compliance 

short.
PACIFICORP – 2013 IRP CHAPTER 3 – PLANNING ENVIRONMENT

54

Renewable Energy Credit (REC) Request for Proposals – Oregon

PacifiCorp issued a request for proposal to the market in December 2012, seeking offers of 

renewable energy credits from generation facilities that are certified by the Oregon Department 

of Energy as eligible for the Oregon Renewable Portfolio Standard. Procurement of unbundled 

RECs were completed to partially defer qualified resource additions in the future to comply with 

Oregon RPS requirements. 

Renewable Energy Credit (REC) Request for Proposals - Washington

PacifiCorp issued a request for proposal to the market in May 2011, seeking offers of renewable 

energy credits from generation facilities that are eligible for Washington’s renewable portfolio 

program (Washington Initiative 937). Procurement of unbundled RECs were completed to 

comply with Washington’s renewable portfolio program requirements.

Renewable Energy Credit (REC) Request for Proposals - California

PacifiCorp issued a request for proposal to the market in May 2011, seeking offers of renewable 

energy credits from generation facilities that are eligible for California’s renewable portfolio 

standard. 

Short-term Market Power Request for Proposals

PacifiCorp issued multiple short-term market power RFPs in 2011 and 2012 to sell power for 

system balancing purposes. These RFPs are typically issued on a quarterly basis and will 

continue through 2013.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

55

CHAPTER 4 – TRANSMISSION 

CHAPTER HIGHLIGHTS

PacifiCorp is obligated to plan for and meet its customers’ future needs, despite 

uncertainties surrounding environmental and emissions regulations and potential 

new renewable resource requirements. Regardless of future policy direction, the 

Company’s planned transmission projects are well aligned to respond to changing 

policy direction, comply with increasing reliability requirements while providing 

sufficient flexibility to ensure investments cost-effectively and reliably meet its 

customers’ future needs.

Given the long periods of time necessary to site, permit and construct major new 

transmission lines, these projects need to be planned well in advance and developed 

in time to meet customer need. 

The Company’s transmission planning and benefits evaluation efforts adhere to 

regulatory and compliance requirements and are responsive to commission and 

stakeholder requests for a robust evaluation process and criteria for evaluating 

transmission additions. 

A System Operational and Reliability Benefits Tool (SBT) has been developed to 

measure the benefits associated with transmission that are incremental to those 

benefits measured by traditional IRP modeling tools.

PacifiCorp requests acknowledgment of its plan to construct the Sigurd to Red 

Butte transmission project (Energy Gateway Segment G) based on the regulatory 

and compliance requirements driving the project’s need and timing, and supported 

by the project’s benefits as quantified using the SBT. 

While construction of future Energy Gateway segments (i.e., Gateway West and 

Gateway South) is beyond the scope of acknowledgement for this IRP, these 

segments continue to offer benefits under multiple, future resource scenarios. Thus, 

the Company believes continued permitting of these segments is warranted to 

ensure it is well positioned to advance these projects as required to meet customer 

need. As such, a preliminary SBT analysis summary is provided for the next major 

segment of Energy Gateway, the Windstar to Populus transmission project 

(Gateway West Segment D), to support the Company’s continued permitting of 

Gateway West.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

56

Introduction

PacifiCorp’s bulk transmission network is designed to reliably transport electric energy from 

generation resources (owned generation or market purchases) to various load centers. There are 

several related benefits associated with a robust transmission network: 

1. Reliable delivery of power to continuously changing customer demands under a wide 

variety of system operating conditions.

2. Ability to supply aggregate electrical demand and energy requirements of customers at 

all times, taking into account scheduled and reasonably unscheduled outages.

3. Economic exchange of electric power among all systems and industry participants.

4. Development of economically feasible generation resources in areas where it is best 

suited.

5. Protection against extreme market conditions where limited transmission constrains 

energy supply. 

6. Ability to meet obligations and requirements of PacifiCorp’s Open Access Transmission 

Tariff (OATT).

7. Increased capability and capacity to access Western energy supply markets. 

PacifiCorp’s transmission network is a critical component of the IRP process and is highly 

integrated with other transmission providers in the western United States. It has a long history of 

reliable service in meeting the bulk transmission needs of the region. Its purpose will become 

more critical in the future as energy resources become more dynamic and customer expectations 

continue to grow. 

Regulatory Requirements

Open Access Transmission Tariff

Consistent with the requirements of its OATT, approved by the Federal Energy Regulatory 

Commission (FERC), PacifiCorp plans and builds its transmission system based on its network 

customers’ 10-year load and resource (L&R) forecasts. Each year, the Company solicits L&R 

data from each of its network customers in order to determine future load and resource 

requirements for all transmission network customers. These customers include PacifiCorp 

Energy (which serves PacifiCorp’s retail customers and comprises the bulk of the Company’s 

transmission network customer needs), Utah Associated Municipal Power Systems, Utah 

Municipal Power Agency, Deseret Generation & Transmission Cooperative (including Moon 

Lake Electric Association), Bonneville Power Administration, Basin Electric Power 

Cooperative, Black Hills Power and Light, and Western Area Power Administration. 

The Company uses its customers’ L&Rs and best available information to determine project 

need and investment timing. In the event that customer L&R forecasts change significantly, 

PacifiCorp may consider alternative deployment scenarios and/or schedules for its project 

investment as appropriate. Per FERC guidelines, the Company is able to reserve transmission 

network capacity based on this 10-year forecast data. PacifiCorp’s experience, however, is that 

the lengthy planning, permitting and construction timeline required for significant transmission 

investments, as well as the typical useful life of these facilities, is well beyond the 10-year 
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

57

timeframe of load and resource forecasts.18 A 20-year planning horizon and ability to reserve 

transmission capacity to meet forecasted need over that timeframe is more consistent with the 

time required to plan for and build large scale transmission projects, and PacifiCorp supports 

clear regulatory acknowledgement of this reality and corresponding policy guidance.

Reliability Standards

PacifiCorp is required to meet mandatory FERC, North American Electric Reliability 

Corporation (NERC) and Western Electricity Coordinating Council (WECC) reliability 

standards and planning requirements.19 The Company conducts annual system assessments to 

confirm minimum levels of system performance during a wide range of operating conditions, 

from serving loads with all system elements in service to extreme conditions where parts of the 

system are out of service. Factored into these assessments are load growth forecasts, operating 

history, seasonal performance, resource additions or removals, new transmission asset additions, 

and the largest transmission and generation contingencies. Based on these analyses, the 

Company identifies any potential system deficiencies and determines the infrastructure 

improvements needed to reliably meet customer loads. NERC planning standards define 

reliability of the interconnected bulk electric system in terms of adequacy and security. 

Adequacy is the electric system’s ability to meet aggregate electrical demand for customers at all 

times. Security is the electric system’s ability to withstand sudden disturbances or unanticipated 

loss of system elements. Increasing transmission capacity often requires redundant facilities in 

order to meet NERC reliability criteria.

IRP Feedback

In response to Commission feedback to PacifiCorp’s 2011 Integrated Resource Plan, the 

Company committed to a revised action plan, which included the following action item for 

transmission:

In the scenario definition phase of the IRP process, the Company will address with 

stakeholders the inclusion of any transmission projects on a case-by-case basis.

Develop an evaluation process and criteria for evaluating transmission additions.

Review with stakeholders which transmission projects should be included and why.

Based on the outcome of these steps, PacifiCorp will provide appropriate transmission 

segment analysis for which the Company requests acknowledgement.

PacifiCorp has since developed and discussed with stakeholders a new transmission System 

Operational and Reliability Benefits Tool (SBT) for the purpose of identifying and quantifying 

transmission benefits that are not captured using traditional IRP analysis tools. Traditional means 

of least cost transmission planning and net power cost modeling help identify the IRP scenario 

with the lowest present value revenue requirement, but have historically failed to capture the full 

 

18 For example, PacifiCorp’s application to begin the Environmental Impact Statement process for Energy Gateway 

West was filed with the Bureau of Land Management in late 2007 as of the 2013 IRP the federal permit has not been 

issued.

19 FERC requirements; NERC standards; WECC standards.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

58

range of benefits associated with additional transmission capabilities. The SBT identifies, 

measures and monetizes benefits that are incremental to those identified via models used in the 

IRP process. 

The Company is working to improve its ability to quantify these additional transmission benefits, 

both in response to the directives of FERC Order No. 1000 and to feedback received from state 

regulators, customers and stakeholders. However, transmission benefit evaluation is no simple 

task. There is no “off the shelf” transmission benefit calculator readily available to the Company. 

Development of the SBT is a long-term objective that will continue to require adjustments based 

on utility industry experience, and regulator and stakeholder input. In the near term, the SBT will 

be used to help support transmission segments for which the Company is seeking regulatory 

acknowledgment, which for the 2013 IRP includes the Sigurd to Red Butte transmission project. 

Ultimately, this tool will be used to complement future IRP modeling efforts, compare project 

options and support regulatory acknowledgment by providing a more complete picture of the 

benefits of additional transmission capability.

In addition to a comprehensive overview of the SBT approach, this chapter provides: 

The justification supporting acknowledgement of the Company’s plan to construct the 

Sigurd to Red Butte transmission project, including the SBT-calculated benefits for the 

project; 

A preliminary SBT analysis for the Windstar to Populus transmission project (Energy

Gateway Segment D) supporting the Company’s plan to continue permitting Gateway 

West;

Key background information on the evolution of the Energy Gateway Transmission 

Expansion Plan; and

An overview of how the Company’s investments in short-term system improvements 

have helped to maximize efficient use of the existing system and to defer the need for 

larger scale infrastructure investment.

System Operational and Reliability Benefits Tool

Background

Federal and state regulators, customers and stakeholders alike have expressed a need for 

improved methods of measuring transmission benefits and identifying beneficiaries. The 

traditional IRP System Optimizer and Planning and Risk models identify the IRP scenario with 

the lowest present value revenue requirement from an energy delivery view, but these models are 

not intended to capture a broader range of “day to day” operational and reliability benefits 

provided by transmission. A different approach is required to identify and quantify the benefits 

not captured by these traditional tools, and to better inform the Company’s transmission planning 

process in the context of integrated resource planning. 

While there is no “off the shelf” transmission benefit calculator to use, there are various 

approaches used by other transmission planning entities that are informative. PacifiCorp, both 

independently and as part of the Northern Tier Transmission Group’s FERC Order No. 1000 

compliance effort, looked to other regional transmission planning groups to understand how 

various metrics are used to evaluate transmission project benefits, impacts to existing 
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

59

transmission systems and customer benefits. These groups include the Southwest Power Pool, 

California Independent System Operator (ISO), Midwest ISO, New York ISO, ISO New 

England, PJM Interconnection, and Georgia Power. By no means have these groups perfected 

the measurement of transmission benefits, nor is there a “one size fits all” approach for assessing 

these benefits, but their efforts are several years in the making and, through their own 

stakeholder processes, they have developed and vetted several common metrics that were

considered as part of PacifiCorp’s efforts to develop a tool to measure transmission project 

benefits. 

Informed by these approaches, PacifiCorp has developed the SBT to help quantify the 

operational and reliability benefits directly associated with new transmission projects and their 

integration into the existing transmission system. The metrics that comprise the SBT will 

continue to improve and evolve over time, with stakeholder input and through utility industry 

experience. 

Provided below is a description of the SBT metrics the Company is working with initially, plus 

the SBT-calculated benefits for the Sigurd to Red Butte transmission project, for which the 

Company is seeking acknowledgment in this IRP. 

Benefits Evaluated

Each transmission project has its own unique set of objectives, physical characteristics and 

benefits, and therefore may require a unique set of metrics for evaluation. A larger, more 

complex project may involve more metrics—or derive higher values from the same metrics—

than a smaller, less complex project. For example, not all of the metrics described below derive 

benefit values for the Sigurd to Red Butte transmission project, whereas they may derive values 

for other Energy Gateway segments. 

Operational Cost Savings (economic driven)

Where the IRP model topology can evaluate the specific transmission project, results from the 

IRP modeling process may be used to determine economic benefits (i.e. net power cost savings) 

of new transmission. However, in situations where the IRP model topology cannot recognize the 

project due to granularity limitations, a system production cost modeling program, with detailed 

system topology and assumptions, may be relied upon to determine the economic benefits of the 

specific transmission project. Alternatively, where operational cost savings are not derived 

specifically from production cost benefits, this metric may be used to compare operational cost 

savings of potential solutions. For the Sigurd to Red Butte project, the IRP model topology did 

not recognize the project which exists within a single IRP topology load bubble. For example, 

potential alternatives identified could include the addition of a new generation resource, the 

purchase of firm energy and wheeling costs or an alternative transmission project. 

It is important to note that benefits will only be included as part of the SBT analysis to the extent 

they are incremental and not already captured in the production cost benefits identified through 

the IRP modeling process. The purpose of the SBT is to identify and measure transmission

benefits not already captured via the IRP modeling—i.e., no duplication of benefits. 

Segment Loss Savings (energy and capacity)
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

60

Energy – The addition of a new transmission line operated in parallel with an existing line(s) 

reduces the electrical impedance of the transmission system, resulting in lower energy line losses 

(megawatt-hours) over the life of the project. Depending on the amount of power flow, line loss 

savings can be substantial. Losses for any transmission line are determined according to the 

formula I

2

R (where I is the current flow and R is resistance). To calculate current (I), megavolt 

amperes are divided by (√3 x voltage). Since the predominant flow on the Company’s 

transmission lines is real power (megawatts), the difference when calculating current is small 

between megawatts (MW) and megavolt amperes (MVA). Hence, megawatt flow can be used 

rather than megavolt amperes as a close approximation. Factors such as line length and 

conductor type, material and size determine change in system impedance. The electrical 

impedance of parallel lines is determined by calculating an equivalent resistance (Requivalent) 

before and after a transmission project is placed in service. 

In the SBT analysis, the Company’s assessment of energy line losses is based on actual power 

flow (megawatts) as a proxy for a typical year, with line flow increasing in future years as 

determined by network customers’ load forecast submittals. Line losses are compared before and 

after the addition of new transmission and are calculated between the connection points, with the 

difference being the loss savings attributed to the new line(s). A forward energy price curve is 

used to monetize the value of line loss energy savings as an avoided market purchase of energy 

and the present value of the annual savings is then calculated.

Capacity – Lower line segment losses reduce the overall system demand and the amount of 

generation capacity needed to meet that demand, thereby reducing the need for new incremental 

generation. To determine generation capacity related savings due to reduced line segment losses, 

average demand savings (megawatts) are calculated for a segment using system peak flow data 

from previous years. To monetize these savings, the base capital cost of a combined cycle gas 

generating plant ($1,026 per installed megawatt)20 is multiplied by the capacity value 

(megawatts) of the line loss savings and the present value of the annual savings is then 

calculated.

System Reliability Benefits

The SBT calculates system reliability benefits gained by adding new transmission between 

points in the existing system. The addition of new transmission results in new incremental 

capacity, but also results in improved performance of the existing system. These performance

benefits are derived using Company historical transmission line outage data, for both scheduled 

and unscheduled line outages, and then determining the improved system performance with the 

new segment(s) in service during outages of a single transmission line (N-1) or multiple 

transmission lines (N-1-1). Benefits are measured as: 

Avoidance of transmission system capacity reductions or “derates” 

To calculate this benefit, the impact to the transmission system capacity—or “derate”—is 

evaluated for each line outage. These figures are then compared to the system capability 

with the new line segment(s) in service. The difference between capacities (megawatts) is 

the “derate” benefit.

 

20 Cost from PacifiCorp’s 2013 Integrated Resource Plan.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

61

Reductions in forced generator outages caused by transmission outages or limitations

Reductions in forced generator outages is calculated using the same methodology used to 

calculate the “derate” benefit, but the analysis instead looks at the impacts on affected

generation resources. The amount of generation that is reduced due to transmission 

system capacity limitations is determined with and without the new segment(s) in service. 

The impacts from transmission capacity reductions and the reductions in forced generator 

outages are then compared. To avoid double counting, only the highest megawatt value 

between the two impacts is selected for valuation. This megawatt value is priced using 

historical line outage data and a weighted average yearly price comprised of light-load 

and heavy-load hours using a suitable forward price curve. The present value is then 

determined. For calculation of multiple line outages, it is assumed that it takes a fixed 

amount of time—based on historical information—to restore affected generation. Since it 

is impossible to determine the exact time of day when an outage will occur, the megawatt 

value for multiple line outages is priced using the weighted heavy-load and light-load 

hour average of the entire forward price curve. This value is then multiplied by the 

probability of the outage and the present value is then determined.

Reduced exposure to loss of firm customer load, based on calculation of avoided loss of 

retail revenue from customers during system outages. 

The system is evaluated with the new segment(s) in service and compared against the 

existing system. If the configuration with the new segment(s) enables load service that 

would otherwise be lost during outage conditions, this difference is the reduction in risk 

to customer load loss. For multiple outages (N-1-1), the probability of such an occurrence 

is utilized and load is assumed to be lost for two hours for each outage occurrence. The 

value is developed by multiplying the loss in customer demand by the probability of the 

outage condition by the Company’s average Retail Energy Rate (dollars per kWh) for the 

state where the new transmission segment is placed in service. Based on this, the present 

value is determined.

The system performance criteria used by the Company are specified in the mandatory FERC, 

NERC and WECC Transmission System Planning Standards and Performance Criteria. 

Customer and Regulatory Benefits

As growing demand depletes excess transmission capacity, the likelihood of impacting large 

industrial or commercial customers increases due to a need to curtail load to maintain a safe and 

reliable operating system under certain, abnormal conditions. Such circumstances can result in 

lost retail sales of energy, lost sales for retail customers, equipment damage, lost product, and 

potentially a negative economic development value for areas impacted by poor transmission 

system reliability. In addition, the regulatory costs following a significant outage and the 

resulting investigation and remediation costs can be quantified. The risk of such circumstances 

can be significantly reduced with new transmission capacity that supports customer load growth 

across the operating system. 

Avoided Capital Cost

This metric considers capital investment that may be avoided by a transmission alternative, 

where the addition of a new transmission project resolves underlying issues identified by 

planning studies. In such a case, the transmission project avoids underlying upgrades for load 

service or reliability needs and SBT factors in the one-time capital investment as an avoided cost
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

62

benefit of those projects displaced or deferred. The avoided cost of replaced or deferred 

investments is a commonly used metric in transmission benefit analysis. 

Improved Generation Dispatch (reliability driven)

Without adequate transmission capacity, the system may not be able to fully utilize generation 

resources in constrained areas. As a result of this congestion, the Company may be unable to 

dispatch the most economic resources to meet customer needs, increasing costs to customers. 

New transmission infrastructure can alleviate these conditions and improve overall generation 

dispatch to meet system load and reliability requirements. Additionally, the same generation 

resources that are constrained by transmission limitations can also provide capacity benefits that 

may be used for system reserves through the addition of transmission capability. The SBT 

calculates the value of generation that may be online but not at full output and could otherwise 

be dispatched up to full nameplate capacity for reserves purposes when new segment(s) reduce 

or eliminate transmission congestion. The benefits associated with increased access to existing, 

dispatchable generation for reserves is calculated as the difference between the minimum unit 

operating limit and the amount of increased transmission capacity provided by the new 

segment(s) up to the maximum output of each unit. The benefit value of this generation is based 

on the reduced need for incremental new generation at the cost of acquiring generation or market 

purchases, whichever is lower.

Wheeling Revenue Opportunity 

Transmission services sold to system users provides a wheeling revenue benefit derived from 

selling new incremental transmission capacity. The SBT reviews new incremental transmission 

capacity for each segment or sub-segment analyzed and identifies the value of this new capacity. 

The present value of the benefit attributable to wheeling revenue for each of the segments or subsegments is based on PacifiCorp’s long-term point-to-point wheeling charge (Schedules 7, 1 and 

2

21) and the new transfer capability (megawatts) not otherwise captured in the Operational Cost 

Savings. Incremental system capacity for each segment or sub-segment is determined by 

comparing the initial path transfer capability with the improved path capacity after adding the 

new segment(s). In cases where the available capacity has not been fully subscribed by point-topoint users, this benefit is referred to as a wheeling revenue “opportunity.” 

Request for Acknowledgement of Sigurd to Red Butte

The Sigurd to Red Butte transmission project is required to satisfy the Company’s federal 

regulatory obligations to its network transmission customers under its OATT and comply with 

the mandatory FERC, NERC and WECC reliability standards. In addition, consistent with the 

Company’s commitment described at the beginning of this chapter, PacifiCorp has developed—

in consultation with other transmission providers, transmission planning regions, and 

stakeholders—a SBT for evaluating the benefits of transmission projects for which the Company 

seeks regulatory acknowledgment. The SBT helps identify and quantify those transmission 

benefits not recognized using traditional IRP analysis tools, capturing the full range of benefits 

associated with additional transmission. Using this tool, the Company has calculated at least 

$645 million in benefits associated with the Sigurd to Red Butte transmission project, and a 1.64 

benefit-to-cost ratio. In March 2013, PacifiCorp obtained a certificate of public convenience and 

 

21 At a minimum, these rate schedules would be applicable to purchasers of long-term point-to-point transmission 

service.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

63

necessity authorizing construction of the Sigurd to Red Butte transmission line from the Utah 

Public Service Commission. To meet regulatory reliability requirements, with demonstration of 

project need and showing of project benefits, the Company requests regulatory 

acknowledgement of the Sigurd to Red Butte transmission project. 

Factors Supporting Acknowledgement 

The key drivers supporting PacifiCorp’s request for acknowledgement of the Sigurd to Red Butte 

transmission project include meeting its obligations to its network transmission customers 

consistent with its OATT, complying with mandatory FERC, NERC and WECC reliability 

standards and the positive cost benefit analysis of this project compared to other alternatives. 

Improved Transmission System Capacity

The full-rated capacity of the southwest Utah transmission system, including the existing Sigurd 

to Three Peaks to Red Butte No. 1 – 345 kV transmission line, cannot currently provide adequate 

service under all expected operating conditions and customer demands. The existing Sigurd to 

Red Butte transmission line represents the sole connection to a major southwest Utah load area, 

with customer designated generation sources to this critical load isolated during line outage 

events. Load growth in southwestern Utah continues, and is forecasted to continue, surpassing 

the capability of the existing transmission system. New facilities must be constructed to provide 

reliable capacity for load service. Without the Sigurd to Red Butte transmission project, peak 

load in southwestern Utah cannot be reliably served during transmission line outages or major 

equipment contingencies. The Sigurd to Red Butte transmission project also supports future 

electrical load growth in southwestern Utah and improves the ability of the Company’s 

transmission system to transport energy into southwest and central Utah and to high growth areas 

along the Wasatch Front of Salt Lake City. 

Enhanced Transfer Capability to Promote Energy Transfers

Under its OATT, the Company has transmission service contract obligations for firm 

transmission service into and out of southwestern Utah. Indeed, the OATT obligates the 

Company to provide adequate and non-discriminatory network transmission service for delivery 

of network generation to loads. The current system supports up to 400 MW of firm energy 

transfers (bi-directional) between southwestern Utah and Nevada. The Company has contractual 

commitments and future load service requirements that cannot reliably be delivered via the 

transmission system existing in the area today. To meet these transfer obligations, the Company 

must increase the total capacity between the existing Sigurd and Red Butte substations. 

Following completion of the Sigurd to Red Butte project, the transfer capacity of the existing 

system between Utah and Nevada will increase by an additional 200 MW. This additional 

transmission capacity can be purchased by the Company to make off-system sales during periods 

when surplus energy exists, or can be purchased for use by third parties. The Sigurd to Red Butte 

transmission project will enable the Company to continue to meet its OATT obligations, as well 

as its contractual service obligations to PacifiCorp Energy, Utah Associated Municipal Power 

Systems, Utah Municipal Power Association, and Deseret Generation & Transmission Cooperative, Inc. The added transfer capacity is vital to the Company’s continued ability to provide 

reliable service to these entities in the future.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

64

Improved Transmission System Reliability

In addition to increasing system capacity, the Sigurd to Red Butte transmission project will 

provide needed redundancy to the existing infrastructure and substantially improve the 

Company’s ability to provide reliable electric service to its customers in compliance with 

mandatory FERC, NERC and WECC reliability standards. These standards require that 

transmission providers evaluate all expected customer demand levels and operating conditions, 

and plan for adequate redundancy in their systems in order to maintain required system 

reliability and performance levels. It is the responsibility of the Company as the transmission 

provider to utilize operational history and experience to plan, design, site and construct 

transmission projects as required to meet system performance requirements and manage 

reliability, risks, and costs. Without the Sigurd to Red Butte transmission project, peak loads in 

southwestern Utah will not be reliably served and transmission service contract obligations will 

not be met. The Sigurd to Red Butte transmission project has been designed in a manner that 

meets the Company’s system planning criteria (developed in compliance with mandatory FERC, 

NERC and WECC standards and criteria, and based on the Company’s operational history and 

experience), substantially improving the Company’s ability to provide reliable electric service to 

its customers long term and enhancing the reliability and capacity of the existing transmission 

system. 

Sigurd to Red Butte Cost Benefit Analysis

The SBT metrics quantify the transmission benefits that are otherwise not captured within the 

existing IRP analysis. As applied to the Sigurd to Red Butte transmission project, for which the 

Company is seeking acknowledgement in this IRP, the SBT derived the following benefits and 

benefit-to-cost ratio. 
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

65

Table 4.1 – SBT-Derived Values for Sigurd to Red Butte

* * * * * * * * * SBT-Derived values for Sigurd to Red Butte * * * * * * * * *

$645 million over 2015-2034 period, 1.64 benefit-cost ratio

Operational Cost Savings

Energy (option at 25% of total) ................................ $470 million

Third-party wheeling ................................................ $104 million

Segment Loss Savings22

Energy....................................................................... $55.5 million

Capacity .................................................................... $14.9 million

System Reliability Benefits

N-1 load curtailment (load over 580 MW)............... $1 million

Customer and Regulatory Benefits.......................................TBD

Wheeling Revenue Opportunity:

ATC firm southbound............................................... $57 million

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

TOTAL MEASURED BENEFITS 

(minus Wheeling Revenue Opportunity).............................. $645 million

PROJECT CAPITAL COST............................................. $392 million23

PROJECT BENEFIT-TO-COST RATIO........................ 1.64

NOTE: See excel spreadsheet for detailed Sigurd to Red Butte SBT assumptions and calculations24

Gateway West – Continued Permitting

The Windstar to Populus transmission project (Energy Gateway Segment D) is the first of two

planned segments of Gateway West. Given the delays experienced in the permitting process, the 

current project schedule for Windstar to Populus shows a delay of the in-service date to 

December 31, 2019. In a future IRP, the Company will support a request for acknowledgement 

to construct Windstar to Populus with a thorough cost-benefit analysis for the project, similar to 

that provided in this IRP for the Sigurd to Red Butte transmission project. While the Company is 

 

22 All present value calculations for Sigurd to Red Butte line losses are based on a 20-year time horizon starting in 

2015, using a 6.88% discount rate, which was PacifiCorp’s weighted average cost of capital at the time the analysis 

was undertaken.

23 Includes fully loaded capital and related operations and maintenance costs on a 20-year time horizon starting in 

2015, discounted at 6.88%.

24 “System Benefit Tool for Sigurd to Red Butte Transmission Line (Segment G)”

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/PacTra

ns_SigurdToRedButte-SBT_4-30-13.xlsx
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

66

not requesting acknowledgement in this IRP of a plan to construct the Windstar to Populus 

project, the Company will continue to permit the project, and provides below a preliminary SBT 

analysis summary that demonstrates significant project benefits to support this plan. 

Windstar to Populus

The Windstar to Populus transmission project consists of three key sections: 

A single-circuit 230 kilovolt (kV) line that 

will run approximately 75 miles between the 

existing Windstar substation in eastern 

Wyoming and the Aeolus substation to be 

constructed near Medicine Bow, Wyoming; 

A single-circuit 500 kV line running 

approximately 140 miles from the Aeolus 

substation to a new annex substation near the 

existing Bridger substation in western 

Wyoming; and 

A single-circuit 500 kV line running approximately 200 miles between the new annex 

substation and the recently constructed Populus substation in southeast Idaho. 

The project would enable the Company to more efficiently dispatch system resources, improve 

performance of the transmission system (i.e. reduced line losses), improve reliability, and enable

access to a diverse range of new resource alternatives over the long-term.

Preliminary SBT Analysis – Windstar to Populus (Segment D)

The SBT metrics quantify the transmission benefits that are otherwise not captured within the 

existing IRP analysis. The footnoted excel spreadsheet provides for a detailed view of the project 

benefits, including operational savings as measured by the System Optimizer model25. 

The following metrics were determined to apply to Segment D and were analyzed to determine 

possible benefits associated with each:

 

25 “System Benefit Tool for Preferred Portfolio Case 07 Energy Gateway Scenario 2 (Segment D)” 

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/2013I

RP_System-Benefits-Tool-C07_4-23-13.xlsx
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

67

Table 4.2 – Windstar to Populus Benefits Calculation

Benefits Calculation

Case EG2-

C07

System Optimizer Analysis $511

Avoided Transmission System Capital Cost $151

System Reliability Benefits $112

Improved Generation Dispatch $39

Segment Loss Savings - Energy $69

Segment Loss Savings - Capacity $18

Customer and Regulatory Benefits $249

Wheeling Revenue Opportunity $16

Total Benefits ($m) $1,165

Costs ($m) $ (934)

Net Benefit ($m, 2012$) $ 231

Plan to Continue Permitting Gateway West

The Windstar to Populus transmission project continues to offer benefits under multiple, future 

resource scenarios. To ensure the Company is well positioned to advance the project as required 

to meet customer need, PacifiCorp believes it is prudent to continue to permit the Gateway West 

transmission project.

Evolution of the Energy Gateway Transmission Expansion Plan

Introduction

Given the long periods of time necessary to successfully site, permit and construct major new 

transmission lines, these projects need to be planned and developed in time to meet customer 

need. The Energy Gateway Transmission Expansion Plan is the result of several robust local and 

regional transmission planning efforts that are ongoing and have been conducted multiple times 

over a period of several years. The purpose of this section is to provide important background 

information on the transmission planning efforts that led to the Company’s proposal of the 

Energy Gateway Transmission Expansion Plan. 

Background
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

68

Until the Company’s announcement of Energy Gateway in 2007, its transmission planning 

efforts traditionally centered around the generation additions identified in the IRP. As the figure 

here shows, the generation resources 

in the Company’s preferred 

portfolio have historically fluctuated 

significantly from one IRP to the 

next. With timelines of seven to ten 

years or more required to site, 

permit, and build transmission, this 

traditional planning approach was 

proven problematic, leading to a 

perpetual state of transmission 

planning and new transmission 

capacity not being available in time 

to be viable transmission resource 

options for meeting customer need.

The existing transmission system 

has been at capacity for several 

years and new capability is 

necessary to enable new resource development.

The Energy Gateway Transmission Expansion Plan, formally announced in May 2007, has 

origins in numerous local and regional transmission planning efforts discussed further below. 

Energy Gateway was designed to ensure a reliable, adequate system capable of meeting current 

and future customer needs. Importantly, given the changing resource picture, its design supports 

multiple future resource scenarios by connecting resource-rich areas and major load centers 

across the Company’s multi-state service area. Energy Gateway has since been included in all 

relevant local, regional and interconnection-wide transmission studies.

Planning Initiatives

Energy Gateway is the result of robust local and regional transmission planning efforts. The 

Company has participated in numerous transmission planning initiatives, both leading up to and 

since Energy Gateway’s announcement. Stakeholder involvement has played an important role 

in each of these initiatives, including participation from state and federal regulators, government 

agencies, private and public energy providers, independent developers, consumer advocates, 

renewable energy groups, policy think tanks, environmental groups, and elected officials. These 

studies have shown a critical need to alleviate transmission congestion and move constrained 

energy resources to regional load centers throughout the West, and include: 

Northwest Transmission Assessment Committee (NTAC)

The NTAC was the sub-regional transmission planning group representing the Northwest 

region, preceding Northern Tier Transmission Group and ColumbiaGrid. The NTAC 

developed long term transmission options for resources located within the provinces of 

British Columbia and Alberta, and the states of Montana, Washington and Oregon to 

serve Northwest loads and Northern California. 

0

200

400

600

800

1000

1200

1400

1600

1800

May-07 May-09 March-11 2012 Bus

Plan

DSM

Wind

Coal

CCCT

Short term

(avg/yr)

Megawatts

Resource Portfolio Variation
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

69

Rocky Mountain Area Transmission Study26

Recommended transmission expansions 

overlap significantly with Energy Gateway 

configuration, including: 

o Bridger system expansion similar to 

Gateway West 

o Southeast Idaho to Southwest Utah 

expansion akin to Gateway Central 

and Sigurd-Red Butte

o Improved East-West connectivity 

similar to Energy Gateway Segment 

H alternatives 

Western Governors’ Association Transmission Task Force Report27

Examined the transmission needed to 

deliver the largely remote generation 

resources contemplated by the Clean and 

Diversified Energy Advisory Committee. 

This effort built upon the transmission 

previously modeled by the Seams Steering 

Group-Western Interconnection, and 

included transmission necessary to support a 

range of resource scenarios, including high 

efficiency, high renewables and high coal 

scenarios. Again, for PacifiCorp’s system, 

the transmission expansion that supported 

these scenarios closely resembled Energy Gateway’s configuration. 

Western Regional Transmission Expansion Partnership (WRTEP)

The WRTEP was a group of six utilities working with four western governors' offices to 

evaluate the proposed Frontier Transmission Line. The Frontier Line was proposed to 

connect California and Nevada to Wyoming's Powder River Basin through Utah. The 

utilities involved were PacifiCorp, Nevada Power, Pacific Gas & Electric, San Diego Gas 

& Electric, Southern California Edison, and Sierra Pacific Power. 

Northern Tier Transmission Group Transmission Planning Reports

o 2007 Fast Track Project Process and 

Annual Planning Report28

o 2008-2009 Transmission Plan29

o 2010-2011 Transmission Plan30

Each Energy Gateway segment was included 

in the 2007 Fast Track Project Process and 

 

26 http://psc.state.wy.us/rmats/rmats.htm

27 http://www.westgov.org/index.php?option=com_joomdoc&task=doc_download&gid=97&Itemid

28 http://nttg.biz/site/index.php?option=com_docman&task=doc_download&gid=353&Itemid=31

29 http://nttg.biz/site/index.php?option=com_docman&task=doc_download&gid=1020&Itemid=31

30 http://nttg.biz/site/index.php?option=com_docman&task=doc_download&gid=1437&Itemid=31

“The analyses presented in this 

Report suggest that wellconsidered transmission 

upgrades, capable of giving LSEs 

greater access to lower cost 

generation and enhancing fuel 

diversity, are cost-effective for 

consumers under a variety of 

reasonable assumptions about 

natural gas prices.”

“The Task Force observes that 

transmission investments 

typically continue to provide 

value even as network 

conditions change. For example, 

transmission originally built to 

the site of a now obsolete 

power plant continues to be 

used since a new power plant is 

often constructed at the same 

location.”

“The Fast Track Project Process 

was used in 2007 to identify 

projects needed for reliability and 

to meet Transmission Service 

Requests.”
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

70

has since been reevaluated as part of each Northern Tier Transmission Group biennial 

planning process. These are open, stakeholder processes.

WECC/TEPPC Annual Reports and Western Interconnection Transmission Path 

Utilization Studies 31

These analyses measure the historical 

utilization of transmission paths in the West 

to provide insight into where congestion is 

occurring and assess the cost of that 

congestion. The Energy Gateway segments 

have been included in the analyses that 

support these studies, alleviating several 

points of significant congestion on the 

system, including Path 19 (Bridger West) and Path 20 (Path C). 

Energy Gateway Configuration

For addressing constraints identified on PacifiCorp’s system, as well as meeting system 

reliability requirements discussed further below, the recommended bulk electric transmission 

additions took on a consistent footprint, which is now known as Energy Gateway. This 

expansion plan establishes a triangle over Utah, Idaho and Wyoming with paths extending into 

Oregon and Washington, and contemplates logical resource locations for the long-term based on 

environmental constraints, economic generation resources, and federal and state energy policies. 

Since Energy Gateway’s announcement, this series of projects has continued to be vetted 

through multiple public transmission planning forums at the local, regional and interconnectionwide levels. In accordance with the local planning requirements in PacifiCorp’s federal OATT, 

Attachment K, the Company 

has conducted numerous 

public meetings on Energy 

Gateway and transmission 

planning in general. 

Meeting notices and 

materials 

are posted publicly on 

PacifiCorp’s Attachment K 

Open Access Same-time 

Information System 

(OASIS) 

site. PacifiCorp is also a 

member of the Northern Tier 

Transmission Group 

(NTTG) and 

WECC’s Transmission 

Expansion Policy and 

Planning Committee 

 

31 http://www.wecc.biz/committees/BOD/TEPPC/External/Forms/external.aspx 

“Path 19 [Bridger] is the most 

heavily loaded WECC path in the 

study... Usage on this path is 

currently of interest due to the 

high number of requests for 

transmission service to move 

renewable power to the West 

from the Wyoming area.”
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

71

(TEPPC). 

These groups continually evaluate PacifiCorp’s transmission plan in their efforts to develop and 

refine the optimal regional and interconnection-wide plans. Please refer to PacifiCorp’s OASIS 

site for information and materials related to these public processes.32

Additionally, the Project Teams conducted an extensive 18-month stakeholder process on 

Gateway West and Gateway South. This stakeholder process was conducted in accordance with 

WECC Regional Planning Project Review guidelines and FERC OATT planning principles, and 

was used to establish need, assess benefits to the region, vet alternatives and eliminate 

duplication of projects. Meeting materials and related reports can be found on PacifiCorp’s 

Energy Gateway OASIS site.

Energy Gateway’s Continued Evolution

The Energy Gateway Transmission Expansion Plan is the result of years of ongoing local and 

regional transmission planning efforts with significant customer and stakeholder involvement. 

Since its announcement in May 2007, Energy Gateway’s scope and scale have continued to 

evolve to meet the future needs of PacifiCorp customers and the requirements of mandatory 

transmission planning standards and criteria. Additionally, the Company has improved its ability 

to meet near-term customer needs through a limited number of smaller-scale investments that 

maximize efficient use of the current system and help defer, to some degree, the need for larger 

capital investments like Energy Gateway (see the following section on Efforts to Maximize 

Existing System Capability). The IRP process, as compared to transmission planning, is a 

frequently changing resource planning process that does not support the longer-term 

development needs of transmission, or the ability to implement transmission in time to meet 

customer need. Together, however, the IRP and transmission planning processes complement 

each other by helping the Company optimize the timing of its transmission and resource 

investments for meeting customer needs.

While the core principles for Energy Gateway’s design have not changed, the project 

configuration and timing continue to be reviewed and modified to coincide with the latest 

mandatory transmission system reliability standards and performance requirements, annual 

system reliability assessments, input from several years of federal and state permitting processes, 

and changes in generation resource planning and our customers’ forecasted demand for energy. 

As originally announced in May 2007, Energy Gateway consisted of a combination of singleand double-circuit 230 kV, 345 kV and 500 kV lines connecting Wyoming, Idaho, Utah, Oregon 

and Nevada. In response to regulatory and industry input regarding potential regional benefits of 

“upsizing” the project capacity (e.g. maximized use of energy corridors, reduced environmental 

impacts and improved economies of scale), the Company included in its original plan the 

potential for doubling the project’s capacity to accommodate third-party and equity partnership 

interests. During late 2007 and early 2008, PacifiCorp received in excess of 6,000 MW of 

requests for incremental transmission service across the Energy Gateway footprint, which 

supported the upsized configuration. The Company identified the costs required for this upsized 

system and offered transmission service contracts to queue customers. These customers, 

 

32 http://www.oatioasis.com/ppw/index.html
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

72

however, were unable to commit due to the upfront costs and lack of firm contracts with 

customers to take delivery of future generation, and withdrew their requests. In parallel, 

PacifiCorp pursued several potential partnerships with other transmission developers and entities 

with transmission proposals in the Intermountain Region. Due to the significant upfront costs 

inherent in transmission investments, firm partnership commitments also failed to materialize, 

leading the Company to pursue the current configuration with the intent of only developing 

system capacity sufficient to meet the long-term needs of its customers. 

In 2010, the Company entered into memorandums of understanding (MOU) to explore potential 

joint-development opportunities with Idaho Power on its Boardman to Hemingway project and 

with Portland General Electric (PGE) on its Cascade Crossing project. One of the key purposes 

of Energy Gateway is to better integrate the Company’s East and West control areas, and 

Gateway Segment H from western Idaho into southern Oregon was originally proposed to satisfy 

this need. However, recognizing the potential mutual benefits and value for customers of jointly 

developing transmission, PacifiCorp has pursued these potential partnership opportunities as a 

lower cost alternative. 

In 2011, the Company announced the indefinite postponement of the 500 kV Gateway South 

segment between the Mona substation in central Utah and Crystal substation in Nevada. This 

extension of Gateway South, like the double-circuit configuration discussed above, was a 

component of the upsized system to address regional needs if supported by queue customers or 

partnerships. However, despite significant third-party interest in the Gateway South segment to 

Nevada, there was a lack of financial commitment needed to support the upsized configuration. 

In 2012, the Company determined, due to experience with land use limitations and National 

Environmental Policy Act permitting requirements, that one new 230 kV line between the 

Windstar and Aeolus substations and a rebuild of the existing 230 kV line was feasible, and that 

the second new proposed 230 kV line planned between Windstar and Aeolus would be 

eliminated. This decision resulted from the Company’s ongoing focus on meeting customer 

needs, taking stakeholder feedback and land use limitations into consideration, and finding the 

best balance between cost and risk for customers. In January 2012 the Company signed the 

Boardman to Hemingway Permitting Agreement with Idaho Power and Bonneville Power 

Administration that provides for the Company’s participation through the permitting phase of the 

project. 

In January 2013, the Company began discussions with PGE regarding changes to its Cascade 

Crossing transmission project and potential opportunities for joint-development and/or firm 

capacity rights into PacifiCorp’s Oregon system. PacifiCorp continues to pursue potential 

partnership opportunities with PGE on Cascade Crossing and with Idaho Power and Bonneville 

Power Administration on the Boardman to Hemingway project as an alternative to PacifiCorp’s 

originally proposed transmission segment from eastern Idaho into southern Oregon (Hemingway 

to Captain Jack). 

Finally, the timing of segments is regularly assessed and adjusted. While permitting delays have 

played a significant role in the adjusted timing of some segments (e.g., Gateway West and 

Gateway South), the Company has been proactive in deferring in-service dates due to permitting 

schedules, moderated load growth, changing customer needs, and system reliability 

improvements discussed below (e.g., Sigurd-Red Butte and Oquirrh-Terminal).
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

73

The Company will continue to adjust the timing and configuration of its proposed transmission 

investments based on its ongoing assessment of the system’s ability to meet customer needs and 

its compliance with mandatory reliability standards.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

74

Figure 4.1 – Energy Gateway Transmission Expansion Plan 

This map is for general reference only and reflects current plans.

It may not reflect the final routes, construction sequence or exact line configuration.

Segment & Name Description

Approximate

Mileage Status33 and Scheduled In-Service

(A)

Wallula-McNary 230 kV, single circuit 30 mi Status: local permitting completed 

Scheduled in-service: 2013-2014*

(B)

Populus-Terminal 345 kV, double circuit 135 mi Status: completed

Placed in-service November 2010

(C)

Mona-Oquirrh

500 kV single circuit

345 kV double circuit 100 mi Status: construction nearing completion

Scheduled in-service: May 2013

Oquirrh-Terminal 345 kV double circuit 14 mi Status: rights-of-way acquisition underway

Scheduled in-service: June 2016*

(D)

Windstar-Populus

230 kV single circuit

500 kV single circuit 400 mi Status: permitting underway

Scheduled in-service: 2019-2021*

(E)

Populus-Hemingway 500 kV single circuit 600 mi Status: permitting underway

Scheduled in-service: 2020-2023*

(F)

Aeolus-Mona 500 kV single circuit 400 mi Status: permitting underway

Scheduled in-service: 2020-2022*

(G)

Sigurd-Red Butte 345 kV single circuit 170 mi Status: construction started April 2013

Scheduled in-service: June 2015

(H)

West of Hemingway 500 kV single circuit 500 mi

Status: pursuing joint-development and/or firm 

capacity opportunities with project sponsors

Scheduled in-service: sponsor driven

 * Scheduled in-service date adjusted since last IRP Update.

 

33 Status as of the filing of this IRP.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

75

Efforts to Maximize Existing System Capability

The system analyses described above continue to confirm the need for the Energy Gateway 

projects, but have also been used to identify short-term improvements throughout the Company’s 

system that have helped maximize efficient use of the existing system and defer the need for 

larger scale infrastructure investment. Over the past 20 to 30 years, limited new transmission 

capacity has been added to the system. Instead, PacifiCorp has maintained system reliability and 

maximized system efficiency through these smaller-scale, incremental projects. 

System-wide, the Company has instituted more than 120 grid operating procedures and 17 

special protection schemes to maximize the existing system capability while managing system 

risk. Since 2008, the Company has upgraded or rebuilt over 140 miles of existing Wyoming 230 

kV transmission lines to achieve new capacity, relocated and reused more than 800 MVA of 

existing transformers, upgraded three major series capacitors to increase capacity, and obtained 

WECC approval of four major path rating upgrades. PacifiCorp recently installed equipment that 

will allow real time dynamic line ratings on a critical 230 kV path in Wyoming (pending WECC 

approval). This equipment will allow the maximum capability of the conductor, or winter rating, 

to be used during periods of moderate temperature in summer months, as a way to maximize 

capability of the existing system. Other transmission system improvements include:

Southern Utah:

o Installed 345 kV series capacitor at Pinto substation;

o Installed shunt capacitors at Pinto and Red Butte substations; 

o Installed static var compensator at Red Butte substation;

o Installed second 230/345 kV transformer at Harry Allen substation in Las Vegas, 

Nevada. 

 These investments, together, helped maximize the existing system’s 

capability, improved the Company’s ability to serve growing customer 

loads, increased transfer capacity across WECC Paths TOT2B1 (Four 

Corners to Pinto, Glen Canyon to Sigurd) and TOT2C (Harry Allen to Red 

Butte), and reduced the risk of voltage collapse following the loss of one 

of the two 345 kV lines serving the Red Butte area. Specifically, these 

benefits include the upgrade of Path TOT2C by 300 MW, the 

simultaneous operation of Paths TOT2C and TOT2B1 to approved limits, 

and elimination of a Path TOT2B1 de-rate with growing load in southern 

Utah. 

Wyoming

o Reconductored over 66 miles of 230 kV line between Windstar, Dave Johnston 

and Casper;

o Installed shunt capacitors at Riverton, Midwest and Atlantic City substations; 

o Replaced components of the Jim Bridger transmission system Remedial Action 

Scheme (RAS); 

o Upgraded the series capacitor at the Borah substation and the switches in the 

Borah and Kinport substations;

o Installed a dynamic line rating system on the Miners to Platte 230 kV line;

o Installed a phase shifting transformer at the Monument substation.
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

76

 These investments improved reliability and helped maximize the 

transmission system’s capabilities, providing numerous system and 

customer benefits:

Maximized transfer capability between Windstar, Dave Johnston 

and Casper substations during all seasons;

Improved the Company’s ability to move Wyoming resources to 

PacifiCorp’s customer loads;

Increased transfer capacity of Paths TOT4A (south and west of 

Casper and Dave Johnston) and TOT4B (north and west of Casper 

and Dave Johnston), which otherwise would have been 

downgraded, requiring curtailment of generation in Wyoming;

Increased Bridger West path rating from 2200 MW to 2400 MW, 

allowing integration of new resources and improved ability to 

serve large-customer load growth in Wyoming;

Reduced risk of customer impact during peak-condition operation 

of Jim Bridger generator;

Eliminated line overload conditions and generating plant output 

reductions.

Idaho

o Installed two 230 kV capacitor banks at the Meridian substation located in 

Oregon which supports an increased eastbound line rating on the Summer Lake to 

Hemingway line from 400 MW to 550 MW. 

 This investment supports load growth and the ability to move additional 

resources and reserves from PacifiCorp’s western control area to its 

eastern control area, supporting reliability and load service. 

Oregon/Washington/California

o Participated with BPA in a number of upgrades to the California-Oregon Intertie 

(COI), including two new series capacitor banks at Bakeoven substation; 500 kV 

capacitor banks at Captain Jack and Slatt substations; reconductoring of a section 

of the 500 kV line; and replacement and upgrade of the Malin substation series 

capacitor;

o Reconductored the 230 kV tie line between Dixonville 500 kV and Dixonville 

230 kV;

o Installed the new Nickel Mountain 230-115 kV substation and converted Line 37 

in southwest Oregon from 69 to 115 kV; 

o Converted Line 3 in the Medford, Oregon area and Line 1 in the Yreka, California 

area from 69 kV to 115 kV; 

o Reconductored 5 miles of the Union Gap to North Park 115 kV line in Yakima 

Washington. 

 These investments helped maximize the transmission system’s capabilities 

and provided numerous system and customer benefits, including:

Increased the COI operating capability by 300 MW;
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

77

Improved the Company’s ability to move resources to customer 

loads;

Enabled operation of the COI at its limits in the summer months, 

increasing the system capability by an average of 80 MW and 

supporting customer load growth;

Improved reliability and support for customer load growth in 

southern Oregon and northern California;

Complied with required NERC and WECC reliability standards 

and improved service to customers in the Yakima, Washington 

area.

These improvements have enabled more efficient use of the transmission system and, coupled 

with the recent economic sluggishness, have helped meet short-term needs. However, with 

projected long-term growth and the need for additional resources as depicted in our customers’ 

load and resource forecasts, PacifiCorp’s transmission system is approaching the point where no 

additional capacity is available, requiring additional transmission infrastructure to meet the longterm needs of our customers. 
PACIFICORP – 2013 IRP CHAPTER 4 – TRANSMISSION

78
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

79

CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

CHAPTER HIGHLIGHTS

On both a capacity and energy basis, PacifiCorp calculates load and resource 

balances using existing resource levels, forecasted loads and sales, and reserve 

requirements. The capacity balance compares existing resource capability at the 

time of the coincident system peak load hour.

For capacity expansion planning, the Company uses a 13-percent planning reserve 

margin applied to PacifiCorp’s obligation (Loads – Interruptibles – DSM). The 13-

percent planning reserve margin is supported by Stochastic Loss of Load 

Probability Study in Appendix I.

The system coincident peak load is forecasted to grow at a compounded average 

annual growth rate of 1.2 percent for 2013 through 2022. On an energy basis, 

PacifiCorp expects system-wide average load growth of 1.1 percent per year from 

2013 through 2022. 

The Company has updated the calculation of the Load and Resource balance in-step 

with the upgraded IRP models. Certain items have moved from one component 

category to another. Sales moved from increasing obligation to reducing existing 

resources. Non-Owned Reserves moved from increasing reserves to reducing 

existing resources. Existing DSM and Interruptible contracts moved from 

increasing Existing Resources to reducing obligation. 

The Company projects a summer peak resource deficit of 824 MW for the 

PacifiCorp system beginning in 2013. The table below shows the system capacity 

position forecast, indicating the widening capacity deficit, which reaches 2,308 MW 

by 2022.

The near-term deficit will be met by incremental demand-side management 

programs, and market purchases. 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

80

Introduction

This chapter presents PacifiCorp’s assessment of resource need, focusing on the first ten years of 

the IRP’s 20-year study period, 2013 through 2022. The Company’s long-term load forecasts 

(both energy and coincident peak load) for each state and the system as a whole are addressed in 

detail in Appendix A. The summary level system coincident peak is presented first, followed by 

a profile of PacifiCorp’s existing resources. Finally, load and resource balances for capacity and 

energy are presented. These balances are comprised of a year-by-year comparison of projected 

loads against the resource base without new additions. This comparison indicates when 

PacifiCorp is expected to be either deficit or surplus on both a capacity and energy basis for each 

year of the planning horizon.

System Coincident Peak Load Forecast

The system coincident peak load is the maximum load on the system in any hour in a one-year 

period. The Company’s long-term load forecasts (both energy and coincident peak) for each 

state and the system are addressed in detail in Appendix A.

The 2013 IRP used the Company’s July 2012 load forecast. Table 5.1 shows the annual 

coincident peak load stated in megawatts as reported in the capacity load and resource balance

prior to any load reductions from energy efficiency (Class 2 DSM). The system peak load grows 

at a compounded average annual growth rate (CAAGR) of 1.2 percent for 2013 through 2022. 

Table 5.1 – Forecasted System Coincidental Peak Load in Megawatts, Prior to Energy 

Efficiency Reductions

Region 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

System 10,136 10,330 10,495 10,359 10,512 10,687 10,816 10,971 11,133 11,280 

Existing Resources

For the forecasted 2013 summer peak, PacifiCorp owns, or has interest in, resources with an 

expected system peak capacity of 11,964 MW. Table 5.2 provides anticipated system peak 

capacity ratings by resource category as reflected in the IRP load and resource balance for 2013. 

Note that capacity ratings in the following tables are rounded to the nearest megawatt and a 

column shows the Load and Resource balance capacity value at the time of system coincident 

peak.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

81

Table 5.2 – 2013 Capacity Contribution at System Peak for Existing Resources

Resource Type 1/

L&R Balance 

Capacity at 

System Peak 

(MW) 2/ Percent (%)

Pulverized Coal 6,168 51.6%

Gas-CCCT 1,994 16.7%

Gas-SCCT 562 4.7%

Hydroelectric 913 7.6%

DSM 3/

407 3.4%

Renewables 121 1.0%

Purchase 4/

1,487 12.4%

Qualifying Facilities 171 1.4%

Interruptible 141 1.2%

Total 11,964 100%

1/ Sales and Non-Owned Reserves are not included.

2/ Represents the capacity available at the time of system peak used for preparation of the 

capacity load and resource balance. For specific definitions by resource type see the section 

entitled, “Load and Resource Balance Components”, later in this chapter.

3/ DSM includes existing Class 1 and Class 2 programs.

4/ Purchases constitute contracts that do not fall into other categories such as hydroelectric, 

renewables, and natural gas.

Thermal Plants 

Table 5.3 lists existing PacifiCorp’s coal fired thermal plants and Table 5.4 lists existing natural 

gas fired plants. The assumed end of life dates are used for the 2013 IRP modeling of existing 

coal resources, additional information on methodology is in Chapter 7. The IRP confidential 

Volume III goes into additional analysis on coal plants.

Table 5.3 – Coal Fired Plants

Plant

PacifiCorp 

Percentage Share 

(%) State

L&R Balance 

Capacity at System 

Peak (MW)

Assumed End 

of Life Year

Carbon 1 100 Utah 67 2014

Carbon 2 100 Utah 105 2014

Cholla 4 100 Arizona 387 2042

Colstrip 3 10 Montana 74 2046

Colstrip 4 10 Montana 74 2046

Craig 1 19 Colorado 84 2034

Craig 2 19 Colorado 84 2034

Dave Johnston 1 100 Wyoming 106 2027

Dave Johnston 2 100 Wyoming 106 2027

Dave Johnston 3 100 Wyoming 220 2027

Dave Johnston 4 100 Wyoming 330 2027

Hayden 1 24 Colorado 45 2030
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

82

Plant

PacifiCorp 

Percentage Share 

(%) State

L&R Balance 

Capacity at System 

Peak (MW)

Assumed End 

of Life Year

Hayden 2 13 Colorado 33 2030

Hunter 1 94 Utah 418 2042

Hunter 2 60 Utah 269 2042

Hunter 3 100 Utah 479 2042

Huntington 1 100 Utah 459 2036

Huntington 2 100 Utah 450 2036

Jim Bridger 1 67 Wyoming 354 2037

Jim Bridger 2 67 Wyoming 363 2037

Jim Bridger 3 67 Wyoming 349 2037

Jim Bridger 4 67 Wyoming 353 2037

Naughton 1 100 Wyoming 158 2029

Naughton 2 100 Wyoming 205 2029

Naughton 3* 100 Wyoming 330 2029

Wyodak 80 Wyoming 268 2039

TOTAL – Coal 6,168

* Naughton 3 to repower to Natural Gas fueled generators in early 2015.

Table 5.4 – Natural Gas Plants

Natural Gas -fueled

PacifiCorp 

Percentage 

Share (%) State

L&R Balance 

Capacity at System 

Peak (MW)

Chehalis 100 Washington 477

Currant Creek 100 Utah 506

Gadsby 1 100 Utah 57 

Gadsby 2 100 Utah 69 

Gadsby 3 100 Utah 105

Gadsby 4 100 Utah 39

Gadsby 5 100 Utah 39

Gadsby 6 100 Utah 39

Hermiston 1 * 50 Oregon 233

Hermiston 2 * 50 Oregon 233

Lake Side 100 Utah 545

Lake Side 2 ** 100 Utah 628

James River Cogen (CHP) 100 Washington 14

West Valley – Lease 0 Utah 200

TOTAL – Gas and Combined Heat & Power 2,556

* Hermiston plant 50% owned and 50% under long-term contract.

** Lake Side 2 is currently under construction with in-service date of mid-2014.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

83

Renewables 

PacifiCorp’s renewable resources, presented by resource type, are described below.

Wind

PacifiCorp either owns or purchases under contract 2,186 MW of wind resources. Since the 2011 

IRP Update, the Company has entered into power purchase agreements totaling 160 MW:

Meadow Creek 

- North Point 

- Five Pine

Butter Creek 

- High Plateau

- Mule Hollow

- Lower Ridge

- Pine City

Table 5.5 shows existing wind facilities owned by PacifiCorp, while Table 5.6 shows existing 

wind power purchase agreements.

Table 5.5 – PacifiCorp-owned Wind Resources

Utility-Owned Wind Projects

Capacity 

(MW)

L&R Balance 

Capacity at System 

Peak (MW)

In-Service 

Year State

Foote Creek I * 33 2 2005 WY

Leaning Juniper 101 4 2006 OR

Goodnoe Hills East Wind 94 4 2007 WA

Marengo 140 6 2007 WA

Marengo II 70 3 2008 WA

Glenrock Wind I 99 4 2008 WY

Glenrock Wind III 39 2 2008 WY

Rolling Hills Wind 99 4 2008 WY

Seven Mile Hill Wind 99 4 2008 WY

Seven Mile Hill Wind II 20 1 2008 WY

High Plains 99 4 2009 WY

McFadden Ridge 1 29 1 2009 WY

Dunlap 1 111 4 2010 WY

TOTAL – Owned Wind 1,032 43

*Net total capacity for Foote Creek I is 40 MW.

Table 5.6 – Wind Power Purchase Agreements and Exchanges

Power Purchase Agreements / 

Exchanges

Capacity 

(MW)

L&R Balance 

Capacity at 

System Peak 

(MW)

In-Service 

Year State

Foote Creek II 2 0 2005 WY

Foote Creek III 25 1 2005 WY

Foote Creek IV 17 1 2005 WY

Combine Hills 41 2 2003 OR

Stateline Wind 175 17 2002 OR / WA

Wolverine Creek 65 3 2005 ID

Rock River I 50 2 2006 WY

Mountain Wind Power I 60 3 2008 WY
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

84

Power Purchase Agreements / 

Exchanges

Capacity 

(MW)

L&R Balance 

Capacity at 

System Peak 

(MW)

In-Service 

Year State

Mountain Wind Power II 80 3 2008 WY

Spanish Fork Wind Park 2 19 1 2008 UT

Three Buttes Wind Power (Duke) 99 4 2009 WY

Oregon Wind Farms I 45 3 2009 OR

Oregon Wind Farms II 20 0 2010 OR

Casper Wind 17 0 2010 WY

Top of the World 200 8 2010 WY

Power County Wind Park North 22 1 2011 ID

Power County Wind Park South 22 1 2011 ID

Meadow Creek Project – North Point * 80 3 2012 ID

Meadow Creek Project – Five Pine * 40 2 2012 ID

Butter Creek – High Plateau * 10 0 2013 OR

Butter Creek – Lower Ridge * 10 0 2013 OR

Butter Creek – Mule Hollow * 10 0 2013 OR

Butter Creek – Pine City * 10 0 2013 OR

TOTAL – Purchased Wind 1,154 55

*New since the 2011 IRP Update.

Geothermal

PacifiCorp owns and operates the Blundell Geothermal Plant in Utah, which uses naturally 

created steam to generate electricity. The plant has a net generation capacity of 34 MW. 

Blundell is a fully renewable, zero-discharge facility. The bottoming cycle, which increased the 

output by 11 MW, was completed at the end of 2007. The Oregon Institute of Technology added 

a new small qualifying facility (QF) using geothermal technologies to produce renewable power 

for the campus and is rated at 0.28 MW. The Company has also entered into a Qualifying 

Facility agreement for a 10 MW Oregon Geothermal plant scheduled to be online in late 2013.

Biomass / Biogas

Since the 2011 IRP Update, PacifiCorp has added more than 8 MW of Biogas resources. These 

types of resources are primarily Qualifying Facilities. 

Renewables Net Metering

As of year-end 2012, PacifiCorp had 4,974 net metering customers throughout its six-state 

territory, generating more than 35,000 kW using solar, hydro, wind, and fuel cell technologies. 

About 95 percent of customer generators are solar-based, followed by wind-based generation at 4 

percent of total generation.

Net metering has grown by more than 33 percent from last year. The Company averaged 114 

new net metered customers a month in 2012, compared to 84 new customers per month in 2011.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

85

Hydroelectric Generation 

PacifiCorp owns 1,145 MW34 of hydroelectric generation capacity and purchases the output from 

136 MW of other hydroelectric resources. These resources account for approximately 10 percent 

of PacifiCorp’s total generating capability, in addition to providing operational benefits such as 

flexible generation, spinning reserves and voltage control. PacifiCorp-owned hydroelectric plants 

are located in California, Idaho, Montana, Oregon, Washington, Wyoming, and Utah.

The amount of electricity PacifiCorp is able to generate or purchase from hydroelectric plants is 

dependent 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. Operational limitations of the hydroelectric facilities are impacted by varying 

water levels, licensing requirements for fish and aquatic habitat, and flood control; leading to

load and resource balance capacity values that are different from net facility capacity ratings.

Hydroelectric purchases are categorized into two groups as shown in Table 5.7, which reports 

2013 capacity included in the load and resource balance.

Table 5.7 – Hydroelectric Contracts - Load and Resource Balance Capacities

Hydroelectric Contracts 

by Load and Resource Balance Category

L&R Balance 

Capacity at System 

Peak (MW)

Hydroelectric 99

Qualifying Facilities - Hydroelectric 37

 Total Contracted Hydroelectric Resources 136

Table 5.8 provides an operational profile for each of PacifiCorp’s owned hydroelectric 

generation facilities. The dates listed refer to a calendar year.

Table 5.8 – PacifiCorp Owned Hydroelectric Generation Facilities - Load and Resource 

Balance Capacities

Plant State

L&R Balance 

Capacity at System 

Peak (MW)

West

Big Fork Montana 4

Clearwater 1 Oregon 15

Clearwater 2 Oregon 26

Copco 1 and 2 California 47

Fish Creek Oregon 0

Iron Gate California 11

JC Boyle Oregon 15

Lemolo 1 Oregon 32

Lemolo 2 Oregon 16

Merwin Washington 23

Rogue Oregon 30

Small West Hydro 1/ California / Oregon / Washington 3

 

34 2012 PacifiCorp 10-K filing shows 1,145 MW of Net Facility Capacity.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

86

Plant State

L&R Balance 

Capacity at System 

Peak (MW)

Soda Springs Oregon 12

Swift 1 Washington 240

Swift 2 2/ Washington 72

Toketee and Slide Oregon 26

East-Side / West-Side Oregon 3

Yale Washington 134

East

Bear River Idaho / Utah 86

Small East Hydro 3/ Idaho / Utah / Wyoming 29

TOTAL – Hydroelectric before contracts 824

 Hydroelectric Contracts 136

TOTAL – Hydroelectric 960

1/ Includes Bend, Condit, Fall Creek, and Wallowa Falls

2/ Cowlitz County PUD owns Swift No. 2, and is operated in coordination with the other projects by PacifiCorp 

3/ Includes Ashton, Paris, Pioneer, Weber, Stairs, Granite, Snake Creek, Olmstead, Fountain Green, Veyo, Sand 

Cove, Viva Naughton, and Gunlock

Hydroelectric Relicensing Impacts on Generation

Table 5.9 lists the estimated impacts to average annual hydro generation from FERC orders and 

relicensing settlement commitments. PacifiCorp assumes that the Klamath hydroelectric 

facilities will be decommissioned pursuant to the Klamath Hydroelectric Settlement Agreement 

in the year 2020 and that the Wallowa Falls project and other projects to be relicensed in future 

years will receive new operating licenses, but that additional operating restrictions imposed in 

new licenses, such as higher bypass flow requirements, will reduce generation available from 

these facilities.

Table 5.9 – Estimated Impact of FERC License Renewals and Relicensing Settlement 

Commitments on Hydroelectric Generation

Year Lost Generation (MWh)

2013 201,228

2014 201,228

2015 201,228

2016 201,228

2017 201,228

2018 201,228

2019 201,228

2020 918,048

2021 918,048

2022 918,048

2023 918,048

2024 918,048

2025 918,048

2026 918,048

2027 918,048

2028 918,048

2029 918,048

2030 918,048
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

87

Year Lost Generation (MWh)

2031 918,048

2032 918,048

Demand-side Management 

DSM 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 effectively managing utility 

investments, resource costs and system operations. Those that have greater persistence and 

firmness can be reasonably relied upon as a base resource for planning purposes; those that do 

not are more suited as system reliability resource options. Reliability tools are used to avoid 

outages or high resource costs as a result of weather conditions, plant outages, market prices, and 

unanticipated system failures. DSM resources/products can be divided into four general classes 

based on their relative characteristics, the classes are:

Class 1 DSM: Resources from fully dispatchable or scheduled firm capacity product 

offerings/programs – Class 1 DSM programs are those for which capacity savings occur as 

a result of active Company control or advanced scheduling. Once customers agree to 

participate in Class 1 DSM program, the timing and persistence of the load reduction is 

involuntary on their part within the agreed upon limits and parameters of the program. In 

most cases, loads are shifted rather than avoided. Examples include residential and small 

commercial central air conditioner load control programs (“Cool Keeper”) that are 

dispatchable in nature and irrigation load management and interruptible or curtailment 

programs (which may be dispatchable or scheduled firm, depending on the particular 

program design and/or event noticing requirements). 

Class 2 DSM: Resources from non-dispatchable, firm energy and capacity product 

offerings/programs – Class 2 DSM programs are those for which sustainable energy and 

related capacity savings are achieved through facilitation of technological advancements in 

equipment, appliances, lighting and structures, or repeatable and predictable voluntary 

actions on a customer’s part to manage the energy use at their facility or home. Class 2 DSM 

programs generally provide financial and/or service incentives to customers to improve the 

efficiency of existing or new customer-owned facilities through the installation of more 

efficient equipment such as lighting, motors, air conditioners, or appliances or upgrading 

building efficiency through improved insulation levels, windows, etc. however the category 

has recently been expanded to include strategic energy management efforts at business 

facilities and home energy reports in the residential sector. The savings endure (are 

considered firm) over the life of the improvement or customer action. Program examples 

include comprehensive commercial and industrial new and retrofit energy efficiency 

programs (“Energy FinAnswer” and “FinAnswer Express”), refrigerator recycling programs 

(“See ya later, refrigerator®”), comprehensive home improvement retrofit programs (“Home 

Energy Saving”), strategic energy management and home energy reports. 

Class 3 DSM: Resources from price responsive energy and capacity product 

offerings/programs – Class 3 DSM programs seek to achieve short-duration (hour by hour) 

energy and capacity savings from actions taken by customers voluntarily, based on a 

financial incentive or signal. Savings are measured at a customer-by-customer level (via 

metering and/or metering data analysis against baselines), and customers are compensated or 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

88

in accordance with a program’s pricing parameters. As a result of their voluntary nature, 

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 profile provide 

sufficient information for a reliable diversity result for modeling and planning purposes. 

Savings typically only endure for the duration of the incentive offering and in many cases 

loads tend to be shifted rather than avoided. Program examples include large customer 

energy bid programs (“Energy Exchange”), time-of-use pricing plans, critical peak pricing 

plans, and inverted block tariff designs. Although the impacts of such programs may not be

explicitly considered in the resource planning process however are captured naturally in 

long-term load growth patterns and forecasts. 

Class 4 DSM: Non-incented behavioral based savings achieved through broad energy 

education and communication efforts – Class 4 DSM programs promote reductions in 

energy or capacity usage through broad based energy education and communication efforts. 

The program objectives are to help customers better understand how to manage their energy 

usage through no cost actions such as conservative thermostat settings and turning off 

appliances, equipment and lights when not in use. The programs also are used to increase 

customer awareness of additional actions they might take to save energy and the service and 

financial tools available to assist them. Class 4 DSM programs help foster an understanding 

and appreciation of why utilities seek customer participation in Classes 1, 2 and 3 DSM 

programs. Program examples include Company brochures with energy savings tips, customer 

newsletters focusing on energy efficiency, case studies of customer energy efficiency 

projects, and public education and awareness programs such as “Let’s turn the answers on” 

and “wattsmart” campaigns. Like Class 3 resources, the impacts of such programs may not 

be explicitly considered in the resource planning process however are captured naturally in 

long-term load growth patterns and forecasts

PacifiCorp has been operating successful DSM programs since the late 1970s. While the 

Company’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 2012 investments of nearly $120

million (all states). Work continues on the expansion of program portfolios and savings 

opportunities in all states while at the same time adapting programs and measure baselines to 

reflect the impacts of advancing state and federal energy codes and standards. In Oregon the 

Company continues to work closely with the Energy Trust of Oregon to help identify additional 

resource opportunities, improve delivery and communication coordination, and ensure adequate 

funding and Company support in pursuit of DSM resource targets. Washington’s portfolio and 

programs continue to evolve under Initiative 937 requirements and the performance of 

Wyoming’s program portfolio has shown increasing improvement since the latest round of 

program revisions were approved in November, 2011. Finally, significant changes to the Idaho 

and Utah Class 1 DSM portfolios are underway in an effort to improve program effectiveness 

and economics in those states and providing for a more viable delivery platforms for the 

expansion of Class 1 programs to the west side of the system as the need and value for new westside capacity resources dictate.

The following represents a brief summary of the existing resources by class.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

89

Class 1 Demand-side Management

Currently there are two Class 1 DSM programs running across PacifiCorp’s six-state service 

area; Utah’s “Cool Keeper” residential and small commercial air conditioner load control 

program and Idaho’s and Utah’s dispatchable irrigation load management programs. In 2012

these programs accounted for over 350 MW of realized reduction from Class 1 DSM program 

resources under management helping the Company better manage demand during peak periods35. 

Class 2 Demand-side Management

The Company currently manages ten distinct Class 2 DSM products, many of which are offered 

in multiple states. In all, the combination of Class 2 DSM programs across the five states where 

the Company is directly responsible for delivery totals thirty-one. The cumulative historical 

energy and capacity savings (1992-2012) associated with Class 2 DSM program activity has 

accounted for over 5.4 million MWh and approximately 925 MW of non-coincident peak load 

reductions. 

Class 3 Demand-side Management

The Company has numerous Class 3 DSM offerings currently available. They include metered 

time-of-day and time-of-use pricing plans (in all states, availability varies by customer class), 

residential seasonal inverted block rates (Idaho, Utah and Wyoming), residential year-round 

inverted block rates (California, Oregon and Washington) and Energy Exchange programs (all 

states). System-wide, approximately 19,500 customers were participating in metered time-of-day 

and time-of-use programs as of December 31, 2011.36 All of the Company’s residential 

customers not opting for a time-of-use rates are currently subject to seasonal or year-round 

inverted block rate plans. 

Savings associated with these resources are captured within the Company’s load forecast, with 

the exception of the more immediate call-to-action programs, and are thus captured in the 

integrated resource planning framework. PacifiCorp continues to evaluate Class 3 DSM 

programs for applicability to long-term resource planning. As part of the development of the 

2013 IRP, the Company commissioned a study by The Cadmus Group to investigate the 

handling of Class 3 DSM by utilities in integrated resource planning. The study, titled 

”Treatment of Class 3 DSM Resources in Integrated Resource Planning”, is provided as 

Appendix D and provides valuable insights into methods used to account for the impacts of Class 

3 DSM resources in integrated resource planning. The study also led to a more thorough impact 

assessment of the Company’s existing Class 3 DSM offerings in the updated “Assessment of 

Long-Term, System-Wide Potential for Demand-Side and Other Supplemental Resources” 

(“DSM Potential Study”), the study that was used in the development of the revised DSM 

resource supply-curves used in the 2013 IRP. Those impacts are reflected in Table 5.10 below. 

In addition, the update to the DSM Potential Study expanded its analysis of the interactive 

effects of competing DSM resources in order to allow for modeling of all classes of DSM 

resources at the same time without the risks of over estimating their impacts. The DSM Potential 

Study is provided as Appendix D. 

 

35 Realized reductions vary by event (temperature and month and time dependent), cited load reduction represents 

the sum of the highest event performance across the three states for the two programs and account for line losses 

(are “at generator” values). 

36 Year-end 2011 participation data were used for the analysis in the DSM Potential Study. At the end of 2012, there 

were approximately 19,200 customers on time-varying rates.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

90

As discussed in Chapter 6, five Class 3 DSM programs were provided as resource options in 

preliminary IRP modeling scenarios.

Class 4 Demand-side Management

Educating customers regarding energy efficiency and load management opportunities is an 

important component of the Company’s long-term resource acquisition plan. A variety of 

channels are used to educate customers including television, radio, newspapers, bill inserts and 

messages, newsletters, school education programs, and personal contact. Load reductions due to 

Class 4 DSM activity will show up in Class 1 and Class 2 DSM program results and nonprogram reductions in the load forecast over time. 

Table 5.10 summarizes the existing DSM programs. Note that since Class 2 DSM is determined 

as an outcome of resource portfolio modeling and is included in the preferred portfolio, existing 

Class 2 DSM is shown as having zero MW37.

Table 5.10 – Existing DSM Summary, 2013-2022 

Program

Class Description

Energy Savings or Capacity 

at Generator

Included as 

Existing Resources for

2013-2022 Period

1

Residential/small 

commercial air conditioner 

load control

120 MW summer peak Yes

Irrigation load 

management 209 MW summer peak38 Yes

Interruptible contracts

2013~ 324 MW, 

2014~298 MW

2015-2022~310 MW

Yes. 

2

Company and Energy 

Trust of Oregon programs 0 MW

No. Class 2 DSM programs are 

modeled as resource options in the 

portfolio development process, and 

included in the preferred portfolio. 

3

Energy Exchange

0-1939 MW (assumes no other 

Class 3 DSM competing 

products running)

No. Program is leveraged as 

economic and reliability resource 

dependent on market prices/system 

loads.

Time-based pricing 27-143 MW summer peak,

19,500 customers

No. Historical behavior is captured 

in load forecast. Impacts estimated 

in 2013 Conservation Potential 

Assessment

Inverted rate pricing

45-123 MW summer peak,

1.5 million residential 

customers

No. Historical behavior is captured 

in load forecast. Impacts estimated 

in 2013 Conservation Potential 

Assessment

 

37 The impacts of historic acquisition rates of Class 2 DSM are backed out of the load forecast prior to modeling for 

new Class 2 DSM.

38 Assumes realized irrigation load curtailment in Idaho and Utah of 171 MW and 38 MW, respectively. 

39 2013 Assessment of Long-Term, System-Wide Potential for Demand-Side and Other Supplemental Resources.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Program

Class Description

Energy Savings or Capacity 

at Generator

Included as 

Existing Resources for

2013-2022 Period

4 Energy Education MWa/MW unavailable

No. Program impacts is captured in 

load forecast over time and other 

Class 1 and 2 DSM program 

results.

Power Purchase Contracts 

PacifiCorp obtains the remainder of its energy requirements, including any changes from 

expectations, through long-term firm contracts, short-term firm contracts, and spot market 

purchases.

Figure 5.1 presents the contract capacity in place for 2013 through 2032 as of November 2012. 

As shown, major capacity reductions in purchases and hydro contracts occur. (For planning 

purposes, PacifiCorp assumes that current qualifying facility and interruptible load contracts are 

extended through the end of the IRP study period.) Note that renewable wind contracts are 

shown at their capacity contribution levels.

Figure 5.1 – Contract Capacity in the 2013 Load and Resource Balance 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Listed below are the major contract expirations expiring between the summer 2013 and summer 

2014: 

Expiring Front Office Transactions East – 300 MW

Expiring Utah Capacity Purchase East – 200 MW

Expiring Front Office Transactions West – 100 MW

Expiring Bonneville Power Administration Spring / Summer Option – 150 MW

Net decrease for other contracts – 18 MW

Load and Resource Balance

Capacity and Energy Balance Overview

The purpose of the load and resource balance is to compare the annual obligations with the 

annual capability of PacifiCorp’s existing resources, absent new resource additions. This is done 

with respect to two views of the system, the capacity balance and energy balance.

The capacity balance compares generating capability to expected peak load at time of system 

peak load hours. It is a key part of the load and resource balance because it provides guidance as 

to the timing and severity of future resource deficits. It was developed by first determining the 

system coincident peak load hour for each of the first ten years (2013-2022) of the planning 

horizon. The peak load and load interruptible programs and load reduction DSM programs were 

netted together for each of the annual system peak hours to compute the annual peak-hour 

obligation. Then the annual firm capacity availability of the existing resources was determined 

for each of these annual system peak hours. The annual resource deficit (surplus) was then 

computed by multiplying the obligation by the planning reserve margin (PRM), and then 

subtracting the result from the existing resources.

The energy balance shows the average monthly on-peak and off-peak surplus (deficit) of energy 

over the first ten years of the planning horizon (2013-2022). The average obligation (load less 

DSM programs) was computed and subtracted from the average existing resource availability for 

each month and time-of-day period. This was done for each side of the PacifiCorp system as well 

as at the system level. The energy balance complements the capacity balance in that it also 

indicates when resource deficits occur, but it also provides insight into what type of resource will 

best fill the need. The usefulness of the energy balance is limited as it does not address the cost 

of the available energy. The economics of adding resources to the system to meet both capacity 

and energy needs are addressed with the portfolio studies described in Chapter 8.

Load and Resource Balance Components

The capacity and energy balances make use of the same load and resource components in their 

calculation. The main component categories consist of the following: existing resources, 

obligation, reserves, position, and reserve margin. The Company has updated the calculation of 

the Load and Resource balance in-step with the upgraded IRP models. Certain items have 

moved from one component category to another.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Under the new calculation, there are now negative values in the table for both the resources and 

obligation sections. This modification provides an improvement as to how resources are 

modeled and represented in the categories in relation to the updated models. The four resource 

categories are Sales, Non-Owned Reserves, Interruptibles, and Class 1 DSM. Later in the 

portfolio load and resource balance Class 2 DSM follows Class 1 DSM into the obligation 

section. Listed below are the changes for the four categories:

Sales moved from increasing obligation to reducing Existing Resources

Non-Owned Reserves moved from increasing Reserves to reducing Existing Resources

Existing Class 1 DSM moved from increasing Existing Resources to reducing obligation

Existing Interruptible contracts moved from increasing Existing Resources to reducing 

obligation

For comparability to prior IRP load and resource balance tables, Table 5.11 has been provided in 

the prior format. This next section provides a description of these various components.

Existing Resources

A description of each of the resource categories follows:

Thermal. This category includes all thermal plants that are wholly-owned or partially-owned 

by PacifiCorp. The capacity balance counts them at maximum dependable capability at time 

of system peak. The energy balance also counts them at maximum dependable capability, but 

de-rates them for forced outages and maintenance. This includes the existing fleet of 11 coalfired plants, six natural gas-fired plants, and one cogeneration unit. These thermal resources 

account for roughly two-thirds of the firm capacity available in the PacifiCorp system.

Hydro. This category includes all hydroelectric generation resources operated in the 

PacifiCorp system as well as a number of contracts providing capacity and energy from 

various counterparties. The capacity balance counts these resources by the maximum 

capability that is sustainable for one hour at the time of system peak, an approach consistent 

with current WECC capacity reporting practices. The energy associated with critical level 

stream flow is estimated and shaped by the hydroelectric dispatch from the Vista Decision 

Support System model. The energy impacts of hydro relicensing requirements, such as 

higher bypass flows that reduce generation, are also accounted for. Over 90 percent of the 

hydroelectric capacity is situated on the west side of the PacifiCorp system.

Renewable. This category comprises geothermal and variable (wind and solar) renewable 

energy capacity. The capacity balance counts the geothermal plant by the maximum 

dependable capability while the energy balance counts the maximum dependable capability 

after forced outages. 

For wind and solar resources, the Company changed its method of calculating capacity 

contributions for wind and solar resources for this IRP. Rather than using a statistical 

approach to derive peak load carrying capabilities for each resource, the Company now 

determines aggregate peak capacity credits for each resource type by analyzing historical 

energy generation data for the period 2007 through 2010. For wind resources, PacifiCorp 

calculated the capacity credit for each year by first summing the hourly generation for all 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

94

wind resources for each hour of the year and dividing the hourly generation by the aggregate 

nameplate capacity to get hourly capacity factors. The average capacity factor for the 100 

highest summer peak hours in the year is then calculated. Finally, the wind capacity credit is 

multiplied by 0.90, or 90 percent, to reflect the Company’s assumption that there is a 90 

percent probability that the wind resources will generate at the annual historical level in 

future years. The resulting annual capacity credit, averaged for the four years of historical 

data, is 4.2 percent. Since the Company has no historical data for solar resources, a similar 

set of calculations was performed based on simulated hourly solar profiles that use historic 

meteorological solar radiation data for five locations across the Company’s service territory. 

The capacity credit for solar resources is 13.6 percent assuming that most installations are 

optimized for energy output rather than peak capacity. See Appendix O for additional 

information on wind and solar peak contributions. 

Purchase. This includes all of the major contracts for purchases of firm capacity and energy 

in the PacifiCorp system. The capacity balance counts these by the maximum contract 

availability at time of system peak. The energy balance counts the optimum model dispatch. 

Purchases are considered firm and thus planning reserves are not held for them.

Qualifying Facilities (QF). All QF that provide capacity and energy are included in this 

category. Like other power purchases, the capacity balance counts them at maximum system 

peak availability and the energy balance counts them by optimum model dispatch. It should 

be noted that three of the QF resources (Kennecott, Tesoro, and US Magnesium) are 

considered non-firm and thus do not contribute to capacity planning.

Sales. This includes all contracts for the sale of firm capacity and energy. The capacity 

balance counts these contracts by the maximum obligation at time of system peak and the 

energy balance counts them by optimum model dispatch. All sales contracts are firm and thus 

planning reserves are held for them in the capacity view. Due to the way System Optimizer 

now handles the calculation of reserve margins, sales are now categorized as a resource 

modifier, and are applied as a decrease to resource capacity.

Non-owned reserves. For this IRP, non-owned reserves capacity is now categorized as a 

decrease to resource capacity to represent the treatment of Non-owned reserve capacity in the 

of System Optimizer. There are a number of counterparties that operate in the PacifiCorp 

control areas that purchase operating reserves. The annual reserve obligation is about 9 MW

and 138 MW on the west and east balancing authorities, respectively. As the balancing 

authority, PacifiCorp is required to hold reserves for these counterparties but is not required 

to serve any associated loads.

Obligation

The obligation is the total electricity demand that PacifiCorp must serve, consisting of forecasted 

retail load less Demand-side Management and less Interruptibles. The following are descriptions 

of each of these components:

Load. The largest component of the obligation is the retail load. The capacity balance counts 

the peak load (MW) at the hour of system coincident peak load. The system coincident peak 

hour is determined by summing the loads for all locations (topology bubbles with loads). 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Loads reported by East and West control areas thus reflect loads at the time of PacifiCorp’s 

coincident system peak. The energy balance counts the load as an average of monthly as well 

as annual time-of-day energy (MWa).

Dispatchable Load Control (Class 1 DSM). For this IRP, existing dispatchable load control 

program capacity is categorized as a decrease to the obligation rather than an increase to 

resource capacity as was done for prior IRPs. This change is in line with the treatment of 

DSM capacity in the latest version of System Optimizer. DSM capacity is now handled as a 

“load modifier”, which means that it reduces load in the denominator of the planning reserve 

margin formula used by the model (As noted below, the reserve margin is the difference 

between system capability and anticipated peak demand as a percentage of the peak load.) In 

contrast, prior capacity balances included existing Class 1 DSM as a resource increase.

Interruptible. There are three east-side load curtailment contracts in this category. These 

agreements with Monsanto, US Magnesium, and Nucor provide about 324 MW of load 

interruption capability at time of system peak. Both the capacity balance and energy balance 

count these resources at the level of full load interruption on the executed hours. Interruptible 

resources directly curtail load and thus planning reserves are not held for them. As with Class 

1 DSM, this resource is now categorized as a decrease to the peak load.

Reserves

The reserves are the total megawatts of planning that must be held for this load and resource 

balance. A description of the two types of reserves follows:

Planning reserves. This is the total reserves that must be held to provide the planning

reserve margin (PRM). The planning reserve margin accounts for WECC operating 

reserves

40, load forecast errors, and other long-term resource adequacy planning 

uncertainties. The following equation expresses the planning reserve requirement.

Position

The position is the resource surplus (deficit) after subtracting obligation plus required reserves 

from the resource total. While similar, the position calculation is slightly different for the 

capacity and energy views of the load and resource balance. Thus, the position calculation for 

each of the views will be presented in their respective sections.

Reserve Margin

The reserve margin is the difference between system capability and anticipated peak demand, 

measured either in megawatts or as a percentage of the peak load. A positive reserve margin 

indicates that system capabilities exceed system obligations. Conversely, a negative reserve 

margin indicates that system capabilities do not meet obligations. If system capabilities equal 

obligations, then the reserve margin is zero. It should be pointed out that the position can be 

negative when the corresponding reserve margin is non-negative. This is because the reserve 

margin is measured relative only to obligation, while the position is measured relative to 

obligation plus reserves. PacifiCorp adopted a 13 percent target planning reserve margin for the 

2013 IRP. Note that a resource can only serve load in another topology location if there is 

 

40 As part of the WECC, PacifiCorp is currently required to maintain at least 5 percent and 7 percent operating 

reserve margins on hydro and thermal load-serving resources, respectively.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

96

adequate transfer capacity. PacifiCorp captures transfer capacities as part of its capacity 

expansion planning process. The supporting loss of load probability study is included as 

Appendix I.

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 planning horizon. Then the annual firm-capacity availability of 

the existing resources is determined for each of these annual system peak hours and summed as 

follows:

Existing Resources = Thermal + Hydro + Renewable + Firm Purchases + Qualifying 

Facilities – Firm Sales – Non-owned Reserves

The peak load, Interruptible and Class 1 DSM are netted together for each of the annual system 

peak hours to compute the annual peak-hour obligation:

Obligation = Load – Class 1 DSM – Interruptibles 

The amount of reserves to be added to the obligation is then calculated. This is accomplished by 

the net system obligation calculated above multiplied by the planning reserve margin of 13%. 

The formula for this calculation is the following:

Planning Reserves = Obligation x PRM 

Finally, the annual capacity position is derived by adding the computed reserves to the 

obligation, and then subtracting this amount from existing resources as shown in the following 

formula: 

Capacity Position = Existing Resources – (Obligation + Reserves)

Firm capacity transfers from PacifiCorp’s west to east control areas are reported for the east 

capacity balance, while capacity transfers from the east to west control areas are reported for the 

west capacity balance. Capacity transfers represent the optimized control area interchange at the 

time of the system coincident peak load as determined by the System Optimizer model.41

Load and Resource Balance Assumptions

The assumptions underlying the current load and resource balance are generally the same as 

those from the 2011 IRP update with a few exceptions. The following is a summary of these 

assumption changes:

Wind Additions. Since the 2011 IRP Update the following wind resource additions are 

included in existing portion of the Load and Resource balance: 

 

41 West-to-east and east-to-west transfers 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. 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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New Qualifying Facility Wind Plants 

- Meadow Creek Project – Five Pine – 40 MW

- Meadow Creek Project – North Point – 80 MW

- Lower Ridge Wind – 10 MW

- Mule Hollow Wind – 10 MW

- High Plateau Wind – 10 MW

- Pine City Wind – 10 MW

Solar Wind. PacifiCorp has acquired a 2 MW photovoltaic solar plant in eastern Oregon to 

meet the Oregon Statute ORS 757.370, which requires the Company to acquire 8.7 MWac of 

qualifying photovoltaic system capacity by 2020.

- Black Cap Solar – 2 MW

Coal plant turbine upgrades. The current load and resource balance assumes 14 MW of 

coal plant turbine upgrades for Craig unit 2 (2 MW) and Jim Bridger Unit 2 (12 MW), 

completing the scheduled upgrades as noted in the 2011 IRP Update Report. 

Construction of Lake Side 2. PacifiCorp has begun construction of the Lake Side 2 plant in 

Utah. This plant is expected to have a net capacity of 645 MW. 

Capacity Balance Results

PacifiCorp has updated the format for the load and resource balance table in Table 5.12. For 

reference, the Company has also provided table 5.11 which shows the same underlying 

information but in the table format used in prior IRPs. The tables show the annual capacity 

balances and component line items using a target planning reserve margin of 13 percent to 

calculate the planning reserve amount. Balances for the system as well as PacifiCorp’s east and 

west balancing authority are shown. (It should be emphasized that while west and east balances 

are broken out separately, the PacifiCorp system is planned for and dispatched on a system 

basis.) Also note that the new Qualifying Facility wind projects listed above are reported under 

the Qualifying Facilities line item rather than the Renewables line item.

Table 5.11 provides a view of the Load and Resource balance using the old IRP’s format for 

comparability to past IRP tables on the system level. 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Table 5.11 – Old IRP Format: System Capacity Loads and Resources without Resource 

Additions

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

System

Thermal 8,724 9,150 8,984 8,974 8,957 8,957 8,957 8,957 8,957 8,954

Hydroelectric 913 891 916 917 915 912 858 861 782 785

Class 1 DSM 407 407 407 407 407 407 407 407 407 407

Renewable 121 121 119 119 119 119 119 119 118 99

Purchase 1,487 836 842 411 298 298 287 287 259 259

Qualifying Facilities 171 172 172 162 162 162 161 162 162 114

Interruptible 141 143 155 155 155 155 155 155 155 155

Transfers (2) (1) 0 0 0 0 0 (2) 0 0

System Existing Resources 11,962 11,719 11,595 11,145 11,013 11,010 10,944 10,946 10,840 10,773

System Total Resources 11,962 11,719 11,595 11,145 11,013 11,010 10,944 10,946 10,840 10,773

Load 10,136 10,330 10,495 10,359 10,512 10,687 10,816 10,971 11,133 11,280

Sale 1,292 992 890 834 748 748 748 749 267 261

System Obligation 11,428 11,322 11,385 11,193 11,260 11,435 11,564 11,720 11,400 11,541

Planning reserves (13%) 1,246 1,271 1,291 1,274 1,294 1,316 1,333 1,353 1,374 1,393

Non-owned reserves 112 112 147 147 147 147 147 147 147 147

System Reserves 1,358 1,383 1,438 1,421 1,441 1,463 1,480 1,500 1,521 1,540

System Obligation + Reserves 12,786 12,705 12,823 12,614 12,701 12,898 13,044 13,220 12,921 13,081

System Position (824) (986) (1,228) (1,469) (1,688) (1,888) (2,100) (2,274) (2,081) (2,308)
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Table 5.12 – Updated Format: System Capacity Loads and Resources without Resource 

Additions

Figures 5.2 through 5.4 charts the table above for annual capacity position (resource surplus or 

deficits) for the system, west balancing area, and east balancing area, respectively. The east 

increase in 2014 is primarily due to the addition of Lake Side 2 natural gas plant.

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

East

Thermal 6,200 6,626 6,460 6,454 6,454 6,454 6,454 6,454 6,454 6,454

Hydroelectric 137 140 140 135 135 132 135 135 135 135

Renewable 85 85 83 83 83 83 83 83 82 80

Purchase 1,005 611 611 398 285 285 285 285 257 257

Qualifying Facilities 83 73 73 73 73 73 73 73 73 25

Sale (1,032) (732) (730) (724) (638) (638) (638) (639) (158) (158)

Non-Owned Reserves (103) (103) (138) (138) (138) (138) (138) (138) (138) (138)

Transfers 750 829 737 672 678 683 1,124 1,122 1,124 706

East Existing Resources 7,125 7,529 7,236 6,953 6,932 6,934 7,378 7,375 7,829 7,361

Load 6,920 7,061 7,188 6,994 7,105 7,217 7,337 7,455 7,584 7,697

Existing Resources:

Interruptible (141) (143) (155) (155) (155) (155) (155) (155) (155) (155)

DSM (379) (379) (379) (379) (379) (379) (379) (379) (379) (379)

East obligation 6,400 6,539 6,654 6,460 6,571 6,683 6,803 6,921 7,050 7,163

Planning Reserves (13%) 832 850 865 840 854 869 884 900 917 931

East Reserves 832 850 865 840 854 869 884 900 917 931

East Obligation + Reserves 7,232 7,389 7,519 7,300 7,425 7,552 7,687 7,821 7,967 8,094

East Position (107) 140 (283) (347) (493) (618) (309) (446) (138) (733)

East Reserve Margin 11.3% 15.1% 8.7% 7.6% 5.5% 3.8% 8.5% 6.6% 11.0% 2.8%

West

Thermal 2,524 2,524 2,524 2,520 2,503 2,503 2,503 2,503 2,503 2,500

Hydroelectric 776 751 776 782 780 780 723 726 647 650

Renewable 36 36 36 36 36 36 36 36 36 19

Purchase 482 225 231 13 13 13 2 2 2 2

Qualifying Facilities 88 99 99 89 89 89 88 89 89 89

Sale (260) (260) (160) (110) (110) (110) (110) (110) (109) (103)

Non-Owned Reserves (9) (9) (9) (9) (9) (9) (9) (9) (9) (9)

Transfers (752) (830) (737) (672) (678) (683) (1,124) (1,124) (1,124) (706)

West Existing Resources 2,885 2,536 2,760 2,649 2,624 2,619 2,109 2,113 2,035 2,442

Load 3,216 3,269 3,307 3,365 3,407 3,470 3,479 3,516 3,549 3,583

Existing Resources:

Interruptible 0 0 0 0 0 0 0 0 0 0

DSM (28) (28) (28) (28) (28) (28) (28) (28) (28) (28)

West obligation 3,188 3,241 3,279 3,337 3,379 3,442 3,451 3,488 3,521 3,555

Planning Reserves (13%) 414 421 426 434 439 447 449 453 458 462

West Reserves 414 421 426 434 439 447 449 453 458 462

West Obligation + Reserves 3,602 3,662 3,705 3,771 3,818 3,889 3,900 3,941 3,979 4,017

West Position (717) (1,126) (945) (1,122) (1,194) (1,270) (1,791) (1,828) (1,944) (1,575)

West Reserve Margin (9.5%) (21.8%) (15.8%) (20.6%) (22.3%) (23.9%) (38.9%) (39.4%) (42.2%) (31.3%)

System

Total Resources 10,010 10,065 9,996 9,602 9,556 9,553 9,487 9,488 9,864 9,803

Obligation 9,588 9,780 9,933 9,797 9,950 10,125 10,254 10,409 10,571 10,718

Reserves 1,246 1,271 1,291 1,274 1,294 1,316 1,333 1,353 1,374 1,393

Obligation + Reserves 10,834 11,051 11,224 11,071 11,244 11,441 11,587 11,762 11,945 12,111

System Position (824) (986) (1,228) (1,469) (1,688) (1,888) (2,100) (2,274) (2,081) (2,308)

Reserve Margin 4.4% 2.9% 0.6% (2.0%) (4.0%) (5.6%) (7.5%) (8.8%) (6.7%) (8.5%)
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Figure 5.2 – System Capacity Position Trend

Figure 5.3 – West Capacity Position Trend

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Megawatts

Obligation + 13% Planning Reserves

Obligation 

East Existing Resources

2022 Resource Gap

2,308 MW 2013 Resource Gap

824 MW

West Existing Resources

13% Reserves 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Megawatts

Obligation + 13% Planning Reserves

Obligation 

2022 Resource Gap

1,575 MW

2013 Resource Gap

717 MW

West Existing Resources

13% Reserves 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Figure 5.4 – East Capacity Position Trend

Energy Balance Determination

Methodology

The energy balance shows the average monthly on-peak and off-peak surplus (deficit) of energy. 

The on-peak hours are weekdays and Saturdays from hour-ending 7:00 am to 10:00 pm; off-peak 

hours are all other hours. Peaking resources such as the Gadsby units are counted only for the 

on-peak hours. This is calculated using the formulas that follow. Please refer to the section on 

load and resource balance components for details on how energy for each component is counted. 

Existing Resources = Thermal + Hydro + Class 1 DSM + Renewable + Firm Purchases + QF 

+ Interruptible – Sales

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 (13 percent PRM)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Megawatts

Obligation + 13% Planning Reserves

Obligation 

East Existing Resources

2022 Resource Gap

733 MW

2013 Resource Gap

107 MW

13% Reserves 
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Energy Balance Results

The capacity position shows how existing resources and loads balance during the coincident 

peak load hour of the year inclusive of a planning reserve margin. Outside of the peak hour, the 

Company economically dispatches its resources to meet changing load conditions taking into 

consideration prevailing market conditions. In those periods when system resource costs are less 

than the prevailing market price for power, the Company can dispatch resources that in aggregate 

exceed then-current load obligations facilitating off system sales that reduce customer costs. 

Conversely, at times when system resource costs fall below prevailing market prices, system 

balancing market purchases can be used to meet then-current system load obligations to reduce 

customer costs. The economic dispatch of system resources is critical to how the Company 

manages net power costs. Figures 5.5 through 5.7 provide for the system, west balancing area, 

and east balancing area, respectively, a snapshot of how existing system resources could be used 

to meet forecasted load across on-peak and off-peak periods given current planning assumptions 

and current wholesale power and natural gas prices.42 The figures show expected monthly 

energy production from resources during on-peak and off-peak periods in relation to load 

assuming no additional resources are added to PacifiCorp’s system. At times, resources are 

economically dispatched above load levels facilitating net system balancing sales. This occurs 

more often in off-peak periods than in on-peak periods. At other times, economic conditions 

result in net system balancing purchases, which occur more often during on-peak periods. 

Figures 5.5 through 5.7 also show how much energy is available from existing resources at any 

given point in time. Those periods where all available resource energy falls below forecasted 

loads are highlighted in red, and are indicative of short energy positions absent the addition of 

incremental resources to the portfolio. During on-peak periods, the first energy shortfall appears 

in July 2018, and by 2022 available system energy falls short of monthly loads in January, July, 

August, and October. During off-peak periods, there are no energy shortfalls through the 2022 

timeframe.

 

42 On-peak hours are defined as hour ending 7 AM through 10 PM, Monday through Saturday, excluding NERCobserved holidays. All other hours define off-peak periods.
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Figure 5.5 – System Average Monthly and Annual Energy Positions

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

On-Peak Energy Balance

System Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall System Energy Available Load

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

Off-Peak Energy Balance

System Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall System Energy Available Load
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

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Figure 5.6 – West Average Monthly and Annual Energy Positions

0

500

1,000

1,500

2,000

2,500

3,000

3,500 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

West On-Peak Energy Balance

Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall Energy Available Load

0

500

1,000

1,500

2,000

2,500

3,000

3,500 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

West Off-Peak Energy Balance

Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall Energy Available Load
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

105

Figure 5.7 – East Average Monthly and Annual Energy Positions

Load and Resource Balance Conclusions

Without additional resources the Company projects a summer peak system resource deficit of 

824 MW beginning in 2013. The near-term deficit will be filled by additional DSM programs 

and market purchases. 

0

500

1,000

1,500

2,000

2,500

3,000

3,500 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

East On-Peak Energy Balance

Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall Energy Available Load

0

500

1,000

1,500

2,000

2,500

3,000

3,500 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 GWh

East Off-Peak Energy Balance

Energy at or Below Load Net Balancing Sale Net Balancing Purchase

Energy Shortfall Energy Available Load
PACIFICORP – 2013 IRP CHAPTER 5 – RESOURCE NEEDS ASSESSMENT

106
PACIFICORP – 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

107

CHAPTER 6 – RESOURCE OPTIONS

Introduction

This chapter provides background information on the various resources considered in the IRP for 

meeting future capacity and energy needs. Organized by major category, these resources consist 

of supply-side generation (utility-scaled and distributed resources), DSM programs, transmission 

resources, and market purchases. For each resource category, the chapter discusses the criteria 

for resource selection, presents the options and associated attributes, and describes the 

technologies. In addition, for supply-side resources, the chapter describes how PacifiCorp 

addressed long-term cost trends and uncertainty in deriving cost figures.

Supply-side Resources

The list of supply-side resource options has been updated to reflect the realities evidenced 

through permitting, internally-generated studies, and externally-commissioned studies 

undertaken to better understand the details of available generation resources. Capital costs, in 

general, have remained stable due to recessionary economic conditions in 2008-2009 and a very 

CHAPTER HIGHLIGHTS

PacifiCorp developed resource attributes and costs for expansion resources that 

reflect updated information from project experience, public meeting comments, and 

studies. Current economic conditions have reduced capital cost uncertainty. Longterm resource pricing, especially for emerging technologies, remains a challenge to 

predict.

Resource costs have been generally stable since the previous IRP due to the 

economic slow-down from 2008 through 2012.

Large utility scale solar photovoltaic options have been included in this IRP.

Geothermal purchase power agreements (PPA) have been included as supply-side 

options in this IRP. 

An expanded number of combustion turbine types and configurations are provided 

in the current Supply Side Resource options table.

Energy storage systems continue to be of interest with options included for 

advanced large batteries (one megawatt) as well as pumped hydro and compressed 

air energy storage. 

A 2013 resource potential study, conducted by The Cadmus Group, served as the 

basis for updated resource characterizations covering demand-side management 

(DSM) and distributed generation. The demand-side resource information was 

converted into supply curves by measure or product type and competed against 

other resource alternatives in IRP modeling. 

PacifiCorp applied cost reduction credits for energy efficiency, reflecting risk

mitigation benefits, transmission & distribution investment deferral benefits, and a 

10 percent market price credit for Washington and Oregon as required by the 

Northwest Power Act.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

108

gradual recovery experienced in 2010-2012. Natural gas-fueled plants are expected to fulfill the 

current and expected base-load obligations to meet customer needs and therefore natural gasfueled resources have received a significant level of attention. A variety of gas-fueled generating 

resources were selected after consultation with major suppliers, large engineering-consulting 

firms, and primary stakeholders. New coal-fueled resources did not receive as much focus during 

this cycle due to ongoing environmental permitting and sociopolitical obstacles for siting new 

coal-fueled generation. The capital and operating costs of simple and combined-cycle gas 

turbine plants have remained relatively low in recent years, with a flat to slightly increasing cost 

trend in the past two years. Certain alternative (i.e. non-fossil-fuel) energy resources such as 

wind and solar received greater emphasis during this review cycle compared to prior reviews. 

Specifically, additional solar and wind resource options have been included in the analysis 

compared to the previous IRP to capture cost and performance differences across different 

regions within the service territory. Additional solar resources include utility-size photovoltaic 

systems (PV) utilizing both fixed and single axis tracking. Energy storage options of at least one 

megawatt continue to be of interest among the stakeholders, with options analyzed for large 

pumped hydro projects, as well as advanced battery, fly wheel and compressed air energy storage 

projects.

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 2011 IRP. This resource list was 

reviewed and modified to reflect stakeholder input, environmental factors, cost dynamics, and 

permitting realities. Once the basic list of resources was determined, the cost and performance 

attributes for each resource were estimated. The information sources used are listed below, 

followed by a brief description on how they were used in the development of the Supply Side 

Resource table:

Recent (2012) third-party, cost and performance estimates;

Prior third-party, cost and performance studies or updated earlier estimates;

Actual PacifiCorp or electric utility industry installations, providing current 

construction/maintenance costs and performance data with similar resource attributes;

Projected PacifiCorp or electric utility industry installations, providing projected 

construction/maintenance costs and performance data of similar or identical resource 

options; and

Recent Requests for Proposals and Requests for Information. 

Recent third-party engineering information from original equipment manufacturers were used to 

develop capital, operating and maintenance costs, performance and operating characteristics and 

planned outage cycle estimates. Engineering-consultants or government agencies have access to 

this data based on prior research studies, academia, actual installations, and direct information 

exchanges with original equipment manufacturers. Examples of this type of effort include the 

2012 Black & Veatch estimates prepared for simple cycle and combined cycle options and the 

2012 HDR Engineering (HDR) study of various storage technologies.

Prior studies include studies prepared by others but not specifically for the Integrated Resource 

Plan process, and include similar types of cost and performance data provided in the Supply Side 

Resource table. This information includes publicly available engineering and government agency 
PACIFICORP – 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

109

reports. Examples of this type of study include the United States Department of Energy’s 2011 

Wind Technologies Market Report.

PacifiCorp or industry installations provide a solid basis for capital/maintenance costs and 

operating histories. Performance characteristics were adjusted to site-specific conditions 

identified in the Supply Side Resource Table. For instance, the capacity of combustion turbine 

based resources varies with elevation and ambient temperature and, to a lesser extent, relative 

humidity. Adjustments were made for site-specific elevations of actual plants to more generic, 

regional elevations for future resources. Examples of actual PacifiCorp installations that were 

used to develop the cost and performance information provided in the Supply Side Resource 

table include the Gadsby GE LM6000PC peaking units, the Lake Side 1 combined cycle plant 

and PacifiCorp’s recent Black Cap solar photovoltaic project in Oregon.

Potential PacifiCorp resources also provide a source for cost and performance data. As with the 

actual installations, performance data was adjusted to match site conditions. Examples of 

potential or under-construction resources that have been used in developing information in the 

Supply Side Resource table include the Lake Side 2 combined cycle plant, the Vogtle Nuclear 

Plant currently under construction in Georgia, as well as the proposed McFadden Ridge 2 Wind 

Plant and 12-Mile Hill Wind Plant sites.

Recent Requests for Information (RFI) and Requests for Proposals (RFP) also provide a useful 

source of cost and performance data. In these cases, original equipment manufacturers provided 

technology specific information. Examples of RFIs informing the Supply Side Resource Table 

include a Greenfield geothermal site data solicitation for the “Generic Geothermal PPA 90% CF” 

option and the Wind Capacity Factor Assumptions RFI for different state-specific wind resource 

options.

Handling of Technology Improvement Trends and Cost Uncertainties

The capital cost uncertainty for many generation options is relatively high. Various factors 

contribute to this uncertainty, including the relatively small number of facilities that have been 

built, especially for new and emerging technologies, as well as prolonged economic uncertainty. 

Despite this uncertainty, the cost profile between the last IRP and the current IRP has not 

changed significantly. For example, Figure 6.1 shows the trend in North American carbon steel 

sheet prices in the last year. This same information was presented in the 2011 IRP and the end 

data from that chart is shown in Figure 6.1. In the last year, costs have decreased slightly from 

higher initial costs and are currently close to costs that existed in September 2010. This is also 

illustrated by the long-term historical steel pricing trend as shown in Figure 6.2. The capital cost 

of generation resources reflect this status quo reality.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

110

Figure 6.1 – World Carbon Steel Pricing by Type

Figure 6.2 – Historic Carbon Steel Pricing

Prices for solar photovoltaic (PV) panels have fallen significantly since the 2011 IRP. Real 

prices are projected to continue to decline for the next several years, but uncertainty in the solar 

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-12

Feb-12

Mar-12

Apr-12

May-12

Jun-12

Jul-12

Aug-12

Sep-12

US $/lb

World Carbon Steel Transaction Pricing

(steelonthenet.com)

Hot Rolled Steel Coil Medium Steel Sections Steel Wire Rod Hot Rolled Steel Plate

Sept. 2010 Pricing

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

$0.50

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

$/lb

World Hot Rolled Coil Steel Prices

(steelonthenet.com)
PACIFICORP – 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

111

market makes it difficult to accurately predict future prices. Other technologies, such as gas 

turbines, and wind turbines have seen more stable prices since the 2011 IRP. Long-term resource 

pricing remains challenging to forecast.

Some generation technologies, such integrated gasification combined cycle (IGCC), have shown 

significant cost uncertainty because only a few units have been built and operated. Recent 

experience with cost overruns on IGCC projects such as Duke Energy’s Edwardsport and 

Southern Company’s Kemper County IGCC plants are examples that illustrate the difficulty in 

accurately estimating capital costs of these developing resource options. As these technologies 

mature and more plants are constructed, the costs of such new technologies may decrease 

relative to more mature options such as pulverized coal and natural gas-fueled plants.

The supply-side resource options tables do not include the potential for such capital cost 

reductions since the benefits are not expected to be realized until the next generation of new 

plants are built and operated. For example, construction and operating “experience curve” 

benefits for IGCC plants are not expected to be available until after their commercial operation 

dates. As such, future IRPs will be better able to incorporate the potential benefits of future cost 

reductions. Given the current emphasis on construction and operating experience associated with 

renewable generation, the Company anticipates the cost benefits for these technologies to be 

available sooner. The estimated capital costs are displayed in the supply-side resource tables 

along with expected availability of each technology for commercial utilization.

Resource Options and Attributes

Table 6.1 presents cost and performance attributes for supply-side resource options designated 

by generic, elevation-specific regions where a resource could ultimately be located:

ISO conditions: 0’ elevation (sea level and 59 degrees F); this is used as a reference only 

for certain modeling purposes.

1,500’ elevation: eastern Oregon/Washington.

4,500’ elevation: northern Utah, specifically Salt Lake/Utah/Davis/Box Elder counties

5,050’ elevation: central Utah, southern Idaho, central Wyoming.

6,500’ elevation: southwestern Wyoming

Tables 6.2 and 6.3 present the total resource cost attributes for supply-side resource options, and 

are based on estimates of the first-year, real- levelized costs for resources, stated in June 2012 

dollars. The resource costs are presented for both the $0 and $16 CO2 tax levels in recognition of 

the uncertainty in characterizing emission costs.

A Glossary of Terms and a Glossary of Acronyms from the Supply Side Resource table is 

summarized in Table 6.4 and Table 6.5.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

112

Table 6.1 - 2013 Supply Side Resource Table (2012$)

Description Resource Characteristics Costs Operating Characteristics Environmental

Net Commercial Design Fixed Average Full Load Water SO2 NOx Hg CO2

Elevation Capacity Operation Life Base Capital Var O&M O&M Heat Rate (HHV EFOR POR Consumed (lbs (lbs (lbs (lbs

Fuel Resource (AFSL) (MW) Year (yrs) ($/KW) ($/MWh) ($/KW-yr) Btu/KWh)/Efficiency (%) (%) (Gal/MWh) /MMBtu) /MMBtu) /TBTu) /MMBtu)

Natural Gas SCCT Aero x3, ISO 0 163 2016 30 1,081 3.50 9.88 9,739 2.6 3.9 56 0.0006 0.018 0.255 118

Natural Gas Intercooled SCCT Aero x1, ISO 0 102 2016 30 1,004 2.92 15.23 8,867 2.9 3.9 78 0.0006 0.018 0.255 118

Natural Gas SCCT Frame "F" x1, ISO 0 203 2016 35 679 8.46 7.73 9,950 2.7 3.9 10 0.0006 0.018 0.255 118

Natural Gas IC Recips x6, ISO 0 117 2016 30 1,204 7.40 15.61 8,447 2.5 5.0 5 0.0006 0.018 0.255 118

Natural Gas CCCT Dry "F", 2x1, ISO 0 609 2017 40 995 2.11 6.13 6,738 2.5 3.8 11 0.0006 0.007 0.255 118

Natural Gas CCCT Dry "F", DF, 2x1, ISO 0 138 2017 40 522 0.08 0.00 8,482 0.8 3.8 11 0.0006 0.007 0.255 118

Natural Gas CCCT Dry "G/H", 1x1, ISO 0 372 2017 40 971 2.53 10.70 6,866 2.5 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 0 48 2017 40 612 0.08 0.00 8,262 0.8 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", 2x1, ISO 0 746 2017 40 959 2.44 5.61 6,743 2.5 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 0 96 2017 40 600 0.07 0.00 8,105 0.8 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", Adv 1x1, ISO 0 439 2018 40 931 2.20 9.13 6,495 2.5 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 0 43 2018 40 486 0.08 0.00 8,611 0.8 3.8 11 0.0006 0.008 0.255 118

Natural Gas Intercooled SCCT Aero x1 1,500 99 2016 30 1,034 2.99 15.67 8,839 2.9 3.9 80 0.0006 0.018 0.255 118

Natural Gas SCCT Frame "F" x1 1,500 197 2016 35 699 8.71 7.97 9,950 2.7 3.9 20 0.0006 0.018 0.255 118

Natural Gas IC Recips x 6 1,500 112 2016 30 1,253 7.63 16.31 8,447 2.5 3.8 5 0.0006 0.030 0.255 118

Natural Gas CCCT Dry "F", 2x1 1,500 583 2016 40 1,039 2.18 6.43 6,738 2.5 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "F", DF, 2x1 1,500 138 2016 40 522 0.08 0.00 8,482 0.8 3.8 11 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", 2x1 1,500 715 2017 40 1,000 2.54 5.86 6,773 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", DF, 2x1 1,500 96 2017 40 600 0.07 0.00 8,135 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", Adv 1x1 1,500 425 2018 40 962 2.27 9.43 6,495 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", DF, Adv 1x1 1,500 43 2018 40 486 0.08 0.00 8,611 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas SCCT Aero x3 4,250 144 2016 30 1,225 3.89 11.11 9,739 2.6 3.9 58 0.0006 0.018 0.255 118

Natural Gas Intercooled SCCT Aero x1 4,250 91 2016 30 1,127 3.23 16.97 8,867 2.9 3.9 80 0.0006 0.018 0.255 118

Natural Gas SCCT Frame "F" x1 4,250 181 2016 35 762 9.48 8.67 9,950 2.7 3.9 20 0.0006 0.018 0.255 118

Natural Gas IC Recips x6 4,250 103 2016 30 1,368 8.15 18.39 8,447 2.5 5.0 5 0.0006 0.030 0.255 118

Natural Gas CCCT Wet "F", 2x1 4,250 545 2017 40 1,104 2.87 8.58 6,666 2.5 3.8 200 0.0006 0.007 0.255 118

Natural Gas CCCT Wet "F", DF, 2x1 4,250 89 2017 40 490 0.32 0.00 7,901 0.8 3.8 200 0.0006 0.007 0.255 118

Natural Gas CCCT Dry "F", 1x1 5,050 255 2017 40 1,253 2.57 13.94 6,815 2.5 3.8 9 0.0006 0.007 0.255 118

Natural Gas CCCT Dry "F", DF, 1x1 5,050 48 2017 40 546 0.08 0.00 8,518 0.8 3.8 9 0.0006 0.007 0.255 118

Natural Gas CCCT Dry "F", 2x1 5,050 523 2017 40 1,159 2.42 7.14 6,738 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "F", DF, 2x1 5,050 138 2017 40 522 0.08 0.00 8,482 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", 1x1 5,050 320 2017 40 1,129 2.94 12.45 6,866 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", DF, 1x1 5,050 48 2017 40 612 0.08 0.00 8,262 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", 2x1 5,050 640 2017 40 1,118 2.82 6.55 6,743 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", DF, 2x1 5,050 96 2017 40 600 0.07 0.00 8,105 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", Adv 1x1 5,050 380 2018 40 1,075 2.54 10.54 6,495 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", DF, Adv 1x1 5,050 43 2018 40 486 0.08 0.00 8,611 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas SO Fuel Cell 4,500 5 2018 20 2,090 0.03 8.82 8,061 3 2 2 0.0006 0 0.255 118

Natural Gas Intercooled SCCT Aero x1 6,500 86 2016 30 1,189 3.39 17.91 8,867 2.9 3.9 80 0.0006 0.018 0.255 118

Natural Gas SCCT Frame "F" x1 6,500 172 2016 35 804 10.00 9.13 9,950 2.7 3.9 20 0.0006 0.018 0.255 118

Natural Gas IC Recips x6 6,500 96 2016 30 1,469 8.60 19.03 8,447 2.5 5.0 5 0.0006 0.0295 0.255 118

Natural Gas CCCT Dry "G/H", 2x1 6,500 617 2017 40 1,159 2.92 6.80 6,743 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "G/H", DF, 2x1 6,500 96 2017 40 600 0.07 0.00 8,105 0.8 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", Adv 1x1 6,500 368 2018 40 1,110 2.62 10.88 6,495 2.5 3.8 9 0.0006 0.008 0.255 118

Natural Gas CCCT Dry "J", DF, Adv 1x1 6,500 43 2018 40 486 0.08 0.00 8,611 0.8 3.8 9 0.0006 0.008 0.255 118
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

113

Table 6.1 - 2013 Supply Side Resource Table (2012$) (Continued)

Description Resource Characteristics Costs Operating Characteristics Environmental

Net Commercial Design Fixed Average Full Load Water SO2 NOx Hg CO2

Elevation Capacity Operation Life Base Capital Var O&M O&M Heat Rate (HHV EFOR POR Consumed (lbs (lbs (lbs (lbs

Fuel Resource (AFSL) (MW) Year (yrs) ($/KW) ($/MWh) ($/KW-yr) Btu/KWh)/Efficiency (%) (%) (Gal/MWh) /MMBtu) /MMBtu) /TBTu) /MMBtu)

Coal SCPC with CCS 4,500 526 2032 40 5,410 6.71 69.22 13,087 5 5 1,004 0.009 0.070 0.022 20.5

Coal SCPC without CCS 4,500 600 2027 40 2,992 0.96 40.65 9,106 4.6 4 600 0.005 0.070 0.022 205.4

Coal IGCC with CCS 4,500 466 2032 40 5,238 11.28 55.78 10,823 8 7 394 0.009 0.050 0.333 20.5

Coal IGCC without CCS 4,500 560 2027 40 3,734 8.39 42.45 8,734 8 7 361 0.013 0.059 0.333 205.4

Coal PC CCS retrofit @ 500 MW 4,500 -139 2029 20 1,188 6.20 74.52 14,372 5 5 1,004 0.005 0.070 1.200 20.5

Coal SCPC with CCS 6,500 692 2032 40 6,126 7.26 64.29 13,242 5 5 1,004 0.009 0.070 0.022 20.5

Coal SCPC without CCS 6,500 790 2027 40 3,388 1.27 37.71 9,214 4.6 4 600 0.005 0.070 0.022 205.4

Coal IGCC with CCS 6,500 456 2032 40 5,931 13.52 60.76 11,047 8 7 394 0.009 0.050 0.333 20.5

Coal IGCC without CCS 6,500 548 2027 40 4,228 10.06 46.24 8,915 8 7 361 0.013 0.059 0.333 205.4

Coal PC CCS retrofit @ 500 MW 6,500 -139 2029 20 1,345 6.71 69.22 14,372 5 5 1,004 0.005 0.070 1.200 20.5

Geothermal Blundell Dual Flash 90% CF 4,500 35 2016 40 4,795 0.98 118.49 na 5 5 1453 0 0 0 0

Geothermal Greenfield Binary 90% CF 4,500 43 2018 40 5,916 0.98 187.85 na 5 5 1453 0 0 0 0

Geothermal Generic Geothermal PPA 90% CF 4,500 30 2016 20 n/a 110.00 n/a na 5 5 1453 0 0 0 0

Wind 2.3 MW turbine 29% CF WA 1,500 100 2017 25 2,365 0.00 33.11 0 Included with CF 0 0 0 0 0

Wind 2.3 MW turbine 29% CF UT 4,500 100 2017 25 2,304 0.00 33.11 0 Included with CF 0 0 0 0 0

Wind 2.3 MW turbine 35% CF WY 6,500 100 2017 25 2,138 0.65 33.11 0 Included with CF 0 0 0 0 0

Wind 2.3 MW turbine 40% CF WY 6,500 200 2017 25 2,257 0.65 33.11 0 Included with CF 0 0 0 0 0

Solar PV Thin Film 21% CF 4,500 2 2014 25 3,476 0.00 51.50 na Included with CF 0 0 0 0 0

Solar PV Poly-Si Fixed Tilt 22% CF 4,500 2 2014 25 3,153 0.00 51.50 na Included with CF 0 0 0 0 0

Solar PV Poly-Si Single Tracking 25% CF 4,500 2 2014 25 3,810 0.00 67.00 na Included with CF 0 0 0 0 0

Solar PV Poly-Si Fixed Tilt 28% CF 4,500 50 2015 25 2,952 0.00 27.81 na Included with CF 0 0 0 0 0

Solar PV Poly-Si Single Tracking 33% CF 4,500 50 2015 25 3,176 0.00 32.55 na Included with CF 0 0 0 0 0

Solar CSP Trough w Natural Gas 4,500 100 2015 30 5,072 0.00 64.00 11,750 Included with CF 725 0 0 0 0

Solar CSP Tower 24% CF 4,500 100 2015 30 4,831 0.00 64.00 na Included with CF 725 0 0 0 0

Solar CSP Tower Molten Salt 30% CF 4,500 100 2015 30 5,796 0.00 64.00 na Included with CF 750 0 0 0 0

Water Hydrokinetic/Wave 40% CF 0 100 2024 20 5,539 0.00 166.17 na na na 0 0 0 0 0

Biomass Forestry Byproduct 1,500 5 2017 30 3,334 0.96 40.65 10,017 5.06 4.4 660 0.1 0.2 0.4 205

Storage Pumped Storage 4,500 1,000 2022 50 3,000 4.30 4.30 77.5% 3 1.9 0 0 0 0 0

Storage Lithium Ion Battery 4,500 10 2015 20 8,712 0.00 27.40 91.0% 3 1.9 0 0 0 0 0

Storage Sodium-Sulfur Battery 4,500 10 2015 20 4,400 0.00 27.40 72.5% 0.3 0 0 0 0 0 0

Storage Vanadium RedOx Battery 4,500 10 2015 20 5,530 0.00 36.53 70.0% 2 0 0 0 0 0 0

Storage Advanced Fly Wheel 4,500 10 2015 20 2,406 0.00 96.24 85.0% 2 0 0 0 0 0 0

Storage CAES 4,500 557 2017 30 1,751 22.51 33.80 83.5% 3.5 3.5 0 0.001 0.011 0.255 118

Nuclear Advanced Fission 4,500 2,236 2025 40 7,093 2.04 88.75 10,710 7.7 7.3 767 0 0 0 0

Nuclear Modular Reactor 4,500 25 2030 40 3,390 1.02 44.38 10,710 7.7 7.3 767 0 0 0 0
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

114

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax

$0 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($)

Resource Description O&M

 Capitalized 

Premium 

 O&M 

Capitalized 

 Gas 

Transporta

tion Total

SCCT Aero x3, ISO 0 $1,081 8.428% $91.13 9.88 1.34% 0.13 32.51 42.52 $133.65

Intercooled SCCT Aero x1, ISO 0 $1,004 8.428% $84.61 15.23 1.40% 0.21 29.59 45.04 $129.65

SCCT Frame "F" x1, ISO 0 $679 7.954% $53.98 7.73 1.37% 0.11 33.21 41.05 $95.02

IC Recips x6, ISO 0 $1,204 8.428% $101.45 15.61 0.40% 0.06 28.19 43.87 $145.31

CCCT Dry "F", 2x1, ISO 0 $995 7.886% $78.43 6.13 1.23% 0.08 22.49 28.69 $107.12

CCCT Dry "F", DF, 2x1, ISO 0 $522 7.886% $41.13 0.00 0.00% 0.00 28.31 28.31 $69.44

CCCT Dry "G/H", 1x1, ISO 0 $971 7.886% $76.59 10.70 1.96% 0.21 22.92 33.83 $110.42

CCCT Dry "G/H", DF, 1x1, ISO 0 $612 7.886% $48.23 0.00 0.00% 0.00 27.58 27.58 $75.81

CCCT Dry "G/H", 2x1, ISO 0 $959 7.886% $75.63 5.61 1.86% 0.10 22.51 28.22 $103.85

CCCT Dry "G/H", DF, 2x1, ISO 0 $600 7.886% $47.32 0.00 0.00% 0.00 27.05 27.05 $74.37

CCCT Dry "J", Adv 1x1, ISO 0 $931 7.886% $73.39 9.13 1.95% 0.18 21.68 30.98 $104.37

CCCT Dry "J", DF, Adv 1x1, ISO 0 $486 7.886% $38.36 0.00 0.00% 0.00 28.74 28.74 $67.10

Intercooled SCCT Aero x1 1500 $1,034 8.428% $87.12 15.67 1.40% 0.22 29.50 45.39 $132.51

SCCT Frame "F" x1 1500 $699 7.954% $55.56 7.97 1.37% 0.11 33.21 41.29 $96.85

IC Recips x 6 1500 $1,253 8.428% $105.64 16.31 0.40% 0.06 28.19 44.57 $150.21

CCCT Dry "F", 2x1 1500 $1,039 7.886% $81.97 6.43 1.23% 0.08 22.49 29.00 $110.96

CCCT Dry "F", DF, 2x1 1500 $522 7.886% $41.13 0.00 0.00% 0.00 28.31 28.31 $69.44

CCCT Dry "G/H", 2x1 1500 $1,000 7.886% $78.87 5.86 1.86% 0.11 22.61 28.57 $107.45

CCCT Dry "G/H", DF, 2x1 1500 $600 7.886% $47.32 0.00 0.00% 0.00 27.15 27.15 $74.47

CCCT Dry "J", Adv 1x1 1500 $962 7.886% $75.83 9.43 1.95% 0.18 21.68 31.29 $107.13

CCCT Dry "J", DF, Adv 1x1 1500 $486 7.886% $38.36 0.00 0.00% 0.00 28.74 28.74 $67.10

SCCT Aero x3 4250 $1,225 8.428% $103.21 11.11 1.34% 0.15 21.95 33.21 $136.42

Intercooled SCCT Aero x1 4250 $1,127 8.428% $94.97 16.97 1.40% 0.24 19.99 37.19 $132.16

SCCT Frame "F" x1 4250 $762 7.954% $60.57 8.67 1.37% 0.12 22.43 31.22 $91.79

IC Recips x6 4250 $1,368 8.428% $115.31 18.39 0.40% 0.07 19.04 37.50 $152.82

CCCT Wet "F", 2x1 4250 $1,104 7.886% $87.05 8.58 0.70% 0.06 15.03 23.67 $110.71

CCCT Wet "F", DF, 2x1 4250 $490 7.886% $38.63 0.00 0.00% 0.00 17.81 17.81 $56.44

CCCT Dry "F", 1x1 5050 $1,253 7.886% $98.81 13.94 1.29% 0.18 15.36 29.49 $128.29

CCCT Dry "F", DF, 1x1 5050 $546 7.886% $43.08 0.00 0.00% 0.00 19.20 19.20 $62.28

CCCT Dry "F", 2x1 5050 $1,159 7.886% $91.37 7.14 1.23% 0.09 15.19 22.42 $113.79

CCCT Dry "F", DF, 2x1 5050 $522 7.886% $41.13 0.00 0.00% 0.00 19.12 19.12 $60.25

CCCT Dry "G/H", 1x1 5050 $1,129 7.886% $89.04 12.45 1.96% 0.24 15.48 28.17 $117.21

CCCT Dry "G/H", DF, 1x1 5050 $612 7.886% $48.23 0.00 0.00% 0.00 18.62 18.62 $66.86

CCCT Dry "G/H", 2x1 5050 $1,118 7.886% $88.16 6.55 1.86% 0.12 15.20 21.87 $110.03

CCCT Dry "G/H", DF, 2x1 5050 $600 7.886% $47.32 0.00 0.00% 0.00 18.27 18.27 $65.59

CCCT Dry "J", Adv 1x1 5050 $1,075 7.886% $84.74 10.54 1.95% 0.21 14.64 25.39 $110.13

CCCT Dry "J", DF, Adv 1x1 5050 $486 7.886% $38.36 0.00 0.00% 0.00 19.41 19.41 $57.77

Elevation 

(AFSL)

Capital Cost $/kW Fixed Cost

 Total Capital Cost 

Payment 

Factor

 Annual 

Payment 

($/kW-Yr) 

Fixed O&M $/kW-Yr

 Total 

Fixed

($/kW-Yr) 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

115

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax (Continued)

$0 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($) Credits

Resource Description

Capacity 

Factor

 Total Fixed

(Mills/kWh) 

Storage 

Efficiency ¢/mmBtu Mills/kWh O&M 

 Capitalized 

Premium 

 O&M 

Capitalized 

 Integration 

Cost Environmental 

 PTC Tax 

Credits / ITC 

(Solar Only) 

SCCT Aero x3, ISO 0 21% 72.65 na 472 45.97 3.50 6.67% 0.23 - - 122.36 - 122.36

Intercooled SCCT Aero x1, ISO 0 21% 70.48 na 472 41.85 2.92 6.83% 0.20 - - 115.45 - 115.45

SCCT Frame "F" x1, ISO 0 21% 51.65 na 472 46.97 8.46 7.80% 0.66 - - 107.74 - 107.74

IC Recips x6, ISO 0 21% 78.99 na 472 39.87 7.40 4.33% 0.32 - - 126.59 - 126.59

CCCT Dry "F", 2x1, ISO 0 56% 21.84 na 472 31.80 2.11 7.69% 0.16 - - 55.91 - 55.91

CCCT Dry "F", DF, 2x1, ISO 0 16% 49.54 na 472 40.04 0.08 0.00% 0.00 - - 89.65 - 89.65

CCCT Dry "G/H", 1x1, ISO 0 56% 22.51 na 472 32.41 2.53 7.05% 0.18 - - 57.63 - 57.63

CCCT Dry "G/H", DF, 1x1, ISO 0 16% 54.09 na 472 39.00 0.08 0.00% 0.00 - - 93.16 - 93.16

CCCT Dry "G/H", 2x1, ISO 0 56% 21.17 na 472 31.83 2.44 7.30% 0.18 - - 55.62 - 55.62

CCCT Dry "G/H", DF, 2x1, ISO 0 16% 53.06 na 472 38.26 0.07 0.00% 0.00 - - 91.39 - 91.39

CCCT Dry "J", Adv 1x1, ISO 0 56% 21.28 na 472 30.66 2.20 7.03% 0.15 - - 54.29 - 54.29

CCCT Dry "J", DF, Adv 1x1, ISO 0 16% 47.87 na 472 40.65 0.08 0.00% 0.00 - - 88.60 - 88.60

Intercooled SCCT Aero x1 1500 21% 72.03 na 472 41.72 2.99 6.83% 0.20 - - 116.95 - 116.95

SCCT Frame "F" x1 1500 21% 52.65 na 472 46.97 8.71 7.80% 0.68 - - 109.00 - 109.00

IC Recips x 6 1500 21% 81.65 na 472 39.87 7.63 4.48% 0.34 - - 129.50 - 129.50

CCCT Dry "F", 2x1 1500 56% 22.62 na 472 31.80 2.18 7.67% 0.17 - - 56.77 - 56.77

CCCT Dry "F", DF, 2x1 1500 16% 49.54 na 472 40.04 0.08 0.00% 0.00 - - 89.66 - 89.66

CCCT Dry "G/H", 2x1 1500 56% 21.90 na 472 31.97 2.54 7.29% 0.19 - - 56.60 - 56.60

CCCT Dry "G/H", DF, 2x1 1500 16% 53.13 na 472 38.40 0.07 0.00% 0.00 - - 91.61 - 91.61

CCCT Dry "J", Adv 1x1 1500 56% 21.84 na 472 30.66 2.27 7.01% 0.16 - - 54.93 - 54.93

CCCT Dry "J", DF, Adv 1x1 1500 16% 47.87 na 472 40.65 0.08 0.00% 0.00 - - 88.60 - 88.60

SCCT Aero x3 4250 21% 74.16 na 431 42.02 3.89 6.67% 0.26 - - 120.33 - 120.33

Intercooled SCCT Aero x1 4250 21% 71.84 na 431 38.26 3.23 6.83% 0.22 - - 113.55 - 113.55

SCCT Frame "F" x1 4250 21% 49.90 na 431 42.93 9.48 7.80% 0.74 - - 103.05 - 103.05

IC Recips x6 4250 21% 83.07 na 431 36.45 8.15 4.48% 0.36 - - 128.03 - 128.03

CCCT Wet "F", 2x1 4250 56% 22.57 na 431 28.76 2.87 6.27% 0.18 - - 54.38 - 54.38

CCCT Wet "F", DF, 2x1 4250 16% 40.27 na 431 34.09 0.32 0.00% 0.00 - - 74.68 - 74.68

CCCT Dry "F", 1x1 5050 56% 26.15 na 431 29.41 2.57 7.50% 0.19 - - 58.33 - 58.33

CCCT Dry "F", DF, 1x1 5050 16% 44.44 na 431 36.75 0.08 0.00% 0.00 - - 81.27 - 81.27

CCCT Dry "F", 2x1 5050 56% 23.20 na 431 29.07 2.42 7.67% 0.19 - - 54.87 - 54.87

CCCT Dry "F", DF, 2x1 5050 16% 42.98 na 431 36.60 0.08 0.00% 0.00 - - 79.66 - 79.66

CCCT Dry "G/H", 1x1 5050 56% 23.89 na 431 29.63 2.94 6.99% 0.21 - - 56.66 - 56.66

CCCT Dry "G/H", DF, 1x1 5050 16% 47.70 na 431 35.65 0.08 0.00% 0.00 - - 83.43 - 83.43

CCCT Dry "G/H", 2x1 5050 56% 22.43 na 431 29.10 2.82 7.27% 0.21 - - 54.55 - 54.55

CCCT Dry "G/H", DF, 2x1 5050 16% 46.80 na 431 34.97 0.07 0.00% 0.00 - - 81.84 - 81.84

CCCT Dry "J", Adv 1x1 5050 56% 22.45 na 431 28.02 2.54 6.98% 0.18 - - 53.19 - 53.19

CCCT Dry "J", DF, Adv 1x1 5050 16% 41.22 na 431 37.15 0.08 0.00% 0.00 - - 78.45 - 78.45

Elevation 

(AFSL)

Convert to Mills

 Variable Costs

(mills/kWh) 

Levelized Fuel

 Total Costs and Credits

(Mills/kWh) 

 Total 

Resource Cost 

 Total Resource 

Cost -

With PTC / ITC 

Credits 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

116

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax (Continued)

$0 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($)

Resource Description O&M

 Capitalized 

Premium 

 O&M 

Capitalized 

 Gas 

Transporta

tion Total

Intercooled SCCT Aero x1 6500 $1,189 8.428% $100.24 17.91 1.40% 0.25 17.07 35.24 $135.47

SCCT Frame "F" x1 6500 $804 7.954% $63.91 9.13 1.37% 0.13 19.16 28.42 $92.33

IC Recips x6 6500 $1,469 8.428% $123.84 19.03 0.40% 0.08 16.27 35.37 $159.21

CCCT Dry "G/H", 2x1 6500 $1,159 7.886% $91.40 6.80 1.86% 0.13 12.99 19.91 $111.31

CCCT Dry "G/H", DF, 2x1 6500 $600 7.886% $47.32 0.00 0.00% 0.00 15.61 15.61 $62.93

CCCT Dry "J", Adv 1x1 6500 $1,110 7.886% $87.54 10.88 1.95% 0.21 12.51 23.60 $111.14

CCCT Dry "J", DF, Adv 1x1 6500 $486 7.886% $38.36 0.00 0.00% 0.00 16.58 16.58 $54.94

IGCC with CCS 6500 $5,931 7.438% $441.13 60.76 0.00% 0.00 0.00 60.76 $501.90

Generic Geothermal PPA 90% CF 4500 $0 6.831% $0.00 735.46 0.00% 0.00 0.00 735.46 $735.46

2.3 MW turbine 29% CF WA 1500 $2,365 8.165% $193.12 33.11 1.14% 0.38 0.00 33.49 $226.61

2.3 MW turbine 29% CF UT 4500 $2,304 8.165% $188.12 33.11 1.14% 0.38 0.00 33.49 $221.61

2.3 MW turbine 40% CF WY 6500 $2,257 8.165% $184.30 33.11 1.14% 0.38 0.00 33.49 $217.78

PV Poly-Si Fixed Tilt 22% CF (1.21 MWdc/MWac) 4500 $3,153 8.165% $257.48 51.50 2.45% 1.26 0.00 52.76 $310.24

PV Poly-Si Fixed Tilt 28% CF (1.37 MWdc/MWac) 4500 $2,952 8.165% $241.05 27.81 2.45% 0.68 0.00 28.49 $269.54

PV Poly-Si Single Tracking 34% CF (1.34 MWdc/MWac) 4500 $3,176 8.165% $259.29 32.55 2.45% 0.80 0.00 33.35 $292.64

Forestry Byproduct 1500 $3,334 7.542% $251.45 40.65 5.07% 2.06 0.00 42.71 $294.16

Pumped Storage 4500 $3,000 7.459% $223.77 4.30 6.19% 0.27 0.00 4.57 $228.34

Sodium-Sulfur Battery 4500 $4,400 8.722% $383.77 27.40 0.00% 0.00 0.00 27.40 $411.17

Advanced Fly Wheel 4500 $2,406 8.722% $209.85 96.24 0.00% 0.00 0.00 96.24 $306.09

CAES 4500 $1,751 8.428% $147.57 33.80 0.00% 0.00 21.95 55.75 $203.33

Advanced Fission 4500 $7,093 7.623% $540.70 88.75 5.79% 5.14 0.00 93.89 $634.59

Elevation 

(AFSL)

Capital Cost $/kW Fixed Cost

 Total Capital Cost 

Payment 

Factor

 Annual 

Payment 

($/kW-Yr) 

Fixed O&M $/kW-Yr

 Total 

Fixed

($/kW-Yr) 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

117

Table 6.2 – Total Resource Cost for Supply-Side Resource Options, $0 CO2 Tax (Continued)

$0 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($) Credits

Resource Description

Capacity 

Factor

 Total Fixed

(Mills/kWh) 

Storage 

Efficiency ¢/mmBtu Mills/kWh O&M 

 Capitalized 

Premium 

 O&M 

Capitalized 

 Integration 

Cost Environmental 

 PTC Tax 

Credits / ITC 

(Solar Only) 

Intercooled SCCT Aero x1 6500 21% 73.64 na 431 38.26 3.39 6.83% 0.23 - - 115.52 - 115.52

SCCT Frame "F" x1 6500 21% 50.19 na 431 42.93 10.00 7.80% 0.78 - - 103.90 - 103.90

IC Recips x6 6500 21% 86.55 na 431 36.45 8.60 4.48% 0.39 - - 131.98 - 131.98

CCCT Dry "G/H", 2x1 6500 56% 22.69 na 431 29.10 2.92 7.27% 0.21 - - 54.92 - 54.92

CCCT Dry "G/H", DF, 2x1 6500 16% 44.90 na 431 34.97 0.07 0.00% 0.00 - - 79.94 - 79.94

CCCT Dry "J", Adv 1x1 6500 56% 22.66 na 431 28.02 2.62 6.96% 0.18 - - 53.48 - 53.48

CCCT Dry "J", DF, Adv 1x1 6500 16% 39.20 na 431 37.15 0.08 0.00% 0.00 - - 76.43 - 76.43

IGCC with CCS 6500 86% 66.96 na 271 29.91 13.52 12.08% 1.63 - - 112.02 - 112.02

Generic Geothermal PPA 90% CF 4500 90% 93.28 na - - 11.00 0.00% 0.00 - - 104.29 - 104.29

2.3 MW turbine 29% CF WA 1500 29% 89.20 na - - 0.00 0.00% 0.00 2.55 - 91.76 (19.48) 72.28

2.3 MW turbine 29% CF UT 4500 29% 87.23 na - - 0.00 0.00% 0.00 2.55 - 89.79 (19.48) 70.31

2.3 MW turbine 40% CF WY 6500 40% 62.15 na - - 0.65 0.00% 0.00 2.55 - 65.36 (19.48) 45.88

PV Poly-Si Fixed Tilt 22% CF (1.21 MWdc/MWac) 4500 22% 160.98 na - - 0.00 0.00% 0.00 0.64 - 161.62 (19.91) 141.70

PV Poly-Si Fixed Tilt 28% CF (1.37 MWdc/MWac) 4500 28% 108.69 na - - 0.00 0.00% 0.00 0.64 - 109.33 (14.49) 94.84

PV Poly-Si Single Tracking 34% CF (1.34 MWdc/MWac) 4500 34% 98.86 na - - 0.00 0.00% 0.00 0.64 - 99.50 (13.06) 86.45

Forestry Byproduct 1500 91% 37.00 na 512 51.29 0.96 0.00% 0.00 - - 89.25 (17.86) 71.39

Pumped Storage 4500 42% 62.56 77.5% 472 59.32 4.30 0.00% 0.00 - - 126.18 - 126.18

Sodium-Sulfur Battery 4500 25% 187.75 72.5% 472 63.41 0.00 0.00% 0.00 - - 251.16 - 251.16

Advanced Fly Wheel 4500 5% 698.84 85.0% 472 54.09 0.00 0.00% 0.00 - - 752.93 - 752.93

CAES 4500 33% 69.63 83.5% 472 55.06 22.51 10.29% 2.32 - - 149.52 - 149.52

Advanced Fission 4500 86% 84.67 na 85 9.11 2.04 0.00% 0.00 - - 95.82 - 95.82

Elevation 

(AFSL)

Convert to Mills

 Variable Costs

(mills/kWh) 

Levelized Fuel

 Total Costs and Credits

(Mills/kWh) 

 Total 

Resource Cost 

 Total Resource 

Cost -

With PTC / ITC 

Credits 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

118

Table 6.3 – Total Resource Cost for Supply-Side Resource Options, $16 CO2 Tax

$16 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($)

Resource Description O&M

 Capitalized 

Premium 

 O&M 

Capitalized 

 Gas 

Transporta

tion Total

SCCT Aero x3, ISO 0 $1,081 8.428% $91.13 9.88 1.34% 0.13 32.51 42.52 $133.65

Intercooled SCCT Aero x1, ISO 0 $1,004 8.428% $84.61 15.23 1.40% 0.21 29.59 45.04 $129.65

SCCT Frame "F" x1, ISO 0 $679 7.954% $53.98 7.73 1.37% 0.11 33.21 41.05 $95.02

IC Recips x6, ISO 0 $1,204 8.428% $101.45 15.61 0.40% 0.06 28.19 43.87 $145.31

CCCT Dry "F", 2x1, ISO 0 $995 7.886% $78.43 6.13 1.23% 0.08 22.49 28.69 $107.12

CCCT Dry "F", DF, 2x1, ISO 0 $522 7.886% $41.13 0.00 0.00% 0.00 28.31 28.31 $69.44

CCCT Dry "G/H", 1x1, ISO 0 $971 7.886% $76.59 10.70 1.96% 0.21 22.92 33.83 $110.42

CCCT Dry "G/H", DF, 1x1, ISO 0 $612 7.886% $48.23 0.00 0.00% 0.00 27.58 27.58 $75.81

CCCT Dry "G/H", 2x1, ISO 0 $959 7.886% $75.63 5.61 1.86% 0.10 22.51 28.22 $103.85

CCCT Dry "G/H", DF, 2x1, ISO 0 $600 7.886% $47.32 0.00 0.00% 0.00 27.05 27.05 $74.37

CCCT Dry "J", Adv 1x1, ISO 0 $931 7.886% $73.39 9.13 1.95% 0.18 21.68 30.98 $104.37

CCCT Dry "J", DF, Adv 1x1, ISO 0 $486 7.886% $38.36 0.00 0.00% 0.00 28.74 28.74 $67.10

Intercooled SCCT Aero x1 1500 $1,034 8.428% $87.12 15.67 1.40% 0.22 29.50 45.39 $132.51

SCCT Frame "F" x1 1500 $699 7.954% $55.56 7.97 1.37% 0.11 33.21 41.29 $96.85

IC Recips x 6 1500 $1,253 8.428% $105.64 16.31 0.40% 0.06 28.19 44.57 $150.21

CCCT Dry "F", 2x1 1500 $1,039 7.886% $81.97 6.43 1.23% 0.08 22.49 29.00 $110.96

CCCT Dry "F", DF, 2x1 1500 $522 7.886% $41.13 0.00 0.00% 0.00 28.31 28.31 $69.44

CCCT Dry "G/H", 2x1 1500 $1,000 7.886% $78.87 5.86 1.86% 0.11 22.61 28.57 $107.45

CCCT Dry "G/H", DF, 2x1 1500 $600 7.886% $47.32 0.00 0.00% 0.00 27.15 27.15 $74.47

CCCT Dry "J", Adv 1x1 1500 $962 7.886% $75.83 9.43 1.95% 0.18 21.68 31.29 $107.13

CCCT Dry "J", DF, Adv 1x1 1500 $486 7.886% $38.36 0.00 0.00% 0.00 28.74 28.74 $67.10

SCCT Aero x3 4250 $1,225 8.428% $103.21 11.11 1.34% 0.15 21.95 33.21 $136.42

Intercooled SCCT Aero x1 4250 $1,127 8.428% $94.97 16.97 1.40% 0.24 19.99 37.19 $132.16

SCCT Frame "F" x1 4250 $762 7.954% $60.57 8.67 1.37% 0.12 22.43 31.22 $91.79

IC Recips x6 4250 $1,368 8.428% $115.31 18.39 0.40% 0.07 19.04 37.50 $152.82

CCCT Wet "F", 2x1 4250 $1,104 7.886% $87.05 8.58 0.70% 0.06 15.03 23.67 $110.71

CCCT Wet "F", DF, 2x1 4250 $490 7.886% $38.63 0.00 0.00% 0.00 17.81 17.81 $56.44

CCCT Dry "F", 1x1 5050 $1,253 7.886% $98.81 13.94 1.29% 0.18 15.36 29.49 $128.29

CCCT Dry "F", DF, 1x1 5050 $546 7.886% $43.08 0.00 0.00% 0.00 19.20 19.20 $62.28

CCCT Dry "F", 2x1 5050 $1,159 7.886% $91.37 7.14 1.23% 0.09 15.19 22.42 $113.79

CCCT Dry "F", DF, 2x1 5050 $522 7.886% $41.13 0.00 0.00% 0.00 19.12 19.12 $60.25

CCCT Dry "G/H", 1x1 5050 $1,129 7.886% $89.04 12.45 1.96% 0.24 15.48 28.17 $117.21

CCCT Dry "G/H", DF, 1x1 5050 $612 7.886% $48.23 0.00 0.00% 0.00 18.62 18.62 $66.86

CCCT Dry "G/H", 2x1 5050 $1,118 7.886% $88.16 6.55 1.86% 0.12 15.20 21.87 $110.03

CCCT Dry "G/H", DF, 2x1 5050 $600 7.886% $47.32 0.00 0.00% 0.00 18.27 18.27 $65.59

CCCT Dry "J", Adv 1x1 5050 $1,075 7.886% $84.74 10.54 1.95% 0.21 14.64 25.39 $110.13

CCCT Dry "J", DF, Adv 1x1 5050 $486 7.886% $38.36 0.00 0.00% 0.00 19.41 19.41 $57.77

Intercooled SCCT Aero x1 6500 $1,189 8.428% $100.24 17.91 1.40% 0.25 17.07 35.24 $135.47

SCCT Frame "F" x1 6500 $804 7.954% $63.91 9.13 1.37% 0.13 19.16 28.42 $92.33

IC Recips x6 6500 $1,469 8.428% $123.84 19.03 0.40% 0.08 16.27 35.37 $159.21

CCCT Dry "G/H", 2x1 6500 $1,159 7.886% $91.40 6.80 1.86% 0.13 12.99 19.91 $111.31

CCCT Dry "G/H", DF, 2x1 6500 $600 7.886% $47.32 0.00 0.00% 0.00 15.61 15.61 $62.93

CCCT Dry "J", Adv 1x1 6500 $1,110 7.886% $87.54 10.88 1.95% 0.21 12.51 23.60 $111.14

CCCT Dry "J", DF, Adv 1x1 6500 $486 7.886% $38.36 0.00 0.00% 0.00 16.58 16.58 $54.94

Elevation 

(AFSL)

Capital Cost $/kW Fixed Cost

 Total Capital Cost 

Payment 

Factor

 Annual 

Payment 

($/kW-Yr) 

Fixed O&M $/kW-Yr

 Total 

Fixed

($/kW-Yr) 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

119

Table 6.3 – Total Resource Cost for Supply-Side Resource Options, $16 CO2 Tax (Continued)

$16 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($) Credits

Resource Description

Capacity 

Factor

 Total Fixed

(Mills/kWh) 

Storage 

Efficiency ¢/mmBtu Mills/kWh O&M 

 Capitalized 

Premium 

 O&M 

Capitalized 

 Integration 

Cost Environmental 

 PTC Tax 

Credits / ITC 

(Solar Only) 

SCCT Aero x3, ISO 0 21% 72.65 na 498 48.47 3.50 6.67% 0.23 - 3.86 128.72 - 128.72

Intercooled SCCT Aero x1, ISO 0 21% 70.48 na 498 44.13 2.92 6.83% 0.20 - 3.52 121.24 - 121.24

SCCT Frame "F" x1, ISO 0 21% 51.65 na 498 49.52 8.46 7.80% 0.66 - 3.95 114.24 - 114.24

IC Recips x6, ISO 0 21% 78.99 na 498 42.04 7.40 4.33% 0.32 - 3.35 132.10 - 132.10

CCCT Dry "F", 2x1, ISO 0 56% 21.84 na 498 33.53 2.11 7.69% 0.16 - 2.67 60.31 - 60.31

CCCT Dry "F", DF, 2x1, ISO 0 16% 49.54 na 498 42.21 0.08 0.00% 0.00 - 3.36 95.19 - 95.19

CCCT Dry "G/H", 1x1, ISO 0 56% 22.51 na 498 34.17 2.53 7.05% 0.18 - 2.72 62.12 - 62.12

CCCT Dry "G/H", DF, 1x1, ISO 0 16% 54.09 na 498 41.12 0.08 0.00% 0.00 - 3.28 98.56 - 98.56

CCCT Dry "G/H", 2x1, ISO 0 56% 21.17 na 498 33.56 2.44 7.30% 0.18 - 2.67 60.02 - 60.02

CCCT Dry "G/H", DF, 2x1, ISO 0 16% 53.06 na 498 40.34 0.07 0.00% 0.00 - 3.21 96.69 - 96.69

CCCT Dry "J", Adv 1x1, ISO 0 56% 21.28 na 498 32.32 2.20 7.03% 0.15 - 2.58 58.53 - 58.53

CCCT Dry "J", DF, Adv 1x1, ISO 0 16% 47.87 na 498 42.86 0.08 0.00% 0.00 - 3.41 94.22 - 94.22

Intercooled SCCT Aero x1 1500 21% 72.03 na 498 43.99 2.99 6.83% 0.20 - 3.51 122.73 - 122.73

SCCT Frame "F" x1 1500 21% 52.65 na 498 49.52 8.71 7.80% 0.68 - 3.95 115.50 - 115.50

IC Recips x 6 1500 21% 81.65 na 498 42.04 7.63 4.48% 0.34 - 3.35 135.02 - 135.02

CCCT Dry "F", 2x1 1500 56% 22.62 na 498 33.53 2.18 7.67% 0.17 - 2.67 61.17 - 61.17

CCCT Dry "F", DF, 2x1 1500 16% 49.54 na 498 42.21 0.08 0.00% 0.00 - 3.36 95.20 - 95.20

CCCT Dry "G/H", 2x1 1500 56% 21.90 na 498 33.71 2.54 7.29% 0.19 - 2.69 61.02 - 61.02

CCCT Dry "G/H", DF, 2x1 1500 16% 53.13 na 498 40.49 0.07 0.00% 0.00 - 3.23 96.92 - 96.92

CCCT Dry "J", Adv 1x1 1500 56% 21.84 na 498 32.32 2.27 7.01% 0.16 - 2.58 59.17 - 59.17

CCCT Dry "J", DF, Adv 1x1 1500 16% 47.87 na 498 42.86 0.08 0.00% 0.00 - 3.41 94.22 - 94.22

SCCT Aero x3 4250 21% 74.16 na 472 45.97 3.89 6.67% 0.26 - 3.86 128.15 - 128.15

Intercooled SCCT Aero x1 4250 21% 71.84 na 472 41.85 3.23 6.83% 0.22 - 3.52 120.66 - 120.66

SCCT Frame "F" x1 4250 21% 49.90 na 472 46.97 9.48 7.80% 0.74 - 3.95 111.03 - 111.03

IC Recips x6 4250 21% 83.07 na 472 39.87 8.15 4.48% 0.36 - 3.35 134.81 - 134.81

CCCT Wet "F", 2x1 4250 56% 22.57 na 472 31.46 2.87 6.27% 0.18 - 2.64 59.73 - 59.73

CCCT Wet "F", DF, 2x1 4250 16% 40.27 na 472 37.30 0.32 0.00% 0.00 - 3.13 81.02 - 81.02

CCCT Dry "F", 1x1 5050 56% 26.15 na 472 32.17 2.57 7.50% 0.19 - 2.70 63.79 - 63.79

CCCT Dry "F", DF, 1x1 5050 16% 44.44 na 472 40.21 0.08 0.00% 0.00 - 3.38 88.10 - 88.10

CCCT Dry "F", 2x1 5050 56% 23.20 na 472 31.80 2.42 7.67% 0.19 - 2.67 60.27 - 60.27

CCCT Dry "F", DF, 2x1 5050 16% 42.98 na 472 40.04 0.08 0.00% 0.00 - 3.36 86.46 - 86.46

CCCT Dry "G/H", 1x1 5050 56% 23.89 na 472 32.41 2.94 6.99% 0.21 - 2.72 62.17 - 62.17

CCCT Dry "G/H", DF, 1x1 5050 16% 47.70 na 472 39.00 0.08 0.00% 0.00 - 3.28 90.05 - 90.05

CCCT Dry "G/H", 2x1 5050 56% 22.43 na 472 31.83 2.82 7.27% 0.21 - 2.67 59.96 - 59.96

CCCT Dry "G/H", DF, 2x1 5050 16% 46.80 na 472 38.26 0.07 0.00% 0.00 - 3.21 88.34 - 88.34

CCCT Dry "J", Adv 1x1 5050 56% 22.45 na 472 30.66 2.54 6.98% 0.18 - 2.58 58.40 - 58.40

CCCT Dry "J", DF, Adv 1x1 5050 16% 41.22 na 472 40.65 0.08 0.00% 0.00 - 3.41 85.36 - 85.36

Intercooled SCCT Aero x1 6500 21% 73.64 na 472 41.85 3.39 6.83% 0.23 - 3.52 122.63 - 122.63

SCCT Frame "F" x1 6500 21% 50.19 na 472 46.97 10.00 7.80% 0.78 - 3.95 111.88 - 111.88

IC Recips x6 6500 21% 86.55 na 472 39.87 8.60 4.48% 0.39 - 3.35 138.76 - 138.76

CCCT Dry "G/H", 2x1 6500 56% 22.69 na 472 31.83 2.92 7.27% 0.21 - 2.67 60.33 - 60.33

CCCT Dry "G/H", DF, 2x1 6500 16% 44.90 na 472 38.26 0.07 0.00% 0.00 - 3.21 86.44 - 86.44

CCCT Dry "J", Adv 1x1 6500 56% 22.66 na 472 30.66 2.62 6.96% 0.18 - 2.58 58.69 - 58.69

CCCT Dry "J", DF, Adv 1x1 6500 16% 39.20 na 472 40.65 0.08 0.00% 0.00 - 3.41 83.34 - 83.34

Elevation 

(AFSL)

Convert to Mills

 Variable Costs

(mills/kWh) 

Levelized Fuel

 Total Costs and Credits

(Mills/kWh) 

 Total 

Resource Cost 

 Total Resource 

Cost -

With PTC / ITC 

Credits 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

120

Table 6.3 – Total Resource Cost for Supply-Side Resource Options, $16 CO2 Tax (Continued)

$16 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($)

Resource Description O&M

 Capitalized 

Premium 

 O&M 

Capitalized 

 Gas 

Transporta

tion Total

IGCC with CCS 6500 $5,931 7.438% $441.13 60.76 0.00% 0.00 0.00 60.76 $501.90

Generic Geothermal PPA 90% CF 4500 $0 6.831% $0.00 735.46 0.00% 0.00 0.00 735.46 $735.46

2.3 MW turbine 29% CF WA 1500 $2,365 8.165% $193.12 33.11 1.14% 0.38 0.00 33.49 $226.61

2.3 MW turbine 29% CF UT 4500 $2,304 8.165% $188.12 33.11 1.14% 0.38 0.00 33.49 $221.61

2.3 MW turbine 40% CF WY 6500 $2,257 8.165% $184.30 33.11 1.14% 0.38 0.00 33.49 $217.78

PV Poly-Si Fixed Tilt 22% CF (1.21 MWdc/MWac) 4500 $3,153 8.165% $257.48 51.50 2.45% 1.26 0.00 52.76 $310.24

PV Poly-Si Fixed Tilt 28% CF (1.37 MWdc/MWac) 4500 $2,952 8.165% $241.05 27.81 2.45% 0.68 0.00 28.49 $269.54

PV Poly-Si Single Tracking 34% CF (1.34 MWdc/MWac) 4500 $3,176 8.165% $259.29 32.55 2.45% 0.80 0.00 33.35 $292.64

Forestry Byproduct 1500 $3,334 7.542% $251.45 40.65 5.07% 2.06 0.00 42.71 $294.16

Pumped Storage 4500 $3,000 7.459% $223.77 4.30 6.19% 0.27 0.00 4.57 $228.34

Sodium-Sulfur Battery 4500 $4,400 8.722% $383.77 27.40 0.00% 0.00 0.00 27.40 $411.17

Advanced Fly Wheel 4500 $2,406 8.722% $209.85 96.24 0.00% 0.00 0.00 96.24 $306.09

CAES 4500 $1,751 8.428% $147.57 33.80 0.00% 0.00 21.95 55.75 $203.33

Advanced Fission 4500 $7,093 7.623% $540.70 88.75 5.79% 5.14 0.00 93.89 $634.59

Elevation 

(AFSL)

Capital Cost $/kW Fixed Cost

 Total Capital Cost 

Payment 

Factor

 Annual 

Payment 

($/kW-Yr) 

Fixed O&M $/kW-Yr

 Total 

Fixed

($/kW-Yr) 

$16 CO2 Tax

Supply Side Resource Options

Mid-Calendar Year 2012 Dollars ($) Credits

Resource Description

Capacity 

Factor

 Total Fixed

(Mills/kWh) 

Storage 

Efficiency ¢/mmBtu Mills/kWh O&M 

 Capitalized 

Premium 

 O&M 

Capitalized 

 Integration 

Cost Environmental 

 PTC Tax 

Credits / ITC 

(Solar Only) 

IGCC with CCS 6500 86% 66.96 na 271 29.91 13.52 12.08% 1.63 - 0.76 112.79 - 112.79

Generic Geothermal PPA 90% CF 4500 90% 93.28 na - - 11.00 0.00% 0.00 - - 104.29 - 104.29

2.3 MW turbine 29% CF WA 1500 29% 89.20 na - - 0.00 0.00% 0.00 2.55 - 91.76 (19.48) 72.28

2.3 MW turbine 29% CF UT 4500 29% 87.23 na - - 0.00 0.00% 0.00 2.55 - 89.79 (19.48) 70.31

2.3 MW turbine 40% CF WY 6500 40% 62.15 na - - 0.65 0.00% 0.00 2.55 - 65.36 (19.48) 45.88

PV Poly-Si Fixed Tilt 22% CF (1.21 MWdc/MWac) 4500 22% 160.98 na - - 0.00 0.00% 0.00 0.64 - 161.62 (19.91) 141.70

PV Poly-Si Fixed Tilt 28% CF (1.37 MWdc/MWac) 4500 28% 108.69 na - - 0.00 0.00% 0.00 0.64 - 109.33 (14.49) 94.84

PV Poly-Si Single Tracking 34% CF (1.34 MWdc/MWac) 4500 34% 98.86 na - - 0.00 0.00% 0.00 0.64 - 99.50 (13.06) 86.45

Forestry Byproduct 1500 91% 37.00 na 512 51.29 0.96 0.00% 0.00 - 6.90 96.15 (17.86) 78.29

Pumped Storage 4500 42% 62.56 77.5% 472 59.32 4.30 0.00% 0.00 - - 126.18 - 126.18

Sodium-Sulfur Battery 4500 25% 187.75 72.5% 472 63.41 0.00 0.00% 0.00 - - 251.16 - 251.16

Advanced Fly Wheel 4500 5% 698.84 85.0% 472 54.09 0.00 0.00% 0.00 - - 752.93 - 752.93

CAES 4500 33% 69.63 83.5% 472 55.06 22.51 10.29% 2.32 - 3.86 153.38 - 153.38

Advanced Fission 4500 86% 84.67 na 85 9.11 2.04 0.00% 0.00 - - 95.82 - 95.82

Elevation 

(AFSL)

Convert to Mills

 Variable Costs

(mills/kWh) 

Levelized Fuel

 Total Costs and Credits

(Mills/kWh) 

 Total 

Resource Cost 

 Total Resource 

Cost -

With PTC / ITC 

Credits 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

121

Table 6.4- Glossary of Terms from Supply Side Resource Table

Term Description

Fuel: Primary fuel used for electricity generation or storage.

Resource: Primary technology used for electricity generation or storage.

Elevation (afsl): Average feet above sea level for the proxy site for the given resource.

Net Capacity (MW):

Net dependable capacity is the net electrical output for a given technology at 

the given elevation and annual average ambient temperature in a "new and 

clean" condition.

Commercial Operation 

Year:

First year the resource could be placed in service; available for generation and 

dispatch.

Design Life (yrs):

Average number of years the resource is expected to be "used and useful", 

based on various factors such as OEM guarantees, fuel availability and 

environmental regulations.

Base Capital ($/kW): 

Total capital expenditure in $/kW for the development and construction of a 

resource, including direct costs (equipment, buildings, installation/overnight 

construction, commissioning, EPC fees/profit, and contingency), owner's costs 

(land acquisition, water rights, air permitting, rights of way, design 

engineering, spare parts, project management costs, legal/financial costs, grid 

interconnection costs, owner’s contingency), and financial costs (AFUDC, 

capital surcharge, property taxes, escalation).)

Var O&M ($/MWh): 

Includes real levelized variable operating costs such as combustion turbine 

maintenance, raw water costs, boiler water/circulating water treatment 

chemicals, pollution control chemicals, equipment maintenance chemicals, and 

fired hour fee.

Fixed O&M ($/KWyr):Includes fixed operating costs: labor costs, combustion turbine fixed 

maintenance fees, contracted services fees, office equipment, training.

Full Load Heat Rate 

HHV (Btu/KWh):

Efficiency of a resource to generate electricity for a given heat input in a "new 

and clean" condition.

EFOR (%): Estimated Equivalent Forced Outage Rate, which includes forced outages and 

derates, for a given resource at the given site.

POR (%): Estimated Planned Outage Rate for a given resource at the given site.

Water Consumed 

(gal/MWh):

Average amount of water consumed by a resource for make-up, cooling water 

make-up, inlet conditioning and pollution control.

SO2 (lbs/MMBtu): Expected permitted level of sulfur dioxide emissions in pounds of sulfur 

dioxide per million Btu of heat input.

NOx (lbs/MMBtu): Expected permitted level of nitrogen oxides (expressed as NO2) in pounds of 

NOx per million Btu of heat input.

Hg (lbs/TBtu): Expected permitted level of mercury emissions in pounds per trillion Btu of 

heat input.

CO2 (lbs/MMBtu): Pounds of carbon dioxide emitted per million Btu of heat input.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

122

Table 6.5 – Glossary of Acronyms Used in the Supply Side Resource Table

Acronyms Description

Adv: Advanced (Combined Cycle Combustion Turbine)

AFSL: Average Feet (Above) Sea Level

CAES: Compressed Air Energy Storage

CCCT: Combined Cycle Combustion Turbine

CCS: Carbon Capture and Sequestration

CF: Capacity Factor

CSP: Concentrated Solar Power

DF: Duct Firing

IC: Internal Combustion

IGCC: Integrated Gasification Combined Cycle

ISO: International Organization for Standardization (Temp = 59 F/15 C, Pressure = 

14.7 psia/1.013 bar)

PC CCS: Pulverized Coal-Carbon Capture and Sequestration

PV Poly-Si: Photovoltaic cells constructed from poly-crystalline silicon semiconductor 

wafers

Recip: Reciprocating Engine

SCCT: Simple Cycle Combustion Turbine

SCPC: Super-Critical Pulverized Coal

SO: Solid Oxide (Fuel Cell)

Some important factors that apply to the Supply Side Resource Tables are listed below:

Capital costs are all-inclusive and include Allowance for Funds Used During 

Construction (AFUDC), land, EPC (Engineering, Procurement, and Construction) cost 

premiums, owner’s costs, etc. Capital costs in Table 6.5 reflect mid-2012 dollars, and do 

not include escalation from mid-year to the year of commercial operation.

Costs of energy for solar resources include investment tax credits. Hybrid solar with 

natural gas backup would not qualify for investment tax credits.

Wind, hydrokinetic, biomass, and geothermal resources are assumed to qualify for 

Production Tax Credits (PTC), depending on the installation date. 

Capital costs include interconnection costs to the transmission system (switchyard and 

other upgrades needed to interconnect the resource to PacifiCorp’s transmission network) 

but do not include transmission system network upgrades.

For the nuclear resource, capital costs include the cost of storing spent fuel on-site during 

the life of the facility. Costs for ultimate off-site disposal of spent fuel are not included.

Wind resources are representative generic resources included in the IRP models for 

planning purposes. Cost and performance attributes of specific resources are identified as 

part of the acquisition process. An estimate for wind integration costs, $2.55/MWh, has 

been added to variable O&M cost.

State specific tax benefits are excluded from the IRP supply side table but would be 

considered in the evaluation of a specific project.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

123

A sensitivity analysis was prepared for three Natural Gas-fired Combined Cycle Combustion 

Turbine resource options at varying capacity factors. Table 6.6 shows the total resource cost 

results for this analysis.

Table 6.6 – Total Resource Cost, Natural Gas-fired plants at varying Capacity Factors 

(2012$)

Total Resource Cost (Mills/kWh)

Capacity Factor CCCT 40% 56% 80%

Capacity Factor Duct Fire 10% 16% 22%

CCCT Wet "F", 2x1 4250 $68.75 $59.73 $52.96

CCCT Wet "F", DF, 2x1 4250 $105.18 $81.02 $70.04

CCCT Dry "F", 1x1 5050 $74.25 $63.79 $55.95

CCCT Dry "F", DF, 1x1 5050 $114.76 $88.10 $75.98

CCCT Dry "F", 2x1 5050 $69.55 $60.27 $53.32

CCCT Dry "F", DF, 2x1 5050 $112.25 $86.46 $74.74

CCCT Dry "G/H", 1x1 5050 $71.73 $62.17 $55.00

CCCT Dry "G/H", DF, 1x1 5050 $118.67 $90.05 $77.04

CCCT Dry "G/H", 2x1 5050 $68.93 $59.96 $53.23

CCCT Dry "G/H", DF, 2x1 5050 $116.42 $88.34 $75.58

CCCT Dry "J", Adv 1x1 5050 $67.38 $58.40 $51.66

CCCT Dry "J", DF, Adv 1x1 5050 $110.09 $85.36 $74.12

Elevation 

(AFSL)
PACIFICORP – 2013 IRP CHAPTE

124

Distributed Generation

Table 6.7 presents cost and performance attributes for small combined heart and power and solar

resource options.

Tables 6.8 and 6.9 present the total resource cost attributes for small combined heat and power and 

solar resource options, and are based on estimates of the first-year real levelized cost per megawatthour of resources, stated in June 2012 dollars. The resource costs are presented for both the $0 and $16 

CO2 tax levels in recognition of the uncertainty in characterizing emission costs. Additional 

explanatory notes for the tables are as follows:

Administrative costs, representing the estimated cost of delivering a program to end-use customers, 

are included for solar photovoltaic and water heating systems. Small combined heart and power are 

considered qualifying facilities as such do not include administrative or interconnection costs.

As available, federal tax benefits are included for the following resources based on a percent of 

capital cost.

- Reciprocating Engine 10 percent

- Microturbine 10 percent

- Fuel Cell 30 percent

- Gas Turbine 10 percent

- Industrial Biomass 10 percent

- Anaerobic Digesters 10 percent

The resource cost for Industrial Biomass is based on data from The Cadmus Group, Inc. (Cadmus). 

The fuel is assumed to be provided by the project owner at no cost, a conservative assumption. In 

reality, the cost to the Company would be each state’s filed avoided cost rate.

Installation costs for on-site (“micro”) solar generation technologies are treated on a total resource 

cost basis; that is, customer installation costs are included. If available, capital costs are adjusted 

downward to reflect federal tax credits of 30 percent of installed system costs. Conversely, no 

adjustment is made for state tax incentives as these are not included in the Total Resource Cost test 

that sees the incentive as a benefit to customers but also as a cost to the state’s tax payers, making 

the net effect zero. In Utah, these resources are assessed on a Utility Cost Test basis, considering 

only utility incentives and program administrative 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

125

Table 6.7- Distributed Generation Resource Supply-Side Options

Supply-side Resource Options

Mid-Calendar Year 2012 Dollars ($)

Resource Description Installation Location

Earliest InService 

Date 

(Middle of 

year)

Average 

Capacity MW Fuel

Design 

Plant Life 

in Years

Annual 

Average 

Heat Rate 

HHV 

BTU/kWh

Maint. 

Outage 

Rate

Equivalent 

Forced 

Outage Rate

Base Capital 

Cost in $/kW

Var. O&M, 

$/MWh

Fixed 

O&M in 

$/kW-yr

SO2 in 

lbs/MMBt

u

NOx in 

lbs/MMBt

u

Hg in 

lbs/trillion 

Btu

CO2 in 

lbs/mmBtu

Reciprocating Engine Idaho 2013 0.40 Natural Gas 20 8,000 2% 3% $ 1,495 - $ 47.41 0.001 0.101 0.255 118.00

Reciprocating Engine Utah 2013 6.61 Natural Gas 20 8,000 2% 3% $ 1,495 - $ 47.41 0.001 0.101 0.255 118.00

Reciprocating Engine Oregon / California 2013 1.04 Natural Gas 20 8,000 2% 3% $ 1,495 - $ 47.41 0.001 0.101 0.255 118.00

Reciprocating Engine Washington 2013 1.28 Natural Gas 20 8,000 2% 3% $ 1,495 - $ 47.41 0.001 0.101 0.255 118.00

Reciprocating Engine Wyoming 2013 0.89 Natural Gas 20 8,000 2% 3% $ 1,495 - $ 47.41 0.001 0.101 0.255 118.00

Gas Turbine Idaho 2013 0.14 Natural Gas 20 6,300 2% 3% $ 1,757 - $ 55.42 0.001 0.050 0.255 118.00

Gas Turbine Utah 2013 1.90 Natural Gas 20 6,300 2% 3% $ 1,757 - $ 55.42 0.001 0.050 0.255 118.00

Gas Turbine Oregon 2013 0.27 Natural Gas 20 6,300 2% 3% $ 1,757 - $ 55.42 0.001 0.050 0.255 118.00

Gas Turbine Washington 2013 0.13 Natural Gas 20 6,300 2% 3% $ 1,757 - $ 55.42 0.001 0.050 0.255 118.00

Gas Turbine Wyoming 2013 0.30 Natural Gas 20 6,300 2% 3% $ 1,757 - $ 55.42 0.001 0.050 0.255 118.00

Microturbine Utah 2013 0.95 Natural Gas 10 8,000 2% 3% $ 2,168 - $ 63.42 0.001 0.101 0.255 118.00

Fuel Cell Utah 2013 0.47 Natural Gas 10 6,100 2% 3% $ 3,673 - $ 186.91 0.001 0.003 0.255 118.00

Commercial Biomass, Anaerobic Digester Utah 2013 0.20 Biomass 25 - 10% 10% $ 2,452 - $ 61.78 - - - -

Commercial Biomass, Anaerobic Digester Wyoming 2013 0.16 Biomass 25 - 10% 10% $ 2,452 - $ 61.78 - - - -

Industrial Biomass, Waste Utah 2013 0.16 Biomass 25 - 5% 5% $ 631 - $ 28.82 - - - -

Industrial Biomass, Waste Oregon / California 2013 0.55 Biomass 25 - 5% 5% $ 631 - $ 28.82 - - - -

Rooftop Photovoltaic (Utility Cost) Utah 2013 13.116 Solar 30 - $ 902 - - - - - -

Rooftop Photovoltaic Wyoming 2013 0.291 Solar 30 - $ 4,693 - $ 20.47 - - - -

Rooftop Photovoltaic Oregon / California 2013 7.613 Solar 30 - $ 4,753 - $ 20.47 - - - -

Rooftop Photovoltaic Idaho 2013 0.148 Solar 30 - $ 4,693 - $ 20.47 - - - -

Rooftop Photovoltaic Washington 2013 0.154 Solar 30 - $ 4,693 - $ 20.47 - - - -

Water Heaters (Utility Cost) Utah 2013 1.531 Solar 20 - $ 194 - - - - - -

Water Heaters Oregon 2013 2.159 Solar 20 - $ 1,600 - $ 20.36 - - - -

Small Combined Heat & Power

Location / Timing Plant Details Outage Information Costs Emissions

Solar
PACIFICORP – 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

126

Table 6.8 – Distributed Generation Total Resource Cost, $0 CO2 Tax

$0 CO2 Tax Capital Cost $/kW

Supply-side Resource Options Mid-Calendar Year 2012 Dollars ($)

Resource Description

 Tax 

Incentive O&M

Capacity 

Factor

 Total Fixed

(Mills/kWh) ¢/mmBtu Mills/kWh O&M 

 Gas 

Transportation Environmental 

 Tax 

Incentive 

(Mills/kWh) 

Reciprocating Engine Idaho $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 431.47 34.52 - $ 2.06 - $ 95.39 $ 5.03 $ 100.42

Reciprocating Engine Utah $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 431.47 34.52 - $ 2.06 - $ 95.39 $ 5.03 $ 100.42

Reciprocating Engine Oregon / California $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 472.04 37.76 - $ 3.05 - $ 99.62 $ 5.03 $ 104.65

Reciprocating Engine Washington $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 472.04 37.76 - $ 3.05 - $ 99.62 $ 5.03 $ 104.65

Reciprocating Engine Wyoming $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 431.47 34.52 - $ 1.76 - $ 95.09 $ 5.03 $ 100.12

Gas Turbine Idaho $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 431.47 27.18 - $ 1.62 - $ 62.89 $ 2.92 $ 65.81

Gas Turbine Utah $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 472.04 29.74 - $ 1.62 - $ 65.45 $ 2.92 $ 68.37

Gas Turbine Oregon $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 472.04 29.74 - $ 1.62 - $ 65.45 $ 2.92 $ 68.37

Gas Turbine Washington $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 431.47 27.18 - $ 1.62 - $ 62.89 $ 2.92 $ 65.81

Gas Turbine Wyoming $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 431.47 27.18 - $ 1.62 - $ 62.89 $ 2.92 $ 65.81

Microturbine Utah $ 241 $ 2,168 14.39% $ 311.92 $ 63.42 $ 375.34 49% 87.44 431.47 34.52 - $ 2.06 - $ 124.02 $ 8.07 $ 132.09

Fuel Cell Utah $ 1,574 $ 3,673 14.39% $ 528.51 $ 186.91 $ 715.42 71% 115.03 431.47 26.32 - $ 1.57 - $ 142.92 $ 36.42 $ 179.33

Commercial Biomass, Anaerobic Digester Utah $ 272 $ 2,452 8.17% $ 200.23 $ 61.78 $ 262.00 46% 65.09 - - - - - $ 65.09 $ 5.53 $ 70.62

Commercial Biomass, Anaerobic Digester Wyoming $ 272 $ 2,452 8.17% $ 200.23 $ 61.78 $ 262.00 46% 65.09 - - - - - $ 65.09 $ 5.53 $ 70.62

Industrial Biomass, Waste Utah $ 70 $ 631 8.17% $ 51.50 $ 28.82 $ 80.32 90% 10.19 - - - - - $ 10.19 $ 0.73 $ 10.91

Industrial Biomass, Waste Oregon / California $ 70 $ 631 8.17% $ 51.50 $ 28.82 $ 80.32 90% 10.19 - - - - - $ 10.19 $ 0.73 $ 10.91

Rooftop Photovoltaic (Utility Cost) Utah $ 902 $ 902 7.54% $ 68.05 - $ 68.05 17% 45.70 - - - - - $ 45.70 - $ 45.70

Rooftop Photovoltaic Wyoming $ 2,011 $ 131 $ 4,693 7.54% $ 353.93 $ 20.47 $ 374.40 19% 229.23 - - - - - $ 229.23 $ 92.87 $ 322.11

Rooftop Photovoltaic Oregon / California $ 2,037 $ 133 $ 4,753 7.54% $ 358.49 $ 20.47 $ 378.96 16% 274.87 - - - - - $ 274.87 $ 111.44 $ 386.31

Rooftop Photovoltaic Idaho $ 2,011 $ 131 $ 4,693 7.54% $ 353.93 $ 20.47 $ 374.40 15% 279.35 - - - - - $ 279.35 $ 113.17 $ 392.52

Rooftop Photovoltaic Washington $ 2,011 $ 131 $ 4,693 7.54% $ 353.93 $ 20.47 $ 374.40 14% 298.88 - - - - - $ 298.88 $ 121.09 $ 419.97

Water Heaters (Utility Cost) Utah $ 194 $ 194 9.15% $ 17.72 - $ 17.72 6% 33.92 - - - - - $ 33.92 - $ 33.92

Water Heaters Oregon $ 752 $ 267 $ 1,600 9.15% $ 146.45 $ 20.36 $ 166.81 7% 263.15 - - - - - $ 263.15 $ 108.58 $ 371.73

Levelized Fuel

Small Combined Heat & Power

 Location 

 Net Capital 

Costs 

Payment 

Factor

 Annual 

Payment 

($/kW-Yr) 

 Total Fixed

($/kW-Yr) 

 Total Resource 

Cost without 

Tax Benefits

(Mills/kWh) 

Solar

Fixed Cost Convert to Mills Variable Costs

(mills/kWh) 

 Total Resource 

Cost with Tax 

Benefits

(Mills/kWh) 

 Rebate and 

Administrative 

Costs 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Table 6.9 – Distributed Generation Total Resource Cost, $16 CO2 Tax

$16 CO2 Tax Capital Cost $/kW

Supply-side Resource Options Mid-Calendar Year 2012 Dollars ($)

Resource Description Tax 

Incentive O&M

Capacity 

Factor

 Total Fixed

(Mills/kWh) ¢/mmBtu Mills/kWh O&M 

 Gas 

Transportation

or Wind 

Integration Environmental 

 Tax 

Incentive 

(Mills/kWh) 

Reciprocating Engine Idaho $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 472.04 37.76 - $ 2.06 3.17 $ 101.80 $ 5.03 $ 106.83

Reciprocating Engine Utah $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 472.04 37.76 - $ 2.06 3.17 $ 101.80 $ 5.03 $ 106.83

Reciprocating Engine Oregon / California $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 497.71 39.82 - $ 3.05 3.17 $ 104.85 $ 5.03 $ 109.88

Reciprocating Engine Washington $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 497.71 39.82 - $ 3.05 3.17 $ 104.85 $ 5.03 $ 109.88

Reciprocating Engine Wyoming $ 166 $ 1,495 10.61% $ 158.65 $ 47.41 $ 206.07 40% 58.81 472.04 37.76 - $ 1.76 3.17 $ 101.50 $ 5.03 $ 106.53

Gas Turbine Idaho $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 472.04 29.74 - $ 1.62 2.50 $ 67.94 $ 2.92 $ 70.86

Gas Turbine Utah $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 497.71 31.36 - $ 1.62 2.50 $ 69.56 $ 2.92 $ 72.48

Gas Turbine Oregon $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 497.71 31.36 - $ 1.62 2.50 $ 69.56 $ 2.92 $ 72.48

Gas Turbine Washington $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 472.04 29.74 - $ 1.62 2.50 $ 67.94 $ 2.92 $ 70.86

Gas Turbine Wyoming $ 195 $ 1,757 10.61% $ 186.45 $ 55.42 $ 241.87 81% 34.09 472.04 29.74 - $ 1.62 2.50 $ 67.94 $ 2.92 $ 70.86

Microturbine Utah $ 241 $ 2,168 14.39% $ 311.92 $ 63.42 $ 375.34 49% 87.44 472.04 37.76 - $ 2.06 3.17 $ 130.44 $ 8.07 $ 138.51

Fuel Cell Utah $ 1,574 $ 3,673 14.39% $ 528.51 $ 186.91 $ 715.42 71% 115.03 472.04 28.79 - $ 1.57 2.42 $ 147.81 $ 36.42 $ 184.23

Commercial Biomass, Anaerobic Digester Utah $ 272 $ 2,452 8.17% $ 200.23 $ 61.78 $ 262.00 46% 65.09 - - - - - $ 65.09 $ 5.53 $ 70.62

Commercial Biomass, Anaerobic Digester Wyoming $ 272 $ 2,452 8.17% $ 200.23 $ 61.78 $ 262.00 46% 65.09 - - - - - $ 65.09 $ 5.53 $ 70.62

Industrial Biomass, Waste Utah $ 70 $ 631 8.17% $ 51.50 $ 28.82 $ 80.32 90% 10.19 - - - - - $ 10.19 $ 0.73 $ 10.91

Industrial Biomass, Waste Oregon / California $ 70 $ 631 8.17% $ 51.50 $ 28.82 $ 80.32 90% 10.19 - - - - - $ 10.19 $ 0.73 $ 10.91

Rooftop Photovoltaic (Utility Cost) Utah $ 902 $ 902 7.54% $ 68.05 - $ 68.05 17% 45.70 - - - - - $ 45.70 - $ 45.70

Rooftop Photovoltaic Wyoming $ 2,011 $ 131 $ 4,693 7.54% $ 353.93 $ 20.47 $ 374.40 19% 229.23 - - - - - $ 229.23 $ 92.87 $ 322.11

Rooftop Photovoltaic Oregon / California $ 2,037 $ 133 $ 4,753 7.54% $ 358.49 $ 20.47 $ 378.96 16% 274.87 - - - - - $ 274.87 $ 111.44 $ 386.31

Rooftop Photovoltaic Idaho $ 2,011 $ 131 $ 4,693 7.54% $ 353.93 $ 20.47 $ 374.40 15% 279.35 - - - - - $ 279.35 $ 113.17 $ 392.52

Rooftop Photovoltaic Washington $ 2,011 $ 131 $ 4,693 7.54% $ 353.93 $ 20.47 $ 374.40 14% 298.88 - - - - - $ 298.88 $ 121.09 $ 419.97

Water Heaters (Utility Cost) Utah $ 194 $ 194 9.15% $ 17.72 - $ 17.72 6% 33.92 - - - - - $ 33.92 - $ 33.92

Water Heaters Oregon $ 752 $ 267 $ 1,600 9.15% $ 146.45 $ 20.36 $ 166.81 7% 263.15 - - - - - $ 263.15 $ 108.58 $ 371.73

 Location 

 Rebate and 

Administrative 

Costs 

 Net 

Capital 

Costs 

Convert to Mills

Levelized Fuel

 Annual 

Payment 

($/kW-Yr) 

Payment 

Factor

 Total 

Resource 

Cost 

(Mills/kWh) 

 Variable Costs

(mills/kWh) 

Fixed Cost

 Total Fixed

($/kW-Yr) 

 Total Resource 

Cost without Tax 

Benefits

(Mills/kWh) 

Solar

Small Combined Heat & Power
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Resource Option Description

Coal

Potential coal resources are shown in the supply-side resource options table as supercritical 

pulverized coal boilers (PC) and IGCC, located in both Utah and Wyoming. Costs for large coalfired boilers, since the 2007 IRP, have increased by approximately 50 to 60 percent due to many 

factors involving material shortages, labor shortages, and the risk of fixed price contracting. 

Current economic conditions have mitigated many of these concerns and changes in price for 

coal generation have been relatively stable since the previous IRP. The uncertainty of both 

proposed and future carbon regulations and difficulty in obtaining environmental permits for coal 

based generation requires 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. Additionally, there is a greater competitive marketplace for large supercritical 

boilers than for large subcritical boilers. Increasingly, large boiler manufacturers only offer 

supercritical boilers in the 500-plus MW sizes. Due to the increased efficiency of supercritical 

boilers, overall emission intensity rates are smaller than for similarly sized subcritical units. 

Compared to subcritical boilers, supercritical boilers have better load following capability, faster 

ramp rates, use less water and require less steel for construction. The smaller steel requirements 

have also leveled the construction cost estimates for the two coal technologies. The costs for a 

supercritical PC facility reflect the cost of adding a new unit at an existing site. PacifiCorp does 

not expect a significant difference in cost for a multi-unit plant at a new site versus the cost of a 

single unit addition at an existing site.

The potential requirement for CO2 capture and sequestration (CCS) represents a significant cost 

for new and, possibly, existing coal resources. Currently proposed federal New Source 

Performance Standards for Greenhouse Gases (NSPS-GHG) regulations would require CCS for 

new coal units to meet the proposed emissions limit. Research projects are underway to develop 

more cost-effective methods of capturing carbon dioxide from pulverized coal boilers. The costs 

included in the supply side resource tables utilize amine based solvent systems for carbon 

capture. Sequestration would store the CO2 underground for long-term storage and monitoring.

PacifiCorp continues to monitor CO2 capture technologies for possible retrofit application on its 

existing coal-fired resources, as well as their applicability for future coal plants that could serve 

as cost-effective alternatives to IGCC plants if CO2 removal becomes necessary in the future. An 

option to capture CO2 at an existing coal-fired unit has been included in the supply side resource 

tables. Currently there are only a limited number of large-scale sequestration projects in 

operation around the world; most of these have been installed in conjunction with enhanced oil 

recovery. CCS is not considered a viable option before 2025 due to risk issues associated with 

the availability of commercial sequestration sites and the uncertainty regarding long term 

liabilities for underground sequestration.

An alternative to supercritical pulverized-coal technology for coal-based generation is the 

application of IGCC technology. A significant advantage for IGCC when compared to 

pulverized coal, with amine-based carbon capture, is the reduced cost of capturing CO2 from the 

process. Only a limited number of IGCC plants have been built and operated around the world. 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

129

In the United States, these facilities have been demonstration projects, resulting in capital and 

operating costs that are significantly greater than those costs for conventional coal plants. The 

majority of these projects have been constructed with significant funding from the federal 

government. Two large, utility-scale IGCC plants are currently in construction: Duke Energy’s 

Edwardsport Plant that utilizes General Electric’s gasification technology and Southern 

Company’s Kemper County plant that utilizes Southern Company’s Transport Integrated 

Gasifier (TRIG). A third IGCC project, utilizing Siemens gasification technology, the Texas 

Clean Energy Project, is currently in an advanced stage of development. The costs presented in 

the supply-side resource options tables reflect 2007 studies of IGCC costs associated with efforts 

to partner PacifiCorp with the Wyoming Infrastructure Authority (WIA) to investigate the 

acquisition of federal grant money to demonstrate western IGCC projects. 

PacifiCorp communicates regularly with the primary gasification technology suppliers, 

constructors, and other utilities. The results of all these contacts were used to help develop the 

coal-based generation projects in the supply side resource tables.

Coal Plant Efficiency Improvements

Fuel efficiency gains for existing coal plants, which are manifested as lower plant heat rates, are 

realized by: (1) continuous operations improvement, (2) monitoring the quality of the fuel 

supply, and (3) upgrading components if economically justified. Efficiency improvements can 

result in a smaller emissions footprint for a given level of plant capacity, or the same footprint 

when plant capacity is increased.

The efficiency of generating units, primarily measured by the heat rate (the ratio of heat input to 

energy output) degrades gradually as components wear over time. During operation, controllable 

process parameters are adjusted to optimize the unit’s power output compared to its heat input. 

Typical overhaul work that contributes to improved efficiency includes (1) major equipment 

overhauls of the steam generating equipment and combustion/steam turbine generators, (2) 

overhauls of the cooling systems and (3) overhauls of the pollution control equipment. 

When economically justified, efficiency improvements are obtained through major component 

upgrades of the electricity generating equipment. The most notable examples of upgrades 

resulting in greater generating capacity are steam turbine upgrades and generator upgrades. 

Turbine upgrades consist of adding additional rows of blades to the rearward section of the 

turbine shaft (generically known as a “dense pack” configuration), but can also include replacing 

existing blades, replacing end seals and enhancing seal packing media. Generator upgrades 

consist of cleaning and rewinding the coils in the stator, and servicing the electromagnetic core. 

Such upgrade opportunities are analyzed on a case-by-case basis, and are tied to a unit’s major 

overhaul cycle, and, because they are often capital intensive, are only implemented if 

economically justified.

Natural Gas

A number of natural gas fueled generation options are included in the supply-side resource 

options table and are intended to represent technologies that are both currently commercially 

available and/or will be available over the next few years. Both simple and combined cycle 

configurations are included. Capital costs for gas-fueled generation options approximate capital 

costs reported in previous IRPs. In real terms, capital costs have shown a modest decline 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

130

compared to the 2011 IRP, primarily driven by limited domestic orders for new gas-fired 

generation due to a lack of current economic growth.

Combustion turbine options include both simple and combined cycle configurations. The simple 

cycle (SCCT) options include traditional frame machines as well as aero-derivative combustion 

turbines. Two aero-derivative options are included: the General Electric LM6000PG combustion 

turbine and General Electric’s LMS100. These machines are flexible, high efficiency machines 

and can be installed with high temperature oxidation catalysts for carbon monoxide (CO) control 

and an SCR system for nitrogen oxides (NOx) control, which allows them to be located in areas 

with air emissions concerns. LM6000 gas turbines have quick-start capability (less than ten 

minutes to full load) and higher heating value net full load heat rates near 10,000 Btu/kWh. For 

the current supply side resource table, the GE LM6000PG machine was selected, which has a 

slightly higher output than the LM6000PC machine used in the previous IRP supply side 

resource table and which are installed at the Company’s Gadsby Plant. As in the previous IRP, 

the supply-side resource table includes General Electric’s LMS100 intercooled gas turbine. This 

combustion turbine has been successful since its debut with 28 units in service with 

approximately another 20 being installed as of summer 2012. It is a cross between a simple-cycle 

aero-derivative gas turbine and a frame machine with compressor inter-cooling to improve 

efficiency. The machines have higher heating value net full load heat rates of less than 9,000 

Btu/kWh and similar starting capabilities as the LM6000 with significant load following 

capability (up to 50 MW per minute). 

Frame simple cycle machines are represented by the “F” class technology and in the case of the 

current IRP Supply Side Resource options table the frame machine reflects a General Electric 7F 

5 series (previously referred to as the 7FA.05). One combustion turbine can generate 

approximately 180 MW at Western U.S. elevations; they have efficiencies similar to the 

LM6000 family of combustion turbines when operating in simple cycle.

Other natural gas-fired generation options include internal combustion engines and fuel cells. 

Internal combustion engines are represented by a large power plant consisting of six machines at 

17.2 MW each at Western elevations. The underlying technology for this category is the Wartsila 

18V50SG engine; these machines are spark-ignited and have the advantages of a relatively low 

(when compared to simple cycle combustion turbines), low emissions profile, and a high level of 

availability and reliability due to the relatively high number of machines for a given target 

capacity block. They are capable of being brought on line up to full load in less than ten minutes 

and have excellent part-load efficiency which is again due to fact that there is a high number of 

machines for a given capacity. These types of engines also have the advantage of being 

relatively insensitive to elevation and do not require high-pressure natural gas, which is typical 

of advanced combustion turbines. In previous IRPs, the underlying technology was the Wartsila 

20V34SG, a smaller engine. 

At present, fuel cells hold less promise for large utility scale applications due to high capital and 

maintenance costs, partly attributable to the lack of production capability and limited 

development. Fuel cell applications are beginning to advance in small scale with some

customers. 

A number of combined cycle configurations have been provided in this version of the Supply 

Side Resource options table. Configuration options include 1x1 and 2x1 configurations based on 

“F” and “G/H” combustion turbines. The “G/H” frame combustion turbine, although they are 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

131

supplied by different equipment manufacturers, are combined, since the power and performance 

outputs are relatively similar. Also included in the current version of the Supply Side Resource 

options table is the new “J” class combustion turbine, which is a large advanced combustion 

turbine (approximately 470 megawatts in a 1x1 combined cycle configuration under ISO 

conditions). The “J” class combustion turbine is now commercially available in the United 

States, though no orders have been placed to date. The Supply Side Resource table also includes 

Duct Firing (“DF”), which is not a stand-alone resource option, but is considered to be an 

available option for any combined cycle configuration and represents a low cost option to add 

peaking capability at relatively high efficiency and also a mechanism to recover lost power 

generation capability due to high ambient temperatures. The amount of duct firing in the supply 

side resource options table are stated as fixed values at 50 MW for the 1x1 configuration and 100 

MW for the 2x1 configuration, though in reality the amount of duct firing is a design 

consideration which means the incremental capacity that can be added is flexible. In most cases, 

all combined cycle options listed in the current supply side resource table are based on dry 

cooling (i.e. using an air cooled condenser) , rather than wet cooling (i.e. using a forced draft 

cooling tower). It is assumed that the availability of water in the western United States will 

continue to be limited. Furthermore, during cold weather cooling towers can have plumes that 

are sometimes considered a visual nuisance. The assumption of dry cooling is considered to be 

both prudent and conservative. In certain cases and sites, sufficient water may be available for 

wet cooling, in which case, performance and efficiency would be improved; the overall costs of 

energy would be site-specific depending on the total cost of water (commodity cost, 

transport/storage infrastructure cost, treatment cost, discharge cost) .

Wind

Resource Supply, Location, and Incremental Transmission Costs

It should be noted that the primary drivers of wind resource selection are the requirements of 

renewable portfolio standards and the availability of production tax credits. In the previous IRP, 

incremental transmission costs were expressed as dollars-per-kW values that were applied to 

costs of wind resources added in wind-generation-only bubbles. In the present IRP, the 

availability of certain wind resources is contingent upon the different Energy Gateway 

transmission scenarios. In the Energy Gateway scenario 1, no new Wyoming wind is available. 

The availability of higher capacity factor, lower cost Wyoming wind increases moving from 

Energy Gateway scenarios 2 through 5. In Energy Gateway scenarios 1, 2, and 4 the only 

available wind resource on the west side of the system delivers energy to the Willamette Valley 

bubble and assumes a BPA wheel from McNary to the Willamette Valley (inclusive of BPA 

wind integration charges). It is assumed that any potential capital required by BPA is included in 

the cost of the wheel. This west side wind resource further assumes an incremental PacifiCorp 

Transmission capital cost of $10 million (2012$), which equates to $33.33/kW (2012$). For 

Energy Gateway scenarios 3 and 5, a wind resource is available, which delivers energy to the 

Northwest via the transmission path Windstar to Hemmingway. This resource reflects additions 

in Gorge vial route through Boardman and then to Bethel. No BPA wheeling costs apply. No 

incremental transmission costs will be assigned to this resource (assumes Energy Gateway 

Segment H costs cover all transmission integration requirements). Table 6.10 below shows the 

total cumulative wind selection limits for each wind resource based upon Energy Gateway 

scenario.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

132

Table 6.10 – Cumulative Wind Selection Limits by Year and Energy Gateway Scenario

Capital Costs

Capital cost estimates for wind projects are based on the development and construction costs of 

previously built projects and 2012 market prices for the wind turbine generators. All wind 

resources are specified in 100 MW blocks, but the model can choose a fractional amount of a 

block. 

Wind Resource Capacity Factors and Energy Shapes

Resource options in the topology bubbles are assigned capacity factors based upon historic or 

expected project performance. Wyoming resource options are assigned a capacity factor value 

of40 percent, while wind resources in other states are assigned a value of 29 percent. Capacity 

factor is a separate modeled parameter from the capital cost, and is used to scale wind energy 

shapes used by both the System Optimizer and Planning and Risk models. The hourly generation 

shape reflects average hourly wind variability. The hourly generation shape is repeated for each 

year of the simulation.

Wind Integration Costs

To capture the costs of integrating wind into the system, PacifiCorp applied a value of 

$2.55/MWh (in 2012 dollars) for resource selection. The source of this value was the Company’s 

2012 wind integration study, which is included as Appendix H. Integration costs were 

incorporated into wind capital costs based on a 25-year project life expectancy and generation 

performance.

Other Renewable Resources

Other renewable generation resources included in the supply-side resource options table include 

geothermal, biomass and solar. 

Geothermal

The 2010 IRP Update included information from a 2010 geothermal study (see Table 6.11) that 

was commissioned by PacifiCorp and performed by Black & Veatch43. The 2010 study focused 

on geothermal projects that could demonstrate commercial viability and were in advanced phases 

of development. 

 

43 The 2010 geothermal study is available on PacifiCorp’s IRP web page. http://www.pacificorp.com/es/irp.html. 

Wind Capacity Total MW Available Energy Gateway

Resource Factor 2016 2017 2018 2019 2020 2021 >2021 Scenario

Wyoming (Aeolius) 40% - - - - - - - EG1

Wyoming (Aeolius) 40% - - - 650 650 650 650 EG2

Wyoming (Aeolius) 40% - - - 650 1,200 1,200 1,200 EG3

Wyoming (Aeolius) 40% - - - 650 650 1,000 1,000 EG4

Wyoming (Aeolius) 40% - - - 650 650 1,500 1,500 EG5

Oregon/ Washington (Willamette Valley) 29% - - - 300 300 300 300 EG 1,2,4

Oregon/ Washington (Bethel) 29% - - - 600 600 600 600 EG 3,5

South Utah Wind 29% - 200 200 200 200 200 200 All EG 1-5

Idaho (Goshen) Wind 29% - 600 600 600 600 600 600 All EG 1-5
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Table 6.11 – 2010 Geothermal Study Results

In response to the 2010 IRP Update, comments from stakeholders requested additional 

information on geothermal projects near PacifiCorp’s service territory that are in the early stages 

of exploration and development. PacifiCorp issued a Geothermal Information Request (GIR) to 

the public in 2011 to identify geothermal projects in the early stages of exploration and 

development. Black & Veatch was commissioned to review the responses, categorize the 

development stage of each project and recommend projects to PacifiCorp. As a result of the 

GIR, PacifiCorp received Information on 16 projects in the early stages of development from 10 

respondents. 

Black & Veatch reviewed the information provided and evaluated each of the 16 projects. The 

projects were categorized according to the Geothermal Energy Association’s definition of the 

four phases of energy development:

Phase 1 – Resource Procurement and Identification

Phase 2 – Resource Exploration and Confirmation

Phase 3 – Permitting and Initial Development

Phase 4 – Resource Production and Power Plant Construction

Projects that did not meet the minimum requirements to be labeled phase 1 were categorized as 

phase 0. All 16 projects were categorized as phase 0, phase 1, or phase 2. Black & Veatch 

Field Name State

Additional 

Capacity 

Available 

(Gross MW)

Additional 

Capacity 

Available 

(Net MW)

Additional 

Capacity 

Available to 

PacifiCorp 

(Net MW)a

Anticipated 

Plant Type 

for Additonal 

Capacity

LCOE 

(Low, 

$/MWh)b,c

LCOE 

(High, 

$/MWh)b,c

Lake City CA 30 24 24 Binary $83 $90

Medicine Lake CA 480 384 384 Binary $91 $98

Raft River ID 90 72 43 Binary $93 $100

Neal Hot 

Springs OR 30 24 0 Binary $80 $87

Cove Fort UT 100 80 60 to 63 Binary $68 $75

CrystalMadsen UT 30 24 0 Binary $93 $100

Roosevelt Hot 

Springs UT 90 81d 81d Flash/Binary Hybrid $46 $51

Thermo Hot 

Springs UT 118 94 0 Binary $91 $98

Totals 968 783 592 to 595

Source: BVG analysis for PacifiCorp.

Note:

a

 Calculated by subtracting the amount of resource under contract to or in contract negotiations

with other parties from the estimated net capacity available.

b

 Net basis

c

 These screening level cost estimates are based on available public information. More detailed

estimates based on proprietary information and calculated on a consistent basis might yield

different comparisons.

d

 While 81 MW net are estimated to be available, the resource should be developed in smaller

increments to verify resource sustainability

Table 1-1. Sites Selected for In-Depth Review.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

134

reviewed the experience of the project team, viability of the site, generation technology, 

economics, readiness and system interconnection of each project and recommended six projects. 

The six projects are shown below in Table 6.12 and Figure 6.3. The six recommended projects 

include two projects from each phase of development represented. Two of the recommended 

projects plan to use Enhanced Geothermal Systems (EGS), a technology that has not been 

commercially applied in the United States. The remaining four projects plan to use binary 

technology, which is inherently more costly and less efficient than the flash design suitable for 

projects with higher-temperature brine. The equivalent energy cost for each of the six projects 

ranges between $100 and $180/MWh. All six projects are in early stages of development and 

will have higher development risks than projects that have successfully completed higher phases 

of development. 

Table 6.12 – 2012 Geothermal Study Results

PHASE DEVELOPER PROJECT LOCATION MW TYPE

2

Oski Energy Cove Fort Cove Fort, UT 15 Binary (Kalina)

Davenport Newberry Newberry 

Volcano

Deschutes County, 

OR

15 Likely Binary 

/Flash EGS

1

Standard Steam Trust Newdale Newdale, ID Undef. Binary

Ida-Therm Renaissance Honeyville, UT 100 Binary

0

AltaRock Energy Buck Mountain Klamath Falls, OR 10 Dual Flash EGS

Surprise Valley Surprise Valley 

Hot Springs

Modoc County, CA 2-5 Binary 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

135

Figure 6.3 - Commercially Viable Geothermal Resources near PacifiCorp’s Service 

Territory
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

136

The cost recovery mechanisms currently available to PacifiCorp as a public electric utility are 

not compatible with the inherent risks associated with the development of geothermal resources 

for the production of electricity. The primary risks of geothermal development are dry holes, 

insufficient temperature and insufficient pressure. These risks cannot be quantified until after 

wells are dug. The costs to confirm production capability of a geothermal energy resource can be 

as high as 35 percent of total project development costs. Test wells drilled during the exploration 

phase of project development are typically estimated to cost between $500,000 and $1.5 million 

per well. Full diameter wells drilled during the confirmation phase of development are estimated 

to cost between $4 million and $5 million per well. Variations in the permeability of subsurface 

materials can determine whether wells in close proximity are commercially viable, lacking in 

pressure or temperature, or completely dry with no interconnectivity to a geothermal resource. 

As a regulated utility subject to the public utility commissions of six states, PacifiCorp is not 

compensated nor incentivized to engage in risk inherent activities. 

To mitigate the financial risks of geothermal development, PacifiCorp would use an RFP process 

to obtain market proposals for geothermal power purchase agreements or build-own-transfer 

project agreement structures. Geothermal developers, external to PacifiCorp, have the flexibility 

to structure project pricing to include all development risks. Through an RFP process, PacifiCorp

could choose the geothermal project with the lowest cost offered by the market and avoid 

considerable risk for the Company and its customers. In the event PacifiCorp identifies a 

geothermal asset that appears to be economically attractive but also determines that there is a 

significant possibility of development risk that the market will not economically absorb, 

PacifiCorp may approach state regulators with estimates of resource development costs and risks 

associated to obtain approval for a mechanism to address risks such as dry holes. Because public 

utility commissions typically do not allow recovery of expenditures which do not result in a 

direct benefit to customers, and at least one state has a statute that precludes cost recovery of any 

asset that is not considered to be “used and useful,” obtaining a mechanism to recover 

geothermal development costs may be difficult.

Biomass 

Cost and performance data for biomass based resources were obtained from third-party studies. 

In general, large-scale (greater than 50 MW) plants are rare, which is why the resource option 

shows a 5 MW plant on the supply side resource table. Nonetheless, select coal plants have been 

converted from burning coal to burning various types of biomass, including wood chips, 

cellulosic switch grass, municipal solid waste, or, in rare cases, an engineered fuel which adds 

processing and sorbents to the aforementioned base fuels. Certain coal plants have been 

identified as candidates for coal to biomass conversion, most notably Portland General Electric’s 

580 MW Boardman Plant in Oregon. The greatest challenge to building large biomass plants or 

retrofitting a coal unit to a large biomass plant is the cost, availability, reliability, and 

homogeneity of a long-term fuel supply. The transport and handling logistics of large quantities 

of biomass fuel poses a significant challenge, depending on the size of the facility. Because of 

the need to be close to a large source of biomass, the Pacific Northwest or Atlantic Southeast are 

generally considered good regions for siting biomass resources. The climate and economy of 

these regions promotes growth of trees in large plantations. While PacifiCorp currently does not 

own any biomass plants, the company does purchase power from a number of biomass fueled 

installations in Oregon through power purchase agreements.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

137

Solar

Three solar technologies are included in the supply side resource table: photovoltaic (PV) 

crystalline (both fixed and single axis tracking) and concentrated solar. Market prices for PV 

crystalline solar panels have dropped substantially during the past five plus years, giving the PV 

crystalline technology a cost advantage over concentrated solar and thin film. Unlike other 

resource options, the real capital costs for PV solar resources have been projected to decline 

slightly over the IRP study period. To model these decreases in real capital cost, data from 

PacifiCorp’s 2012 market estimate and the price change curve of the nominalized 2009 NREL 

price forecast data were used.

Oregon passed a law in 2009 that requires electric utilities in the state to meet photovoltaic solar 

generation requirements with facilities in Oregon that have nameplate capacities between 500 

kW and 5 MW. PacifiCorp is required to have a total of 8.7 MW of photovoltaic solar sources 

within its generation system in Oregon by January 1, 2020. 

To meet the Oregon solar requirement, PacifiCorp issued an RFP for solar projects and 

commissioned a study to evaluate solar resources in 2011. The Black Cap solar facility was 

selected in the RFP process and was constructed in 2012. The Black Cap facility represents 

completion of 2 MW of PacifiCorp’s 8.7 MW solar requirement in Oregon. A study to evaluate 

solar resources in Oregon was completed by Black & Veatch and focused on development of 2 

MW projects that could be built to meet Oregon’s solar generation requirement. The Oregon 

report evaluated PV thin film, fixed tilt PV multi-crystalline, and single axis PV multi-crystalline 

installations. Capital cost information in the Oregon report was updated in August 2012 to 

incorporate market changes in the cost of equipment. Information from this report is the basis for 

cost and production data for 2 MW solar resources listed in the Supply Side Resource table. 

In August 2012, PacifiCorp commissioned an additional cost and performance evaluation on 

estimated energy production, capital and operating and maintenance costs for a nominal 50 MW 

solar PV resource located in southwestern Utah. The Utah estimate studied fixed-tilt and singleaxis mounting systems for PV crystalline solar panels. The higher annual insolation and solar 

irradiance in Utah improved capacity factors and economy of scale benefits of the 50 MW 

resource compared to the 2 MW resource, resulting in lower total energy costs. 

Distributed Supply Side Resources

As in the previous IRP, three general categories of small-scale customer-sited generation (also 

referred to as Distributed Generation) were included as resource options in the 2013 IRP; 

Combined Heat and Power (CHP), Solar Photovoltaics (“Solar PV”) and Solar Water Heating 

(“SWH”). Traditionally, such resources fall outside the standard classification of Class 2 DSM 

resources for two main reasons: either they reduce utility-provided electricity consumption at the 

building level (rather than at an end-use level, as applies to CHP and PV), or they rely on 

renewable resources (solar PV, SWH, and certain CHP technologies).

CHP systems generate electricity and utilize waste heat for thermal loads, such as space or water 

heating. They can be used in buildings with a fairly coincident thermal and electric load, or in 

buildings producing combustible biomass or biogas, such as lumber mills or landfills. CHP 

broadly divides into subcategories based on fuels used: nonrenewable CHP typically runs on 

natural gas, while renewable CHP runs on a biologically derived fuel (biomass or biogas). 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

138

The IRP includes the same CHP systems as in the 2011 IRP: 

Nonrenewable

- Reciprocating engines (RE);

- Microturbines (MT);

- Gas turbines (GT); and 

- Fuel cells (FC).

Renewable

- Industrial biomass systems are utilized in industries such as lumber mills or pulp 

and paper manufacturing, where site-generated waste products can be combusted 

in place of natural gas or other fuels.

- Anaerobic digesters create methane gas (biogas fuel) by breaking down liquid or 

solid biological waste.

Solar PV systems include a collection of solar modules, generally mounted on building roofs, 

with an inverter to convert available sunlight into electricity compatible with a building’s 

standard electrical infrastructure. Widely applicable in the residential and nonresidential sectors, 

Solar PV has been in use for several decades. In 2012, the Utah Public Service Commission 

approved a large expansion of the Utah Solar Incentive Program. The program is designed to 

encourage the development of distributed Solar PV through the payment of a rebate to customers 

that complete the installation of onsite Solar PV generation facilities. Based on utility experience 

with similar incentive programs, the 2013 IRP assumes that the program will have full 

participation and drive the installation of 60 MW of Solar PV resources across the Company’s 

Utah service territory between 2013 and 2017. This has the impact of accelerating the adoption 

of Solar PV in Utah over the first five years of the 2013 IRP and if realized reduces the 

remaining potential in Utah in the later years of the plan.

SWH systems use sunlight to pre-heat domestic hot water tanks, reducing the need for electricity 

to heat water. Widely applicable in the residential and nonresidential sectors, SWHs have been in 

use for several decades. 

Table 6.13 shows modeling attributes for the distributed generation resources reflected in 

“Assessment of Long-Term, System-Wide Potential for Demand-Side and Other Supplemental 

Resources” study completed in March 2013 by Cadmus (“DSM potential study"). 

Table 6.13 – Distributed Generation Resource Attributes44

 

44 More details on the distributed generation resources can be found in the DSM potentials study report available for 

download on PacifiCorp’s demand-side management Web page, http://www.pacificorp.com/es/dsm.html.

Available MW Capacity each Year by Topology Bubble 1/

Annual 

Fixed 

O&M 

Costs 

Measure 

Life 

(Yrs)

Heat Rate 

(Ave. 

Btu/kWh)

Admin Cost

(% of total 

program cost)

Capital 

Cost 

($/kW), 

Total 

Technology 

Cost 

Change

California Oregon

Walla Walla, WA

Yakima, WAGoshen, 

ID Utah Wyoming

Reciprocating Engine 0.15 0.89 0.36 0.92 0.40 6.61 0.89 47.41 20 8,000 0% 1,495 1%

MicroTurbine - - - - - 0.95 - 63.42 10 8,000 0% 2,168 -1%

Fuel Cell - - - - - 0.47 - 186.91 10 6,100 0% 3,673 -3%

Gas Turbine - 0.27 - 0.13 0.14 1.90 0.30 55.42 20 6,300 0% 1,757 1%

Industrial Biomass - 0.55 - - - 0.16 - 28.82 25 N/A 0% 631 1%

Anaerobic Digesters - - - - - 0.20 0.16 61.78 18 N/A 0% 2,452 -1%

P V 0.49 7.12 - 0.15 0.15 13.12 0.29 20.47 30 N/A 10% 4,693 -2%

Solar Water Heaters - 2.16 - - - 1.53 - 20.36 20 N/A 10% 1,600 2%

Technology Type
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

139

Nuclear

Included in the supply side resource table is a larger 2,236 MW system, which reflects the 

current state-of-the-art advanced nuclear plant and is modeled after the Westinghouse AP1000 

technology currently being installed by Southern Company at the Vogtle Generating Station in 

Georgia. It is assumed that this technology would be installed at the proposed Blue Castle site 

near Green River, Utah. Nuclear fuel cost is assumed at $2,770/kg in 2011 dollars but nuclear 

power is not considered a viable option in the PacifiCorp service territory before 2030 due to 

total capital cost uncertainty (including EPC and owner’s costs), sociopolitical resistance, and 

regulatory obstacles.

Energy Storage

As in past IRPs, a number of energy storage technologies are included, such as compressed 

energy storage (CAES), pumped hydroelectric, and advanced batteries. There are a number of 

potential CAES sites—specifically solution-mined sites associated with natural gas storage in

western Utah and southwest Wyoming—that could be developed in areas of existing gas 

transmission. CAES may be an attractive alternative for high elevation sites since the gas 

compression could compensate for the facility capacity derate affects associated with higher 

elevation. 

Energy storage continues to be of interest since the variable nature of some conventional 

renewable generation alternatives could be enhanced if the energy produced could be stored. To 

model the storage options, PacifiCorp conducted an energy storage study with HDR in 201145.

Table 6.14 outlines the conclusions of the HDR study. The focus of this study was in defining 

the cost and performance characteristics of available storage technologies. The dry cell and Zinc 

Bromide (ZnBr) battery options were removed because these systems are similar to other options 

shown. Zinc-bromide batteries are similar to the VRB batteries, while the dry cells are similar to 

the Lithium-Ion (Li-Ion) batteries.

Table 6.14 –HDR Energy Storage Study Summary Cost and Capacity Results (2011$)

Flywheel Li-Ion NaS VRB Pumped 

Storage CAES

System Cost 

($/kW and/or 

$/kWh)

$2,406 per 

kW

$1,100 (High 

Energy)

$4,000/kW $644/kWh $1,500-

$3,000/kW

$1,400-

$1,700/kW

Rated System 

Size (MW)

20 89 (High 

Energy)

1 1 1,000 500

Rated 

Capacity (hrs)

0.25 4 (High 

Energy)

7.2 1 8 to 10 8

Numerous examples of pumped hydro systems are included in the HDR study and a composite 

case is presented in the resource table representing both the large size capable with this 

technology (1,000 MW) but at the high end of the cost range to reflect the permitting difficulties 

present with this geologic intense generation option. O&M is presented in both variable and 

fixed components. A larger variable component has been used to mirror the different potential 

capacity factors available with this flexible resource.

 

45 The 2011 energy storage study is available on PacifiCorp’s IRP web page. http://www.pacificorp.com/es/irp.html. 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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CAES has been shown at the specific size case illustrated in the HDR study. A 557 net MW 

capacity case is shown in the resource table at the 6,000 foot elevation example. Capital costs 

include the solution mining component of the technology. O&M costs are broken out into fixed 

and variable components.

Battery energy storage is unique in that capital costs are defined in terms of energy storage 

capability and not necessarily in terms of how much energy can be delivered instantaneously. In 

order to properly compare different battery systems it is necessary to compare the battery 

systems on a common denominator basis. The common denominator basis is defined by the 

sodium-sulfur (NaS) battery and all systems were compared on storing 7.2 hours of energy as 

shown in Table 6.15. All O&M in Table 6.15 is assumed fixed for ease of comparison.

Table 6.15 –HDR Storage Study, Normalized Battery Cost Comparison (2011$)

Battery $/kW -

Capacity

$/kWh 

Energy 

Storage

Replacement –

10 yr life

$ 

Millions

kWh –

Energy 

Storage

$/kWh for 

Energy 

Storage

$/kW –

Capacity 

& Energy

O&M

$/kW-yr

Li-Ion $1,100 $1,100 $8.71 7,200 $1,210 $8,712 $27.4

NaS $4,000 $4,000 $4.40 7,200 $0.611 $4,400 $27.4

Vanadium 

Redox (VRB)

$400 $644 $644 $5.53 7,200 $0.768 $5,530 $36.5

Notes to Table 6-15:

Capacity Factor equal to 3 hours per day – 6 months per year = 6.25%

Battery size normalized at 1 MW

Normalize energy storage capability to 7.2 hours equal to the standard NaS system

Demand-side Resources

Resource Options and Attributes

Source of Demand-side Management Resource Data

Demand-side management (DSM) resource opportunity estimates used in the development of the 

2013 IRP were derived from the DSM potential study. The DSM potential study, conducted by 

Cadmus, provided a broad estimate of the size, type, location and cost of demand-side 

resources.46 For the purpose of integrated resource planning, the demand-side resource 

information from the DSM potential study was converted into supply curves by type 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 cost of resources. Supply curves provide a representative look at 

how much of a particular resource can be acquired at a particular price point. Resource modeling 

 

46 The 2013 DSM potential study is available on PacifiCorp’s demand-side management web page. 

http://www.pacificorp.com/es/dsm.html. 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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utilizing supply curves allows utilities to select least-cost resources (products and quantities) 

based on each resource’s competitiveness against alternative resource options.

As with supply-side resources, the development of demand-side resource supply curves requires 

specification of quantity, availability, and cost attributes. Attributes specific to demand-side 

supply curves include:

Resource quantities available in each year—either megawatts or megawatt-hours—

recognizing that some resources may come from stock additions not yet built, and that 

elective resources cannot all be acquired in the first year;

Persistence of resource savings; for example, Class 2 DSM (energy-based) resource 

measure lives

Seasonal availability and hours available (Classes 1 and 3 DSM capacity resources)

The hourly shape of the resource (load shape of the Class 2 DSM energy resource); and

Levelized resource costs (dollars per kilowatt per year for Classes 1 and 3 DSM capacity 

resources, or dollars per megawatt-hour over the resource’s life for Class 2 DSM energy 

resources).

Once developed, DSM supply curves are treated like discrete supply-side resources in the IRP 

modeling environment. 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Class 1 DSM Capacity Supply Curves 

Supply curves were created for three distinct Class 1 DSM products:

1) Direct load control (DLC) of residential and small commercial central air conditioning 

and water heating;

2) Irrigation load curtailment; and

3) Commercial/industrial curtailment

The potentials and costs for each product were provided at the state level resulting in three 

products across six states or the development of eighteen Class 1 DSM supply curves for the 

2013 IRP modeling process. 

Class 1 DSM resource price differences between West and East control areas for similar 

resources were driven by resource differences in each market, such as irrigation pump size and 

hours of operation as well as product performance differences. For instance, residential air 

conditioning load control in the West is more expensive on a unitized or dollar per kilowatt-year 

basis due to climatic differences that result in a lower load impact per installed switch. 

The assessment of potential for distributed standby generation47 was combined with an 

assessment of commercial/industrial energy management system controls in the development of 

the resource opportunity and costs of the commercial/industrial curtailment product. The costs 

for this product are constant across all jurisdictions assuming a pay-for-performance delivery 

model.

Recognizing that some Class 1 and 3 DSM products compete for the management of the same 

customer end-use loads, and to avoid overstating available impacts, the supply curves accounted 

for interactions within and between Class 1 and Class 3 DSM resources. Resources were 

prioritized within each customer sector by the firmness of the resource and then by cost. The 

following are examples of the logic that was applied to account for these interactions:

Participation in the Class 1 DSM DLC air conditioning and water heating programs or 

DLC irrigation programs would take precedence over participation in Class 3 DSM 

Time-of-Use (TOU) rates/programs. Customers already enrolled in the DLC air 

conditioning and water heating and DLC irrigation programs would not opt out to 

participate in the TOU programs.

Participation in the Class 1 DSM commercial/industrial curtailment programs would take 

precedent over Class 3 DSM Demand Buyback and/or Critical Peak Pricing programs 

where load curtailment is offered. 

Tables 6.16 and 6.17 show the summary level Class 1 DSM resource information, by control 

area, used in the development of the Class 1 DSM resource supply curves. Potential shown is 

incremental to the existing Class 1 DSM resources identified in Table 5.10. For existing program 

offerings, it is assumed the Company could begin acquiring incremental potential in 2013. For 

resources representing new product offerings, it is assumed the Company could begin acquiring 

 

47 In February 2010 the Environmental Protection Agency made the Reciprocating Internal Combustion Engines 

National Emission Standards for Hazardous Air Pollutants ruling. The ruling puts restrictions on the use of standby 

generation after May, 2014 unless the generators meet the rulings required emission standards.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

143

potential in 2014, accounting for the time required for program design, regulatory approval, 

vendor selection, etc.

Table 6.16 – Class 1 DSM Program Attributes West Control Area

Products

Competing 

Strategy

Hours

Available Season

Potential 

(MW)

Levelized 

Cost 

($/kW-yr)

First 

Year(s) 

Available

Residential and Small 

Commercial Air 

Conditioning and Water 

Heating

Residential timeof-use

50 hours, 

average of 4 

hours per 

event

Summer 42 $83 - $103 2014

Irrigation Direct Load 

Control

Irrigation timeof-use

50 hours, 

average of 4 

hours per 

event

Summer 11 $61 - $64 2014

Commercial/Industrial 

Curtailment (includes 

distributed standby 

generation)

Demand 

buyback and 

Critical peak 

pricing

30 hours, 

average of 4 

hours per 

event

Summer 

and 

Winter

64 $65 2014

Table 6.17 – Class 1 DSM Program Attributes East Control Area

Products

Competing 

Strategy

Hours

Available Season

Potential 

(MW)

Levelized 

Cost 

($/kW-yr)

First 

Year(s) 

Available

Residential and Small 

Commercial Air 

Conditioning and Water 

Heating

Residential timeof-use

50 hours, 

average of 4 

hours per 

event

Summer 31 $70 - $133 2013-

2014

Irrigation Direct Load 

Control

Irrigation timeof-use

50 hours, 

average of 4 

hours per 

event

Summer 1 $51 - $64 2013-

2014

Commercial/Industrial 

Curtailment (includes 

distributed standby 

generation)

Demand 

buyback and 

Critical peak

pricing

30 hours, 

average of 4 

hours per 

event

Summer 

and 

Winter

125 $65 2014

A number of data conversions and resource attributes are required to configure the supply curves 

for use in the System Optimizer model. All programs are defined to operate within a 5x8 hourly 

window and are priced in $/kW-month. The following are the primary model attributes required 

by the model:

The Capacity Planning Factor (CPF): This is the percentage of the program size (capacity) 

that is expected to be available at the time of system peak. For Classes 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 

reserves.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

144

Daily and annual energy limits: These parameters, expressed in Gigawatt-hours, are used to 

implement hourly limits on the programs. They are obtained by multiplying the hours 

available by the program size.

Nameplate capacity (MW) and service life (years)

Maximum Annual Units: This parameter, specified as a pointer to a vector of values, 

indicates the maximum number of resource units available in the year for which the resource 

is designated.

First year and month available / last year available

Class 3 DSM Capacity Supply Curves 

Supply curves were created for four discrete Class 3 DSM products, which are capacity-based 

resources like Class 1 DSM products:

1) Residential time-of-use rates;

2) Commercial critical peak pricing;

3) Commercial and industrial demand buyback; and

4) Voluntary irrigation time-of-use

48

The potentials and costs for each product were provided at the state level resulting in four 

products across six states or the development of twenty-four Class 3 DSM supply curves for the 

2013 IRP modeling process.

As discussed above with regard to Class 1 DSM resources, the potential for each Class 3 DSM 

product was adjusted for expected interactions with competing Class 1 and 3 DSM resource 

options.

Modest product price differences between west and east control areas were driven by resource 

opportunity differences. The DSM potential study assumed the same fixed costs in each state in 

which it is offered regardless of quantity available. Therefore, states with lower resource 

availability for a particular product have a higher cost per kilowatt-year.

Tables 6.18 and 6.19 show the summary level Class 3 DSM resource information, by control

area, used in the development of the Class 3 DSM resource supply curves. Potential shown is 

incremental to the existing Class 3 DSM resources identified in Table 5.10. For existing program 

offerings, it is assumed the Company could begin acquiring incremental potential in 2013. For 

resources representing new product offerings, it is assumed the Company could begin acquiring 

potential in 2014, accounting for the time required for program design, regulatory approval, 

vendor selection, etc. System Optimizer data formats and parameters for Class 3 DSM programs 

are similar to those defined for the Class 1 DSM programs.

Table 6.18 – Class 3 DSM Program Attributes, West Control Area

Products

Competing 

Strategy

Hours

Available Season

Potential 

(MW)

Levelized 

Cost 

($/kW-yr)

First 

Year(s) 

Available

Residential Time-ofUseResidential A/C 

and Water 528 hours Summer 3

$117 -

$347

2013 -

2014

 

48 The 2011 IRP included significantly more potential for irrigation load control driven by the assumption of 

mandatory participation.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

145

Products

Competing 

Strategy

Hours

Available Season

Potential 

(MW)

Levelized 

Cost 

($/kW-yr)

First 

Year(s) 

Available

Heating DLC

Commercial Critical 

Peak Pricing

C&I 

Curtailment, 

Demand 

Buyback

40 hours Summer 

and Winter 0* $9 - $96 2014

Commercial/Industrial 

Demand Buyback

C&I 

Curtailment, 

Critical Peak 

Pricing

50 hours Summer 

and Winter 0* $26 2014

Voluntary Irrigation 

Time-of-Use Irrigation DLC 120 hours Summer 5 $40 - $97 2013 -2014

* Although standalone potential was identified in the DSM potential study, there is assumed to be no 

potential available after accounting for competition with other Class 1 and 3 DSM resources.

Table 6.19 – Class 3 DSM Program Attributes, East Control area

Products

Competing 

Strategy

Hours

Available Season

Potential 

(MW)

Levelized 

Cost 

($/kW-yr)

First 

Year(s) 

Available

Residential Time-ofUse

Residential A/C 

and Water 

Heating DLC

480/600 

hours Summer 8

$124 -

$195

2013 -

2014

Commercial Critical 

Peak Pricing

C&I 

Curtailment, 

Demand 

Buyback

40 hours Summer 

and Winter 0* $9 - $38 2014

Commercial/Industrial 

Demand Buyback

C&I 

Curtailment, 

Critical Peak 

Pricing

50 hours Summer 

and Winter 0* $26 2014

Voluntary Irrigation 

Time-of-Use Irrigation DLC 120 hours Summer 0.2 $20 - $97 2013 -2014

* Although standalone potential was identified in the DSM potential study, there is assumed to be no 

potential available after accounting for competition with other Class 1 and 3 DSM resources.

Class 2 DSM, Energy Supply Curves

The 2013 IRP represents the third time the Company has utilized the DSM supply curve 

methodology in the evaluation and selection of Class 2 DSM resources. The 2013 DSM potential 

study provided the information to fully assess the potential contribution from Class 2 DSM 

resources over the IRP planning horizon and adjusted resource potentials and costs to account for 

changes in building codes, advancing equipment efficiency standards, market transformation, 

resource cost changes, and state specific resource evaluation considerations (e.g., costeffectiveness criteria). Class 2 DSM resource potential was assessed by state down to the 

individual measure and facility levels; e.g., specific appliances, motors, lighting configurations 

for residential buildings, small offices, etc. The 2013 DSM potential study provided Class 2 

DSM resource information at the following granularity:

State: Washington, California, Idaho, Utah, Wyoming49

Measure:

 

49 Oregon’s Class 2 DSM potential was assessed in a separate study commissioned by the Energy Trust of Oregon.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

146

– 131 residential measures

– 145 commercial measures

– 93 industrial measures

– Three irrigation measures

– Four street lighting measures 

Facility type50:

– Six residential facility types 

– 24 commercial facility types

– 14 industrial facility types

– One irrigation facility type

– Four street lighting types 

The 2013 DSM potential study levelized total resource costs (including measure costs and a 20 

percent adder for program administrative costs) over the study period at PacifiCorp’s cost of 

capital, consistent with the treatment of supply-side resources. Consistent with regulatory 

mandates, Utah Class 2 DSM resource costs were levelized using utility costs (incentive and 

non-incentive program costs) instead of total resource costs. 

The technical potential for all Class 2 DSM resources across five states over the twenty-year 

DSM potential study horizon totaled 7.2 million MWh.51 The technical potential represents the 

total universe of possible savings before adjustments for what is likely to be realized 

(achievable). When the achievable assumptions described below are considered the technical 

potential is reduced to a technical achievable potential for modeling consideration of 5.7 million 

MWh. The achievable technical potential, representing available potential at all costs, is 

provided to the IRP model for economic screening relative to supply-side alternatives.

Despite the granularity of Class 2 DSM resource information available, it was impractical to 

model the Class 2 DSM resource supply curves at this level of detail. The combination of 

measures by facility type and state generated over 19,000 separate permutations or distinct 

measures that could be modeled using the supply curve methodology.52 To reduce the resource 

options for consideration without losing the overall resource quantity available or its relative 

cost, resources were consolidated into bundles, using ranges of levelized costs to reduce the 

number of combinations to a more manageable number. The granularity or range of measure 

costs in a particular bundle were narrowed in the development of the Class 2 DSM supply curves 

in the 2013 IRP relative to the 2011 IRP to address concerns regarding using too broad of 

 

50 Facility type includes such attributes as existing or new construction, single or multi-family, etc. Facility types are 

more fully described in the 2013 DSM potential study.

51 The identified technical potential represents the cumulative impact of Class 2 DSM measure installations in the 

20th year of the study period. This may differ from the sum of individual years’ incremental impacts due to the 

introduction of improved codes and standards over the study period. 

52 Not all energy efficiency measures analyzed are applicable to all market segments. The two most common 

reasons for this are (1) differences in existing and new construction and (2) some end-uses do not exist in all

building types. For example, a measure may look at the savings associated with increasing an existing home’s 

insulation up to current code levels. However, this level of insulation would already be required in new construction, 

and thus, would not be analyzed for the new construction segment. Similarly, certain measures, such as those 

affecting commercial refrigeration would not be applicable to all commercial building types, depending on the 

building’s primary business function; for example, office buildings would not typically have commercial 

refrigeration.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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measure costs within a bundle and its possible impact on the selection of bundled resources at or 

near the IRP model’s economic selection point. The result was the creation of twenty-seven cost 

bundles; eighteen more than were developed for the 2011 IRP. 

Bundle development began with the Class 2 DSM technical potential identified by the 2013 

DSM potential study. To account for the practical limits associated with acquiring all available 

resources in any given year, the technical potential by measure was adjusted to reflect the 

amount that is realistically achievable over the 20-year planning horizon. Consistent with the 

Northwest’s aggressive53 regional planning assumptions, it was assumed that 85 percent of the 

technical potential for discretionary (retrofit) resources and 72 percent of lost-opportunity (new 

construction or equipment upgrade on failure) could be achievable over the 20-year planning 

period. Over the planning period, the aggregate (both discretionary and lost opportunity) 

achievable technical potential is 79 percent of the technical potential. 

Consistent with the 2011 IRP, the technical achievable potential for each measure by state is 

assigned a measure and market ramp rate, reflecting the relative state of technology and program 

state specific delivery infrastructure/maturity, respectively. New technologies and states with 

newer programs were assumed to take more time to ramp up than those with more extensive 

track records. 

The Energy Trust of Oregon (ETO) applies achievability assumptions and ramp rates in a similar 

manner in its resource assessment. For a more detailed description of the methods used in 

PacifiCorp’s 2013 DSM Potential Study and the ETO’s resource assessment, see Appendix D in 

Volume II of this document. In contrast to the 2011 IRP, the ETO did not perform an economic 

pre-screening of measures in the development of the Oregon DSM supply curves allowing 

resource opportunities in Oregon to be economically screened in the IRP model in a comparable 

way as is done across PacifiCorp’s other five states.

Twenty-seven cost bundles were available across six states (including Oregon), which equates to 

189 Class 2 DSM supply curves. Table 6.20 shows the MWh potential for Class 2 DSM cost 

bundles, designated by ranges of $/MWh. Table 6.21 shows the associated bundle price after 

applying cost credits afforded to Class 2 DSM resources within the model. These cost credits 

include the following:

A transmission and distribution investment deferral credit of $54/kW-year;

Stochastic risk reduction credit of $7.05/MWh54;

Northwest Power Act 10-percent credit (Oregon and Washington resources only)55

 

53 The Northwest’s achievability assumptions include savings realized through improved codes and standards and 

market transformation, and thus, applying them to identified technical potential represents an aggressive view of 

what could be achieved through utility DSM programs.

54 PacifiCorp developed this credit by taking the difference between a comparison of deterministic PaR runs for the 

2011 IRP preferred portfolio with and without DSM and a comparison of stochastic PaR runs for the 2011 IRP 

preferred portfolio with and without DSM and then dividing that difference by the MWh of DSM in the 2011 IRP 

preferred portfolio. 

55 The formula for calculating the $/MWh credit is: (Bundle price - ((First year MWh savings x market value x 10%) 

+ (First year MWh savings x T&D deferral x 10%))/First year MWh savings. The levelized forward electricity price 

for the Mid-Columbia market is used as the proxy market value.
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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The bundle price is the average levelized cost for the group of measures in the cost range, 

weighted by potential. In specifying the bundle cost breakpoints, narrower cost ranges were 

defined for the lower-cost resources to improve the cost accuracy for the bundles considered 

more likely to be selected by the System Optimizer model. The highest-cost bundles were 

specified with wider cost breakpoints that are more granular than the cost ranges used in the 

development of the 2011 IRP56. 

Table 6.20 – Class 2 DSM MWh Potential by Cost Bundle

 

56 Increasing the granularity of the cost bundles between the 2011 IRP and 2013 IRP increased the number of total 

bundles within each state and load bubble from 9 to 27, respectively. 

Bundle California Idaho Oregon Utah Washington Wyoming

<= 10 12,499 47,610 386,701 1,158,187 149,999 260,077

10 - 20 20,796 33,861 266,687 561,726 55,791 368,790

20 - 30 8,122 16,448 415,912 259,141 61,938 89,097

30 - 40 6,731 15,149 319,680 147,314 39,224 73,359

40 - 50 6,057 22,737 230,316 114,005 52,318 41,511

50 - 60 6,221 12,542 187,293 296,558 21,271 46,368

60 - 70 3,092 42,507 30,576 169,084 30,652 35,426

70 - 80 10,223 3,952 130,529 42,672 11,993 34,507

80 - 90 6,236 26,341 27,734 59,885 21,866 8,132

90 - 100 2,545 4,690 163,658 123,069 11,629 24,313

100 - 110 13,516 5,116 26,496 143,361 13,967 52,805

110 - 120 2,049 32,070 80,433 120,914 14,856 9,397

120 - 130 3,657 942 136,215 52,796 36,833 7,200

130 - 140 465 2,040 159,330 7,810 2,631 8,554

140 - 150 1,056 8,866 9,889 20,569 9,489 9,930

150 - 160 10,928 5,589 699 9,366 37,975 16,832

160 - 170 536 2,610 15,893 34,191 11,759 2,208

170 - 180 3,330 780 1,380 37,774 12,784 1,923

180 - 190 1,701 3,055 40,912 9,847 2,945 9,364

190 - 200 3,009 1,597 16,093 32,717 2,926 11,293

200 - 250 4,691 10,981 22,796 199,384 38,157 12,118

250 - 300 2,333 5,849 33,267 103,864 14,683 18,227

300 - 400 8,166 12,931 14,581 72,193 18,759 52,596

400 - 500 3,020 2,336 11,141 62,203 19,659 23,462

500 - 750 2,077 5,753 11,028 29,966 9,048 14,670

750 - 1,000 2,213 13,313 6,853 15,890 26,499 8,578

> 1,000 5,176 6,541 6,543 133,702 25,666 22,650
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Table 6.21 – Class 2 DSM Adjusted Prices by Cost Bundle

To capture the time-varying impacts of Class 2 DSM resources, each bundle has an annual 8,760 

hourly load shape specifying the portion of the maximum capacity available in any hour of the 

year. These shapes are created by spreading measure-level annual energy savings over 8,760 

load shapes, differentiated by state, sector, market segment, and end use accounting for the 

hourly variance of Class 2 DSM impacts by measure. These hourly impacts are then aggregated 

for all measures in a given bundle to create a single weighted average load shape for that bundle.

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 percent), while an hour with half the maximum demand would 

have a value of 0.50 (50 percent). Summing the fractional values for all of the hours, and then 

multiplying this result by non-coincident peak-hour demand, produces the annual energy savings 

represented by the supply curve.

To plan for DSM, a planning capacity factor is input into the System Optimizer model for each 

bundle and year. To determine the planning capacity factor, an average of the capacity for hours 

14 through 19 during the average July day is divided by the overall maximum capacity value 

during the year for each bundle and year. Levelized Cost after Adjustments ($/MWh)

Bundle California Idaho Oregon Utah Washington Wyoming

<= 10 - - - - - -

10 - 20 - - - - - 0.74

20 - 30 8.51 3.55 - 3.57 1.00 7.23

30 - 40 17.37 4.13 9.46 13.26 5.64 13.25

40 - 50 26.86 27.26 17.56 23.78 11.15 25.76

50 - 60 31.84 30.41 32.82 35.81 22.65 38.16

60 - 70 34.19 37.68 35.17 45.22 36.98 47.20

70 - 80 52.23 54.64 48.43 52.69 50.94 57.00

80 - 90 62.51 67.31 56.88 68.38 58.82 59.73

90 - 100 81.20 74.33 71.77 78.11 60.15 76.73

100 - 110 86.79 81.74 80.39 81.02 69.50 88.13

110 - 120 96.96 89.80 87.42 78.39 73.89 100.24

120 - 130 106.58 100.81 91.07 107.36 93.44 104.28

130 - 140 98.03 107.05 105.26 112.48 107.35 116.42

140 - 150 119.39 127.24 113.15 122.43 121.51 122.24

150 - 160 131.33 136.23 103.06 133.11 129.27 136.85

160 - 170 147.79 147.73 141.29 136.84 139.10 142.66

170 - 180 150.00 147.84 101.76 156.05 106.49 154.47

180 - 190 164.92 168.18 156.50 157.52 154.22 169.48

190 - 200 174.69 168.42 160.34 173.06 168.43 172.27

200 - 250 211.04 198.24 202.41 210.35 204.53 198.20

250 - 300 255.99 250.90 244.55 233.09 239.56 258.98

300 - 400 329.67 334.22 306.16 316.09 316.61 342.23

400 - 500 408.29 419.68 403.00 430.59 420.65 442.96

500 - 750 601.51 592.73 557.54 513.73 603.17 578.06

750 - 1,000 827.70 895.12 772.20 863.26 798.91 802.18

> 1,000 3,620.28 2,315.69 2,548.01 3,841.62 2,672.86 3,614.73
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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An accelerated Class 2 DSM acquisition scenario was created for inclusion in three of the IRP 

core cases. Although the total available potential over the 20-year planning period did not change 

for this scenario, discretionary resource acquisition was accelerated and market ramp rates were 

removed57 to allow the System Optimizer model to select up to two percent of retail sales 

annually in each state until discretionary resources were exhausted. In this scenario, the costs for 

accelerated measures were increased to acknowledge that such a scenario would likely require 

higher incentive and non-incentive program expenditures to expand participation and delivery 

infrastructure58.

Distribution Energy Efficiency

In 2012, the Company conducted a pilot to assess the feasibility of distribution energy efficiency 

for four circuits in Washington. Of the 0.09 aMW predicted to be acquired through the pilot, less 

than 0.01 aMW was actually achieved. The pilot was not cost effective. Less than half of the 

anticipated reduction in average voltage was achieved, and the estimated cost of energy savings 

was $112.49/MWh. Following the pilot, the Company screened all active distribution circuits in 

Oregon, Idaho, Wyoming, and Utah and found that between 0 and 0.2 aMW of conservation 

voltage reduction energy savings might exist within the Company’s service territory in those four 

states. However, it is likely that pursuing measures in those states would not be cost effective. 

Two key lessons from the pilot and subsequent screening effort are:

1) Most of the Company’s circuits are already operating at a relatively low voltage and 

improvements necessary to allow an even lower voltage are not usually justified by the 

value of the energy saved.

2) Small amounts of saved energy on the utility system cannot be accurately and repeatably

measured due to the dynamic interplay between the system and the customers’ 

requirements.

Distribution energy efficiency measures were not modeled as potential resources in this IRP, 

since the Company found through its pilot that savings from such measures are unreliable and 

generally not cost-effective. Further details on this pilot and its conclusions are provided in 

Appendix E.

 

57 Hypothetical adjustments to real world constraints were made in order to provide sufficient Class 2 DSM 

resources to allow the model to select up to 2 percent of retail sales in each state.

58 The resource cost adjustments in the accelerated DSM scenario may not represent the actual costs of such a 

scenario; there was limited information available to inform the Company what costs would be required to facilitate 

this level of customer participation in markets with low retail rates and limited capital. 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Transmission Resources

For this IRP, PacifiCorp investigated five Energy Gateway scenarios, consisting of various 

combinations of transmission segments. Detailed information on the scenarios and associated 

modeling approach and findings are provided in Chapter 4.

In this IRP, adjustments to fixed O&M costs were developed to model the additional costs of 

transmission upgrades to interconnect certain supply-side resources to the Company’s system. 

Table 6.22 below shows fixed O&M cost associated with these transmission upgrades by 

resource and location. 
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Table 6.22 – Transmission Upgrades by Supply-Side Resource and Location

Fuel Resource Location

Elevation 

(AFSL)

Transmission Cost 

Stated in 2012 $/kwyear

Natural Gas SCCT Aero x3, ISO Portland / 0 $37.92

Natural Gas Intercooled SCCT Aero x1, ISO North Coast 0 $37.92

Natural Gas SCCT Frame "F" x1, ISO 0 $37.92

Natural Gas IC Recips x6, ISO 0 $37.92

Natural Gas CCCT Dry "F", 2x1, ISO 0 $37.92

Natural Gas CCCT Dry "F", DF, 2x1, ISO 0 $37.92

Natural Gas CCCT Dry "G/H", 1x1, ISO 0 $37.92

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 0 $37.92

Natural Gas CCCT Dry "G/H", 2x1, ISO 0 $37.92

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 0 $37.92

Natural Gas CCCT Dry "J", Adv 1x1, ISO 0 $37.92

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 0 $37.92

Natural Gas SCCT Aero x3, ISO Willamette 0 $55.12

Natural Gas Intercooled SCCT Aero x1, ISO Valley 0 $55.12

Natural Gas SCCT Frame "F" x1, ISO 0 $55.12

Natural Gas SCCT Aero x3, ISO Walla Walla 1,500 $3.51

Natural Gas Intercooled SCCT Aero x1, ISO 1,500 $3.51

Natural Gas SCCT Frame "F" x1, ISO 1,500 $3.51

Natural Gas IC Recips x6, ISO 1,500 $3.51

Natural Gas CCCT Dry "F", 2x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "F", DF, 2x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "G/H", 1x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "G/H", 2x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "J", Adv 1x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 1,500 $3.51

Natural Gas CCCT Dry "G/H", 1x1, ISO Yakima 1,500 $3.51

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 1,500 $3.51

Natural Gas SCCT Frame "F" x1, ISO 1,500 $3.51

Natural Gas Intercooled SCCT Aero x1, ISO 1,500 $3.51

Natural Gas SCCT Aero x3, ISO Salt Lake 4,250 $12.80

Natural Gas Intercooled SCCT Aero x1, ISO Valley 4,250 $12.80

Natural Gas SCCT Frame "F" x1, ISO 4,250 $12.80

Natural Gas IC Recips x6, ISO 4,250 $12.80

Natural Gas CCCT Dry "F", 2x1, ISO 4,250 $12.80

Natural Gas CCCT Dry "F", DF, 2x1, ISO 4,250 $12.80

Natural Gas CCCT Dry "G/H", 1x1, ISO 5,050 $12.80

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 5,050 $12.80

Natural Gas CCCT Dry "G/H", 2x1, ISO 5,050 $12.80

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 5,050 $12.80

Natural Gas CCCT Dry "J", Adv 1x1, ISO 5,050 $12.80

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 5,050 $12.80

Natural Gas SCCT Aero x3, ISO Eastern 4,250 $29.32

Natural Gas Intercooled SCCT Aero x1, ISO Wyoming 4,250 $29.32

Natural Gas SCCT Frame "F" x1, ISO 4,250 $29.32

Natural Gas IC Recips x6, ISO 4,250 $29.32

Natural Gas CCCT Dry "F", 2x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "F", DF, 2x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "G/H", 1x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "G/H", 2x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "J", Adv 1x1, ISO 5,050 $29.32

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 5,050 $29.32
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Table 6.22 – Transmission Upgrades by Supply-Side Resource and Location (Continued)

Fuel Resource Location

Elevation 

(AFSL)

Transmission Cost 

Stated in 2012 $/kwyear

Natural Gas SCCT Aero x3, ISO Idaho 4,250 $3.44

Natural Gas Intercooled SCCT Aero x1, ISO 4,250 $3.44

Natural Gas SCCT Frame "F" x1, ISO 4,250 $3.44

Natural Gas IC Recips x6, ISO 4,250 $3.44

Natural Gas CCCT Dry "G/H", 1x1, ISO 5,050 $3.44

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 5,050 $3.44

Natural Gas SCCT Aero x3, ISO Southern 4,250 $18.96

Natural Gas Intercooled SCCT Aero x1, ISO Oregon 4,250 $18.96

Natural Gas SCCT Frame "F" x1, ISO 4,250 $18.96

Natural Gas IC Recips x6, ISO 4,250 $18.96

Natural Gas CCCT Dry "F", 2x1, ISO 4,250 $18.96

Natural Gas CCCT Dry "F", DF, 2x1, ISO 4,250 $18.96

Natural Gas CCCT Dry "G/H", 1x1, ISO 5,050 $18.96

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 5,050 $18.96

Natural Gas CCCT Dry "G/H", 2x1, ISO 5,050 $18.96

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 5,050 $18.96

Natural Gas CCCT Dry "J", Adv 1x1, ISO 5,050 $18.96

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 5,050 $18.96

Natural Gas SCCT Aero x3, ISO Utah 4,250 $7.94

Natural Gas Intercooled SCCT Aero x1, ISO South 4,250 $7.94

Natural Gas SCCT Frame "F" x1, ISO 4,250 $7.94

Natural Gas IC Recips x6, ISO 4,250 $7.94

Natural Gas CCCT Dry "F", 2x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "F", DF, 2x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "G/H", 1x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "G/H", 2x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "J", Adv 1x1, ISO 5,050 $7.94

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 5,050 $7.94

Natural Gas Intercooled SCCT Aero x1, ISO SW 6,500 $12.27

Natural Gas SCCT Frame "F" x1, ISO Wyoming 6,500 $12.27

Natural Gas IC Recips x6, ISO 6,500 $12.27

Natural Gas CCCT Dry "F", 2x1, ISO 5,050 $12.27

Natural Gas CCCT Dry "F", DF, 2x1, ISO 5,050 $12.27

Natural Gas CCCT Dry "G/H", 1x1, ISO 5,050 $12.27

Natural Gas CCCT Dry "G/H", DF, 1x1, ISO 5,050 $12.27

Natural Gas CCCT Dry "G/H", 2x1, ISO 6,500 $12.27

Natural Gas CCCT Dry "G/H", DF, 2x1, ISO 6,500 $12.27

Natural Gas CCCT Dry "J", Adv 1x1, ISO 6,500 $12.27

Natural Gas CCCT Dry "J", DF, Adv 1x1, ISO 6,500 $12.27

Coal IGCC with CCS Wyoming 6,500 $29.32

Geothermal Generic Geothermal PPA 90% CF OT/UT 4,500 $0.00

Wind 2.3 MW turbine 29% CF (EG 1, 2 and 4)1 WA/OR 1,500 $35.07

Wind 2.3 MW turbine 29% CF (EG 3 and 5) WA/OR 1,500 $0.00

Wind 2.3 MW turbine 29% CF Utah 4,500 $7.94

Wind 2.3 MW turbine 29% CF Idaho 4,500 $3.44

Wind 2.3 MW turbine 40% CF Wyoming 6,500 $0.00

Solar PV Poly-Si Fixed Tilt 22% CF Various 4,500 $0.00

Solar PV Poly-Si Fixed Tilt 28% CF Utah 4,500 $6.99

Solar PV Poly-Si Single Tracking 33% CF Utah 4,500 $6.99

Biomass Forestry Byproduct Various 1,500 $0.00

Storage Pumped Storage Utah South 4,500 $17.83

Storage Sodium-Sulfur Battery Various 4,500 0

Storage Advanced Fly Wheel Various 4,500 0

Storage CAES SW Wyoming 4,500 $8.57

Nuclear Advanced Fission Utah 4,500 $25.12
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Market Purchases

PacifiCorp and other utilities engage in purchases and sales of electricity on an ongoing basis to 

balance the system and maximize the economic efficiency of power system operations. In 

addition to reflecting spot market purchase activity and existing long-term purchase contracts in 

the IRP portfolio analysis, PacifiCorp modeled front office transactions (FOT). FOTs are proxy 

resources, assumed to be firm, that represent procurement activity made on an annual forward 

basis to help the Company cover short positions. 

As proxy resources, FOTs represent a range of purchase transaction types. They are usually 

standard products, such as heavy load hour (HLH), light load hour (LLH), and/or daily HLH call 

options (the right to buy or “call” energy at a “strike” price) and typically rely on standard 

enabling agreements as a contracting vehicle. FOT prices are determined at the time of the 

transaction, usually via a third party broker and based on the view of each respective party 

regarding the then-current forward market price for power. An optimal mix of these purchases 

would include a range of volumes and terms for these transactions.

Solicitations for FOTs can be made years, quarters or months in advance. Annual transactions 

can be available up to as much as three or more years in advance. Seasonal transactions are 

typically delivered during quarters and can be available from one to three years or more in 

advance. The terms, points of delivery, and products will all vary by individual market point.

Two FOT types were included for portfolio analysis: an annual flat product, and a HLH third 

quarter 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 purchases 

received 16 hours per day, six days per week from July through September. Because these are 

firm products the counterparties supply the reserves; and back the supply. For example, a 100 

MW front office purchase requires the seller to deliver 100 MW to PacifiCorp regardless of 

circumstance.59 Thus, to insure delivery, the seller must hold the required level of reserves as 

warranted by its system to insure supply. For this reason, PacifiCorp does not need to hold 

additional reserves on its 100 MW firm front office purchase. Table 6.23 shows the FOT

resources included in the IRP models, identifying the market hub, product type, annual megawatt 

capacity limit, and availability.

Table 6.23 – Maximum Available Front Office Transaction Quantity by Market Hub

Market Hub/Proxy FOT Product Type Megawatt Limit and Availability

Mid-Columbia 

Flat Annual (“7x24”) and 

3

rd Quarter Heavy Load Hour (“6x16”)

400 MW + 375 MW with 10% price 

premium, 2013-2032

California Oregon Border (COB) 

Flat Annual (“7x24”) and 

3

rd Quarter Heavy Load Hour (“6x16”)

400 MW, 2013-2032

Southern Oregon / Northern California

(NOB)

3

rd Quarter Heavy Load Hour (“6x16”)

100 MW, 2013-2032

 

59 Typically, the only exception would be under force majeure. Otherwise, the seller is required to deliver the full 

amount even if the seller has to acquire it at an exorbitant price. 
PACIFICORP - 2013 IRP CHAPTER 6 – RESOURCE OPTIONS

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Market Hub/Proxy FOT Product Type Megawatt Limit and Availability

Mead

3

rd Quarter, Heavy Load Hour (6x16)

190 MW, 2013-2014 

0 MW, 2015+

Mona

3

rd Quarter, Heavy Load Hour (6x16) 300 MW, 2013+

To arrive at these maximum quantities, PacifiCorp considered the following:

Historical operational data and institutional experience with transactions at the market 

hubs.

The Company’s forward market view, including an assessment of expected physical 

delivery constraints and market liquidity and depth.

Financial and risk management consequences associated with acquiring purchases at 

higher levels, such as additional credit and liquidity costs.

Prices for FOT purchases are associated with specific market hubs and are set to the relevant 

forward market prices, time period, and location, plus appropriate wheeling charges.
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PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

157

CHAPTER 7 – MODELING AND PORTFOLIO 

EVALUATION APPROACH 

Introduction 

The IRP modeling approach seeks to determine the comparative cost, risk, and reliability 

attributes of resource portfolios. These portfolio attributes form the basis of an overall 

quantitative portfolio performance evaluation. This chapter describes the modeling and risk 

analysis process that supported that portfolio performance evaluation. The information drawn 

from this process, summarized in Chapter 8, was used to determine PacifiCorp’s preferred 

portfolio and support the analysis of resource acquisition risks.

CHAPTER HIGHLIGHTS

The IRP modeling approach seeks to determine the comparative cost, risk, and 

reliability attributes of resource portfolios. The 2013 IRP modeling approach 

consists of eight phases, from defining scenarios for portfolio development—

referred to as “cases,” to final selection of preferred portfolio based on costs and 

risk measures.

PacifiCorp worked closely with stakeholders to define 19 core cases that were 

applied uniformly across five Energy Gateway transmission scenarios and 

developed an additional 12 sensitivity cases reflecting alternative assumptions for 

load forecasts, availability of renewable resource federal tax incentives, renewable 

portfolio standard modeling, Class 3 demand-side management (DSM) resource 

availability, and coal unit environmental investments. In total 106 portfolios, each 

analyzing unit-by-unit environmental investments in existing coal resources, were 

developed and risk assessment studies were completed for 37 portfolios among 

three carbon dioxide (CO2) tax levels.

Three underlying natural gas price forecasts (low, medium, and high) were used to 

develop gas price projections consistent with a range of CO2 price assumptions: 

zero, medium, and high, plus U.S. hard cap prices required for the power sector to 

achieve an 80% reduction in emission by 2050 using both medium and high natural 

gas price assumptions.

Top-performing portfolios were selected on the basis of system costs using Monte 

Carlo simulations over a twenty year planning horizon. The Monte Carlo runs 

capture stochastic behavior of electricity prices, natural gas prices, loads, thermal 

unit availability, and hydro availability across 100 iterations.

Final preferred portfolio selection considers additional criteria such as risk-adjusted 

portfolio cost, CO2 emissions, supply reliability, resource diversity, and attainability 

of DSM program and renewable portfolio standard (RPS) requirements.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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The 2013 IRP modeling approach consists of eight phases, depicted as a flow chart in Figure 7.1. 

The eight phases are as follows: 

(1) Define input scenarios, referred to as cases, characterized by varying assumptions for 

CO2 prices, commodity gas prices, wholesale electricity prices, coal prices, 

environmental policy and other cost drivers.

(2) Case-specific price forecast development, where natural gas and power price 

assumptions are developed consistent with the definitions for each case.

(3) Optimized portfolio development for each case that excludes RPS assumptions using 

PacifiCorp’s System Optimizer capacity expansion model.

(4) Development of a renewable resource floor, reflecting renewable resource additions 

chosen in optimized portfolios, developed in Phase 3 of the modeling approach, that 

meet RPS requirements in cases that include RPS assumptions. This is a new step in 

the modeling process for the 2013 IRP that relies upon the RPS Scenario Maker 

model.

(5) Optimized portfolio development for each case that includes RPS assumptions using

PacifiCorp’s System Optimizer capacity expansion model requiring renewable 

resource additions that include at least those renewable resources developed in Phase 

4 of the modeling approach.

(6) Monte Carlo production cost simulation of optimized portfolios using PacifiCorp’s 

Planning and Risk (PaR) model to support stochastic risk analysis.

(7) Selection of top-performing portfolios using a three-phase screening process 

(preliminary screening, initial screening, and final screening) that incorporates 

stochastic portfolio cost and risk assessment measures, and 

(8) Preliminary preferred portfolio selection followed by final selection of the preferred 

portfolio. 

This chapter describes the overall modeling approach, including a discussion of modeling and 

price assumptions, and provides a profile of each modeling phase described above.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.1 – Modeling and Risk Analysis Process

Portfolio Modeling: System Optimizer

The System Optimizer model operates by minimizing for each year the operating costs for 

existing resources, taking into consideration potential compliance alternatives to coal unit 

environmental investments, subject to system load balance, reliability and other constraints. Over 

the 20-year study period, it optimizes resource additions subject to resource investment and 

capacity constraints (monthly peak loads plus a planning reserve margin for each load area 

represented in the model). In the event that early retirement of a coal unit is a lower cost 

alternative to installation of coal unit environmental investments, the System Optimizer model 

will select additional resources as required to meet monthly peak loads inclusive of a planning 

reserve margin.

To accomplish these optimization objectives, the model performs a time-of-day least-cost 

dispatch for existing and potential planned generation, contract, DSM, 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-type pattern representing an entire week. Each 

month is represented by one week, with results scaled to the number of days in the month and 

then the number of months in the year. The dispatch also determines optimal electricity flows 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

160

between zones and includes spot market transactions for system balancing. The model minimizes 

the overall PVRR, consisting of the net present value of contract and spot market purchase costs, 

generation costs (fuel, fixed and variable operation and maintenance, unserved energy, and 

unmet capacity), and amortized capital costs for planned resources. 

Modeling Capital Costs and Addressing “End-Effects”

For capital cost derivation, System Optimizer uses annual capital recovery factors to convert 

capital dollars into real levelized revenue requirement costs to address end-effects issues 

associated with capital-intensive investments that have different lives and in-service dates. All 

capital costs evaluated in the IRP are converted to real levelized revenue requirement costs. Use 

of real levelized revenue requirement costs is an established and preferred methodology to 

account for analysis of capital investment decisions that have unequal lives and/or when it is not 

feasible to capture operating costs and benefits over the entire life of any given investment 

decision. To achieve this, the real levelized revenue requirement method spreads the return of 

investment (book depreciation), return on investment (equity and debt), property taxes and 

income taxes over the life of the investment. The result is an annuity or annual payment that 

grows at inflation such that the PVRR is identical to the PVRR of the nominal annual 

requirement when using the same nominal discount rate. For the 2013 IRP, the PVRR is 

calculated inclusive of real levelized capital revenue requirement through the end of the 2032 

planning period. PacifiCorp uses the real-levelized capital costs produced by System Optimizer 

for portfolio cost reporting by the PaR model.

In prior IRPs, growth station resources were included as generic resource alternatives in the out 

years of the IRP planning horizon. Historically, this resource option was used to balance 

capacity in each load area as a means to manage simulation run times by simplifying resource 

selection beyond the first 10 years of the planning period. Growth stations were ascribed costs 

derived from the forward power price curve. Upon expanding the scope of the 2013 IRP to 

evaluate coal unit environmental investments in all System Optimizer simulations, the use of 

growth resources was eliminated, allowing selection of supply and demand side resource 

alternatives in meeting loads over the entire 20 year planning horizon. This approach is required 

to ensure that the economics of potential early coal unit retirements capture the full cost of 

replacement resources over the long-term.

Modeling Front Office Transactions 

Front office transactions (FOTs) are assumed to be transacted on a one-year basis, and are 

represented as available in each year of the study. For capacity optimization modeling, System 

Optimizer engages in market transactions. FOT transactions are firm forward power purchases 

that contribute capacity and energy to the system. System balancing transactions are short-term 

purchases and sales used to balance energy supply with demand in all hours across the system. 

System balancing purchases are energy transactions and do not contribute in meeting system 

capacity and planning reserve margin needs.

The FOTs modeled in the PaR model generally have the same characteristics as those modeled in 

the System Optimizer, except that transaction prices reflect wholesale forward electric market 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

161

prices that are “shocked” according to a stochastic modeling process prior to simulation 

execution.

Modeling Wind and Solar Resources 

Wind and solar resources are modeled as non-dispatchable, must-run resources in both the 

System Optimizer and PaR models using fixed energy profiles that vary by month and time of 

day. The total energy generation for wind and solar resources represents the expected generation 

levels in which half of the time actual generation would fall below expected levels, and half of 

the time actual generation would be above expected levels.

In this IRP, the peak contribution of the wind resources is set at 4.2 percent, which was 

determined based upon review of actual wind generation data interconnected to PacifiCorp’s 

system. The peak contribution of solar resources is set at 13.6 percent, which is based on third 

party information due to the lack of sufficient actual solar resource generation data within the 

Company’s system. Volume II, Appendix O of this report discusses the details of the 

methodology that determined the peak contribution assumptions for wind and solar resources.

Modeling Coal Unit Environmental Investments

Building upon modeling techniques developed in the 2011 IRP and 2011 IRP Update, 

environmental investments required to achieve compliance with known and prospective 

regulations at existing coal resources have been integrated into the portfolio modeling process 

for the 2013 IRP. Potential alternatives to environmental investments associated with known and 

prospective compliance obligations are considered in the development of all resource portfolios. 

Integrating potential environmental investment decisions into the portfolio development process 

allows each portfolio to reflect potential early retirement and resource replacement and/or natural 

gas conversion as alternatives to incremental environmental investment projects on a unit-by-unit 

basis. This advancement in analytical approach marks a significant evolution of the IRP process 

as it requires consideration of potential resource contraction while simultaneously analyzing 

alternative resource expansion plans.

Integrating coal unit environmental investment decisions in the development of resource 

portfolios identifies whether investments are cost effective in relation to other compliance 

alternatives. However, additional analysis is required to numerically quantify the economic 

benefit of investment decisions required on any given unit as compared to the next best 

alternative. Confidential Volume III summarizes additional analysis of coal unit environmental 

investments that are used to quantify the economic benefits of specific investment decisions that 

have been analyzed in the development of resource portfolios for the 2013 IRP.

Table 7.1 outlines the type of costs that are assigned to existing coal units configured with early 

retirement and gas conversion alternatives.
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Table 7.1 Resource Costs, Existing and Associated Gas Conversion Alternatives

Existing Coal Unit Costs Coal Unit Early Retirement 

Alternative

Gas Conversion Alternative

Incremental capital 

for environmental 

investments

Variable reagent costs 

for incremental 

environmental 

investments

Run-rate operations & 

maintenance (O&M)

and capital

Incremental mine 

capital (as applicable)

Cash coal fuel costs

End-of-life 

decommissioning

Decommissioning 

costs

Recovery of 

incremental 

environmental capital 

and run-rate capital 

spent prior to early 

retirement date

Coal contract 

liquidated damages 

(as applicable)

Up-front capital cost

Run-rate operations & 

maintenance (O&M)

Fixed and variable 

natural gas 

transportation

Natural gas fuel cost

Recovery of 

incremental 

environmental capital 

and run-rate capital 

spent prior to gas 

conversion

Coal contract 

liquidated damages 

(as applicable)

Reserve Margin Requirement

In the System Optimizer model, PacifiCorp continues to apply a 13 percent planning reserve 

margin. The planning reserve margin is used to ensure that the Company has sufficient resources 

to meet peak loads recognizing that there is a possibility for load fluctuation and extreme 

weather conditions, a possibility for unplanned resource outages, and a requirement to carry 

contingency and regulating reserves.

In the PaR model, explicit categories of operational reserve requirements are modeled. The 

contingency reserves are approximately 7 percent of the system load. The amount of regulating 

reserves includes ramping of load, as well as requirement to integrate variable energy resources, 

such as wind. The reserve requirements to integrate wind resources are the results of 

PacifiCorp’s 2012 Wind Integration Study, which is presented in Volume II, Appendix H of this 

report. The forced outages and fluctuation in load due to temperature are reflected in the 

modeling of resource availability and simulated in the stochastic runs.

Modeling Energy Gateway Transmission Scenarios 

The Energy Gateway transmission project is modeled in this IRP under five scenarios. The 

scenarios for Energy Gateway transmission paths are modeled as fixed inputs to both the System 

Optimizer and PaR models, which cannot endogenously add additional transmission resources as 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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can be done for supply and demand side resources. The costs of Energy Gateway segments are 

modeled as a real levelized revenue requirement, as discussed above, based on a real levelized 

capital recovery factor of 7.069 percent, which intends to recover the investment cost of the

assets, return on and of capital, income taxes and property taxes. Fixed operating and 

maintenance costs are also included in the model as 1.07 percent of the investment.

Modeling Energy Storage Technologies 

Energy storage resources in both System Optimizer and PaR models are distinguished from other 

resources by the following three attributes:

Energy “take” – generation or extraction of energy from a reservoir on-peak;

Energy “return” – energy used to fill (or charge) a reservoir off-peak; and

Storage cycle efficiency – an indicator of the energy loss involved in storing and 

extracting energy over the course of the take-return cycle.

The models require specification of a reservoir size. For System Optimizer and PaR models, 

reservoir size is defined in gigawatt-hours. System Optimizer dispatches a storage resource to 

optimize energy used by the resource subject to constraints such as storage cycle efficiency, the 

daily balance of take and return energy, and fuel costs (for example, the cost of natural gas for 

expanding air with gas turbine expanders). To determine the least-cost resource expansion plan, 

the model accounts for conventional generation system performance and cost characteristics of 

the storage resource, including investment cost, capacity factor, heat rate (if fuel is used), 

operating and maintenance cost, minimum capacity, and maximum capacity.

In the PaR model, simulations are conducted on a week-ahead basis. The model operates the 

storage plant to balance generation and charging, accounting for cycle efficiency losses, in order 

to end the week in the same net energy position as it began. The model chooses periods to 

generate and return energy to minimize system cost. It does this by calculating an hourly value of 

energy for charging. This value of energy, a form of marginal cost, is used as the cost of 

generation for dispatch purposes, and is derived from calculations of system cost and unit 

commitment effects. For compressed air energy storage (CAES) plants, a heat rate is included as 

a parameter to capture fuel conversion efficiency. The heat rates entered in both models 

represent the use of PacifiCorp’s off-peak coal-fired plants.

General Assumptions and Price Inputs 

Study Period and Date Conventions 

PacifiCorp executes its IRP models for a 20-year period beginning January 1, 2013 and ending 

December 31, 2032. Future IRP resources reflected in model simulations are given an in-service 

date of January 1st of a given year, with the exception of natural gas conversion alternatives to 

incremental environmental investments required at existing coal units, which are given an inservice date of June 1st for the year gas conversion is completed.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Escalation Rates and Other Financial Parameters 

Inflation Rates

The IRP model simulations and price forecasts reflect PacifiCorp’s corporate inflation rate 

schedule unless otherwise noted. For the System Optimizer model, a single escalation rate value 

is used. This value, 1.9 percent, is estimated as the average of the annual corporate inflation rates 

for the period 2013 to 2032, using PacifiCorp’s March 2012 inflation curve. PacifiCorp’s 

inflation curve is a straight average of forecasts for Gross Domestic Product (GDP) inflator and 

Consumer Price Index (CPI).

Discount Factor

The rate used for discounting in financial calculations is PacifiCorp’s after-tax weighted average 

cost of capital (WACC). The value used for the 2013 IRP is 6.882 percent. The use of the aftertax WACC complies with the Public Utility Commission of Oregon’s IRP guideline 1a, which 

requires that the after-tax WACC be used to discount all future resource costs.60

Federal Renewable Resource Tax Incentives 

In the current IRP, it is assumed that federal production tax credits (PTC) for qualifying 

renewable resources are expired and that the federal investment tax credits (ITC) for qualifying 

renewable resources will expire at the end of 2016, consistent with the Emergency Economic 

Stabilization Act of 2008 (P.L. 110-343), which allows utilities to claim the 30 percent ITC for 

solar facilities placed in service by January 1, 2017. This tax credit is factored into the capital 

cost for solar resource options in the System Optimizer model. Select cases evaluated for the 

2013 IRP assume federal PTCs and ITCs are extended through 2019.

Asset Lives 

Table 7.2 lists the generation resource asset book lives assumed for levelized fixed charge 

calculations.

 

60 Public Utility Commission of Oregon, Order No. 07-002, Docket No. UM 1056, January 8, 2007.
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Table 7.2 – Resource Book Lives

Resource

Book Life

(Years)

Integrated Gasification Combined-Cycle with carbon capture and sequestration 40

Combined Cycle Combustion Turbine (CCCT) 40

Pumped Storage 50

Simple Cycle Combustion Turbine (SCCT) Frame 35

Solar Photovoltaic 25

Solar Thermal 30

Compressed Air Energy Storage 30

Single Cycle Combustion Turbine (SCCT) Aero 30

Intercooled Aeroderivative SCCT 30

Internal Combustion Engine 20

Fuel Cells 20

Wind 25

Battery Storage 30

Biomass 30

Nuclear Plant 40

CHP - Reciprocating Engine 20

CHP - Gas Turbine 20

CHP - Microturbine 10

CHP - Fuel Cell 10

CHP - Commercial Biomass, Anaerobic Digester 17

CHP - Industrial Biomass Waste 17

Solar - Rooftop Photovoltaic 30

Solar - Water Heaters 20

Transmission System Representation

PacifiCorp uses a transmission topology consisting of 19 bubbles (electrically connected areas) 

in its eastern balancing authority area and 18 bubbles in its western balancing authority area 

designed to best describe major load and generation centers, regional transmission congestion 

impacts, import/export availability, and external market dynamics. Firm transmission paths link 

the bubbles. The transfer capabilities for these links represent PacifiCorp Merchant’s current 

firm rights on the transmission lines. This topology is defined for both the System Optimizer and 

PaR models.

Figure 7.2 shows the IRP transmission system model topology. Segments of the planned Energy 

Gateway Transmission Project are indicated with red dashed lines and with alphabetic names. 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.2 – Transmission System Model Topology

The most significant change to the model topology from the 2011 IRP is the addition of four new 

bubbles and the identification of the Energy Gateway line segments.

 

The Hemingway bubble addition was essential for modeling the Energy Gateway path 

“H” of Hemingway-Boardman-Bethel with bi-directional capabilities, and to improve the 

ability to model the separate transfer capability through the Idaho Power system.

The Midpoint-Meridian bubble addition is an improved representation of existing east to 

west transfer capability. This modeling of the legacy contract is needed since it contains 

provisions limiting what energy may be transferred on the west side of the Idaho Power 

system.

The Bridger Constraint bubble addition is included to model a reliability constraint 

consistent with operations that limits the transfer from Jim Bridger to the east balancing 

authority area to three of the four generating units.

The Nevada Oregon Border (NOB) bubble addition is to provide existing access to the 

California ISO market via PacifiCorp’s DC Intertie rights in the model. Without this 

addition the benefits of the existing rights would not be apparent.

The 2011 IRP utilized separate wind bubbles in order to assign incremental transmission 

interconnection investment costs to the wind resources. However, in the current IRP, the 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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incremental transmission costs are assigned directly to the wind resources and, therefore, 

eliminated the need to model separate wind bubbles.

Carbon Dioxide Regulatory Compliance Scenarios 

Carbon Dioxide Scenarios 

Table 7.3 shows five different sets of CO2 price assumptions used in the 2013 IRP. Each CO2

price scenario is accompanied by a consistent set of natural gas and wholesale power price 

assumptions. For modeling purposes, the cost of CO2 emissions are applied as a tax in which 

there is a cost imputed on each ton of CO2 emissions generated by system resources. This 

approach is used in recognition that there are a wide range of policy mechanisms that might be 

used to regulate CO2 emissions in the power sector at some point in the future. Application of 

CO2 prices as a tax is a means to assign costs to CO2 emissions as a surrogate for a wide range of 

potential future policy tools, whether implemented as a tax, cap-and-trade program, emission 

performance standards, or some other policy mechanism. Each of the CO2 price scenarios used in 

the 2013 IRP is discussed in turn below:

Zero CO2 Price Scenario

Given that there is currently no specific legislative proposal that has been passed by Congress for 

the President’s consideration and no current federal regulation that would impose a direct cost on 

CO2 emissions, the 2013 IRP includes a zero CO2 price scenario. Under this scenario, there is no 

direct cost applied to CO2 emissions from generation sources throughout the IRP 20-year 

planning horizon.

Medium CO2 Price Scenario

The medium CO2 price scenario ascribes a cost to CO2 emissions within ten years of 2013, and 

as such, prices are assumed beginning in 2022. Price levels in this scenario are consistent with 

recent projections from third party forecasters. Price levels in the medium CO2 price scenario 

are generally aligned with a price signal that would be required to induce switching from coal to 

natural gas-fired generation sources with an assumed annual real escalation rate of 3 percent.

High CO2 Price Scenario

Under the high CO2 price scenario, a cost is ascribed to CO2 emissions beginning 2020, which is 

two years earlier than in the medium CO2 price scenario. Under the high scenario, it is assumed 

that regulation would ramp into more stringent requirements over the first two years (in 2020 and 

2021). The high scenario reflects how prospective CO2 prices might respond to a future with new 

regulations that would impose costs on fossil fuel sources and new regulations that could 

increase natural gas prices (i.e. regulations that would increase the cost of natural gas supply). 

Under such a scenario, the CO2 price signal required to induce switching from coal to natural 

gas-fired generation sources would be higher as compared to the medium CO2 price scenario, 

and the resulting price trajectory is similar to the price ceiling that was included in a climate and 

energy bill proposed by Senator John Kerry and Senator Joe Lieberman in the American Power 

Act of 2010.

U.S. Hard Cap, Medium Natural Gas CO2 Price Scenario

This scenario reflects a CO2 price trajectory produced using the Integrated Planning Model 

(IPM®) assuming a generic cap-and-trade program is imposed upon the power sector of the U.S. 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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economy beginning in 2020 with declining annual emission limits that reach 80 percent below 

2005 levels by 2050. In this simplified analysis, it was assumed that domestic and international 

CO2 offsets could not be used to mitigate power sector emissions, and the resulting CO2 price 

projection was developed off of medium natural gas price assumptions.

U.S. Hard Cap, High Natural Gas CO2 Price Scenario

As in the U.S. hard cap scenario described above, this scenario reflects a CO2 price trajectory 

resulting from a cap-and-trade program imposed upon the power sector of the U.S. economy 

beginning in 2020 with declining annual emission limits that reach 80 percent below 2005 levels 

by 2050. Similarly, it is assumed that domestic and international offsets cannot be used to 

mitigate power sector emissions. In this variant of the U.S. hard cap CO2 price scenario, the CO2

price projection was developed off of high natural gas price assumptions. With higher natural 

gas price assumptions, the resulting CO2 price level is higher than those developed for the U.S. 

Hard Cap, Medium Natural Gas CO2 Price Scenario. 

Table 7.3 CO2 Price Scenarios

Year

CO2 Price, Nominal $/short ton

None Base High

Hard Cap, 

Base Gas

Hard Cap, 

High Gas

2020 $0.00 $0.00 $13.53 $47.47 $57.08

2021 $0.00 $0.00 $19.68 $50.86 $61.17

2022 $0.00 $16.00 $26.05 $54.49 $65.53

2023 $0.00 $16.78 $32.67 $58.38 $70.21

2024 $0.00 $17.61 $39.52 $62.55 $75.22

2025 $0.00 $18.47 $46.62 $67.01 $80.59

2026 $0.00 $19.37 $49.88 $71.80 $86.34

2027 $0.00 $20.32 $53.37 $76.94 $92.52

2028 $0.00 $21.32 $57.11 $82.44 $99.14

2029 $0.00 $22.36 $61.10 $88.35 $106.24

2030 $0.00 $23.46 $65.38 $94.67 $113.84

2031 $0.00 $24.63 $70.02 $101.55 $122.12

2032 $0.00 $25.86 $74.99 $108.88 $132.25

Figure 7.3 compares the five CO2 price scenarios graphically, and Table 7.4 shows the U.S. 

power sector projected carbon emissions through 2050 under the U.S. Hard Cap Scenario.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.3 – Carbon Dioxide Price Scenario Comparison

 $-

 $20

 $40

 $60

 $80

 $100

 $120

 $140 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Nominal $/ Short Ton

Low ($0) Base (Sept 2012 OFPC) High Hard Cap - Base Gas Hard Cap - High Gas
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Table 7.4 Carbon Reduction under U.S. Hard Cap Scenarios

Year

Potential Hard Cap Reduction Scenario: 80% 

reduction from 2005 CO2 power sector emission levels

by 2050 (short tons)

2005 2,617,96061

2020 2,200,511

2021 2,144,614

2022 2,088,716

2023 2,032,819

2024 1,976,922

2025 1,921,024

2026 1,865,127

2027 1,809,230

2028 1,753,333

2029 1,697,435

2030 1,641,538

2031 1,585,641

2032 1,529,743

2033 1,473,846

2034 1,417,949

2035 1,362,052

2050 523,593

Oregon Environmental Cost Guideline Compliance 

The Oregon Public Utility Commission (OPUC), in their IRP guidelines, directs utilities to 

construct a base-case scenario that reflects what it considers to be the most likely regulatory 

compliance future for CO2, as well as alternative scenarios “ranging from the present CO2

regulatory level to the upper reaches of credible proposals by governing entities.” Modeling

portfolios with no CO2 cost represents the current regulatory level. The base scenario was 

considered the most likely regulatory compliance scenario at the time that IRP CO2 scenarios 

were being prepared and vetted by public stakeholders (early fall of 2012). Given the late-2010 

collapse of comprehensive federal energy legislation and loss of momentum for implementing 

federal carbon pricing schemes, it is not likely Congress will pass federal climate change 

legislation for consideration by the President over the near-term. At this time, it is likely that 

federal CO2 regulations will come in the form of new source performance standards, applicable 

to both new and existing electric generating units. 

PacifiCorp believes that its CO2 tax and hard cap scenarios reflect a reasonable range of 

compliance futures for meeting the OPUC scenario development guideline. As discussed in the 

preceding section, the Company’s CO2 prices are indicative of varying levels of CO2 prices 

signals that might arise from a wide range of future policy outcomes at the federal level. 

Moreover, the System Optimizer model runs using the above CO2 assumptions yielded varied 

composition of portfolios, with some portfolios showing nearly all of PacifiCorp’s coal units 

shutting down or converting to natural gas within the 20-year planning horizon.

 

61 Energy Information Administration / Emissions of Greenhouse Gases in the United States 2005, November 2006.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Phase (1) Case Definition 

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 to inputs representing the predominant sources of portfolio cost variability and 

uncertainty. PacifiCorp generally specified low, medium, and high values for key assumptions to 

ensure that a reasonably wide range in potential outcomes is captured. For the 2013 IRP, 

PacifiCorp worked closely with stakeholders to develop 19 core case definitions applied 

uniformly across five different Energy Gateway scenarios with an additional 12 sensitivity cases 

that in total sum to 106 different resource portfolios. Each of the five Energy Gateway scenarios 

were defined to explore how different combinations of Energy Gateway segments influence 

resource selection and system costs.

Core cases focus on broad comparability of portfolio performance results for five key variables. 

These variables include (1) timing of and level of CO2 prices, (2) natural gas and wholesale 

electricity prices, (3) policy assumptions pertaining to federal tax incentives and RPS 

requirements, (4) policy assumptions pertaining to coal unit compliance requirements driven by 

Regional Haze regulations, and (5) acquisition ramp rates for Class 2 DSM energy efficiency 

resources.

In contrast, sensitivity cases focus on changes to resource-specific assumptions and alternative 

load growth forecasts. The resulting portfolios from the sensitivity cases are typically compared 

to one of the core case portfolios. PacifiCorp developed 12 sensitivity cases reflecting 

alternative assumptions for load forecasts, availability of renewable resource federal tax 

incentives, renewable portfolio standard modeling, Class 3 DSM resource availability, and coal 

unit environmental investments.

In developing these cases, PacifiCorp worked collaboratively with stakeholders to develop case 

definitions meeting the following objectives: (1) case definitions expected to yield resource 

diversity and comparative consistency among cases, (2) portfolio development structure that 

isolates the how individual Energy Gateway segments affect resource selection, (3) provides for 

an understanding of how RPS requirements affect renewable resource needs, and (4) is 

responsive to stakeholder requests targeting specific resource technologies. 

With these objectives in mind, the Company initiated the portfolio case development process and 

sample case definitions at the June 20, 2012 public input meeting. In response to stakeholder 

comments, the Company produced draft core case definitions at the July 13, 2012 public 

meeting. Additional stakeholder comments were reviewed and significantly influenced updated 

draft core case definitions reviewed with stakeholders at the September 14, 2012 meeting. 

Detailed “fact sheets”, describing high level assumptions for each core case in a consistent 

format, was shared with stakeholders at the October 24, 2012 meeting and updated at the 

December 18, 2012 meeting. Sensitivity case fact sheets were shared with stakeholders at the 

February 27, 2013 public meeting.

Case Specifications 

Table 7.5 defines the five Energy Gateway scenarios, and Figure 7.4 shows the generation 

location of specific Energy Gateway Segments.
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Table 7.5 – Energy Gateway Scenario Definitions

Scenario Segments Description

EG1 C and G Reference – Mona-OquirrhTerminal, Sigurd-Red Butte

EG2 C, D, and G System Improvement – 2013 

Business Plan

EG3 C, D, E, G, and H

West/East Consolidation –

Increase interchange between PACE 

and PACW

EG4 C, D, G, and F Triangle – East side wind and 

improved reliability

EG5 C, D, E, G, H, and F Full Gateway – All Energy 

Gateway segments

Figure 7.4 – Future Energy Gateway Transmission Expansion Plan

This map is for general reference only and reflects current plans.

It may not reflect the final routes, construction sequence or exact line configuration.

Portfolio development cases developed for the 2013 IRP were categorized into four different 

themes, each described in turn below:

(5) Reference: There are three different core cases developed for the Reference Theme. 

Each case relied upon base case assumptions for market prices, environmental policy 
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inputs, energy efficiency assumptions, and load projections. RPS assumptions 

differentiate the three cases in the Reference Theme, with one case assuming no state 

or federal RPS requirements, one case assuming only state RPS requirements, and 

one case assuming both state and federal RPS requirements must be met.

(6) Environmental Policy: There are 11 different core cases and two types of sensitivity 

cases developed for the Environmental Policy Theme. Five of the 11 core cases 

reflect base case assumptions for Regional Haze requirements on existing coal units, 

and six of the 11 cases assume more stringent Regional Haze requirements. 

Differentiating the sets of cases with different Regional Haze compliance 

requirements are varying assumptions for market prices (low, medium, and high), 

CO2 prices (zero, medium, and high), RPS requirements (with and without state and 

federal RPS), and energy efficiency. The two types of sensitivity cases developed for 

the Environmental Policy Theme describe additional analysis performed to evaluate 

near-term coal unit environmental investments that are summarized in Confidential 

Volume III.

(7) Targeted Resources: There are four different core cases and five different sensitivity 

cases developed for the Targeted Resource Theme. Each of the cases is characterized 

by alternative assumptions for specific resource types to understand how these 

assumptions influence resource portfolios, costs, and risk. One of the four core cases 

prevents combined cycle resources from being added to the resource portfolio and 

assumes energy efficiency resources can be acquired at an accelerated rate. The 

second of the four core cases in this theme assumes that geothermal power purchase 

agreement resources will be used to meet RPS requirements. The third of four core 

cases in this theme assumes a spike in power prices over the period 2017 through 

2022 and assumes natural gas prices will rise above base case levels over the entirety 

of the planning horizon. The fourth core case in this theme targets clean energy 

resources and assumes CO2 prices rise consistent with a federal hard cap scenario, 

that natural gas prices rise above those assumed in the base case, that federal tax 

incentives for renewable resources are extended through 2019, and that energy 

efficiency resources can be acquired at an accelerated rate.

(8) Transmission: The Transmission Theme included one core case, which assumes that 

third party transmission can be purchased from a newly built line as an alternative to 

the Company’s Gateway Segment D project. This case was only analyzed in four of 

the five Energy Gateway scenarios that include the Gateway Segment D project.

Tables 7.6 and 7.7 provide the definitions of the core cases and sensitivity cases. In addition, 

detailed descriptions of all cases are provided in case fact sheets that are available in Volume II, 

Appendix M of this report.
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Table 7.6 – Core Case Definitions

Theme Case Gas Price CO2 Price Coal Price RPS Class 2 DSM Other

Reference C01 Medium Medium Medium None Base n/a

C02 Medium Medium Medium State Base n/a

C03 Medium Medium Medium State & Federal Base n/a

Environmental C04 Low High High None Base n/a

Policy C05 Low High High State & Federal Base n/a

C06 High Zero Low None Base n/a

C07 High Zero Low State & Federal Base n/a

C08 Low High High None Base n/a

C09 Low High High State & Federal Base n/a

C10 Medium Medium Medium None Base n/a

C11 Medium Medium Medium State & Federal Base n/a

C12 High Zero Low None Base n/a

C13 High Zero Low State & Federal Base n/a

C14 Medium

Hard Cap 

(Medium Gas) Medium State & Federal Accelerated n/a

Targeted C15 Medium Medium Medium State & Federal Accelerated No CCCT

Resources C16 Medium Medium Medium State & Federal Base Geothermal/RPS

C17 High Medium Medium State & Federal Base Market Spike

C18 Medium

Hard Cap (High 

Gas) Medium None Accelerated Clean Energy

Transmission C19 Medium Medium Medium State & Federal Base Alt. to Segment D
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Table 7.7 – Sensitivity Case Definitions

Theme Case # Load Gas Price CO2 Price RPS PTC/ITC Coal 

Investments

Load Sensitivity S-01 Low Medium Medium

State & Federal

(RPS Floor) 2012/2016 Optimized

S-02 High Medium Medium

State & Federal

(RPS Floor) 2012/2016 Optimized

S-03 1 in 20 Medium Medium

State & Federal

(RPS Floor) 2012/2016 Optimized

Targeted S-05 Base Medium Medium None 2019/2019 Optimized

Resource S-06 Base Medium Medium

State & Federal

(RPS Floor) 2019/2019 Optimized

S-07 Base Medium Medium

State & Federal

(Optimized) 2012/2016 Optimized

S-09 Base High High

State & Federal

(RPS Floor) 2019/2019 Optimized

S-10 Base Medium Medium

State & Federal

(RPS Floor) 2012/2016 Optimized

Environmental 

Policy

S-04

(Volume III) Base Medium Medium

State & Federal

(RPS Floor) 2012/2016

Hypothetical 

Regional Haze

S-X

(Volume III) Base Medium Medium

State & Federal

(RPS Floor) 2012/2016

Next Best 

Alternative

Notes

1. All sensitivity cases are based on Energy Gateway Scenario 2, consistent with the scenario in the 2013 IRP preferred portfolio.

2. Sensitivity Case S-07 applies state RPS targets as system targets in the System Optimizer model. All other sensitivities either use the RPS Scenario 

Maker to establish a renewable resource floor or exclude RPS requirements altogether.

3. Case S-08 (simulating PacifiCorp’s 2013 Business Plan portfolio in the current input setup) was removed due to incompatibilities in how Class 2 DSM 

resources are modeled in the 2013 IRP.

4. Sensitivity cases S-04 (Hypothetical Regional Haze Compliance Alternative) and S-X (Emission Control PVRR(d) Analysis) are confidential and 

summarized in confidential Volume III of the 2013 IRP report.
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Phase (2) Scenario Price Forecast Development 

On a central tendency basis, commodity markets tend to respond to the evolution of supply and 

demand fundamentals over time. Due to a complex web of cross-commodity interactions, price 

movements in response to supply and demand fundamentals for one commodity can have 

implications for the supply and demand dynamics and price of other commodities. This 

interaction routinely occurs in markets common to the electric sector as evidenced by a strong 

positive correlation between natural gas prices and electricity prices. 

Some relationships among commodity prices have a long historical record that have been studied 

extensively, and consequently, are often forecasted to persist with reasonable confidence. 

However, robust forecasting techniques are required to capture the effects of secondary or even 

tertiary conditions that have historically supported such cross-commodity relationships. For 

example, the strong correlation between natural gas prices and electricity prices is intrinsically 

tied to the increased use of natural gas-fired capacity to produce electricity. If for some reason 

natural gas-fired capacity diminishes in favor of an alternative technology, the linkage between 

gas prices and electricity prices would almost certainly weaken. 

PacifiCorp deploys a variety of forecasting tools and methods to capture cross-commodity 

interactions when projecting prices for those markets most critical to this IRP – natural gas 

prices, electricity prices, and emission prices. Figure 7.5 depicts a simplified representation of 

the framework used by PacifiCorp to develop the price forecasts for these different commodities. 

At the highest level, the commodity price forecast approach begins at a global scale with an 

assessment of natural gas market fundamentals. This global assessment of the natural gas market 

yields a price forecast that feeds into a national model where the influence of emission and 

renewable energy policies is captured. Finally, outcomes from the national model feed into a 

regional model where delivered gas prices and emission prices drive a forecast of wholesale 

electricity prices. In this fashion, the Company is able to produce an internally consistent set of 

price forecasts across a range of potential future outcomes at the pricing points that interface 

with PacifiCorp’s system.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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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 natural gas prices. In this step, PacifiCorp relies upon a number of 

expert third-party proprietary data and forecasting services to establish a range of gas price 

scenarios. Each price scenario reflects a specific view of how the North American natural gas 

market will balance supply and demand. 

Once a natural gas price forecast is established, the Integrated Planning Model (IPM®) is used to 

simulate the entire North American power system. IPM®, a linear program, determines the least 

cost means of meeting electric energy and capacity requirements over time, and in its quest to 

lower costs, ensures that all assumed emission policies and RPS policies are met. Concurrently, 

IPM® can be configured with a dynamic natural gas price supply curve that allows natural gas 

prices to respond to changes in demand triggered by environmental compliance. Additional 

outputs from IPM® include a forecast of resource additions consistent with all specified RPS National Model Regional Model PacifiCorp System Models Global Outlook

MIDAS

● Wholesale electricity prices

Planning and Risk 

(PaR)

System Optimizer

Integrated Planning 

Model (IPM®)

● Gas price response to 

environmental policy

● Emission prices

Third-party 

Proprietary Data 

Services

● Natural gas market 

fundamentals and price 

scenarios

● Unadjusted natural 

gas prices

● Delivered gas prices

● Wholesale electricity prices

● Emission prices

● Emission policy

● RPS targets

● RPS resource additions

● Regional gas prices

● Emission prices

● RPS resource 

additions
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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targets, electric energy and capacity prices, coal prices62, electric sector fuel consumption, and 

emission prices for policies that limit emissions or emission rates.

63

Once emission prices and the associated gas price response are forecasted with IPM®, results are 

used in a regional model, Multi Objective Integrated Decision Analysis System (MIDAS), to 

produce an accompanying wholesale electricity price forecast. MIDAS is an hourly 

chronological dispatch model configured to simulate the Western Interconnection and offers a 

more refined representation of western wholesale electricity markets than is possible with IPM®. 

Consequently, PacifiCorp produces a more granular price projection that covers all of the 

markets required for the system models used in the IRP. The natural gas and wholesale 

electricity 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

PacifiCorp’s official forward price curve (OFPC) for natural gas prices is composed of market 

forwards for the first 72 months, followed by 12 months of blended prices which transition into a

third-party fundamentals forecast, starting in month 85. 

The first 72 months of the official forward price curve represents market forwards, the value that 

market participants will buy and sell today for a commodity that delivers sometime in the 

future. There is a constant consideration for what happens between today and the time of 

delivery and all days in between as demonstrated by dynamic (constant) changes in bids and 

offers. A forward curve is not a forecast; it is simply a representation of where one believes they 

can transact today for forward settlements/deliveries.

In contrast to market forwards, starting in month 85, PacifiCorp’s OFPC is based on a third-party 

fundamentals forecast. This forecast is a single description of what one expects the value a 

commodity to be at the time it is delivered and consumed. A forecast contains no consideration 

for what happens between today and the forecast’s scope of time.

The underlying base natural gas price forecasts used in this IRP are significantly lower than 

those produced for the Company’s 2011 IRP and the subsequent 2011 IRP Update filed with 

state commissions March 2011 and March 2012, respectively. Figures 7.6, 7.7, and 7.8 compare 

base natural gas (Henry Hub) and electricity (Palo Verde and Mid C) price forecasts for the 2013 

IRP, 2011 IRP Update, and 2011 IRP.

 

62 IPM® contains over 75 coal supply curves, with reserve estimates, by rank and quality. Coal supply curves are 

matched to coal demand areas, including transportation costs, and optimized. As such, IPM® is able to capture coal 

price response from incremental (decremental) demand, which ultimately affects the natural gas and emission prices 

that feed into System Optimizer and Planning and Risk.

63 Emission modeling capabilities of IPM® were also used in this IRP to develop CO2 prices for the two U.S. Hard 

Cap CO2 price scenarios.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.6 – Comparison of Base Henry Hub Gas Price Forecasts used for Recent IRPs

Figure 7.7 –Palo Verde Electricity Price Forecasts used in Recent IRPs

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PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.8 – Mid Columbia Electricity Price Forecasts used in Recent IRPs

Five natural gas price forecasts were used to derive the gas price projections for the 19 core cases 

analyzed in this IRP. A range of fundamental assumptions affecting how the North American 

market will balance supply and demand defines the underlying price forecasts. 

The hard cap studies were developed June 2012. The supporting expert third-party high natural 

gas price scenario was issued May 2012 while the base price forecast reflects PacifiCorp’s June 

29, 2012 OFPC. The OFPC is composed of market forwards for the first 72 months, followed by 

12 months of blended prices which transition into an expert third-party fundamentals forecast, 

starting in month 85. 

The CO2 tax studies were developed September 2012. The supporting expert third-party high and 

low natural gas price scenarios were issued August 2012 while the base price forecast reflects 

PacifiCorp’s September 2012 OFPC. Again, the OFPC is composed of market forwards for the 

first 72 months, followed by 12 months of blended prices which transition into an expert thirdparty fundamentals forecast, starting in month 85.

Table 7.8 shows prices at the Henry Hub benchmark for the five underlying natural gas price 

forecasts. The forecasts serve as a point of reference and are adjusted to account for changes in 

natural gas demand driven by a range of environmental policy and technology assumptions 

specific to each IRP case. Figure 7.9 compares the five underlying Henry Hub price forecasts 

used in the 2013 IRP.

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PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Table 7.8 – Underlying Henry Hub Natural Gas Price Forecast Summary (Nominal 

$/MMBtu)

Forecast Name 2013 2015 2020 2025 2032

High (Tax Scenario) $4.68 $4.94 $8.07 $10.40 $12.49

Base (Tax Scenario) $3.84 $4.37 $6.43 $7.59 $8.84 

Low (Tax Scenario) $2.58 $3.21 $3.83 $4.59 $5.68 

High (Hard Cap Scenario) $4.24 $5.01 $8.61 $11.35 $13.63

Base (Hard Cap Scenario) $3.58 $4.13 $6.43 $7.59 $8.84

Figure 7.9 – Underlying Henry Hub Natural Gas Price Forecast Summary (Nominal 

$/MMBtu)

Price Projections Tied to the High Forecast

The driving assumption of the underlying high-price scenario is that of high oil prices. Outside 

of power generation, which was quick to respond to lower gas prices in 2012, the bulk of new 

demands will come later in the decade as liquefied natural gas (LNG) export facilities come 

online. Currently, the Cheniere Sabin Pass LNG export terminal is expected to be online in 2015 

with other export terminals awaiting approval from the Federal Energy Regulatory Commission 

(FERC). Asian buyers are particularly attracted to Gulf Coast and East Coast export facilities 

since the LNG is more likely to be indexed to the price of Henry Hub (versus oil). Increased 

industrial demands are also expected to materialize later in the decade from the petrochemical, 

fertilizer, steel, and transportation sectors. Volumes expected to move into the transportation 

sector are particularly significant and will exert upward price pressure in the early 2020’s. 

Moreover, the underlying high price scenarios assume that global shale development will be 

lagging. The lagging of global shale development helps keep natural gas pegged to oil prices 

(abroad) which, in turn, provides support to the US LNG export industry. Figure 7.10

summarizes prices at the Henry Hub benchmark and Figure 7.11 summarizes the accompanying 

electricity prices for the forecasts developed around the high gas price projection. 

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Sept 28, 2012 OFPC Jun 29, 2012 OFPC Hard Cap High Expert

Hard Cap

High Expert Low Expert
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.10 – Henry Hub Natural Gas Prices Derived from the High Underlying Forecast

Figure 7.11 – Western Electricity Prices from the High Underlying Gas Price Forecast

Price Projections Tied to the Medium Forecast

The underlying September 2012 medium gas price forecast is also PacifiCorp’s OFPC and, as 

such, is composed of market forwards for the first 72 months, followed by 12 months of blended 

prices which transition into an expert third-party fundamentals forecast, starting in month 85. 

The expert third-party fundamentals forecast component was issued May 2012. The market 

portion of the forecast is based upon forwards as of market close September 28, 2012. 

The medium gas scenario reflects a strong, but tempered, long-term demand for natural gas 

partially offset by increasing supply volumes resulting from new shale plays, increased well 

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Cases 6,7,12,13 Case 17 Hard Cap: Case 18

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PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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productivity, and rig efficiencies. While associated gas, from wet plays, has filled a large part of 

the void left by re-directed dry gas drilling, volumes are beginning to decline. To incent new dry 

gas drilling, prices will need to rise. 

On the demand side, increased industrial loads are expected to materialize later in the decade 

from the petrochemical, fertilizer, steel, and transportation sectors. Like the high case, long-term 

demand increases are expected from the LNG export and transportation sectors however at a 

slower pace due to the lengthy approval process. Environmental restrictions on shale plays are 

expected to increase costs but not to the point of disrupting or adversely impacting supply. In 

short, the medium scenario assumes the continuance of prolific liquids plays producing 

significant amounts of price insensitive associated gas. However, going forward, quantities of 

associated gas cannot fully compensate for the lack of dry gas production. Thus, upward price 

pressure is forthcoming as decreased associated gas supply, coupled with increasing demands 

from the industrial, export, and transportation sectors, take hold later this decade. Figure 7.12

shows Henry Hub benchmark prices and Figure 7.13 includes the accompanying electricity 

prices for the forecasts developed around the medium gas price projection.

Figure 7.12– Henry Hub Natural Gas Prices Derived from the Medium Underlying 

Forecast

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Hard Cap: Case 14 Cases 1-3,10,11,15,16,19
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.13 – Western Electricity Prices from the Medium Underlying Gas Price Forecast

Price Projections Tied to the Low Forecast

The low price is driven by excess gas supply and dampened demand (arising from moderated oil 

prices). On the supply side, increasing well productivity, technological innovations, and large 

volumes of price-insensitive associated gas create a flattened supply curve. Third party providers 

have reduced low price projections as base case forecasts have fallen to reflect continued 

improvements in well productivity and the large amount of price insensitive dry gas being 

produced as a byproduct in wet gas and shale oil plays. Even today, one-third of associated dry 

gas is being flared in the Bakken oil shale fields. 

Under the low price assumptions, demand is tempered by limited natural gas use in both the 

transportation and LNG export sectors; no LNG export growth is assumed post 2020. Under this 

scenario, there is little incentive to invest in LNG export facilities or in gas-for-oil substitution in 

the transportation sector due to moderated oil prices. Moderate oil prices are attributed to the 

surge of U.S. shale liquids coming online. This is in keeping with expectations from both Exxon 

Mobile and the Energy Information Administration (EIA). Exxon Mobile’s latest outlook 

expects the U.S. to be a net energy exporter by 2025 while the EIA expects U.S. gas production 

to outpace demand by 202064. By 2030, the low price scenario assumes that over 19 million 

barrels per day (MMB/D) will be forthcoming from U. S. shale liquids, more than double that 

assumed in the high price scenario. Figure 7.14 shows Henry Hub benchmark prices and Figure 

7.15 includes the accompanying electricity prices for cases built on the low price forecast in the 

2013 IRP.65

 

64 Wall Street Journal, Exxon Find: America as Net Energy Exporter, December 11, 2012, page B1.

65 All case definitions that assume low natural gas prices also assume high CO2 price assumptions.

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PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.14– Henry Hub Natural Gas Prices from the Low Underlying Forecast

Figure 7.15 – Western Electricity Prices Derived from the Low Underlying Gas Price 

Forecast

Phase (3) Optimized Portfolio Development: No RPS Cases

For Phase 3 of the IRP modeling, System Optimizer is executed for each set of cases that 

exclude RPS requirements. These cases are completed for each of the five Energy Gateway 

scenarios, generating an optimized investment plan and associated real levelized PVRR for 2013 

through 2032. System Optimizer simulations were first completed for these cases to identify 

potential renewable resources that are cost effective on a system basis. Cost effective renewable 

resource selections are then used to inform the next two phases of the IRP modeling process, as 

discussed in more detail in the following sections of this chapter.

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Phase (4) Establishing a Renewable Resource Floor

For case definitions that include RPS assumptions, a minimum level of new renewable resources 

are needed to ensure that compliance can be achieved with specific state and/or assumed federal 

RPS requirements. This is achieved using an RPS compliance tool called the RPS Scenario 

Maker model. The RPS Scenario Maker model was introduced to the 2013 IRP modeling 

process in response to changing policy and market drivers that have effectively lowered the cost 

effectiveness of new renewable resource alternatives. These policy and market drivers are 

summarized below:

Policy makers continue to debate Federal budget deficits, and deep philosophical 

differences have thus far proven to be a barrier to budgetary compromise making the 

long-term outlook for federal tax incentives that have traditionally benefited new 

renewable resources uncertain. Absent tax incentives, the cost for renewable resources 

per unit of energy output increases. 

Policy makers have not succeeded in passing federal greenhouse gas legislation for 

consideration by the President. While the U.S. Environmental Protection Agency 

(EPA) has proposed new source performance standards to regulate greenhouse gas 

emissions from new sources, it has not established a definitive schedule to propose 

rules applicable to existing sources. With continued uncertainty in federal greenhouse 

gas policy, the advantages of zero emission generation resources are diminished as 

compared to other resource alternatives.

Over the past two years, reduced regional loads and low natural gas prices have 

contributed to reduced wholesale power prices. Reduced wholesale power prices 

lowers the energy value of generation from new renewable resources.

Given the drivers outlined above, the economic benefits of new renewable resources have 

deteriorated since the 2011 IRP was produced. In response, case definitions for the 2013 IRP 

were strategically designed to include cases that assume there are no RPS requirements to clearly 

identify whether new renewable resources are cost effective system resources or whether new 

renewable resources are needed for the sole purpose of meeting RPS requirements. To ensure 

that RPS compliance obligations are satisfied among those cases with RPS assumptions, the RPS 

Scenario Maker model was used to develop a renewable resource floor.

The RPS Scenario Maker model uses retail sales forecast inputs, state-specific targets, statespecific banked renewable energy credit (REC) balances, forecasted generation from existing 

RPS-eligible renewable resources, and cost and performance assumptions for potential new 

resources to optimize the type, timing, and location of additional renewable resources needed to 

meet future RPS compliance obligations. The RPS Scenario Maker model considers compliance 

flexibility mechanisms specific to any give RPS program including unbundled REC rules and 

banking rules that cannot be configured in the System Optimizer model to establish a least cost 

renewable resource mix that meets RPS requirements. 

There are two steps in establishing the least cost RPS resource portfolio for each case that 

includes RPS assumptions. First, any renewable resources selected by the System Optimizer 

model among those cases that do not assume RPS requirements are automatically included in the 

RPS renewable resource portfolio for the accompanying case that does include RPS assumptions. 

These resources are treated as system resources for purposes of meeting state or assumed federal
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

187

RPS requirements, whereby each state is assumed to receive their proportionate share of energy 

that can be used for state-specific RPS compliance obligations. Second, the RPS Scenario 

Maker tool, configured with constraints to meet RPS targets and to accommodate state-specific 

RPS banking provisions, is used to provide an optimized low cost renewable resource portfolio 

that achieves any remaining state or federal RPS compliance shortfall with situs assigned 

renewable generation.66

Phase (5) Optimized Portfolio Development: RPS Cases

For Phase 5 of the IRP modeling, System Optimizer is executed for each set of cases that assume 

RPS requirements must be achieved. Each of these cases is completed for each of the five 

Energy Gateway scenarios, generating an optimized investment plan and associated real 

levelized PVRR for 2013 through 2032. The System Optimizer modeling process used in this 

phase of IRP modeling is identical to the System Optimizer modeling performed in Phase 3 

(cases that exclude RPS assumptions) with the exception that a renewable resource floor that 

meets RPS compliance obligations is forced into the resource portfolio. Forcing the renewable 

resource floor into the System Optimizer resource expansion plan does not preclude the selection 

of additional renewable resources above and beyond the minimum threshold that is required to 

achieve RPS compliance. 

Phase (6) Monte Carlo Production Cost Simulation

Phase 6 of the IRP modeling entails simulation of each optimized portfolio from Phases 3 and 5 

using the PaR model in stochastic mode. The stochastic simulation produces a dispatch solution 

that accounts for chronological commitment and dispatch constraints. Three stochastic 

simulations were executed for three CO2 tax levels: zero, medium (starting at $16/ton in 2022 

and escalating to approximately $26/ton in 2032), and high (starting at approximately $14/ton 

and escalating to approximately $75/ton by 2032). All simulations used medium natural gas and 

wholesale power prices from the September 2012 OFPC as the expected gas and electricity price 

forecast values.

The PaR simulation incorporates stochastic risk in its production cost estimates by using the

Monte Carlo random sampling of five stochastic variables: loads, commodity natural gas prices, 

wholesale power prices, hydro energy availability, and thermal unit availability for new 

resources. Availability of wind generation is not modeled with stochastic parameters in the PaR 

model; however, the incremental reserve requirements associated with uncertainty and variability 

in wind generation are captured in the stochastic simulation. PacifiCorp’s wind integration study 

is included in Appendix H in Volume II of this report.

For stochastic analysis, PacifiCorp completed simulation of 37 portfolios produced by 18 core 

cases under Energy Gateway Scenario 1 and 19 core cases produced under Energy Gateway 

Scenario 2 using the PaR production cost model among three CO2 price levels to yield 111 

portfolio risk studies. The sensitivity cases developed for the 2013 IRP are informative in 

reporting the impact of isolated changes of inputs on the portfolio selection itself, and therefore, 

these cases were not studied in the PaR model.

 

66 Given the relatively small size of the California RPS compliance need and no restrictions that limit the use of 

unbundled RECs, it is assumed that California RPS compliance obligations are met with unbundled REC purchases.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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The Stochastic Model 

The stochastic model used in the PaR model is a two-factor (short-run and long-run) short-run 

mean reverting model. Variable processes assume normality or log-normality as appropriate. 

Since prices and loads are bounded on the low side by zero they tend to take on a lognormal 

shape. Thus, prices, especially, are described as having a lognormal distribution (i.e. having a 

positively skewed distribution while their loge has more of a normal distribution). Load growth is 

inherently more bounded on the upside than prices, and can therefore be modeled as having a 

normal or lognormal distribution. As such, prices and loads were treated as having a lognormal 

and normal distribution, respectively.

Separate volatility and correlation parameters are used for modeling the short-run and long-run 

factors. The short-run process defines seasonal effects on forward variables, while the long-run 

factor defines random structural effects on electricity and natural gas markets and retail load 

regions. The short-run process is designed to capture the seasonal patterns inherent in electricity 

and natural gas markets and seasonal pressures on electricity demand.

Mean reversion represents the speed at which a disturbed variable will return to its seasonal 

expectation. 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 electricity loads, the Monte Carlo draws define possible forward paths for 

electricity demand. 

Stochastic Model Parameter Estimation 

Stochastic model parameters are developed with econometric modeling techniques. The shortrun seasonal stochastic parameters are developed using a single period auto-regressive regression 

equation (commonly called an AR(1) process). The standard error of the seasonal regression 

defines the short run volatility, while the regression coefficient for the AR(1) variable defines the 

mean reversion parameter. Loads and commodity prices are mean-reverting in the short term. 

For instance, natural gas prices are expected to “hover” around a moving average within a given 

month and loads are expected to hover near seasonal norms. These built-in responses are the 

essence of mean reversion. The mean reversion rate tells how fast a forecast will revert to its 

expected mean following a shock. The short-run regression errors are correlated seasonally to 

capture inter-variable effects from informational exchanges between markets, inter-regional 

impacts from shocks to electricity demand and deviations from expected hydroelectric 

generation performance. Consistent with the last IRP, PacifiCorp did not apply the long run load 

volatility parameter in this IRP.

Long-term volatility of natural gas and electricity prices is estimated using the standard error of a 

random walk regression of historic price data, by market. The resulting parameters are then used 

in the PaR model to develop alternative price scenarios around the Company’s official forward 

price curves, by market, over the twenty-year IRP study period. The long-run regression errors 

are correlated to capture inter-variable effects from changes to expected market equilibrium for 

natural gas and electricity markets, as well as the impacts from changes in expected regional 

electricity loads.
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PacifiCorp’s econometric analysis was performed for the following stochastic variables:

Fuel prices (natural gas prices for the Company’s western and eastern control areas)

Electricity market prices for Mid-Columbia (Mid C), California – Oregon Border (COB)

Four Corners, and Palo Verde (PV) 

Electric transmission area loads (California, Idaho, Oregon, Utah, Washington and 

Wyoming regions)

Hydroelectric generation

Table 7.9 summarizes the 2013 IRP short-term load parameters, which were adopted from the 

2008 IRP, as compared to the parameters used in the 2011 IRP. The 2008 IRP parameters were 

adopted having observed unreasonably large swings in loads using the 2011 IRP data. The 

Company anticipates re-estimating its short-term load parameters for its 2015 IRP. Natural gas 

and electricity price correlations by delivery point, as shown in Table 7.10, are the same as those 

developed for the 2007 IRP.

Table 7.9 – Short Term Load Stochastic Parameter Comparison, 2013 IRP vs. 2011 IRP

Short-term Volatility Idaho Utah Washington Oregon Wyoming

Winter 2013 IRP 0.041 0.026 0.051 0.041 0.025

Spring 2013 IRP 0.051 0.028 0.038 0.032 0.022

Summer 2013 IRP 0.054 0.045 0.053 0.038 0.019

Fall 2013 IRP 0.046 0.036 0.040 0.043 0.019

Winter 2011 IRP 0.045 0.028 0.044 0.043 0.021

Spring 2011 IRP 0.038 0.037 0.043 0.044 0.017

Summer 2011 IRP 0.040 0.040 0.051 0.041 0.017

Fall 2011 IRP 0.040 0.036 0.046 0.042 0.019

Short-term Mean 

Reversion Idaho Utah Washington Oregon Wyoming

Winter 2013 IRP 0.27 0.23 0.24 0.26 0.13

Spring 2013 IRP 0.05 0.09 0.19 0.16 0.10

Summer 2013 IRP 0.08 0.14 0.23 0.28 0.08

Fall 2013 IRP 0.23 0.17 0.20 0.18 0.10

Winter 2011 IRP 0.19 0.10 0.18 0.16 0.07

Spring 2011 IRP 0.02 0.16 0.24 0.21 0.10

Summer 2011 IRP 0.02 0.10 0.24 0.20 0.07

Fall 2011 IRP 0.03 0.08 0.11 0.11 0.05
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Table 7.10 Price Correlations

Winter

Nat Gas 

- East

Four 

Corners COB

MidColumbiaPalo 

Verde

Nat Gas 

- West

Nat Gas - East 1.000 0.304 0.386 0.277 0.371 0.835 

Four Corners 0.304 1.000 0.592 0.784 0.817 0.299 

COB 0.386 0.592 1.000 0.634 0.564 0.492 

Mid-Columbia 0.277 0.784 0.634 1.000 0.811 0.312 

Palo Verde 0.371 0.817 0.564 0.811 1.000 0.364 

Nat Gas - West 0.835 0.299 0.492 0.312 0.364 1.000 

Spring

Nat Gas -

East

Four 

Corners COB

MidColumbiaPalo 

Verde

Nat Gas -

West

Nat Gas - East 1.000 0.085 0.034 (0.131) 0.105 0.281 

Four Corners 0.085 1.000 0.559 0.459 0.787 0.025 

COB 0.034 0.559 1.000 0.770 0.468 0.067 

Mid-Columbia (0.131) 0.459 0.770 1.000 0.540 (0.059)

Palo Verde 0.105 0.787 0.468 0.540 1.000 (0.035)

Nat Gas - West 0.281 0.025 0.067 (0.059) (0.035) 1.000 

Summer

Nat Gas 

- East

Four 

Corners COB

MidColumbiaPalo 

Verde

Nat Gas 

- West

Nat Gas - East 1.000 0.115 0.074 0.002 0.101 0.908 

Four Corners 0.115 1.000 0.705 0.699 0.917 0.132 

COB 0.074 0.705 1.000 0.809 0.734 0.117 

Mid-Columbia 0.002 0.699 0.809 1.000 0.696 0.013 

Palo Verde 0.101 0.917 0.734 0.696 1.000 0.126 

Nat Gas - West 0.908 0.132 0.117 0.013 0.126 1.000 

Fall

Nat Gas 

- East

Four 

Corners COB

MidColumbiaPalo 

Verde

Nat Gas 

- West

Nat Gas - East 1.000 0.156 0.233 0.142 0.182 0.795 

Four Corners 0.156 1.000 0.458 0.719 0.921 0.244 

COB 0.233 0.458 1.000 0.446 0.467 0.299 

Mid-Columbia 0.142 0.719 0.446 1.000 0.740 0.160 

Palo Verde 0.182 0.921 0.467 0.740 1.000 0.281 

Nat Gas - West 0.795 0.244 0.299 0.160 0.281 1.000 

Table 7.11 lists short term volatility and mean reversion parameters for hydro generation that 

were re-estimated for the 2013 IRP based on updated historical hydro generation data, which 

covered calendar years 2003 through 2012.
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Table 7.11 - Hydro Short Term Stochastic Parameter Comparison, 2011 IRP vs. 2013 IRP 

Short-term

Volatility

Short-term

Mean Reversion

2013 IRP 0.130 0.100

Winter 2011 IRP 0.0826 0.2901

Spring 2011 IRP 0.0739 0.2072

Summer 2011 IRP 0.0744 0.2263

Fall 2011 IRP 0.0901 0.2931

For outage modeling, PacifiCorp relies on the PaR model’s Monte Carlo simulation method to 

create a distributed outage pattern for thermal resources. PacifiCorp does not estimate stochastic 

parameters for plant outages. Due to the true randomness of forced outages the Monte Carlo is 

the preferred mode of operation for obtaining results of multi-iteration Monte Carlo quality. 

While average historical and/or technology-specific outage rates are specified by the user the 

timing and duration of outages is random. 

Monte Carlo Simulation 

During model execution, the PaR model makes time-path-dependent Monte Carlo draws for each 

stochastic variable based on the input parameters. The Monte Carlo draws are of percentage

deviations from the expected forward value of the variables, and are the same for each Monte 

Carlo simulation. In the case of natural gas prices, electricity prices, and regional loads, the PaR 

model applies Monte Carlo draws on a daily basis. In the case of hydroelectric generation, 

Monte Carlo draws are applied on a weekly basis.

The PaR model is configured to conduct 100 Monte Carlo iterations for the 20-year study period. 

For each of the 100 Monte Carlo iterations, the PaR model generates a set of natural gas prices, 

electricity prices, loads, hydroelectric generation and thermal outages. Then, the model optimizes 

the dispatch of resources to minimize costs to serve load and wholesale sales obligations subject 

to operating and physical constraints, one of which is a fixed capacity expansion plan. The end 

result of the Monte Carlo simulation is 100 production cost iterations reflecting a wide range of 

portfolio cost outcomes.

For the 37 portfolios produced by the core case assumptions analyzed in Planning and Risk, the 

stochastic simulation utilizes medium electricity and natural gas price forecasts, regardless of the 

inputs used in the System Optimizer model to produce a given portfolio. Figures 7.16 through 

7.19 show the 100-iteration frequencies for market prices resulting from the Monte Carlo draws 

for two representative years, 2013 and 2022, and by the east and west side of PacifiCorp’s 

system. Figures 7.20 through 7.25 show annual loads by load areas and the system for the first, 

10th, 25th, 50th, 75th, 90th, and 99th percentiles. Figure 7.26 shows the 25th, 50th, and 75th

percentiles for hydroelectric generation.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.16 – Frequency of Western (Mid-Columbia) Electricity Market Prices for 2013 

and 2022

Figure 7.17 – Frequency of Eastern (Palo Verde) Electricity Market Prices, 2013 and 2022

Figure 7.18 – Frequency of Western Natural Gas Market Prices, 2013 and 2022
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Figure 7.19 – Frequency of Eastern Natural Gas Market Prices, 2013 and 2022

Figure 7.20 – Frequencies for Idaho (Goshen) Loads

Note: the drop in Idaho (Goshen) load from 2015 to 2017 is due to the expiration of a wholesale contract, under 

which PacifiCorp serves the retail load of the third party.

Figure 7.21 – Frequencies for Utah Loads

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GWh

99th 90th 75th mean 25th 10th 1st

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GWh

99th 90th 75th mean 25th 10th 1st
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Figure 7.22 – Frequencies for Washington Loads

Figure 7.23 – Frequencies for California and Oregon Loads

Figure 7.24 – Frequencies for Wyoming Loads

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GWh

99th 90th 75th mean 25th 10th 1st

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99th 90th 75th mean 25th 10th 1st
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Figure 7.25 – Frequencies for System Loads

Figure 7.26 – Hydroelectric Generation Frequency, 2013 and 2022

The expected values of the Monte Carlo simulation are the average results of all 100 iterations. 

Results from subsets of the 100 iterations are also summarized to signify particularly adverse 

cost conditions, and to derive associated cost measures as indicators of high-end portfolio risk. 

These cost measures, and others are used to assess portfolio performance, and are described in 

the next section.

Stochastic Portfolio Performance Measures 

Stochastic simulation results for the optimized portfolios are summarized and compared to 

determine which portfolios perform best according to a set of performance measures. These 

measures, grouped by category, include the following:

Cost

● Stochastic mean PVRR (Present Value of Revenue Requirement)

● Risk-adjusted mean PVRR

● 20-year customer rate impact

 55,000

 60,000

 65,000

 70,000

 75,000

 80,000

 85,000

GWh

99th 90th 75th mean 25th 10th 1st
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Risk

● Upper-tail Mean PVRR less stochastic mean PVRR

● 5

th and 95th Percentile PVRR

Supply Reliability

● Average annual Energy Not Served (ENS)

● Upper-tail ENS

In addition to these stochastic measures, PacifiCorp also considers resource diversity and the 

CO2 emissions when comparing portfolios.

The following sections describe in detail each of these performance measures as well as the fuel 

source diversity statistics.

Stochastic Mean PVRR 

The stochastic mean PVRR for each portfolio is the average of the portfolio’s net variable 

operating costs for 100 iterations of the PaR model in stochastic mode, combined with the real 

levelized capital costs and fixed costs determined by the System Optimizer model. The PVRR is 

reported in 2012 dollars.

The net variable cost from the stochastic simulations, expressed as a net present value, includes 

system costs for fuel, variable plant O&M, unit start-up, market contracts, spot market purchases 

and sales, and costs associated with making up for generation deficiencies, referred to as energy 

not served. 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 PVRR include renewable PTCs, where applicable, and 

emission externality costs, such as costs associated with CO2 emissions.

The PVRR measure captures the total resource cost for each portfolio, including externality costs 

in the form of CO2 costs. Total resource cost includes all the costs to the utility and customer for 

the variable portion of total system operations, capital requirements and fixed costs as evaluated 

in this IRP.

Risk-adjusted Mean PVRR 

Unlike a simple mean PVRR, the risk-adjusted PVRR also incorporates the expected-value cost 

of low-probability, expensive outcomes.67 This measure – risk-adjusted PVRR, for short – is 

calculated as the stochastic mean PVRR plus five percent of the 95th percentile of the variable 

production cost PVRR, excluding fixed costs. This metric expresses a low-probability portfolio 

cost outcome as a risk premium applied to the expected (or mean) PVRR based on the 100 

Monte Carlo simulations conducted for each production cost 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 trading one cost attribute for another. 

 

67 Prices are assumed to take on a lognormal distribution for stochastic Monte Carlo sampling, since they are 

bounded on the low side by zero and are theoretically unbounded on the up side, exhibiting a skewed distribution.
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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Ten-year Customer Rate Impact 

To derive the rate impact measures, the Company computes the percentage revenue requirement 

increase (annual and cumulative 10-year basis) attributable to the resource portfolio relative to a 

baseline full revenue requirements forecast. The year-on-year percentage change in revenue 

requirement is then calculated for each of the portfolios.

The IRP portfolio revenue requirement is based on the stochastic production cost results and 

capital costs reported for the portfolio by the System Optimizer model on real levelized basis and 

adjusted to nominal dollars based on the timing when new resources are selected and added to 

the portfolio, including investment in transmission resources.

While this approach provides a reasonable representation of projected total system revenue 

requirements for IRP portfolio comparison purposes, it is not intended as an accurate depiction 

of such revenue requirements for rate-making purposes. For example, the IRP revenue impacts 

assume immediate ratemaking treatment and make no distinction between current or proposed 

multi-jurisdictional allocation methodologies.

Upper-Tail Mean PVRR 

The upper-tail mean PVRR is a measure of high-end stochastic cost risk. This measure is derived 

by identifying the Monte Carlo iterations with the five highest production costs on a net present 

value basis. The portfolio’s 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 5

th and 95th percentile stochastic PVRRs are also reported. These PVRR values correspond 

to the iteration out of the 100 that represents the 5

th and 95th percentiles on the basis PVRR of 

production costs, respectively. These measures capture the extent of upper-tail (high cost) and 

lower-tail (low cost) stochastic outcomes. As described above, the 95th percentile PVRR is used 

to derive the high-end cost risk premium for the risk-adjusted PVRR measure. The 5th percentile 

PVRR is for informational purposes.

Production Cost Standard Deviation 

To capture production cost volatility risk, PacifiCorp uses the standard deviation of the 

stochastic production cost for the 100 Monte Carlo simulation iterations. The production cost is 

expressed as a net present value for the annual costs for 2013 through 2032. This measure is 

included because Oregon IRP guidelines require a stochastic measure that addresses the 

variability of costs in addition to one that measures the severity of bad outcomes.

Average and Upper-Tail Energy Not Served 

Certain iterations of a stochastic simulation will have “energy not served” or ENS.68 Energy Not 

Served is a condition where there are insufficient resources available to meet load because of 

physical constraints or market conditions. This occurs when the iteration has one or more 

stochastic variables with large random shocks that prevent the model from fully balancing the 

system for the simulated hour, such as large load shocks and simultaneous unplanned plant 

outages occur in the same iteration. Consequently, ENS, when averaged across all 100 

iterations, serves as a measure of the stochastic reliability risk for a portfolio’s resources.

 

68 Also referred to as Expected Unserved Energy, or EUE.
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For reporting of the ENS statistics, PacifiCorp calculates an average annual value for 2013 

through 2032 in gigawatt-hours, as well as the upper-tail ENS (average of the five iterations with 

the highest ENS). Only the results using the medium CO2 tax scenario are reported, as the tax 

level does not have a material influence on ENS amounts. In the current IRP, ENS is priced at 

$1,000/MWh consistent with a FERC imposed price cap.

Loss of Load Probability (LOLP)

Loss of Load Probability is a term used to describe the probability that the combinations of 

online and available energy resources cannot supply sufficient generation to serve the peak load 

during a given interval of time. 

For reporting LOLP, PacifiCorp calculates the probability of ENS events, where the magnitude 

of the ENS exceeds given threshold levels. PacifiCorp is strongly interconnected with the 

regional network; therefore, only events that occur at the time of the regional peak are the ones 

likely to have significant consequences. Of those events, small shortfalls are likely to be resolved 

with a quick (though expensive) purchase. In Appendix L in Volume II of this report, the 

proportion of iterations with ENS events in July exceeding selected threshold levels are reported 

for each optimized portfolio simulated with the PaR model. The LOLP is reported as a study 

average as well as year-by-year results for an example threshold level of 25,000 MWh. This 

threshold methodology follows the lead of the Pacific Northwest Resource Adequacy Forum, 

which reports the probability of a “significant event” occurring in 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 three resource categories as reflected in the System 

Optimizer expansion plan:

Thermal

Renewables

Demand-side management

Phase (7) Top-Performing Portfolio Selection

Initial Screening

As noted earlier, PacifiCorp conducted stochastic simulations of all core cases across two Energy 

Gateway scenarios and three CO2 tax levels. For preferred portfolio selection, the Company 

reviewed stochastic performance metrics among those core cases developed under Energy 

Gateway Scenarios 1 and 2. Transmission lines in Energy Gateway Scenario 1 have either 

already been constructed or are currently under construction. Energy Gateway Scenario 2 

includes preliminary analysis using the System Operational and Reliability Benefits Tool (SBT), 

described in Chapter 4, supports continued pursuit of Gateway Segment D. Portfolios developed 

under Energy Gateway Scenarios 3 through 5 were not analyzed as candidates for the preferred 

portfolio. Stochastic risk analysis of Energy Gateway segments included in these scenarios will 

be studied in future IRPs as the SBT, described in Chapter 4, is developed for each segment. 

One of the cost measures in the screening of portfolios is the system PVRR. In order for the 

portfolios from different Energy Gateway scenarios to be comparable, the costs of the portfolios 
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from Energy Gateway Scenario 2 are adjusted to reflect the benefits of Segment D as determined 

by the SBT that is discussed in Chapter 4.

Prior to the initial screening process, for each of the CO2 price levels, a pre-screening was 

performed to remove outlier portfolios among the 36 portfolios whose mean PVRR and upper 

tail mean PVRR were clear cost and/or risk outliers in relation to other portfolios. Figure 7.27, 

which plots the upper tail risk and stochastic mean PVRR cost of candidate portfolios, illustrates 

how a clear delineation of cost and risk variance among portfolios can be used to exclude 

extreme outliers. 

Figure 7.27 – Illustrative Pre-Screening to Remove Outliers

For the initial screening, PacifiCorp applied the following decision rule for identifying portfolios 

with the best combination of lowest mean PVRR and lowest upper-tail mean PVRR.

For each CO2 tax scenario:

Identify the portfolio with the lowest mean PVRR to establish a cost and risk threshold 

calculated as two percent of the least-cost portfolio;

Identify portfolios that fall within the threshold amount as compared to the least cost 

portfolio;

Identify portfolios that fall within the threshold amount as compared to the least risk 

portfolio, using the upper tail mean PVRR less the stochastic mean PVRR as the risk 

metric; then 

Select portfolios that fall within the least cost and least risk thresholds among any CO2

price scenario as top performing portfolios.

The mean and upper-tail portfolio cost comparisons, as well as the top-performing portfolios, are 

shown graphically with the use of scatter-plot graphs. Figure 7.28 illustrates the application of 
PACIFICORP – 2013 IRP CHAPTER 7 – MODELING APPROACH

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the decision rule for the medium CO2 tax scenario results, where the dashed red curve shows the 

demarcation separating the lowest cost least risk portfolios.

Figure 7.28 – Illustrative Stochastic Mean vs. Upper-tail Mean PVRR Scatter-plot

Final Screening

The optimal portfolios for the three CO2 cost scenarios plus the cost averaging view are 

evaluated based on the following primary criteria and measures:

Risk-adjusted PVRR

Carbon dioxide emissions

Supply reliability – average annual Energy Not Served and upper-tail mean (ENS)

Phase (8): Preliminary and Final Preferred Portfolio Selection

Selection of a preliminary preferred portfolio is based upon the Company’s assessment of the 

criteria and measures used to summarize and rank candidate portfolios in the final screening 

analysis. In this phase, portfolio rankings are reviewed while considering deliverability and the 

core case definitions used to develop candidate portfolios. The Company also evaluates resource 

diversity among candidate portfolios, looking at both capacity and energy measures.

Final selection is made after performing additional analysis, as required, on the preliminary 

preferred portfolio taking into consideration conclusions drawn from analyses performed 

throughout the modeling process. For the 2013 IRP, the Company completed additional analysis 

on an alternative RPS compliance strategy that informed final section of the preferred portfolio
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CHAPTER 8 – MODELING AND PORTFOLIO SELECTION 

RESULTS

CHAPTER HIGHLIGHTS

Top performing portfolios developed from a range of core case definitions have 

consistently utilize front office transactions (FOTs) and demand side management 

programs to meet system capacity requirements in the first ten years of the planning 

periods. 

Portfolios with extensive coal retirements and coal unit gas conversions, occurring in 

cases defined by low natural gas prices and/or high carbon dioxide prices (CO2), rely 

heavily on incremental gas resources, and are high cost and high risk as compared to 

portfolios that have no or limited coal retirements and coal unit gas conversions.

In cases that do not have extensive coal retirements and coal unit gas conversions, most 

portfolios do not include incremental natural gas fired generation within the first ten 

years of the planning period. Beyond the Lake Side 2 project, which is currently under 

construction, the preferred portfolio does not show a need for a natural gas thermal 

resource until 2024.

Cases defined without renewable portfolio standard (RPS) requirements produce 

portfolios that have limited utility-scale renewable resources, and cases defined with 

RPS requirements generally do not include incremental renewable resources beyond the 

minimum levels required achieve compliance with RPS targets. 

Inclusive of benefits calculated using the System Operational and Reliability Benefits 

Tool (SBT), top performing portfolios containing renewable resources that achieve 

compliance with RPS requirements perform better under Energy Gateway Scenario 2, 

which includes the Windstar-Populus project, when compared to portfolios developed 

under Energy Gateway Scenario 1.

PacifiCorp’s preferred portfolio includes the resources identified in the following table:
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Introduction

This chapter reports modeling and performance evaluation results for the portfolios developed with a 

broad range of input assumptions using the System Optimizer model and simulated with the Planning 

and Risk model. The preferred portfolio 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 two main sections.

Preferred Portfolio Selection – This section covers: (1) core case portfolio results, (2) stochastic 

production cost modeling results for these portfolios, (3) portfolio screening results, (4) 

evaluation of the top-performing portfolios, and (5) preferred portfolio selection.

Portfolio Sensitivity Analysis – This section covers development and a comparative analysis of 

sensitivity case portfolios to core case portfolios.

Preferred Portfolio Selection

Core Case Portfolio Results

The preferred portfolio selection process began with the development of resource portfolios using the 

System Optimizer model. There are 19 core cases under each of the Energy Gateway scenarios.69

Figures 8.1 to 8.5 represent the cumulative capacity additions by resource type for each of the core 

case portfolios and under the five Energy Gateway scenarios during the study period of 2013 to 2032. 

The detailed resource portfolio tables are included in Appendix K, along with present value of 

revenue requirement (PVRR) results. Comparison of the resource portfolios supports the following 

observations:

Through the 20 year planning period, resource portfolios have stable levels of front office 

transactions (FOTs) and demand side management (DSM) resources, indicating selection of 

these resource types are cost effective among a wide range of scenarios.

Except for those scenarios with core case assumptions that yield extensive coal unit 

retirements and gas conversions, natural gas resource additions are stable and not required 

until the latter years of the planning horizon.

Core case definitions with low natural gas prices and/or high CO2 prices produced portfolios 

with large scale early coal unit retirements and natural gas conversions that create an 

increased capacity need largely satisfied with incremental gas resource additions.

Over the 20-year planning horizon, resource selections, while not identical, are similar among 

the different Energy Gateway scenarios. The type and timing of new renewable resources 

among cases with renewable portfolio standard (RPS) assumptions are influenced by inclusion 

of Energy Gateway transmission, and are largely driven by increased access to high capacity 

 

69 Core case C-19, which assumes an alternative to Energy Gateway Segment D, was not analyzed under Energy Gateway 

Scenario 1, which does not include the Segment D project.
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factor wind resources in Wyoming with the addition of the Windstar-Populus project, which is 

included in Energy Gateway Scenarios 2 through 5.

Figure 8.1 – Total Cumulative Capacity under Energy Gateway Scenario 1, 2013 through 2032

Figure 8.2 – Total Cumulative Capacity under Energy Gateway Scenario 2, 2013 through 2032

Figure 8.3 – Total Cumulative Capacity under Energy Gateway Scenario 3, 2013 through 2032

3.0 3.4 3.2

6.2 6.2

3.2 3.2

6.2 5.8

3.5 3.5 3.2 3.2

7.1

3.0 2.8 3.2 2.7 3.4

1.2 1.3

0.3 1.2

1.2

0.3 1.2

1.2 1.2

1.8

1.3 1.0 1.9 3.5 1.3 1.9

1.7 1.8

1.6 1.6

1.6

1.8

1.5 1.5

1.7

1.8

1.6

1.8

1.5

1.6 1.7

1.8

1.7

1.8 1.5 1.3 1.5

1.4 1.4

1.4

1.2

1.5 1.3

1.3

1.3

1.4

1.2

1.0

1.5 1.5

1.2 1.0

1.4

2.7

(0.6)

(4.1) (4.1) (3.9) (3.7)

(0.6)

(3.7) (1.5) (1.5) (1.5) (2.3)

(0.4) (0.4)

(1.5) (1.5)

(0.6) (0.4)

(1.5) (1.5) (1.5) (1.5)

(1.2)

(1.5) (1.5) (1.5)

(1.4)

(1.5)

0.3 0.3 0.3

1.8 1.8

0.3 0.3

1.8 2.2

0.3

0.3

0.3 0.3

1.4

0.3 0.3

0.3

1.1

0.3

-5.0

-2.5

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2.5

5.0

7.5

10.0

12.5

15.0

C01 C02 C03 C04 C05 C06 C07 C08 C09 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 Capacity (GW)

Energy Gateway Scenario 3

Gas Renewable DSM FOTs Other Early Retirement End of Life Retirement Gas Conversion
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Figure 8.4 – Total Cumulative Capacity under Energy Gateway Scenario 4, 2013 through 2032

Figure 8.5 – Total Cumulative Capacity under Energy Gateway Scenarios 5, 2013 through 2032

Resource Selection by Resource Type

Gas Resources

All portfolios include the Lake Side 2 combined cycle combustion turbine (CCCT) generating 

plant, which is currently under construction with a 2014 in-service date.

There are no near-term gas-fired resources in cases defined with medium or high natural gas 

prices paired with medium or zero CO2 price assumptions. 

Near-term natural gas resources are included in those portfolios where extensive coal unit 

retirements and natural gas conversions take place. This includes those cases with a combination 

of low natural gas prices, high CO2 prices, and high coal costs (cases C04, C05, C08, and C09) 

and cases with U.S. hard cap CO2 price assumptions (cases C14 and C18). 

A 2017 CCCT is included in case C17, driven by an assumed market price spike that makes FOTs 

more expensive.

Gas-fired resources, added primarily in the latter half of the planning horizon among most cases, 

include both CCCTs in both 2x1 and 1x1 configurations with duct firing capability, and simple 

cycle combustion turbines (SCCTs).
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Renewable Resources

Cases that do not assume RPS assumptions are generally devoid of incremental wind resources, 

indicating that new wind resource additions are not cost effective given deteriorating policy and 

market conditions.

Cases defined with RPS requirements generally do not include incremental renewable resources 

beyond the minimum levels required to achieve compliance with RPS targets. An exception to 

this outcome is case C14, which assumed U.S. hard cap CO2 prices that improve the cost 

effectiveness of new wind generation.

Case C18, which assumes policy and market drivers favorable to renewable resource additions 

(high natural gas prices, high power prices, U.S. hard cap CO2 prices, and extension of federal tax 

credits through 2019) includes between 1,100 and 2,900 megawatts (MW) of new wind resources, 

depending upon the Energy Gateway scenarios, 450 MW of large utility scale solar photovoltaic 

(PV) resources, and 135 MW of capacity through a geothermal PPA by the end of the planning 

horizon.

Large scale utility solar PV resources located in Utah are added in cases with RPS requirements 

under Energy Gateway Scenario 1 and in all 18 cases. With the exception of case C18, wind 

resource additions displace large utility scale solar PV resources in meeting RPS obligations when 

the Windstar-Populus transmission project is included among Energy Gateway Scenarios 2 

through 5.

Geothermal resources were modeled as a power purchase agreement (PPA) in the 2013 IRP and 

are forced into C16 portfolios. 

All portfolios include approximately 15 MW of distributed solar resource additions each year 

totaling 290 MW over the 20 year planning horizon. These resources are largely driven by a Utah 

solar incentive program, currently scheduled to conclude in 2017. Through the 2017 period, it is 

assumed the program will achieve approved installation levels, and beyond 2017, these resources 

are selected by the System Optimizer model. 

Demand-side Management

Energy efficiency (Class 2 DSM) resource additions are prevalent among all portfolios and play a 

significant role in meeting projected capacity and energy needs through the planning horizon.

Energy efficiency additions occur steadily throughout the simulation period, and by 2032 range 

between approximately 1,400 MW and 1,900 MW among portfolios in each Energy Gateway 

Scenario.

70

In cases where accelerated acquisition of energy efficiency resources is assumed to be achievable 

(cases C14, C15, and C18), energy efficiency resources displace FOT resources in the near-term; 

however, over the long-term, these cases do not yield incremental energy efficiency resources as 

compared to other portfolios.

Dispatchable load control programs (Class 1 DSM) are not added to resource portfolios in Energy 

Gateway Scenario 1 until 2020 and not until 2023 in Energy Gateway Scenarios 2 through 5. In 

cases with extensive coal unit retirements and natural gas conversions, little to no Class 1 DSM 

resources are included in the resource mix. On average, among all core case portfolios, System 

Optimizer selected between 123 MW of Class 1 DSM resources by 2032.

 

70 These figures are analogous to a “nameplate” rating for thermal resources, and represent the maximum amount of load 

reduction savings expected for a given year.
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Front Office Transactions

All portfolios utilized front office transactions to fill both near-term and long-term system 

capacity needs, a consistent trend among all Energy Gateway scenarios. Figure 8.6 shows the 

annual front office transactions selected among core case portfolios under Energy Gateway 

Scenario 2. Over the first 10 years of the planning period, FOTs range between 599 MW and 

1,428 MW. In the latter half of the planning horizon, annual FOT resource selections range 

between 710 MW and 1,472 MW. Beyond 2016, selection of FOTs is highest in case C17, which 

assumes a market price spike through 2022. Prior to 2016, FOTs are highest in cases with nearterm coal unit retirements (cases C04, C05, C08 and C09).

Figure 8.6 – Front Office Transaction Addition Trends by Portfolio, EG-2

Retirements/Gas Conversion of Existing Coal-Fired Resources

All portfolios reflected the end of life retirement of Carbon Unit 1 and Unit 2 in 2015.

In addition to Carbon Unit 1 and Unit 2, asset lives of nine coal-fired facilities are assume to end 

prior to the end of this IRP’s study period.

All portfolios reflect the conversion of Naughton Unit 3 to natural gas.

Portfolio selections show that in the cases defined with medium or high natural gas prices and 

medium or low CO2 prices, there are very few occurrences of coal unit early retirements or 

natural gas conversions. This is observed whether base case or stringent case Regional Haze 

investments are assumed.

In the cases defined with high CO2 price, low gas price and high coal cost assumptions (cases 

C04, C05, C08, and C09), the majority of the existing coal-fired facilities retire early and in the 

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

MW

EG2-C01 EG2-C02 EG2-C03 EG2-C04 EG2-C05 EG2-C06 EG2-C07

EG2-C08 EG2-C09 EG2-C10 EG2-C11 EG2-C12 EG2-C13 EG2-C14

EG2-C15 EG2-C16 EG2-C17 EG2-C18 EG2-C19
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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first 10 years of the planning horizon. Among these cases, early retirement outcomes are not 

significantly different whether base case or stringent Regional Haze investments are assumed. In 

cases where U.S. hard cap CO2 price assumptions are made (cases C14 and C18) coal units retire 

early, but latter in the planning period as compared to cases C04, C05, C08, and C09.

Impact of Energy Gateway Segments

Additional segments of the Energy Gateway reduce system costs, especially for cases assuming 

RPS requirements. In these cases, access to high capacity factor Wyoming wind resources made 

possible by the addition of the Windstar-Populus transmission line in Energy Gateway Scenarios 

2 through 5, lower RPS compliance costs. 

Figures 8.7 through 8.10 show the increase in Energy Gateway transmission costs between 

different Energy Gateway Scenarios as compared to Energy Gateway Scenario 1 (red line) 

alongside changes in system PVRR costs, as calculated by System Optimizer, between like 

portfolios in different Energy Gateway Scenarios as compared to Energy Gateway Scenario 1 

(bars). Differences in portfolio costs among like cases do not include the benefits of Segment D 

as determined by the System Operational and Reliability Benefits Tool (SBT) described in 

Volume I, Chapter 4. Bars that fall below the red line indicate portfolios observed system cost 

benefits when incremental Energy Gateway transmission is added. Core cases that include RPS 

assumptions show system cost benefits with incremental transmission investment. Core case C19 

assumes there an alternative to Energy Gateway Segment D, and is not included under Energy 

Gateway Scenario 1. Consequently, case C19 is not shown in the figures below.

Figure 8.7 – PVRR Difference in System Costs between Like Portfolios in Energy Gateway 

Scenario 2 and Energy Gateway Scenario 1 (System Optimizer)

$909 $894 $913 $906 $894 $910

$422

$691 $620 $624 $604 $904 $697 $607 $628 $624 $718 $643

$0

$500

$1,000

$1,500

$2,000

$2,500

C01 C02 C03 C04 C05 C06 C07 C08 C09 C10 C11 C12 C13 C14 C15 C16 C17 C18

Change in System PVRR ($m)

Energy Gateway Scenario 2 

Increase/(Decrease) in System PVRR Without RPS Increase/(Decrease) in System PVRR With RPS

PVRR of Incremental Transmission Cost
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.8– PVRR Difference in System Costs between Like Portfolios in Energy Gateway 

Scenario 3 and Energy Gateway Scenario 1 (System Optimizer)

Figure 8.9 – PVRR Difference in System Costs between Like Portfolios in Energy Gateway 

Scenario 4 and Energy Gateway Scenario 1

Figure 8.10 – PVRR Difference in System Costs between Like Portfolios in Energy Gateway 

Scenario 5 and Energy Gateway Scenario 1

Summary of Portfolios among Core Case Themes

Reference Cases: Cases in the Reference Case Theme are characterized by base/medium 

assumptions with varying types of RPS assumptions.

– Differences among portfolios in this theme are driven by RPS policy assumptions.

$1,557 $1,499 $1,564 $1,548 $1,581 $1,561

$607

$1,356 $1,285 $1,232 $1,269 $1,525 $1,277 $1,264 $1,140 $1,280 $1,378 $1,270

$0

$500

$1,000

$1,500

$2,000

$2,500

C01 C02 C03 C04 C05 C06 C07 C08 C09 C10 C11 C12 C13 C14 C15 C16 C17 C18

Change in System PVRR ($m)

Energy Gateway Scenario 3 

Increase/(Decrease) in System PVRR Without RPS Increase/(Decrease) in System PVRR With RPS

PVRR of Incremental Transmission Cost

$1,550 $1,482 $1,540 $1,507 $1,541 $1,542

$812 $1,322 $1,258 $1,195 $1,232 $1,493 $1,310 $1,233 $1,167 $1,246 $1,348 $1,230

$0

$500

$1,000

$1,500

$2,000

$2,500

C01 C02 C03 C04 C05 C06 C07 C08 C09 C10 C11 C12 C13 C14 C15 C16 C17 C18

Change in System PVRR ($m)

Energy Gateway Scenario 4 

Increase/(Decrease) in System PVRR Without RPS Increase/(Decrease) in System PVRR With RPS

PVRR of Incremental Transmission Cost

$2,178 $2,112 $2,197 $2,161 $2,197 $2,188

$1,048

$1,993 $1,916 $1,855 $1,901 $1,893 $1,928 $1,904 $1,661 $1,918 $2,011 $1,898

$0

$500

$1,000

$1,500

$2,000

$2,500

C01 C02 C03 C04 C05 C06 C07 C08 C09 C10 C11 C12 C13 C14 C15 C16 C17 C18

Change in System PVRR ($m)

Energy Gateway Scenario 5 

Increase/(Decrease) in System PVRR Without RPS Increase/(Decrease) in System PVRR With RPS

PVRR of Incremental Transmission Cost
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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– When no RPS assumptions are made, there are very small quantities of large utility-scale 

renewable resources selected. In these cases, wind resource additions range between zero 

and 78 MW through 2032.

– When state RPS assumptions are applied, renewable resources are added at levels required 

to achieve compliance. In Energy Gateway Scenario 1, wind additions total 600 MW and 

“large scale” solar photovoltaic (PV) additions total 28 MW by 2032. Among Energy 

Gateway Scenarios 2 through five, wind resource additions range between 759 MW and 

829 MW by 2032.

– With both state and federal RPS assumptions, renewable resources are added at levels to 

achieve compliance with targets. In Energy Gateway Scenario 1, incremental wind 

resources total 803 MW and a 227 MW large scale solar PV resource is added in 2026. 

Among Energy Gateway Scenarios 2 through 5, wind resource additions range between 

858 MW and 928 MW by 2032. 

Environmental Policy Cases: Cases in the Environmental Policy Theme are characterized by 

varying combinations of commodity market prices, CO2 prices, RPS requirements, and Regional 

Haze requirements.

– The impact of RPS assumptions on renewable resource additions is similar to those 

observed among cases in the Reference Theme, whereby no to limited amounts of 

incremental renewable resources are added to the resource portfolio when RPS 

compliance obligations are removed.

– Alternative Regional Haze assumptions did not drive changes in coal unit early retirement 

and natural gas conversions.

– Incremental environmental investments in coal units are made in favor of early retirement 

and gas conversion alternatives for nearly all units and in nearly all cases where where 

medium natural gas prices are combined with medium CO2 price and medium coal cost 

assumptions, and in cases where high natural gas prices are combined with zero CO2

prices and low coal costs.

– Under cases defined by low natural gas prices combined with high CO2 prices and high 

coal costs (cases C04, C05, C08, and C09), nearly all of PacifiCorp’s existing coal-fired 

resources are retired or converted to natural gas prior to 2032.

– When U.S. hard cap CO2 prices are assumed, the resulting portfolios reflect coal 

retirements and gas conversions similar to the levels seen in cases C04, C05, C08, and 

C09.

Targeted Resource Cases: Cases in the Targeted Resource Theme are characterized by alternative 

assumptions for specific resource types to understand how they influence resource portfolio costs 

and risk.

– Case C15 assumes energy efficiency resources (Class 2 DSM) can be acquired at an 

accelerated rate and disallows selection of new CCCT generation assets. High level 

adjustments were applied to the 2012 DSM Potential study measures and ramp rates to 

allow selection of up to two percent of 2011 actual sales in each state. After discretionary 

resources are exhausted, annual Class 2 DSM opportunities decrease, with remaining 

resources from equipment upgrades and new construction. As compared to core cases 

with base Class 2 DSM resource availability, System Optimizer model selected additional 

Class 2 DSM resources earlier in the planning horizon, and as intended, this portfolio does 

not include any new CCCT resources through the 20 year planning period.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

210

– Case C16 assumes that state and federal RPS obligations must first be met with available 

geothermal power purchase agreement (PPA) resources among five sites located in 

PacifiCorp’s service territory. In this case, 145 MW of geothermal PPA resource is added 

and supplemented with additional wind resources as required to meet RPS requirements. 

With the addition of the geothermal PPA resources, the 227 MW large utility-scale solar 

PV resources added in 2026 in reference case C03 under Energy Gateway Scenario 1 is 

displaced.

– Case C17 assumes forward power prices under a high natural gas price scenario increase 

by 50 percent during on-peak hours and by 30 percent in off-peak hours. In this case, 

FOT resources are reduced, but not eliminated, and a CCCT natural gas resource is added 

to the portfolio in 2017.

– Case C18 targets a “Clean Energy Bookend” portfolio and is defined with high natural gas 

prices, high power prices, and U.S hard cap CO2 price assumptions along with extension 

of federal tax incentives for renewable resources through 2019. The resulting portfolio 

includes incremental renewable resources beyond 2019, early coal unit retirements and gas

conversions beginning 2023, a nuclear resource in 2025, and an integrated gasification 

combined cycle unit (IGCC) with carbon capture and sequestration (CCS) in 2032.

Transmission Case: The Transmission Theme includes one core case assuming that transmission 

can be purchased from a new line built by a third party as an alternative to the Company’s Energy 

Gateway Segment D project. Resource selections in this case do not vary significantly from those 

observed in reference case C03.

Carbon Dioxide Emissions

Figures 8.11 through 8.13 show annual CO2 emissions from resource portfolios under Energy 

Gateway Scenario 2 grouped by core case theme.71 All cases show emission reductions over the 20 

year planning horizon with the assumed end-of-life retirement of existing coal units. Longer-term 

addition of renewable resources among those cases with RPS assumptions and longer-term addition 

of natural gas resources, required to meet load growth and assumed end-of-life coal unit retirements, 

also contribute to lower emission levels. Portfolios showing the most dramatic CO2 emission 

reductions include those cases in the Environmental Policy and Targeted Resource Themes producing 

portfolios with extensive early coal unit retirements and gas conversions (cases C04, C05, C08, C09, 

C15, and C18).

 

71 Similar emission trends are observed among other Energy Gateway Scenarios. 
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

211

Figure 8.11 – Annual CO2 Emissions: Reference Cases

Figure 8.12 – Annual CO2 Emissions: Environmental Policy

0.0

10.0

20.0

30.0

40.0

50.0

60.0

Millions of Short Tons - CO2

EG2-C01 EG2-C02 EG2-C03

0.0

10.0

20.0

30.0

40.0

50.0

60.0

Millions of Short Tons - CO2

EG2-C04 EG2-C05 EG2-C06 EG2-C07

EG2-C08 EG2-C09 EG2-C10 EG2-C11

EG2-C12 EG2-C13 EG2-C14
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

212

Figure 8.13 – Annual CO2 Emissions: Targeted Resources

Pre-Screening Results

As described in Chapter 7, the Company tested in the Planning and Risk model (PaR) 36 core case 

portfolios from Energy Gateway Scenarios 1 and 2 with the application of stochastic Monte Carlo 

simulation of market prices, loads, thermal outages and hydro generation, across three CO2 price 

levels (zero, medium, and high). Pre-screening of portfolios was performed by producing scatter 

plots of stochastic mean and upper tail mean less stochastic mean PVRR results using data from the 

PaR simulations among each CO2 price scenario.72 The resulting scatter plots, shown in Figures 8.14 

through 8.19, were used to identify portfolios that are extreme cost and or risk outliers relative to 

other portfolios. The red dashed line depicted on each of the following figures demarcates the 

threshold used to identify outlier portfolios. Portfolios to the left and below the dashed red line are 

lower cost and lower risk and were designated as superior relative to those portfolios to the right and 

above the red dashed line.

 

72 Netting the stochastic mean PVRR from the upper tail mean PVRR is done to isolate fixed costs common to both 

metrics.

0.0

10.0

20.0

30.0

40.0

50.0

60.0

Millions of Short Tons - CO2

EG2-C15 EG2-C16 EG2-C17 EG2-C18 EG2-C19
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.14 Remove Outliers, Energy Gateway Scenario 1 with Zero CO2 Prices

Figure 8.15 Remove Outliers, Energy Gateway Scenario 1 with Medium CO2 Prices
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.16 Remove Outliers, Energy Gateway Scenario 1 with High CO2 Prices

Figure 8.17 Remove Outliers, Energy Gateway Scenario 2 with Zero CO2 Prices
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

215

Figure 8.18 Remove Outliers, Energy Gateway Scenario 2 with Medium CO2 Prices

Figure 8.19 Remove Outliers, Energy Gateway Scenario 2 with High CO2 Prices

A consistent set of portfolios among each CO2 price scenario and for each Energy Gateway scenario 

are outliers in relation to other portfolios included on the above plots. These portfolios, each 
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

216

characterized by extensive early coal unit retirements and gas conversions (cases C04, C05, C08, 

C09, C14, and C18), were removed from consideration as candidates for the preferred portfolio. As 

an additional pre-screening step, the case C19 portfolio was removed from consideration because the 

case is predicated on completion of a third party transmission project (the Zephyr DC line), which is 

not currently far enough into the development process for it to be considered for the preferred 

portfolio.73 Similarly, portfolios that cannot meet compliance with state and assumed federal RPS 

requirements were also removed from consideration. As a result, the portfolios identified in the prescreening analysis as potential preferred portfolio candidates include portfolios from cases C03, C07, 

C11, C13, C15, C16 and C17 under Energy Gateway Scenarios 1 and 2 (14 portfolios).

Initial Screening Results

With the removal of pre-screened portfolios, scatter plots of the stochastic mean PVRR and the 

stochastic mean PVRR less the upper tail mean PVRR can be viewed with finer resolution. Figures

8.20 to 8.22 show these scatter plots for the 14 portfolios identified in the pre-screening analysis 

under zero, medium and high CO2 price levels. The red line demarcates the group of portfolios

designated as superior with respect to the combination of the cost and risk metrics. The red 

demarcation line is established by calculating a cost/risk variance threshold using two percent of the 

stochastic mean PVRR of the least cost portfolio under each CO2 price scenario and applying this 

threshold to the least cost and least risk portfolios on each scatter plot. For example, under medium 

CO2 price scenario, the least cost portfolio has a stochastic mean PVRR of $31.3 billion. Two 

percent of this figure is $630 million, which is the threshold used for the medium CO2 price scenario. 

Any portfolio that is within $630 million of the lowest cost portfolio and within $630 million of the 

least risk portfolio in the medium CO2 price scenario is to the left and blow the red dashed line. The 

cost /risk threshold used in the zero and high CO2 scenarios is $550 million and $750 million, 

respectively.

 

73 The Zephyr DC line would provide no reliability benefits to PacifiCorp’s existing transmission system and may require 

additional infrastructure additions to meet reliability for the existing system. The line does not provide interconnection

for of new resources except at the termination points established if the project were constructed and does not allow for 

multiple interconnection points with the existing PacifiCorp transmission system. The proposed line with PacifiCorp 

transmission is more expensive than Energy Gateway Segment D.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.20 Stochastic mean PVRR versus Upper-tail Risk with Zero CO2 Prices

Figure 8.21 Stochastic mean PVRR versus Upper-tail Risk with Medium CO2 Prices
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

218

Figure 8.22 Stochastic mean PVRR versus Upper-tail Risk with High CO2 Prices

Portfolios that fall within the threshold identified by the red dashed line in the figures above under 

any CO2 price scenario are considered as candidates for the preferred portfolio and passed along for 

final screening. Based upon the initial screening scatter plot analysis, which shows there is very little 

separation between portfolios, the top performing portfolios using least cost/least risk metrics include 

portfolios from cases C03, C07, C11, C15, C16 and C17 under Energy Gateway Scenarios 1 and 2

(12 portfolios).

Final Screening Results

Risk-adjusted PVRR

The risk adjusted PVRR is one of the primary metrics used to rank and inform selection of the 

preferred portfolio. As described in Chapter 7, this metric combines cost and risk attributes from the 

PaR model by expressing a low probability portfolio cost outcome as a risk premium to the expected 

PVRR.74 Table 8.1 reports the risk-adjusted PVRR values and relative ranking among the 12

portfolios identified in the initial screening analysis by CO2 price scenario. Portfolios developed 

under core case C15 under Energy Gateway Scenarios 1 and 2 (EG1-C15 and EG2-C15, as depicted 

in the table below), which eliminates the possibility of new CCCT resources and assumes accelerated 

acquisition of Class 2 DSM resources, rank high on a risk adjusted PVRR basis. The portfolio 

developed under core case C07 under Energy Gateway Scenario 2 also ranks high, ranking just below 

the C15 cases in the zero and medium CO2 scenarios and ranking second, above the portfolio 

developed under case C15 from Energy Gateway Scenario 2, when high CO2 prices are assumed.

 

74 This risk adjusted PVRR is calculated as the stochastic mean PVRR plus five percent of the 95th percentile of the 

variable production cost PVRR, excluding fixed costs.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Table 8.1 Portfolio Comparison, Risk-adjusted PVRR

Cumulative Carbon Dioxide Emissions

Table 8.2 reports the average cumulative 20-year CO2 emissions (average of the 100 Monte Carlo 

iterations) for each of the 12 portfolios identified in the initial screening analysis. The EG1-C15 

portfolio has slightly lower CO2 emissions beginning 2017, but emissions are higher in longer-term 

given the absence of base load combined cycle combustion turbine resources. The difference between 

the average annual emissions in the highest ranking portfolio and the lowest ranking portfolio in the 

medium CO2 scenario is 1.3 million tons, or 3% of annual system CO2 emissions among all portfolios. 

Table 8.2 –Portfolio Comparison, Cumulative CO2 Emissions for 2013-2032

While there are differences in cumulative CO2 emissions among each of the portfolios that are used to 

rank the portfolios under each of the CO2 price scenarios, as shown in Figure 8.23, the expected 

emission levels among the 12 portfolios identified in the initial screening analysis are very similar 

over the 20 year planning period.

Risk 

Adjusted 

PVRR

($m)

Change 

from 

Lowest 

Cost 

Portfolio

($m) Rank

Risk 

Adjusted 

PVRR

($m)

Change 

from 

Lowest 

Cost 

Portfolio

($m) Rank

Risk 

Adjusted 

PVRR

($m)

Change 

from 

Lowest 

Cost 

Portfolio

($m) Rank

Risk 

Adjusted 

PVRR

($m)

Change 

from 

Lowest 

Cost 

Portfolio

($m) Rank

EG1-C03 $28,719 $306 7 $32,717 $245 4 $39,175 $179 3 $33,537 $244 5

EG1-C07 $28,894 $481 8 $32,956 $485 8 $39,476 $480 8 $33,775 $482 8

EG1-C11 $29,140 $727 11 $33,123 $651 11 $39,529 $534 9 $33,931 $637 11

EG1-C15 $28,413 $0 1 $32,471 $0 1 $38,996 $0 1 $33,293 $0 1

EG1-C16 $28,703 $290 6 $32,718 $247 5 $39,186 $191 5 $33,536 $243 4

EG1-C17 $29,146 $733 12 $33,203 $732 12 $39,694 $699 12 $34,014 $721 12

EG2-C03 $28,695 $282 5 $32,729 $257 6 $39,203 $208 6 $33,542 $249 6

EG2-C07 $28,621 $208 3 $32,679 $208 3 $39,149 $153 2 $33,483 $190 3

EG2-C11 $29,045 $632 10 $33,108 $636 9 $39,618 $622 11 $33,924 $630 9

EG2-C15 $28,494 $81 2 $32,595 $123 2 $39,186 $191 4 $33,425 $131 2

EG2-C16 $28,646 $233 4 $32,735 $263 7 $39,295 $299 7 $33,558 $265 7

EG2-C17 $29,044 $631 9 $33,120 $648 10 $39,607 $612 10 $33,924 $630 10

Case

Zero CO2 Medium CO2 High CO2 CO2 Scenario Average

Total CO2 

Emissions, 

2013-2032

(Thousand 

Tons)

Change 

from 

Lowest 

Emission 

Portfolio Rank

Total CO2 

Emissions, 

2013-2032

(Thousand 

Tons)

Change 

from 

Lowest 

Emission 

Portfolio Rank

Total CO2 

Emissions, 

2013-2032

(Thousand 

Tons)

Change 

from 

Lowest 

Emission 

Portfolio Rank

Total CO2 

Emissions, 

2013-2032

(Thousand 

Tons)

Change 

from 

Lowest 

Emission 

Portfolio Rank

EG1-C03 871,984 9,220 3 836,154 4,773 3 803,958 2,917 3 837,365 4,990 3

EG1-C07 884,725 21,962 6 845,061 13,680 6 811,879 10,838 6 847,222 14,847 6

EG1-C11 871,047 8,283 2 833,753 2,372 2 801,042 0 1 835,280 2,905 2

EG1-C15 862,764 0 1 831,381 0 1 802,982 1,940 2 832,375 0 1

EG1-C16 873,506 10,743 4 836,778 5,397 4 804,491 3,449 5 838,258 5,883 4

EG1-C17 896,136 33,372 11 857,056 25,675 11 824,668 23,626 10 859,286 26,911 11

EG2-C03 873,964 11,200 5 837,300 5,919 5 804,480 3,439 4 838,581 6,206 5

EG2-C07 884,841 22,077 7 845,998 14,616 7 813,184 12,143 7 848,008 15,632 7

EG2-C11 886,356 23,593 8 848,108 16,727 8 815,771 14,730 8 850,079 17,703 8

EG2-C15 889,384 26,621 10 855,418 24,037 10 824,930 23,889 11 856,578 24,202 10

EG2-C16 888,635 25,871 9 851,427 20,046 9 820,124 19,083 9 853,395 21,020 9

EG2-C17 897,356 34,592 12 858,353 26,972 12 825,533 24,492 12 860,414 28,039 12

Case

Zero CO2 Medium CO2 High CO2 CO2 Scenario Average
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

220

Figure 8.23 Stochastic Mean Annual CO2 Emissions with Medium CO2 Prices

Supply Reliability

Table 8.3 and Table 8.4 report two measures of stochastic supply reliability, average annual energy 

not served (ENS) and upper-tail mean ENS, for each of the 12 portfolios identified in the initial 

screening analysis. The portfolios developed under case EG1-C15 and EG2-C11 perform the best on 

these two measures, and differences among portfolios are not material between CO2 price scenarios. 

The high ranking of the portfolio developed under case EG1-C15 is largely influenced by west side 

Class 1 DSM resources that were added over the period from 2020 to 2025.

Table 8.3 – Portfolio Comparison, Stochastic Mean Energy Not Served

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

55,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Thousands Tons

EG1-C03 EG2-C03 EG1_C07 EG2_C07 EG1_C11 EG2_C11

EG1_C15 EG2_C15 EG1_C16 EG2_C16 EG1_C17 EG2_C17

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

EG1-C03 44.9 10.5 8 46.0 11.1 7 47.1 11.3 5 46.0 11.0 7

EG1-C07 56.8 22.4 11 58.8 23.8 11 61.6 25.7 11 59.0 24.0 11

EG1-C11 40.9 6.5 3 42.3 7.3 2 44.2 8.3 2 42.5 7.4 2

EG1-C15 34.4 0.0 1 35.0 0.0 1 35.8 0.0 1 35.1 0.0 1

EG1-C16 42.4 8.0 4 44.3 9.3 4 46.5 10.7 3 44.4 9.4 4

EG1-C17 61.5 27.0 12 63.6 28.6 12 66.0 30.2 12 63.7 28.6 12

EG2-C03 42.7 8.3 6 45.6 10.7 6 49.0 13.2 7 45.8 10.7 6

EG2-C07 43.2 8.8 7 46.6 11.6 8 50.7 14.9 8 46.8 11.8 8

EG2-C11 40.6 6.2 2 43.3 8.3 3 46.8 11.0 4 43.6 8.5 3

EG2-C15 51.5 17.0 9 53.6 18.7 9 55.6 19.7 9 53.5 18.5 9

EG2-C16 42.7 8.3 5 45.6 10.6 5 48.9 13.1 6 45.8 10.7 5

EG2-C17 51.7 17.3 10 55.8 20.9 10 60.8 25.0 10 56.1 21.1 10

Case

Zero CO2 Medium CO2 High CO2 CO2 Scenario Average
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

221

Table 8.4 – Portfolio Comparison, Energy Not Served - Upper Tail

Most of the differences in ENS ranking of stochastic mean are largely driven by changes in portfolios

beyond the first ten years of the IRP planning horizon. Figure 8.24 shows the annual stochastic mean 

ENS among the 12 portfolios identified in the initial screening analysis under the medium CO2 price 

scenario.

Figure 8.24 Stochastic Mean Annual ENS with Medium CO2 Prices

Preferred Portfolio Selection

Based upon the metrics reviewed in the final screening analysis, and given similarities among 

portfolios, particularly in the near-term, with regard to CO2 emissions and ENS as reported by the 

PaR model, PacifiCorp has primarily relied upon the risk adjusted net PVRR results and the 

associated portfolio rankings to inform preliminary selection of a preferred portfolio. 

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

Average 

Annual 

ENS, 2013-

2032

(GWh)

Change 

from 

Lowest 

ENS 

Portfolio Rank

EG1-C03 69.2 10.7 4 70.9 14.8 2 75.7 15.2 2 71.9 13.6 2

EG1-C07 97.9 39.4 11 104.2 48.2 11 115.6 55.1 10 105.9 47.5 11

EG1-C11 71.2 12.7 5 73.0 17.0 3 86.8 26.3 3 77.0 18.7 3

EG1-C15 58.5 0.0 1 56.1 0.0 1 60.5 0.0 1 58.4 0.0 1

EG1-C16 73.3 14.8 7 77.3 21.2 6 91.9 31.4 4 80.8 22.5 5

EG1-C17 106.0 47.5 12 105.1 49.0 12 113.8 53.3 9 108.3 49.9 12

EG2-C03 68.6 10.1 3 75.4 19.3 5 99.3 38.8 6 81.1 22.7 6

EG2-C07 77.1 18.6 8 89.3 33.3 9 118.4 57.9 11 94.9 36.6 9

EG2-C11 66.9 8.4 2 74.5 18.5 4 95.1 34.6 5 78.8 20.5 4

EG2-C15 82.3 23.8 9 86.3 30.2 8 102.4 41.9 8 90.3 32.0 8

EG2-C16 71.7 13.2 6 84.3 28.2 7 102.0 41.5 7 86.0 27.6 7

EG2-C17 82.6 24.1 10 99.2 43.1 10 133.4 72.9 12 105.1 46.7 10

Case

Zero CO2 Medium CO2 High CO2 CO2 Scenario Average

0

25

50

75

100

125

150

175

200

225

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 GWh

EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C11 EG2-C11

EG1-C15 EG2-C15 EG1-C16 EG2-C16 EG1-C17 EG2-C17
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Deliverability of Accelerated Class 2 DSM and Resource Constraints

Portfolios developed under case C15 for Energy Gateway Scenarios 1 and 2 have the highest risk 

adjusted net PVRR ranking among candidate portfolios across different CO2 price scenarios.75 

Portfolios developed under case C15 assume that acquisition of Class 2 DSM resources can be 

accelerated and was developed absent the opportunity for cost effective selection of CCCT resources. 

High level adjustments were applied to base case measure costs and ramp rates to develop the input 

assumptions required to develop this portfolio using the System Optimizer model. While the risk 

adjusted net PVRR results for the two C15 portfolios rank high in relation to other candidate 

portfolios, the Company has not chosen the C15 portfolios as the preferred portfolio for the following 

reasons:

The high level cost assumptions underlying selection of the accelerated Class 2 DSM 

resources are uncertain. The Company does not have strong evidence in support of the true 

acquisition costs.

Ramp rate assumptions underlying selection of the accelerated Class 2 DSM resources are 

untested ramp rate modifications. The Company does not have strong evidence that the 

revised ramp rate assumptions are achievable given regulatory and market factors.

The Company is reluctant to select a portfolio that was developed with the exclusion of an 

entire class of proven resource technology. It is not reasonable to consider a portfolio that on 

the outset precludes consideration of CCCT resources throughout the entire 20 year planning 

horizon.

Nonetheless, the potential benefits of acquiring Class 2 DSM early is highlighted in the C15 portfolio 

results, and specific action items have been included in the 2013 IRP Action Plan (Chapter 9) 

targeting accelerated acquisition of cost-effective Class 2 DSM resources.

Resource Diversity

Figure 8.25 summarizes the nameplate capacity of cumulative resource selection through 2022 among 

the six portfolios beyond the C15 cases that rank highest on a risk adjusted net PVRR basis. This 

figure illustrates the similarity among the top performing portfolios, identified using cost and risk 

metrics, through the first 10 years of the planning period – the timeframe most critical to influencing 

the 2013 IRP Action Plan. With reduced loads and market prices, each portfolio is dominated by 

Class 2 DSM resources and FOT resources.76 None of the portfolios include a CCCT resource over 

this period. Among these portfolios, renewable resources are added in different quantities and at 

different times for the sole purpose of meeting west side state RPS requirements. The variability in 

quantity, type, and timing of new renewable resources is dependent on whether the Windstar-Populus 

transmission project is built under the Energy Gateway Scenario 2. 

 

75 The C07 portfolio under Energy Gateway Scenario 2 outranks the C15 portfolio under Energy Gateway Scenario 2 

when high CO2 prices are assumed.

76 Among the top ranking portfolios, no Class 1 DSM resources are added in the first 10 years of the planning period.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.25 Resource Types among Top Performing Portfolios

Table 8.5 reports the generation share in each portfolio among new resources by resource category for 

2022 and 2032 for the six portfolios beyond the C15 cases that rank highest on a risk adjusted net 

PVRR basis. The resource categories reported include: thermal (including Lake Side 2), FOTs, 

renewable, and DSM programs.

Table 8.5 – Percentage Share of Generation of New Resources by Category

 

 

-500

0

500

1,000

1,500

2,000

2,500

3,000

3,500 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03 EG1-C07 EG2-C07 EG1-C16 EG2-C16 EG1-C03 EG2-C03

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Cumulative Capacity (MW)

DSM FOTs CCCT Peaking Gas Renewable Retirement Other

Thermal FOTs Renewable DSM

Combined 

Renewables/

DSM

EG1-C03 24% 21% 15% 39% 54%

EG1-C07 24% 21% 15% 39% 54%

EG1-C16 24% 20% 16% 38% 55%

EG2-C03 27% 23% 6% 42% 49%

EG2-C07 27% 23% 6% 43% 49%

EG2-C16 27% 23% 7% 43% 49%

Thermal FOTs Renewable DSM

Combined 

Renewables/

DSM

EG1-C03 26% 13% 15% 46% 60%

EG1-C07 38% 11% 14% 36% 50%

EG1-C16 26% 13% 15% 46% 61%

EG2-C03 27% 11% 16% 45% 61%

EG2-C07 35% 10% 14% 41% 55%

EG2-C16 28% 13% 17% 42% 59%

2022

2032
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Preliminary Selection

With consideration of the concerns around deliverability of Class 2 DSM resources in portfolios 

developed under case C15, portfolio C07 under Energy Gateway Scenario 2 ranks highest among the 

remaining portfolios on a risk-adjusted PVRR basis, and was selected as the preliminary preferred 

portfolio for the 2013 IRP. Selection of the portfolio developed under case C07 under Energy 

Gateway Scenario 2 is further supported by preliminary analysis using the SBT, showing net benefits 

with the addition of the Windstar-Populus project. These benefits would improve in the event the 

policy and market drivers affecting the addition of cost effective new renewables improve. The 

current SBT analysis of the Windstar-Populus project would further improve with prospective future 

additions of other Energy Gateway segments, which would increase the incremental capacity on the 

new line without any incremental cost.

Final Selection

Incremental wind resources included in the preliminary preferred portfolio prior to 2024 are included 

solely to meet the RPS compliance requirement in the state of Washington. However, there are 

potentially lower cost alternatives to meeting the Washington RPS requirement through the use of 

unbundled renewable energy credits. For this IRP, PacifiCorp performed an analysis that evaluated

the use of unbundled renewable energy credits in meeting Washington RPS compliance requirements.

This alternative Washington RPS compliance strategy was performed by first developing an 

alternative to the EG2-C07 portfolio (EG2-C07a) using the System Optimizer model that excludes 

208 MW of wind resources added to the system prior to 2024 that are used entirely for Washington 

RPS compliance.77 In developing this portfolio, the System Optimizer model replaced the 

Washington situs assigned wind generation with alternative resources. The EG2-C07a portfolio was 

then analyzed in the PaR model under the same three CO2 price assumptions used in the portfolio 

screening process described above. Figure 8.26 shows a scatter plot comparing the EG2-C07a 

portfolio to the EG2-C07 portfolio among the three different CO2 price assumptions. As shown in the 

figure, under each CO2 price scenario, EG2-C07a portfolio costs are lower and the upper tail risk 

metric is slightly higher. 

Figure 8.26 Stochastic Mean PVRR versus Upper-tail Risk with Zero CO2 Prices

 

77 The 208 MW of wind that was removed spans the period 2016 through 2023.

$3

$4

$4

$5

$5

$6

Upper Tail Mean PVRR less Stochastic Mean 

$27 $29 $31 $33 $35 $37 $39

PVRR

($ billion)

Stochastic Mean PVRR($ billion)

EG2-C07a Zero CO2 EG2-C07a Medium CO2 EG2-C07a High C02

EG2-C07 Zero CO2 EG2-C07 Medium CO2 EG2-C07 High C02
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Using the PaR simulation results, the Company calculated the difference in the stochastic mean 

PVRR and the difference in the risk-adjusted PVRR per megawatt-hour (MWh) of wind generation 

removed from the EG2-C07 portfolio. Table 8.6 shows the change in the stochastic mean PVRR 

between the two portfolios, the change in the risk-adjusted net PVRR between the two portfolios, and 

the associated first year real levelized change in system costs per megawatt-hour of wind removed. 

Results are provided for each CO2 price scenario.

Table 8.6 – Impact of Washington Situs Assigned Wind Generation Resources

Stochastic Mean PVRR Risk-Adjusted PVRR

Reduction in System 

PVRR with Removal 

of Wind ($m)

Real Levelized 

Reduction System 

PVRR per MWh of 

Wind Removed

($/MWh)

Reduction in System 

PVRR with Removal 

of Wind ($m)

Real Levelized 

Reduction System 

PVRR per MWh of 

Wind Removed

($/MWh)

Zero CO2 243 61 232 59

Medium CO2 200 51 189 48

High CO2 132 33 116 29

The stochastic mean results above demonstrate that use of unbundled renewable energy credits (REC) 

at prices at or below the range of $33/MWh to $61/MWh, depending upon the CO2 price scenario, is 

a lower cost compliance alternative to adding wind resources to the system as a means to achieve 

compliance with Washington RPS requirements. When accounting for risk, using the risk-adjusted 

PVRR metric, the range in unbundled REC prices required to achieve a lower cost compliance 

alternative to meeting Washington RPS requirements is slightly lower than the stochastic mean 

results, but still significantly higher than currently observed unbundled REC prices. The results 

above also suggest that REC prices would need to be in the range of $29/MWh to $61/MWh, 

depending upon CO2 price assumptions and risk profile, for wind resources to be cost-effective given 

current policy and market conditions. With current unbundled REC prices trading at approximately 

$1/MWh, the Company has selected portfolio EG2-C07a as the 2013 IRP preferred portfolio. Figure 

8.27 compares the change in nominal revenue requirement between the EG2-C07a and EG2-C07 

portfolios. The spike observed in 2028 is driven by the acceleration of Class 1 DSM resources by one 

year in the case where wind is removed from the EG2-C07 portfolio.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.27 Increase/(Decrease) in Annual Nominal Revenue Requirement with Wind 

Removed from the EG2-C07 Portfolio

The 2013 IRP Preferred Portfolio

Summary Reports

The following tables and figures summarize the 2013 IRP preferred portfolio:

Table 8.7 shows the nameplate capacity of resources in the preferred portfolio over the 2013 

through 2032 planning period.

Table 8.8 shows the load and resource balance inclusive of preferred portfolio resources for the 

first 10 years of the planning horizon.

Figures 8.28 and 8.29 present the capacity and energy resource mix, respectively, for 

representative years 2013 and 2022.

– In the case where the resource type for a purchased power contract is identifiable, the 

contract is included with the corresponding resource group. 

– Energy mix figures are based upon medium natural gas, power, and CO2 price 

assumptions.

– As noted in Chapter 3, the renewable energy capacity and generation reflect categorization 

by technology type and not disposition of renewable energy attributes for regulatory 

compliance requirements.

Figure 8.30 graphically shows how PacifiCorp’s capacity deficit is met through existing and IRP 

preferred portfolio resources. 

Figure 8.31 shows the contribution of energy from preferred portfolio resources to load growth 

projections from 2013 levels. 

Table 8.9 shows the amount of energy from Class 2 DSM resources by state.

 $(50)

 $(40)

 $(30)

 $(20)

 $(10)

 $-

 $10

 $20

 $30

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$ million
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Table 8.7 – PacifiCorp’s 2013 IRP Preferred Portfolio
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

228

Table 8.8 – Preferred Portfolio Capacity Load and Resource Balance (2013-2022)

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

East

Thermal 6,200 6,626 6,460 6,454 6,454 6,454 6,454 6,454 6,454 6,454

Hydroelectric 137 140 140 135 135 132 135 135 135 135

Renewable 85 85 83 83 83 83 83 83 82 80

Purchase 1,005 611 611 398 285 285 285 285 257 257

Qualifying Facilities 83 73 73 73 73 73 73 73 73 25

Sale (1,032) (732) (730) (724) (638) (638) (638) (639) (158) (158)

Non-Owned Reserves (103) (103) (138) (138) (138) (138) (138) (138) (138) (138)

Transfers 804 574 847 791 890 924 871 850 754 726

East Existing Resources 7,179 7,274 7,346 7,072 7,144 7,175 7,125 7,103 7,459 7,381

Combined heat and Power 0 0 1 3 3 3 3 4 4 6

Front Office Transactions 0 0 0 0 0 41 170 280 22 181

Gas 0 0 0 0 0 0 0 0 0 0

Wind 0 0 0 0 0 0 0 0 0 0

Solar 0 1 2 3 4 5 5 6 7 8

Other 0 0 0 0 0 0 0 0 0 0

East Planned Resources 0 1 3 6 7 4 9 178 290 3 3 195

East Total Resources 7,179 7,275 7,349 7,078 7,151 7,224 7,303 7,393 7,492 7,576

Load 6,920 7,061 7,188 6,994 7,105 7,217 7,337 7,455 7,584 7,697

Existing Resources:

Interruptible (141) (143) (155) (155) (155) (155) (155) (155) (155) (155)

DSM (379) (379) (379) (379) (379) (379) (379) (379) (379) (379)

New Resources:

Class 1 DSM 0 0 0 0 0 0 0 0 0 0

Class 2 DSM (55) (109) (160) (208) (255) (302) (350) (389) (430) (466)

East obligation 6,345 6,430 6,494 6,252 6,316 6,381 6,453 6,532 6,620 6,697

Planning Reserves (13%) 825 836 844 813 821 830 839 849 861 871

East Reserves 825 836 844 813 821 830 839 849 861 871

East Obligation + Reserves 7,170 7,266 7,338 7,065 7,137 7,211 7,292 7,381 7,481 7,568

East Position 9 9 1 1 1 3 1 4 1 3 1 1 1 2 1 1 8

East Reserve Margin 13.1% 13.1% 13.2% 13.2% 13.2% 13.2% 13.2% 13.2% 13.2% 13.1%

West

Thermal 2,524 2,524 2,524 2,520 2,503 2,503 2,503 2,503 2,503 2,500

Hydroelectric 776 751 776 782 780 780 723 726 647 650

Renewable 36 36 36 36 36 36 36 36 36 19

Purchase 482 225 231 13 13 13 2 2 2 2

Qualifying Facilities 88 99 99 89 89 89 88 89 89 89

Sale (260) (260) (160) (110) (110) (110) (110) (110) (109) (103)

Non-Owned Reserves (9) (9) (9) (9) (9) (9) (9) (9) (9) (9)

Transfers (804) (574) (848) (792) (890) (924) (872) (851) (754) (727)

West Existing Resources 2,833 2,792 2,649 2,529 2,412 2,378 2,361 2,386 2,405 2,421

Combined heat and Power 1 1 2 2 3 3 4 4 5 6

Front Office Transactions 734 800 954 1,110 1,246 1,325 1,325 1,325 1,325 1,325

Gas 0 0 0 0 0 0 0 0 0 0

Wind 0 0 0 0 0 0 0 0 0 0

Solar 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 0 0 0 0 0 0 0

West Planned Resources 735 801 956 1,112 1,249 1,328 1,329 1,329 1,330 1,331

West Total Resources 3,568 3,593 3,605 3,641 3,661 3,706 3,690 3,715 3,735 3,752

Load 3,216 3,269 3,307 3,365 3,407 3,470 3,479 3,516 3,549 3,583

Existing Resources:

Interruptible 0 0 0 0 0 0 0 0 0 0

DSM (28) (28) (28) (28) (28) (28) (28) (28) (28) (28)

New Resources:

Class 1 DSM 0 0 0 0 0 0 0 0 0 0

Class 2 DSM (26) (62) (86) (113) (139) (161) (183) (197) (217) (235)

West obligation 3,162 3,179 3,193 3,224 3,240 3,281 3,268 3,291 3,304 3,320

Planning Reserves (13%) 411 413 415 419 421 427 425 428 430 432

West Reserves 411 413 415 419 421 427 425 428 430 432

West Obligation + Reserves 3,573 3,592 3,608 3,643 3,661 3,708 3,693 3,719 3,734 3,752 West Position (5) 1 (3) (2) (0) (2) (3) (4) 1 0 West Reserve Margin 12.8% 13.0% 12.9% 12.9% 13.0% 13.0% 12.9% 12.9% 13.0% 13.0%

System

Total Resources 10,747 10,868 10,954 10,719 10,812 10,930 10,993 11,108 11,227 11,328

Obligation 9,507 9,609 9,687 9,476 9,556 9,662 9,721 9,823 9,924 10,017

Reserves 1,236 1,249 1,259 1,232 1,242 1,256 1,264 1,277 1,290 1,302

Obligation + Reserves 10,743 10,858 10,946 10,708 10,798 10,918 10,985 11,100 11,214 11,319

System Position 4 10 8 11 14 12 8 8 13 9

Reserve Margin 13.0% 13.1% 13.1% 13.1% 13.1% 13.1% 13.1% 13.1% 13.1% 13.1%
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

229

Figure 8.28 – Current and Projected PacifiCorp Resource Capacity Mix for 2013 and 2022

Coal

52.9%

Gas

20.2%

Renewable *

1.5%

Existing 

Purchases

1.7%

Class 2 DSM***

1.3%

Hydroelectric **

8.7%

Front Office 

Transactions

7.9%

CHP & Other

0.0% Class 1 DSM + 

Interruptibles

5.7%

2013 Resource Capacity Mix with Preferred Portfolio 

Resources

* Renewable resources include wind, solar and geothermal. Wind capacity is reported as the peak load contribution. 

** Hydroelectric resouces include owned, qualifying facilities and contract purchases.

*** The contribution of Class 2 DSM represents incremental acquisition of DSM resources over the planning period.

Coal

43.3%

Gas

25.3%

Renewable *

1.3%

Existing 

Purchases

0.7%

Class 2 DSM***

5.8%

Hydroelectric **

6.8%

Front Office 

Transactions

11.7%

CHP & Other

0.1%

Class 1 DSM + 

Interruptibles

4.9%

2022 Resource Capacity Mix with Preferred Portfolio 

Resources

* Renewable resources include wind, solar and geothermal. Wind capacity is reported as the peak load contribution. 

** Hydroelectric resouces include owned, qualifying facilities and contract purchases.

*** The contribution of Class 2 DSM represents incremental acquisition of DSM resources over the planning period.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

230

Figure 8.29 – Current and Projected PacifiCorp Resource Energy Mix for 2013 and 2022

Coal

65.4%

Gas

9.5%

Renewable *

9.9%

Existing 

Purchases

4.6%

Class 2 DSM***

1.4%

Hydroelectric**

7.0%

Front Office 

Transactions

2.0%

CHP & Other

0.0% Class 1 DSM + 

Interruptibles

0.2%

2013 Resource Energy Mix with Preferred Portfolio 

Resources

* Renewable resources include wind, solar and geothermal. 

** Hydroelectric resouces include owned, qualifying facilities and contract purchases.

*** The contribution of Class 2 DSM represents incremental acquisition of DSM resources over the planning period.

Coal

49.3%

Gas

24.6%

Renewable *

9.3%

Existing 

Purchases

0.5%

Class 2 DSM***

7.0%

Hydroelectric**

5.2%

Front Office 

Transactions

3.6%

CHP & Other

0.1%

Class 1 DSM + 

Interruptibles

0.2%

2022 Resource Energy Mix with Preferred Portfolio 

Resources

* Renewable resources include wind, solar and geothermal. 

** Hydroelectric resouces include owned, qualifying facilities and contract purchases.

*** The contribution of Class 2 DSM represents incremental acquisition of DSM resources over the planning period.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

231

Figure 8.30 – Addressing PacifiCorp’s Peak Capacity Deficit, 2013 through 2022

Figure 8.31 – Energy Contribution of the Preferred Portfolio Resources to Load Growth, 

PacifiCorp System (2013-2022)

8,000

9,000

10,000

11,000

12,000

13,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Megawatts

New Firm Market Purchases New - DSM + CHP + Wind + Solar **

Existing - Long Term Contracts and PPA's Lake Side II

Existing - Physical Assests and DSM *** Obligation + Reserves (includes Sales + Non-Owned Reserves) *

Existing - Physical Assets and DSM ***

Existing - Long Term Contracts and PPA's

New - DSM, CHP, and Solar **

New Firm Market Purchase

Obligation + Reserves *

* Includes 13% Planning Reserves, Sales and Non-Owned Reserves

** Solar resources peak contribution is 8 MW by 2022 and Combined Heat and Power (CHP) contributes 12 MW.

*** Includes retirements, turbine upgrades, and gas repower. DSM includes both Class 1 and 2.

2014 Lake Side 2 CCCT (under construction)
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

232

Table 8.9 – Preferred Portfolio Demand Side Management Energy (2013-2022)

Preferred Portfolio Compliance with Renewable Portfolio Standard 

Requirements

Figure 8.32 shows PacifiCorp’s forecasted RPS compliance positions for the California, 

Oregon, and Washington78 programs, along with a federal RPS program scenario79, covering the 

period 2013 through 2022 based on the preferred portfolio. Utah’s RPS goal is tied to a 2025 

compliance date, so the 2013-2022 position is not shown below. However, PacifiCorp meets the 

Utah 2025 state target of 20 percent based on eligible Utah RPS resources, and has significant 

levels of banked RECs to sustain continued future compliance. PacifiCorp anticipates utilizing 

flexible compliance mechanisms such as banking the use of unbundled RECs as allowed in each 

state.

 

78 The Washington RPS requirement is tied to January 1st of the compliance year.

79 The assumed federal RPS requirements are applied to retail sales, with a target of 4.5 percent beginning in 2018, 

7.1 percent in 2019-2020, 9.8 percent in 2021-2022, 12.4 percent in 2023-2024, and 20 percent in 2025. 

Energy Efficiency Energy (MWh) Selected by State and Year 

State 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

CA 4,850 4,980 5,500 5,450 5,560 4,680 4,450 4,300 4,730 4,890

OR 168,040 188,540 148,170 145,020 132,770 126,240 108,870 95,900 91,270 99,140

WA 38,200 36,600 36,430 36,740 36,520 30,640 30,530 28,520 28,330 28,630

UT 234,790 224,220 209,570 208,410 203,540 196,600 202,440 174,740 171,900 165,400

ID 10,690 11,090 11,470 12,010 13,540 13,060 14,560 13,770 14,350 14,740

WY 26,850 30,530 34,740 38,680 42,090 43,810 45,250 45,610 50,000 52,840

Total System 483,420 495,960 445,880 446,310 434,020 415,030 406,100 362,840 360,580 365,640

Cumulative 483,420 979,380 1,425,260 1,871,570 2,305,590 2,720,620 3,126,720 3,489,560 3,850,140 4,215,780
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

233

Figure 8.32 Annual State and Federal RPS Position Forecasts using the Preferred 

Portfolio

Preferred Portfolio Carbon Dioxide Emissions

Cumulative CO2 emissions by 2032 for the preferred portfolio under the three CO2 price

scenarios range from 819 million tons to 889 million tons. These emission quantities are 

reported by the PaR model. Regarding CO2 emission reduction trends, near-term reductions are 

driven by plant dispatch changes in response to assumed CO2 costs. In the longer term, 

accumulated addition of energy efficiency programs, renewable resources, as well as new gasfired resources that fill resource needs with assumed end-of-life coal resource retirements 

contribute to a downward trend in emission levels. Figure 8.33 illustrates the emission trends 

for the preferred portfolio through 2032 under the zero, medium and high CO2 price scenarios.

0

2,000

4,000

6,000

8,000

10,000

12,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

Oregon RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement

0

100

200

300

400

500

600

700

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

Washington RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement

0

5 0

100

150

200

250

300

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

California RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement

0

2,000

4,000

6,000

8,000

10,000

12,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 GWh

Federal RPS Compliance Outcome

Unbundled REC Surrendered Bundled Bank Surrendered

Current Year Generation Surrendered Year-end Bundled Bank Balance

Year-end Unbundled REC Bank Balance Annual Requirement
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Figure 8.33 – Carbon Dioxide Emission Trend

Sensitivity Analyses

System Optimizer Sensitivity Cases

As described in Chapter 7, sensitivity cases focus on changes to resource-specific assumptions 

and alternative load growth forecasts. PacifiCorp developed 12 sensitivity cases aligned with 

the themes used to develop core case portfolios. The sensitivity case themes cover load 

sensitivities, targeted resource sensitivities, and environmental policy sensitivities, which are 

described in Confidential Volume III of this IRP report. Sensitivity cases are variants from the 

System Optimizer portfolios developed under core case definitions. Each sensitivity case was 

completed under Energy Gateway Scenario 2. 

Figure 8.34 shows the cumulative capacity additions by resource type for each of the sensitivity 

case portfolios in 2032, the end of the 2013 IRP planning horizon. For comparison, portfolios 

from core case C03 and the preferred portfolio C07a are also included in the figure. Table 8.10 

lists the system costs from the System Optimizer model for each of the sensitivity cases, core 

case C03, and the preferred portfolio (case C07a). The detailed portfolio resource tables are 

included in Volume II, Appendix K, along with detailed System Optimizer PVRR results.
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

235

Figure 8.34– Total Cumulative Capacity of Sensitivity Cases, 2032

Table 8.10 – PVRR of Sensitivity Cases and the Comparative Core Cases

Load Sensitivities (S01, S02, and S03)

PacifiCorp conducted three System Optimizer runs for three alternative load growth scenarios: 

low load growth (case S01), high load growth (case S02), and 1-in-20 extreme system peak 

scenario (case S03). Figures 8.35 and 8.36 show how coincident peak and system load forecasts 

in these sensitivities compare to the base load forecast used to define core cases.

Case PVRR ($m)

C01 $31,237

C03 $31,584

Preferred Portfolio (C-07a) $27,347

S01 $30,656

S02 $33,129

S03 $31,978

S05 $31,237

S06 $31,485

S07 $31,603

S09 $38,996

S10 $31,586
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

236

Figure 8.35 – Sensitivity Case Coincidental Peak Load Forecasts

Figure 8.36 – Sensitivity Case Load Forecasts

Under the low load forecast sensitivity, the 2024 CCCT that is in the preferred portfolio is 

replaced with peaking gas resources added in 2025 and 2026. Similarly, a 2028 CCCT is 

replaced with a peaking resource in 2029. Under the high load forecast sensitivity, incremental 

FOTs and DSM meet higher loads through 2018 and a west side 203 MW frame peaking 

resource is added to the portfolio in 2019. Under the 1-in-20 peak load forecast scenario, FOTs 

and DSM fill higher capacity requirements through 2017. The portfolio adds a west side 197 

MW frame peaking unit in 2018 and an east side 181 MW frame peaking unit in 2020. In the 

out years (2028 and beyond), peaking units displace a 423 MW CCCT.

10,000

10,500

11,000

11,500

12,000

12,500

13,000

13,500

20132014201520162017201820192020202120222023202420252026202720282029203020312032

MW

Coincident System Peak Load

Low High 1 in 20 Base

60,000

65,000

70,000

75,000

80,000

85,000

20132014201520162017201820192020202120222023202420252026202720282029203020312032

GWh

Load Forecast

Low High 1 in 20 Base
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Extension of PTC and ITC (S05 and S06)

For this group of sensitivity cases, federal production tax credits (PTCs) and investment tax 

credits (ITCs) are extended through the end of 2019. Case S05 assumes no RPS requirements 

and case S06 assumes both state and federal RPS requirements must be met.

Absent RPS assumptions, the extension of the PTC/ITC assumption leads to 144 MW of 

Wyoming wind in in 2019 (the last year of the extension). With RPS requirements, 2019 wind 

additions total 500 MW more than in the base case. Figures 8.37 and 8.38 show the addition of 

wind resources in the two cases. Case S05 wind additions are shown alongside wind additions 

in the reference case C01 portfolio, which similarly does not include RPS assumptions.

Figure 8.37 – Cumulative Wind Additions, No RPS

Figure 8.38 – Cumulative Wind Addition, with RPS

Endogenous Selection of Resources to Meet RPS Requirements (S07)

In this case, instead of using the RPS Scenario Maker model to select renewable resources 

based on state-specific requirements, the resource selections needed to meet RPS requirements 

were modeled endogenously in the System Optimizer model.

0

200

400

600

800

1,000

2013 2015 2017 2019 2021 2023 2025 2027 2029 2031

MW

C03 S06 (Extend PTC/ITC)
PACIFICORP - 2013 IRP CHAPTER 8 – MODELING RESULTS

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Case S07 produced more renewable capacity at different times and in different locations, and 

produced system costs that are approximately $20 million higher than those from case C03. 

Because the System Optimizer model cannot capture state specific rules, none of the resources,

with the exception of the Oregon Geothermal PPA, selected in 2026 could satisfy the 

Washington requirement that resources be in the Pacific Northwest.

80 Moreover, there is no 

objective way to assign generation from resources that were added to meet a “system” RPS 

requirement back to the specific state to ensure that RPS compliance is achieved in each state.

Table 8.11 compares the renewable resources selected in case S07 with the ones selected by the 

RPS Scenario Maker model for case C03.

Table 8.11 – Renewable Resources in Case S07 and Case C03

Renewable resource selected in S07:

Renewable resource selected in C03:

2013 Business Plan Portfolio (S08)

This sensitivity case was intended to test the impact of PacifiCorp’s 2013 Business Plan 

resource portfolio in the 2013 IRP modeling environment. However, the changes and updates in 

the System Optimizer model since the 2013 Business Plan study made it difficult to enforce and 

merge the previously selected portfolio with the new model inputs. Specifically, Class 2 DSM 

resources are configured in more detail as compared to what was used to develop the 2013 

Business Plan portfolio. It is not practical to reconstruct the previous representation of DSM 

resources in a way that is compatible with the current modeling system. Consequently, 

PacifiCorp did not complete this sensitivity case for the 2013 IRP. For comparison purposes, 

categories of resources in the 2013 Business Plan resource portfolio are shown in Table 8.12.

 

80 Legislation has since been passed in Washington that removes the Pacific Northwest geographic requirement. 

However, the point remains valid, which is the System Optimizer model does not capture state-specific RPS rules 

in selecting renewable resources needed to meet RPS requirements. Resource Assigned 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Total

WY Wind (40% CF) System 0 0 0 1 74 0 0 0 0 0 539 26 0 0 9 0 0 649

UT Wind (29% CF) System 0 18 12 0 0 0 0 0 16 0 74 0 0 0 0 7 72 199

UT Utility Scale Solar System 100 0 0 0 0 0 0 0 0 0 0 0 0 0 100 0 0 200

OR Geothermal PPA System 0 0 0 0 0 0 0 0 0 0 30 0 0 0 0 0 0 30

Total 100 18 12 1 74 0 0 0 16 0 643 26 0 0 109 7 72 1078

Resource Assigned 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Total

WY Wind (40% CF) System 0 0 0 0 0 0 0 0 368 282 0 0 0 0 0 0 0 650

UT Wind (29% CF) System 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 22 22

ID Wind (29% CF) WA 73 34 33 14 0 0 45 5 0 0 0 0 0 0 0 0 0 204

Total 73 34 33 14 0 0 45 5 368 282 0 0 0 0 0 0 22 876
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Table 8.12 – 2013 Business Plan Resource Portfolio

Resurgence of Renewable Resources (S09)

This sensitivity was designed to target additional selection of renewable resources with high 

natural gas price and high CO2 price assumptions while assuming PTCs and ITCs are extended 

through 2019. As compared with sensitivity case S06, which shares the same input assumptions, 

but for the use of medium natural gas price and CO2 prices, the case S09 portfolio did not 

include additional renewable resources. 

Class 3 DSM (S10)

For this sensitivity case, 15 MW of Class 3 DSM resources were added as potential resources in 

addition to Class 1 DSM resource alternatives. Based on resource needs and economics, 10 

MW of the potential Class 3 DSM resource were selected, primarily in 2027, 2031 and 2032, 

with minimal impact on System Optimizer system costs.

Additional Analysis

Trigger Point Analysis

The Oregon Public Utility Commission (OPUC) guideline 8(c) requires the utility to identify at 

least one portfolio of resources that is substantially different from the preferred portfolio that 

can be compared on a risk and cost basis among a range of CO2 compliance scenarios. As 

discussed earlier in this chapter, there are several portfolios evaluated across a range of CO2

emission compliance scenarios that yield extensive coal unit retirements. This includes 

portfolios developed under cases C05, C09, C14 and C18. Table 8.13 below compares the 

stochastic mean and risk-adjusted PVRR of these portfolios under Energy Gateway Scenario 2 

to the preferred portfolio. 

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades 19 14 - - - - - - - - - 1 4

Gas - - 638 - - - - - - - - 638

Wind - - - - - - 100 100 100 100 - 400

Other Renewables / Solar 4 4 3 3 - - - - - - - 1 0

DSM, Class 1 - - - - - - - 1 100 - - 101

DSM, Class 2 101 86 90 95 93 90 95 97 100 104 110 960

Distributed Generation 5 5 5 5 5 5 5 5 5 5 5 5 2

Total Long Term Resources 130 109 736 104 9 8 9 5 201 202 305 210 115 2,174

Utah Capacity Purchase * 200 200 - - 200 200 200 200 200 - - 120

East - Firm Market Purchases 62 - 92 51 88 72 130 246 300 81 143 120

West - Firm Market Purchases 1,055 918 875 1,078 1,029 1,168 1,217 1,217 1,217 1,217 1,217 1,115

Firm Market Purchases 1,317 1,118 967 1,128 1,318 1,440 1,546 1,662 1,717 1,297 1,360 1,355

Study includes Naughton 3 gas conversion in 2015

FOT in resource total are 10-year averages
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Table 8.13 – Comparison of Trigger Point Portfolios to the Preferred Portfolio

Zero CO2 Medium CO2 High CO2

Core Case

Increase in 

Stochastic 

Mean PVRR 

Relative to 

the Preferred 

Portfolio

($b)

Increase in 

Risk-adjusted 

PVRR 

Relative to 

the Preferred 

Portfolio

($b)

Increase in 

Stochastic 

Mean PVRR 

Relative to 

the Preferred 

Portfolio

($b)

Increase in 

Risk-adjusted 

PVRR 

Relative to 

the Preferred 

Portfolio

($b)

Increase in 

Stochastic 

Mean PVRR 

Relative to 

the Preferred 

Portfolio

($b)

Increase in 

Risk-adjusted 

PVRR 

Relative to 

the Preferred 

Portfolio

($b)

C05 3.17 7.17 2.54 7.97 1.42 9.06

C09 4.09 8.47 3.59 9.46 2.33 10.55

C14 2.68 5.88 2.03 6.53 0.97 7.53

C18 7.04 0.83 6.48 0.50 5.51 (0.25)

In each of these cases, the resulting portfolios were developed assuming either high or U.S. hard 

cap CO2 price assumptions. Policy makers have not succeeded in passing federal greenhouse 

gas legislation for consideration by the President. While the U.S. Environmental Protection 

Agency (EPA) has proposed new source performance standards to regulate greenhouse gas 

emissions from new sources, it has not finalized those standards, nor has it established a 

schedule to promulgate rules applicable to existing sources. Concurrently, policy makers 

continue to debate Federal budget deficits, and deep philosophical differences have thus far 

proven to be a barrier to budgetary compromise. Given these considerations, the Company does 

not believe greenhouse gas policies or regulations will be mandated at the levels and on a 

schedule that contributed to the extensive level of early coal unit retirements and gas 

conversions observed in the cases summarized in the table above.

Oregon Greenhouse Gas Goals

The OPUC guideline 8(d) requires that a portfolio be constructed that meets state of Oregon 

energy policies, including state goals for reducing greenhouse emissions. Several of the 

portfolios developed in this IRP fall below the Oregon goal stated in House Bill 3543 (10 

percent below 1990 emission levels by 2020). For PacifiCorp’s system, the 1990 emission level 

was 49.88 million short tons, and 10 percent below this level is 44.89 million short tons. Table 

8.13 compares the preferred portfolio with portfolios developed for Energy Gateway Scenario 2 

that are in compliance with the emission reduction goal in Oregon. 
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Table 8.13 – Cost/Risk Comparison of Compliance Portfolios and the Preferred Portfolio, 

with Medium CO2 Prices

Stochastic Mean Upper Tail Mean Emissions in 2020

Case PVRR PVRR Thousands of Ton

EG1-C04 33,507 46,307 34,868

EG1-C05 34,035 46,056 34,695

EG1-C08 34,378 48,397 26,999

EG1-C09 35,009 48,382 26,852

EG1-C14 33,401 44,056 36,811

EG2-C04 33,554 46,234 34,955

EG2-C05 33,898 45,965 34,802

EG2-C07a 31,357 35,452 48,124

EG2-C08 34,548 48,357 27,273

EG2-C09 34,944 48,502 27,239

EG2-C14 33,384 44,013 36,934
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PACIFICORP - 2013 IRP CHAPTER 9 – ACTION PLAN

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CHAPTER 9 – ACTION PLAN

CHAPTER HIGHLIGHTS

The 2013 IRP action plan identifies steps to be taken during the next two to four 

years to implement the IRP. The preferred portfolio reflects a snapshot view of the 

future that accounts for a wide range of uncertainties, and is not intended as a 

procurement commitment.

Achieve renewable compliance with unbundled renewable energy credit purchases.

Manage the expanded Utah Solar Incentive Program to encourage the installation of 

the entire approved capacity. 

Acquire economic front office transactions or power purchase agreements as 

needed through the summer of 2017

Continue to pursue the Energy Imbalance Market activities in California and the 

Northwest Power Pool

Manage and improve the longer term natural gas hedging process and products, and 

continue to work with stakeholders.

Acquire up to 1,425 – 1,876 GWh of cost effective Class 2 energy efficiency by the 

end of 2015 and 2,034 – 3,180 GWh by the end of 2017.

Develop a pilot program in Oregon for Class 3 time-of-use program as an 

alternative approach to Class 1 irrigation load control program for managing 

irrigation load in the west. 

Continue to permit and develop the Naughton Unit 3 natural gas conversion project.

Complete the installation of the baghouse conversion and NOX burner compliance 

projects at Hunter Unit 1 as required by the end of 2014.

Complete the installation of selective catalytic reduction compliance projects at Jim 

Bridger Unit 3 and Jim Bridger Unit 4.

Evaluate alternative compliance strategies that will meet Regional Haze compliance 

obligations for Cholla Unit 4.

Establish a stakeholder group process to review the System Operational and 

Reliability Benefits Tool (SBT).

Complete the Sigurd to Red Butte 345kV transmission line according to the 

construction plan. 

Evaluate through the resource acquisition paths, the fundamentals-based shifts in 

environmental policy, enactment of regulatory policies, and different load 

trajectories.

Continue to use competitive solicitation processes and pursue opportunistic 

acquisitions identified outside of a competitive procurement process that provide 

clear economic benefits to customers.
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Introduction

PacifiCorp’s 2013 IRP action plan identifies the steps the Company will take during the next two 

to four years to implement the plan that covers the 10 year resource acquisition time frame, 

2013-2022. Associated with the action plan is an acquisition path analysis that anticipates 

potential major regulatory actions and other trigger events during the action plan time horizon 

that could materially impact resource acquisition strategies.

The resources included in the 2013 IRP preferred portfolio were used to help define the actions 

included in the action plan, focusing on the size, timing and type of resources needed to meet 

load obligations, and current and potential future state regulatory requirements. The preferred 

portfolio resource combination was determined to be the lowest cost on a risk-adjusted basis 

accounting for cost, risk, reliability, regulatory uncertainty and the long-run public interest.

The 2013 IRP action plan is based upon the latest and most accurate information available at the 

time of portfolio study. 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. 

Resource information used in the 2013 IRP, such as capital and operating costs, incorporate the 

Company’s most up to date cost information. However, it is important to recognize that the 

resources identified in the plan are proxy resources and act as a guide for resource procurement 

and not as a commitment. Resources evaluated as part of procurement initiatives may vary from 

the proxy resource identified in the plan with respect to resource type, timing, size, cost and 

location. Evaluations will be conducted at the time of acquiring any resource to justify such 

acquisition, and the evaluations will comply with then-current laws, regulatory rules and orders.

In addition to the action plan, progress on the prior action plan, and the acquisition path analysis, 

this chapter covers the following topics:

Procurement delays

IRP Action Plan linkage to the business plan

Resource Procurement Strategy 

Assessment of owning assets vs. purchasing power

Managing carbon risk for existing plants

Purpose of hedging 

The treatment of customer and investor risks for resource planning

The Integrated Resource Plan Action Plan

The 2013 IRP action plan, detailed in Table 9.1, provides the Company with a road map for 

moving forward with new resource acquisitions. 
PACIFICORP - 2013 IRP CHAPTER 9 –ACTION PLAN

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The 2013 IRP Action Plan

The 2013 IRP Action Plan identifies specific actions the Company will take over the next two to four years. Action items are based on 

the type and timing of resources in the preferred portfolio, findings from analysis completed over the course of portfolio modeling, and 

feedback received by stakeholders in the 2013 IRP process. Table 9.1 details specific 2013 IRP action items by category.

Table 9.1 – 2013 IRP Action Plan

Action 

Item 12. Renewable Resource Actions

1a.

Wind Integration

Update the wind integration study for the 2015 IRP. The updated wind integration study will consider the 

implications of an energy imbalance market along with comments and feedback from the technical review committee 

and IRP stakeholders provided during the 2012 Wind Integration Study.

1b.

Renewable Portfolio Standard Compliance

With renewable portfolio standard (RPS) compliance achieved with unbundled renewable energy credit (REC) 

purchases, the preferred portfolio does not include incremental renewable resources prior to 2024. Given that the 

REC market lacks liquidity and depth beyond one year forward, the Company will pursue unbundled REC requests 

for proposal (RFP) to meet its state RPS compliance requirements. 

– Issue at least annually, RFPs seeking then current-year or forward-year vintage unbundled RECs that will 

qualify in meeting Washington renewable portfolio standard obligations.

– Issue at least annually, RFPs seeking historical, then current-year, or forward-year vintage unbundled RECs 

that will qualify for Oregon renewable portfolio standard obligations. As part of the solicitation and bid 

evaluation process, evaluate the tradeoffs between acquiring bankable RECs early as a means to mitigate 

potentially higher cost long-term compliance alternatives.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage unbundled RECs that will 

qualify for California renewable portfolio standard obligations.

1c. Renewable Energy Credit Optimization

On a quarterly basis, issue reverse RFPs to sell RECs not required to meet state RPS compliance obligations. 

1d.

Solar

Issue an RFP in the second quarter of 2013 soliciting Oregon solar photovoltaic resources to meet the Oregon small 

solar compliance obligation (Oregon House Bill 3039). Coordinate the selection process with the Energy Trust of 

Oregon to seek 2014 project funding. Complete evaluation of proposals and select potential winning bids in the 
PACIFICORP - 2013 IRP CHAPTER 9 – ACTION PLAN

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fourth quarter of 2013. 

Issue a request for information 180 days after filing the 2013 IRP to solicit updated market information on utility scale 

solar costs and capacity factors. 

1e.

Capacity Contribution

Track and report the statistics used to calculate capacity contribution from wind resources and available solar 

information as a means of testing the validity of the peak load carrying capability (PLCC) method. 

Action 

Item 13. Distributed Generation Actions

2a.

Distributed Solar

Manage the expanded Utah Solar Incentive Program to encourage the installation of the entire approved capacity. 

Beginning in June 2014, as stipulated in the Order in Docket No. 11-035-104, the Company will file an Annual 

Report with program results, system costs, and production data. These reports will also provide an opportunity to 

evaluate and improve the program as the Company will use this opportunity to recommend changes. Interested parties 

will have an opportunity to comment on the report and any associated recommendations.

2b.

Combined Heat & Power (CHP)

Pursue opportunities for acquiring CHP resources, primarily through the Public Utilities Regulatory Policies Act

(PURPA) Qualifying Facility contracting process. For the 2013 IRP Update, complete a market analysis of CHP 

opportunities that will: (1) assess the existing, proposed, and potential generation sites on PacifiCorp’s system; (2) 

assess availability of fuel based on market information; (3) review renewable resource site information (i.e. permits, 

water availability, and incentives) using available public information; and (4) analyze indicative project economics 

based on avoided cost pricing to assist in ranking probability of development.

Action 

Item 14. Firm Market Purchase Actions

3a.

Front Office Transactions

Acquire economic front office transactions or power purchase agreements as needed through the summer of 2017. 

– Resources will be procured through multiple means, such as periodic market RFPs that seek resources less than 

five years in term, and bilateral negotiations. 

– Include in the 2013 IRP Update a summary of the progress the Company has made to acquire front office 

transactions over the 2014 to 2017 forward period.

Action 

Item 15. Flexible Resource Actions
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4a.

Energy Imbalance Market (EIM)

Continue to pursue the EIM activities with the California Independent System Operator and the Northwest Power 

Pool to further optimize existing resources resulting in reduced costs for customers.

Action 

Item 16. Hedging Actions

5a.

Natural Gas Request for Proposal

Convene a workshop for stakeholders by October 2013 to discuss potential changes to the Company’s process in 

evaluating bids for future natural gas RFPs, if any, to secure additional long-term natural gas hedging products.

Action 

Item 17. Plant Efficiency Improvement Actions

6a.

Plant Efficiency Improvements

Production efficiency studies have been conducted to satisfy requirements of the Washington I-937 Production 

Efficiency Measure that have identified categories of cost effective production efficiency opportunity.

– By the end of the first quarter of 2014, complete an assessment of the plant efficiency opportunities identified in 

the Washington I-937 studies that might be applicable to other wholly owned generation facilities.

– Prior to initiating modeling efforts for the 2015 IRP, determine a multi-state “total resource cost test” evaluation 

methodology to address regulatory recovery among states with identified capital expenditures.

– Prior to initiating modeling efforts for the 2015 IRP, present to IRP stakeholders in a public input meeting the 

Company’s recommended approach to analyzing cost effective production efficiency resources in the 2015 IRP.

Action 

Item 18. Demand Side Management (DSM) Actions
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7a.

Class 2 DSM

Acquire 1,425 – 1,876 gigawatt hours (GWh) of cost-effective Class 2 energy efficiency resources by the end of 2015 

and 2,034 – 3,180 GWh by the end of 2017. 

– Collaborate with the Energy Trust of Oregon on a pilot residential home comparison report program to be offered 

to Pacific Power customers in 2013 and 2014. At the conclusion of the pilot program and the associated impact 

evaluation, assess further expansion of the program.

– Implement an enhanced consolidated business program to increase DSM acquisition from business customers in 

all states excluding Oregon. 

 Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd quarter 2013.

 Washington base case schedule is 4th quarter 2014, with an accelerated target of 1st quarter 2014.

 Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with an accelerated target of 2nd

quarter 2014.

– Accelerate to the 2nd quarter of 2014, an evaluation of waste heat to power where generation is used to offset 

customer requirements – investigate how to integrate opportunities into the DSM portfolio. 

– Increase acquisitions from business customers through prescriptive measures by expanding the “Trade Ally 

Network”.

 Base case target in all states is 3rd quarter 2014, with an accelerated target of 4th quarter 2013

– Accelerate small-mid market business DSM acquisitions by contracting with third party administrators to facilitate 

greater acquisitions by increasing marketing, outreach, and management of comprehensive custom projects by 1st

quarter 2014. 

– Increase the reach and effectiveness of “express” or “typical” measure offerings by increasing qualifying 

measures, reviewing and realigning incentives, implementing a direct install feature for small commercial 

customers, and expanding the residential refrigerator and freezer recycling program to include commercial units.

 Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd quarter 2013.

 Washington base case schedule is 4th quarter 2014, with an accelerated target of 1st quarter 2014.

 Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with an accelerated target of 2nd

quarter 2014.

– Increase the reach of behavioral DSM programs: 

 Evaluate and expand the residential behavioral pilot.

 Utah base case schedule is 2nd quarter 2014, with an accelerated target of 4th quarter 2013.

 Accelerate commercial behavioral pilot to the end of the first quarter 2014.

 Expand residential programs system-wide pending evaluation results.

 System-wide target is 3rd quarter 2015, with an accelerated target of 3rd quarter 2014.

– Increase acquisition of residential DSM resources:
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 Implement cost effective direct install options by the end of 2013.

 Expand offering of “bundled” measure incentives by the end of 2013.

 Increase qualifying measures by the end of 2013.

 Review and realign incentives.

 Utah schedule is 1st quarter 2014

 Washington base case schedule is 2nd quarter 2014, with accelerated target of 1st quarter 2014.

 Wyoming, California, and Idaho base case schedule is 3rd quarter 2014, with an accelerated 

target of 2nd quarter 2014

– Accelerate acquisitions by expanding refrigerator and freezer recycling to incorporate retail appliance distributors 

and commercial units – 3

rd quarter 2013. 

– By the end of 2013, complete review of the impact of accelerated DSM on Oregon and the Energy Trust of 

Oregon, and re-contract in 2014 for appropriate funding as required. 

– Include in the 2013 IRP Update Class 2 DSM decrement values based upon accelerated acquisition of DSM 

resources.

– Include in the 2014 conservation potential study an analysis testing assumptions in support of accelerating 

acquisition of cost-effective Class 2 DSM resources, and apply findings from this analysis into the development of 

candidate portfolios in the 2015 IRP.
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7b.

Class 3 DSM

Develop a pilot program in Oregon for a Class 3 irrigation time-of-use program as an alternative approach to a Class 1 

irrigation load control program for managing irrigation loads in the west. The pilot program will be developed for the 

2014 irrigation season and findings will be reported in the 2015 IRP.

Action 

Item 19. Coal Resource Actions

8a.

Naughton Unit 3

Continue permitting and development efforts in support of the Naughton Unit 3 natural gas conversion project. The 

permit application requesting operation on coal through year-end 2017 is currently under review by the Wyoming 

Department of Environmental Quality, Air Quality Division.

Issue a request for proposal to procure gas transportation for the Naughton plant as required to support compliance 

with the conversion date that will be established during the permitting process.

Issue an RFP for engineering, procurement, and construction of the Naughton Unit 3 natural gas retrofit as required to 

support compliance with the conversion date that will be established during the permitting process.

8b.

Hunter Unit 1

Complete installation of the baghouse conversion and low NOX burner compliance projects at Hunter Unit 1 as 

required by the end of 2014.

8c.

Jim Bridger Units 3 and 4

Complete installation of selective catalytic reduction (SCR) compliance projects at Jim Bridger Unit 3 and Jim 

Bridger Unit 4 as required by the end of 2015 and 2016, respectively.

8d.

Cholla Unit 4

Continue to evaluate alternative compliance strategies that will meet Regional Haze compliance obligations, related to 

the U.S. Environmental Protection Agency’s Federal Implementation Plan requirements to install SCR equipment at 

Cholla Unit 4. Provide an update of the Cholla Unit 4 analysis regarding compliance alternatives in the 2013 IRP 

Update.

Action 

Item 20. Transmission Actions

9a.

System Operational and Reliability Benefits Tool (SBT)

60 days after filing the 2013 IRP, establish a stakeholder group and schedule workshops to further review the System 

Benefit Tool (SBT).

– For the 2013 IRP Update, complete additional analysis of the Energy Gateway West Segment D that evaluates 

staging implementation of Segment D by sub-segment.
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– In preparation for the 2015 IRP, continue to refine the SBT for Energy Gateway West Segment D and develop 

SBT analyses for additional Energy Gateway segments.

9b.

Energy Gateway Permitting

Continue permitting for the Energy Gateway transmission plan, with near term targets as follows:

– Segment D, E, and F, continue funding of the required federal agency permitting environmental consultant as 

actions to achieve final federal permits. 

– Segment D, E, and F, continue to support the federal permitting process by providing information and 

participating in public outreach projected through the next 2 to 4 years. 

– Segment H Cascade Crossing, complete benefits analysis in 2013.

– Segment H Boardman to Hemingway, continue to support the project under the conditions of the Boardman to 

Hemingway Transmission. Project Joint Permit Funding Agreement, projected through 2015. 

9c.

Sigurd to Red Butte 345 kilovolt Transmission Line

Complete project construction per plan.

Action 

Item 21. Planning Reserve Margin Actions

10a.

Planning Reserve Margin

Continue to evaluate in the 2015 IRP the results of a System Optimizer portfolio sensitivity analysis comparing a 

range of planning reserve margins considering both cost and reliability impacts of different levels of planning reserve 

margin assumptions. Complete for the 2015 IRP an updated planning reserve margin analysis that is shared with 

stakeholders during the public process.

Action 

Item 22. Planning and Modeling Process Improvement Actions

11a.

Modeling and Process

Within 90 days of filing the 2013 IRP, schedule an IRP workshop with stakeholders to discuss potential process 

improvements that can more efficiently achieve meaningful cost and risk analysis of resource plans in the context of 

the IRP and implement process improvements in the 2015 IRP.

11b.

Cost/Benefit Analysis of DSM Resource Alternatives

Complete a cost/benefit analysis on the level of detail used to evaluate prospective DSM resources in the IRP. The 

analysis will consider the tradeoffs between model run-time and resulting resource selections, will be shared with 

stakeholders early in the 2015 IRP public process, and will inform how prospective DSM resources will be aggregated 

in developing resource portfolios for the 2015 IRP.
PACIFICORP - 2013 IRP CHAPTER 9 –ACTION PLAN 

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Progress on Previous Action Plan Items

This section describes progress that has been made on previous active action plan items 

documented in the 2011 Integrated Resource Plan Update report filed with the state commissions 

on March 31, 2011. Many of these action items have been superseded in some form by items 

identified in the current IRP action plan.

Action Item 1: Renewable / Distributed Generation 2021-2020 

Acquire up to 800 MW of wind resources by 2020, dictated by regulatory and market 

developments such as (1) renewable/clean energy standards; (2) carbon regulations; (3) 

federal tax incentives; (4) economics; (5) natural gas price forecasts; (6) regulatory 

support for investments necessary to integrate variable energy resources (VERs); and (7) 

transmission developments. The 800 MW level is supported by consideration of 

regulatory compliance risks and public policy interest in clean energy resources. 

In the 2013 IRP, PacifiCorp will track and report the statistics used to calculate capacity 

contribution from its wind resources as a means of testing the validity of the PLCC 

method. 

Future IRP cycles will include a projection for wind acquisition with and without 

geothermal until a clearer picture emerges regarding geothermal dry hole risk. 

The Company will continue to refine the wind integration modeling approach; establish a 

technical review committee (TRC) and a schedule and project plan for the next wind 

integration study. The TRC will be formed and members identified within 30 days of the 

effective date of the IRP Order. Within 30 days of the effective date of the IRP Order, a 

schedule for the study will be established, including full opportunity for stakeholder 

involvement and progress reviews by the TRC that will allow the final study to be 

submitted with the next IRP. 

The Company identified over 100 MW of geothermal resources as part of a least-cost 

resource portfolio. Continue to refine resource potential estimates and update resource 

costs in 2011-2012 for further economic evaluation of resource opportunities. 

Continue to explicitly include geothermal projects as eligible resources in future allsource RFPs. 

Evaluate procurement of Oregon solar photovoltaic resources in 2012 via the Company’s 

solar RFP.

Acquire additional Oregon solar resource through RFPs or other means in order to meet 

the Company’s 8.7 MW compliance obligation

Work with Utah parties to investigate solar program design and deployment issues and 

opportunities in late 2011 and 2012, using the Company’s own analysis of Wasatch Front 

roof top solar potential and experience with the Oregon solar pilot program. As 

recommended in the Company’s response to comments under Docket No. 07-035-T14, 

the Company requested that the Utah Commission establish “a process in the fall of 2011 

to determine whether a continued or expanded solar program in Utah is appropriate and 

how that program might be structured.” (Rocky Mountain Power, “Re: Docket No. 07-

035-T14 – Three year assessment of the Solar Incentive Program”, December 15, 2010). 

Investigate, and pursue if cost-effective from an implementation standpoint, 

commercial/residential solar water heating programs.
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Pursue opportunities for acquiring biomass CHP resources, primarily through the PURPA 

Qualifying Facility contracting process.

Proceed with an energy storage demonstration project, subject to Utah Commission 

approval of the Company’s proposal to defer and recover expenditures through the DSM

surcharge. 

Initiate a consultant study in 2011 on incremental capacity value and ancillary service 

benefits of energy storage. 

Conduct a study of grid flexibility for accommodating variable energy resources (VER)

as part of the next IRP filing. 

Develop and refine strategies for renewable portfolio standard compliance in California 

and Washington.

PacifiCorp will expand the next IRP to include discussion of RPS compliance strategies 

and the role of REC sales and purchases. The Company will be selective in its discussion 

to avoid conflict between the IRP, RPS Implementation Plan and RPS Compliance 

Report.

Status 

The Company acquired 160 MW of renewable resources between 2010 and 2012. With the 

decrease in natural gas prices, lower power prices, lack of load and changes in the expectation 

for the extension of the federal tax incentives, incremental wind in the current preferred portfolio 

first appears in 2024 and is driven by renewable portfolio requirements. The renewable portfolio 

standard requirements will be met by purchasing renewable energy credits in the market 

consistent with the preferred portfolio and Action Item 1b in the 2013 IRP Action Plan.

Using historical wind generation data from wind resources in the PacifiCorp system, the 

Company completed a study evaluating how much wind capacity has historically been available 

during peak load conditions. This analysis has been used to update the Company’s capacity 

contribution assumptions for wind resources as summarized in Volume II, Appendix O of the 

2013 IRP. 

Case C-16 in the 2013 IRP is one of five core cases in the “Targeted Resources” theme (Cases C15 through C-18) which evaluates meeting renewable portfolio standards using available 

geothermal resources, modeled as a power purchase agreement, before using other RPS-eligible 

renewable technologies. These cases are characterized by alternative assumptions for specific 

resource types to understand how those assumptions influence resource portfolios, costs and 

stochastic risk. 

For its 2012 Wind Integration Study, PacifiCorp established a technical review committee 

(TRC). The TRC members were selected based on their experience and background in the field 

of the wind integration study and regulatory requirements. PacifiCorp held several meetings 

with the TRC to review the detailed calculations of reserve requirements to integrate wind 

resources in its balancing authority areas. The six TRC members’ biographies and the wind 

integration study’s schedule are posted on PacifiCorp’s IRP website. The TRC will provide their 

report of the wind study in early May 2013 and the Company will file the report within 30 days 

of the receiving it. 
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A Geothermal Information Request report (public version) was posted to the IRP website and 

IRP participants were notified on June 28, 2012. Geothermal resources were explicitly included 

in the All Source request for proposal (RFP) for 2016 resources, which was subsequently 

terminated. In addition, geothermal power purchases approximated based on information 

received from the 2016 All Source RFP were included as proxy resources in the supply side table

in Volume I, Chapter 6 of the 2013 IRP. 

As a result of the 2010S request for proposals, the Company acquired the Black Cap Solar 

Facility which is located on 20 acres a few miles west of Lakeview, Oregon. Ideally situated on 

the sunny side of the Cascade Range, the two-megawatt facility is equipped with a sophisticated 

tracking system that optimizes the sun’s power. Lakeview is in Oregon’s High Desert and sits at 

an elevation of 4,800 feet. The valley opens to the south and enjoys more than 300 days of 

sunshine a year. Black Cap started generating electricity for customers in October 2012 and will 

produce approximately 4,500 megawatt-hours of electricity each year – comparable to the energy 

needed to serve 400 average homes annually. The Company will apply the experience gained 

through the project in its next request for proposals.

A request for proposals will be issued in the second quarter of 2013 to acquire further Oregon 

solar resources as identified in the 2103 IRP Action Item 1d. 

On October 1, 2012, the Utah Public Service Commission approved a large expansion of the 

Utah Solar Incentive Program in Docket 11-03-104. The program will incentivize the installation 

of 60 MW of distributed solar generation in systems sized one MW and below over the next five 

years. The program began accepting applications on January 15, 2013. 

The final Cadmus memo provided to the public on October 31, 2012 provides updated supply 

curves for commercial/residential solar water heating programs which were used in the 2013 

IRP.

The Company continues to pursue resources through PURPA Qualifying Facility contracting 

process. The 2013 IRP Action item 2b will assess the opportunities and provide a market 

analysis for acquiring biomass CHP resources in the 2013 IRP Update. 

The energy storage demonstration project progressed to the point of testing the five kilowatthour electrostatic generator at moderated speed in a partially integrated prototype. At this speed 

the actual resonances encountered closely matched theoretical models. By the end of 2012 the 

prototype was being transported to a higher speed spin pit to test the output voltages produced in 

generation mode. The energy storage demonstration development and demonstrated report was 

sent to the public in May 2012. Due to lack of supplier funding, in 2013 this project is no longer

being pursued by PacifiCorp. 

A consultant study was initiated in 2011 on incremental capacity value and ancillary service 

benefits of energy storage. HDR Engineering (HDR) was retained by PacifiCorp to perform an 

Energy Storage Study to evaluate a portfolio of energy storage options. The scope of the study 

was to develop a current catalog of commercially available and emerging large, utility-scale and 

distribution scale energy storage technologies as well as define respective applications,

performance characteristics and estimated capital and operating costs for each technology. The 
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results are documented in the December 2011 report that was sent to the public on September 4, 

2012. The report can be found at the following website:

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl

an/2013IRP/Report_Energy-Storage-Screening-Study2012.pdf

A study was completed for a needs assessment of PacifiCorp’s flexible resources to meet its 

reserve requirements, which is in Volume II, Appendix F.

In this IRP, the development and refinement for RPS compliance in California and Washington 

and the RPS compliance strategies and the role of REC sales and purchases are outlined in 

Volume I, Chapters 3, 7, and 8. This action item has been superseded by Action Item 1b in Table 

9.1.

Action Item 2: Intermediate/ Base-load Thermal Supply-side Resources 2014-

2016

Acquire a combined-cycle combustion turbine (CCCT) resource at the Lake Side site in 

Utah by the summer of 2014; the plant is proposed to be constructed by CH2M Hill 

E&C, Inc. (“CH2M Hill”) under the terms of an engineering, procurement, and 

construction (EPC) contract. This resource corresponds to the 2014 CCCT proxy resource 

included in the 2011 IRP preferred portfolio.

PacifiCorp will reexamine the timing and type of post-2014 gas resources and other 

resource changes as part of the 2011 business planning process and preparation of the 

2011 IRP Update. The reexamination will include documentation of capital cost and 

operating cost tradeoffs between resource types.

Consider siting additional gas-fired resources in locations other than Utah. Investigate 

resource availability issues including water availability, permitting, transmission 

constraints, access to natural gas, and potential impacts of elevation. 

Issue an all-source RFP in early 2012 for potential acquisition of 

peaking/intermediate/baseload resources by the summer of 2016 to fill any remaining 

resource need indicated by an updated load and resource balance reflecting the results of 

DSM request for proposals, acquisition of front office transactions, reserve margin 

sensitivity analysis, and other relevant information.

Status 

Lake Side 2 project remains on schedule and is within budgeted costs to meet an online date of 

June 2014. The All Source RFP was issued in January 2012 for a 2016 resources. However, the 

RFP was later terminated. The need for post-2014 gas resource(s) is delayed until 2024 based on 

a needs assessment study that PacifiCorp completed as part of the justification in the termination 

of the All Source RFP in September 2012. The timing of this resource is consistent with the 2013 

IRP preferred portfolio. A cost comparison of different gas resources was thus unnecessary due 

to lack of resource need. 
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Action Item 3: Firm Market Purchases 2011-2020

Acquire economic front office transactions or power purchase agreements as needed 

through summer 2016. Resources will be procured through multiple means, such as 

periodic mini-RFPs that seek resources less than five years in term, and bilateral 

negotiations. 

Closely monitor the near-term and long-term need for front office transactions and adjust 

planned acquisitions as appropriate based on market conditions, resource costs, and load 

expectations. Actively search for market options that could cost-effectively defer 

acquisition or construction of a 2016 CCCT resource.

Status 

A market RFP was issued in March 2012 which resulted in the acquisition of 125 MW for 2013, 

100 MW for 2014, 100 MW for 2015 and 100 MW for 2016 on the east side of the system. Due 

to the change in the load forecast and reduced resource needs from the needs assessment in the 

All Source RFP process, no additional front office transactions or power purchases were 

acquired through the summer of 2016. This action item has been superseded by Action Item 3a

in Table 9.1.

Action Item 4: Plant Efficiency Improvements 2011-2020

Continue to pursue economic plant upgrade projects—such as turbine system 

improvements and retrofits—and unit availability improvements to lower operating costs 

and help meet the Company’s future CO2 and other environmental compliance 

requirements.

Successfully complete the dense-pack coal plant turbine upgrade projects scheduled for 

2011 and 2012, totaling 33 MW, subject to economics. The 2012 10-year plan includes 

13.8 MW capacity increase in 2013.

Seek to meet the Company’s updated aggregate coal plant net heat rate improvement goal 

of 478 British thermal unit per kilowatt-hour (Btu/kWh) by 2019. (PacifiCorp Energy 

Heat Rate Improvement Plan, April 2010).

Continue to monitor turbine and other equipment technologies for cost-effective upgrade 

opportunities tied to future plant maintenance schedules. 

For the next IRP complete a study of cost-effective and reliable production efficiency 

opportunities at generating facilities (station load reduction opportunities not currently 

being captured in the IRP) where the Company has sole ownership of the facility. The 

resource opportunities identified will be modeled against competing demand and supplyside resources in the next IRP. Those selected will be targeted for completion by 2015 

provided plant outages are not required.

Status 

An ongoing effort to identify promising new potential plant/unit improvement opportunities has 

been completed through the normal course of business. The effort includes the identification and 

reporting of heat rate improvement opportunities and future project plans. Along with monitoring 

turbine and other equipment technologies as above, this item will now also be tracking the 

aggregate coal plant net heat rate improvement goals. This action item will continue annually. 
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The identified projects will be documented within the annual Heat Rate Improvement Plan, or 

HRIP, and will be posted on the IRP website. The HRIP report includes a 10 year forecast of 

major projects intended to modify the unit design heat rate of the Company’s coal fired plants. 

This action item has been superseded by Action Item 6a in Table 9.1.

Action Item 5: Class 1 DSM 2011-2020

Acquire at least 140 MW of incremental cost-effective DSM resource by 2013 and up to 

250 MW by 2015.

Finalize an agreement for the commercial curtailment product (which includes customerowned standby generation opportunities). If cost effective, the company will file for 

approval by the 3rd quarter of 2012.

Complete an analysis of the economic feasibility of Class 1 irrigation load control in the 

west by the second quarter of 2012. If the analysis suggests Class 1 irrigation load 

control is economic in the west, the Company will source delivery of a program through a 

request for proposals concurrent with the re-sourcing of Class 1 irrigation load control 

program delivery in the east by the third quarter of 2012.

Issue a request for proposal in 2012 to re-procure the delivery of the Cool Keeper 

program following the 2013 control season. For the request for proposal, the Company 

will seek market approaches acceptable to Utah regulators to expand the program beyond 

its current level beginning in 2014.

Status

There were no incremental Class 1 DSM resources added in 2011 or 2012 as a result of the 

Company’s revised load forecast and deferral of need for a 2016 resource. The Company 

canceled the commercial curtailment product due to the revised/lowered load forecast that also 

contributed to the cancelation of the All Source Request for Proposals. 

The Company completed an analysis of the feasibility and costs of west-side Class 1 irrigation 

control and collected costs through a 2012 request for proposal. Despite finding the resource 

reasonably viable, it was not selected as an economic resource in the first ten years of the 2013 

IRP preferred portfolio (see action item 7b). 

An RFP was issued in January 2013 to re-procure the delivery of Utah’s Cool Keeper air 

conditioner load management program. Provisions in the RFP will allow for program expansion 

as conditions warrant. 

Action Item 6: Class 2 DSM 2011-2020

Apply the 2011 IRP conservation analysis as the basis for the Company’s next 

Washington I-937 conservation target setting submittal to the Washington Utilities and 

Transportation Commission for the 2012-2013 biennium. The Company may refine the 

conservation analysis and update the conservation forecast and biennial target as 

appropriate prior to submittal based on final avoided cost decrement analysis and other 

new information.
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Acquire at least 900 MW and up to 1,800 MW of cost-effective Class 2 programs by

2020, equivalent to at least 4,533 GWh and up to 9,066 GWh. Acquire at least 520 MW 

and up to 1000 MW of cost-effective Class 2 DSM by 2016.

 Adjusted to reflect 2011 IRP’s initial MW contribution from Class 2 resources 

expected to be acquired in Oregon (reduces the MW contribution from Oregon 

from 562 MWs by 2020 to 283 MWs, a 279 MW reduction) 

By 1st quarter of 2012 file a residential home residential home comparison report 

program in Utah and Washington, and investigate broader applications by the end of 

2014 that can be implemented by 2016.

By 3rd quarter 2012 the Company will submit for commission approval a plan to acquire 

energy efficiency resources from the Company’s Special Contract customers in Utah and 

Idaho that can be reliably verified and delivered by 2016, and will pursue those resources 

provided the Commissions in those states approve a cost-recovery mechanism for the 

plan.

By 1st quarter 2012 issue a system-wide RFP (excluding Oregon) for specific direct 

install and other direct distribution programs targeting savings from the residential and 

small commercial sectors that can be delivered beginning in 2013. The Company will 

seek to acquire all cost-effective resources that are available from the request for 

proposal. The cost effectiveness analysis will consider any adverse impact on the 

existing DSM programs. The results of the RFP will be known prior to the Company 

seeking acknowledgement of the final short list for the all-source RFP. The Company 

will promptly file for commission approvals to implement the cost-effective programs.

For the next IRP, prior to beginning modeling and screening of DSM, and as part of the 

public input process, provide an analysis of alternatives to the current supply curve 

bundling and ramping methods for modeling energy efficiency measures.

By the end of 2012 provide an analysis of the sufficiency of current staffing levels to 

achieve programmatic cost effective energy efficiency targets established in this plan.

Leverage the distribution energy efficiency analysis of 19 distribution feeders in 

Washington (conducted for PacifiCorp by Commonwealth Associates, Inc.) for analysis 

of potential distribution energy efficiency in other areas of PacifiCorp’s system provided 

the Company receives approval by the appropriate Commission for recovery of the study 

cost through the demand-side customer efficiency surcharge. (The Washington 

distribution energy efficiency study final report was completed December 26, 2011.) 

-- Include in the 2013 IRP a detailed plan and schedule to implement cost-effective 

Conservation Voltage Reduction (CVR) in each state as approved by the state.

By the end of 2013 perform a high-level screening of the remaining 60 percent of its 

distribution circuits in each of the states to identify circuits where cost-effective energy 

savings appear viable and detailed circuit study is warranted provided the Company 

receives approval by the appropriate state commission for recovery of the study cost 

through the demand-side customer efficiency surcharge.

In the 2013 IRP include the results of the CVR evaluation to date.

Status

The Company filed its Washington Initiative 937 10 year conservative forecast and 2012-2013 

biennial targets with the Washington Utilities and Transportation Commission on January 31. 

2012. 
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The Company exceeded its 2011 and 2012 Class 2 DSM acquisition goals by 242,438 megawatthours (MWh) (29 percent), achieving 1,087,747 MWh against the goal amount of 845,036 MWh. 

The Company proposed offering residential home comparison report programs in Utah and 

Washington in April, 2012, and after regulatory discussions implemented the report program in 

August, 2012. 

In addition, the Company is actively working with the Energy Trust of Oregon on a pilot 

program to be offered to PacifiCorp customers in 2013 and 2014. The acquisition of energy 

efficiency resources from special contract customers was discussed with the Utah DSM Advisory 

Steering Group in 2013. The steering group recommended the issue be a subject of the next 

contract negotiations with the special contract customers. 

The Company issued a system-wide RFP (excluding Oregon) for specific direct install and other 

direct distribution programs targeting savings from residential and small commercial sectors in 

March, 2012. Full processing of the RFP proposals was put on “hold” following the Company’s 

revised load forecast and cancellation of 2012 All Source RFP pending the results of the 2013 

IRP. The Company intends to complete the processing of the proposal’s received for 

implementation in fourth quarter of 2013. 

As part of the modeling and screening of the DSM the Company has disaggregated and narrowed 

price bundles. Documentation on ramping and supply curve methods was provided to 

stakeholders. A review of staffing levels to achieve programmatic cost effective energy 

efficiency targets in the 2013 IRP has been completed. Volume II, Appendix D (Demand-Side 

Management and Supplemental Resources) provides the Energy Efficiency ramp rates, the DSM 

potential study and other demand side management studies. 

Prior to the end of 2012 no approval had been provided by the major states to conduct detailed 

analysis for CVR. The high level screening has been completed. The 2013 IRP details for the 

implantation of CVR projects in Washington have been provided based on the results of Tier 1 

and 2 studies. This action item has been superseded by Action Item 7a in Table 9.1. 

Action Item 7: Class 3 DSM 2011-2020

During 2012 update the Conservation Potential Assessment to more accurately reflect 

Class 1 and 3 DSM resource opportunities in regards to 1) market and regulatory 

capabilities and climates in each state, 2) interactions within and between Class 1 and 

Class 3 resource potentials identified, and 3) the impact of existing Class 3 programs on 

product potential.

During 2012 have a third-party consultant review and prepare a report on how other 

utilities treat price-responsive products in their resource planning process (for example, 

as an adjustment to their load forecast and/or as a firm planning resource), and prepare a 

recommendation on how the Company might apply contributions from price products to 

help defer investments in other resource options cost-effectively.

For the 2013 IRP provide a sensitivity analysis, similar to portfolio development Case 31 

in the 2011 IRP, that more accurately reflects incremental Class 3 product opportunities 
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(incremental to Class 1 products, other Class 3 products, and to existing impacts of Class 

3 products the Company is already running). 

Implement in Utah and Washington (subject to regulatory approvals) residential 

information pilots to test the effects of providing customers greater amounts of usage 

information on the quantity of electricity they consume. The pilots will leverage the 

existing Automatic Meter Reading (AMR) metering currently available in these states. 

Pilots will consist of three test groups each receiving varying levels of usage information:

o Group 1 – Home comparison reports and energy conservation suggestions.

o Group 2 – Daily usage data through Home Energy Monitoring software (key 

component to pricing products)

o Group 3 – Home comparison reports, energy savings suggestions, and daily usage 

data through Home Energy Monitoring software 

Pilots will be implemented in 2012, run throughout 2013, and an analysis and 

recommendations prepared in 2014, prior to the development of the 2015 IRP. 

If the analysis of Class 1 irrigation load control in the west (see action item 5) indicates 

that such programs are non-economic, investigate, through a pilot program in Oregon a 

Class 3 irrigation time-of-use program as an alternative approach for managing irrigation 

loads in the west.

Status

The 2012 Conservation Potential Assessment work was expanded to provide a greater 

assessment of opportunities, interactions and impacts of Class 1 and 3 program potentials, 

including the impacts of the Company’s existing Class 3 products. The report also undertook an 

assessment of how other utilities treat demand response resources in their integrated resource 

planning processes. This assessment was distributed to stakeholders in September 2012. The 

2012 Conservation Potential Assessment is included in Appendix D. A memo summarizing 

Cadmus findings regarding treatment of price responsive projects by 23 other utilities in their 

IRPs was distributed to PacifiCorp IRP public stakeholders in September. Cadmus key findings 

included the following: 

1) Like PacifiCorp, most utilities surveyed (13 of the 23) account for existing timeof use (TOU) program impacts directly in their load forecast. Only PacifiCorp and 

two Missouri utilities directly complete incremental price-responsive programs 

opportunities with other resources options in IRP models. 

2) Five of the 23 utilities surveyed did not account for incremental TOU programs in 

their IRPs at all, due to no expected program growth or limited participation 

programs that are too small to warrant load adjustments.

3) Only PacifiCorp and two other utilities delineate program impacts from event 

driven pricing programs (e.g., critical peak pricing and demand bidding). 

Sensitivity case S-10 in the 2013 IRP provides an analysis that reflects incremental Class 3 

products (incremental to Class 1, other Class 3 products, and to existing impacts of Class 3 

products the Company is already running). 
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The implementation of residential information pilots in conjunction with the Home Energy 

Report programs in Utah and Washington were deemed to be too small to return statistically 

relevant results and expanding group size was determined cost prohibitive for the value of the 

information to be obtained. Based on other utility experiences with Home Energy Report 

programs (and their supporting program evaluations), its believed information on varying levels 

of information on customer behavior and savings can be obtained through running variations of 

the existing Group 1 program (standard Home Energy Report program) and from learning’s from 

the impact the evaluations of other utility programs running such variations. 

Because the Oregon Class 1 irrigation load control in the west was not selected as economic in 

the first ten years of the 2013 IRP preferred portfolio, the Company will investigate through an 

Oregon Class 3 irrigation time of use pilot program as an alternative for managing irrigation 

loads in the west – See Action Item 7b in Table 9.1. 

Action Item 8: Planning Process Improvements Process Improvement 

Incorporate plug-in electric vehicles and Smart Grid technologies as a discussion topic 

for the next IRP.

Status

A presentation and question and answer session on PacifiCorp’s Smart Grid evaluation and 

implementation efforts was given to the IRP public stakeholder meeting in December 2012. This 

action item has been superseded by Action Item 11a in Table 9.1.

Action Item 9: Coal Resource Actions

The Company will host a technical workshop for stakeholders and the [Oregon] 

commissioners on February 17, 2012, respectively, for stakeholders that have a 

confidentiality agreement in place. At the technical workshop, the Company will review 

with stakeholders the methodology, assumptions and recently completed analysis of 

upcoming Naughton Unit 3 emission control investments. The Naughton Unit 3 analysis 

will be provided to stakeholders, subject to confidentiality agreements, as soon as 

practicable. At the technical workshop, the Company will present the methodology, 

assumptions and results of a Coal Replacement Study screening analysis performed for 

Jim Bridger 3, Jim Bridger 4, and Hunter 1 at a minimum. The Company will complete 

the analysis on as many other units as possible within the time constraints. The Company 

will also present information pertaining to planned investments in the Craig and Hayden 

facilities of which the Company has ownership share but does not have operational 

responsibilities. The screening analysis will be performed using a spreadsheet model that 

assumes a gas-fired CCCT, scaled to the size of the coal unit being analyzed, replaces the 

coal unit in 2015. The screening analysis will include line-item results showing annual 

capital costs and fixed and variable operating costs for each coal unit and the replacement 

CCCT resource. The screening analysis will be performed on three different market 

scenarios pairing varying levels of natural gas prices and CO2 costs. At least one 

scenario will include a low gas/high CO2 pairing. The screening analysis will report a 

rank order of the nominal levelized net PVRR benefit/cost on a per kW-month basis for 

each scenario. The Company will make available to stakeholders that have signed 
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appropriate confidentiality agreements the assumptions and results of the screening Study 

five business days before the technical workshop.

The Company will include in its 2011 IRP update an updated Coal Replacement Study 

focusing on those units analyzed in the screening analysis as described above. The 

updated Coal Replacement Study will be performed using the System Optimizer model 

and will explore a range of natural gas prices and CO2 costs in varying combinations. The 

updated Coal Replacement Study will discuss and evaluate flexibility in the emerging 

environmental regulations and the associated economics that may present options to the 

Company to avoid early compliance costs by offering to shut down certain individual 

units prior to the end of their currently approved depreciable lives. In the updated Study, 

the Company will provide a concise explanation and transparent example of its treatment 

of post-2030 costs and will provide an analysis that shows the results of treatments of 

environmental investments made prior to 2015 both avoidable and unavoidable. 

Status 

A confidential workshop was held with stakeholders and a commission workshop was held in 

February 2012 in Salem. Confidential material was distributed in February 2012 to stakeholders 

that are signatories under the appropriate protective order. The Screening analysis was completed 

for all units (Naughton Unit 3 was excluded pending completion of updated Naughton Unit 3 

Certificate of Public Convenience and Necessity analysis) and the results were reviewed in a 

February 2012 workshop. Gas-fired CCCT characteristics were reported in the screening model. 

Four market scenarios were modeled:

Base gas/base CO2 price

Low gas/no CO2 price

Base gas/high CO2 price

Low gas/high CO2 price

The information was provided as part of a “Summary Results” worksheet in the screening model. 

Screening model results were provided to stakeholders in February 2012. Confidential and 

redacted versions of the Coal Replacement Study were included with the 2011 IRP Update report 

submitted to the state commissions on March 30, 2012. The Company has analyzed in the 2013 

IRP environmental investments required to meet known and prospective compliance obligations 

across PacifiCorp’s existing coal fleet. Supported by analyses performed as part of the 2013 IRP 

and analyses performed in recent regulatory filings, the Company plans to convert Naughton 

Unit 3 to a natural gas-fired facility and to install environmental investments required to meet 

near term compliance obligations at the Hunter Unit 1, Jim Bridger Unit 3, and Jim Bridger Unit 

4 generating units. Installation of emission control equipment at these facilities will reduce 

emissions of nitrous oxides (NOX) and sulfur dioxide (SO2) and contribute to improved visibility 

in the region. The Company plans to continue to evaluate environmental investments required to 

meet known and prospective environmental compliance obligations at existing coal units in 

future IRPs and future IRP Updates. 

Building upon modeling techniques developed in the 2011 IRP and 2011 IRP Update, 

environmental investments required to achieve compliance with known and prospective 

regulations at existing coal resources have been integrated into the portfolio modeling process in 
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the 2013 IRP. Potential alternatives to environmental investments associated with known and 

prospective compliance obligations tied to Regional Haze rules, Mercury and Air Toxics 

Standards (MATS), regulation of coal combustion residuals (CCR), and regulation of cooling 

water intakes are considered in the development of all resource portfolios developed for the 2013 

IRP. Integrating potential environmental investment decisions into the portfolio development 

process allows each portfolio to reflect potential early retirement and resource replacement 

and/or natural gas conversion as alternatives to incremental environmental investment projects 

on a unit-by-unit basis. In addition to integrating coal unit environmental investment decisions 

into the portfolio development process, the Company has completed detailed financial analysis 

of near-term investment decisions in Confidential Volume III of the 2013 IRP. This action item 

has been superseded by Action Item 8a through 8d in Table 9.1.

Action Item 10: Transmission 

In the scenario definition phase of the IRP process, the Company will address with 

stakeholders the inclusion of any transmission projects on a case-by-case basis.

Develop an evaluation process and criteria for evaluating transmission additions and

review with stakeholders which transmission projects should be included and why.

Based on the outcome of these steps, PacifiCorp will provide appropriate transmission 

segment analysis for which the Company requests acknowledgement (including Wallula

to McNary and Sigurd to Red Butte).

Status 

As part of the 2013 IRP the Company has incorporated five separate Energy Gateway scenarios 

which were run for each of the core cases. The Company has developed an evaluation tool, 

System Operational and Reliability Benefits Tool (SBT), to evaluate transmission additions. The 

SBT identifies, measures, and monetizes benefits that are incremental to those identified in the 

resource portfolio modeling process. Analysis using the SBT supports investment in the Sigurd 

to Red Butte transmission project and preliminary application of the SBT to the Windstar to 

Populus transmission project supports continued permitting of Energy Gateway Segment D. The 

Company has reviewed the tool with stakeholders throughout the 2013 IRP process. In contrast 

to the 2011 IRP, where analysis of Energy Gateway transmission investments preceded resource 

portfolio modeling, Energy Gateway transmission investments have been integrated into the 

portfolio modeling process for the 2013 IRP. This was achieved by replicating the development 

of resource portfolios among five different Energy Gateway transmission scenarios. 

Consequently, 94 unique core case resource portfolios were produced in the 2013 IRP, nearly 

five times the number of core case portfolios developed for the 2011 IRP.

The SBT will continue to be developed and will be applied to additional Energy Gateway 

transmission projects for analysis in future IRPs. This action item has been superseded by Action 

Item 9a through 9c in Table 9.1.

Action Item 11: Planning Reserve Margin 

For the 2011 IRP Update include the results of a System Optimizer portfolio sensitivity 

analysis comparing the resource and cost impacts of a 12 percent versus 13 percent 

planning reserve margin.
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Status 

The 2011 IRP Update included a summary of a planning reserve margin analysis that presented 

the impact on resource need when the planning reserve margin is assumed to change from 13 

percent to 12 percent. Appendix I in the 2013 IRP, which was provided and discussed with 

stakeholders, was completed by Ventyx and provides the resource and cost impact of a 12 

percent vs. 13 percent planning reserve margin. This action item has been superseded by Action 

Item 10a in Table 9.1.

Acquisition Path Analysis

Resource Strategies

PacifiCorp worked with stakeholders to define 19 input scenarios, or “core cases”, which were 

applied across five different Energy Gateway transmission scenarios totaling 94 different 

variations of resource portfolios.81 The 19 different core cases were categorized into four 

different themes. The array of core case definitions, grouped by theme, provides the framework 

for a resource acquisition path analysis by evaluating how resource selections are impacted by 

shifts in policies and changes to fundamental market conditions. The four core case themes are 

summarized as follows:

(9) Reference: There are three different core cases developed for the Reference Theme. 

Each case relied upon base case assumptions for market prices, environmental policy 

inputs, energy efficiency assumptions, and load projections. RPS assumptions 

differentiate the three cases in the Reference Theme, with one case assuming no state 

or federal RPS requirements, one case assuming only state RPS requirements, and 

one case assuming both state and federal RPS requirements must be met.

(10) Environmental Policy: There are 11 different core cases developed for the 

Environmental Policy Theme. Five of the 11 cases reflect base case assumptions for 

Regional Haze requirements on existing coal units, and six of the 11 cases assume 

more stringent Regional Haze requirements. Differentiating the sets of cases with 

different Regional Haze compliance requirements are varying assumptions for market 

prices (low, medium, and high), CO2 prices (zero, medium, and high), RPS 

requirements (with and without state and federal RPS), and energy efficiency.

(11) Targeted Resources: There are four different core cases developed for the 

Targeted Resource Theme. Each of the cases is characterized by alternative 

assumptions for specific resource types to understand how these assumptions 

influence resource portfolios, costs, and risk. One of the four cases prevents CCCT 

resources to be added to the resource portfolio and assumes energy efficiency 

resources can be acquired at an accelerated rate. The second of the four cases in this 

theme assumes that geothermal power purchase agreement resources will be used to 

meet RPS requirements. The third of four cases in this theme assumes a spike in 

 

81 One of the input scenarios is applicable to four out of the five Energy Gateway transmission scenarios.
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power prices over the period 2017 through 2022 and assumes natural gas prices will 

rise above base case levels over the entirety of the planning horizon. The fourth case 

in this theme targets clean energy resources and assumes CO2 prices rise consistent 

with a federal hard cap scenario, that natural gas prices rise above those assumed in 

the base case, that federal tax incentives for renewable resources are extended 

through 2019, and that energy efficiency resources can be acquired at an accelerated 

rate.

(12) Transmission: The Transmission Theme included one core case, which assumes 

that third party transmission can be purchased from a newly built line as an 

alternative to 

Given current load expectations, portfolio modeling performed for the 2013 IRP shows the 

resource acquisition path in the preferred portfolio is robust among a wide range of policy and 

market conditions, particularly in the near-term, when FOTs and energy efficiency resources are 

consistently selected. With regard to renewable resource acquisition, the portfolio development 

modeling performed in the 2013 IRP shows that new renewable resource needs are driven by 

RPS compliance obligations, and all else equal, this result is not significantly changed if federal 

tax incentives are assumed to be extended. Beyond load, the most significant driver affecting 

resource selection in the 2013 IRP are market price and policy assumptions that trigger early coal 

unit retirements as an alternative to environmental investments required to meet known and 

emerging environmental regulations. For these reasons, the acquisition path analysis focuses on 

load trigger events, and combinations of environmental policy and market price trigger events 

that would require alternative resource acquisition strategies. For each trigger event, Table 9.2 

lists the associated planning scenario and both short-term (2013-2022) and long-term (2023-

2032) resource strategies.

Acquisition Path Decision Mechanism

The Utah Commission requires that PacifiCorp provide “[a] plan of different resource acquisition 

paths with a decision mechanism to select among and modify as the future unfolds.”82

PacifiCorp’s decision mechanism is centered on the business planning and IRP processes, which 

together constitute the decision framework for making resource investment decisions. The IRP 

models are used on a macro-level to evaluate alternative portfolios and futures as part of the IRP 

process, and then on a micro-level to evaluate the economics and system benefits of individual 

resources as part of the supply-side resource procurement and DSM target-setting/valuation 

processes. In developing the IRP action plan and path analysis, the Company considers common 

elements across multiple resource strategies (for example, base levels of each resource type 

across many least-cost portfolios optimized according to different futures), planning 

contingencies and resource flexibility, and continuous evaluation of market/regulatory 

developments and resource options. 

PacifiCorp uses the IRP and business plan to serve as decision support tools for senior 

management to determine the most prudent resource acquisition paths for maintaining system 

 

82 Public Service Commission of Utah, In the Matter of Analysis of an Integrated Resource Plan for PacifiCorp, 

Report and Order, Docket No. 90-2035-01, June 1992, p. 28.
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reliability and low-cost electricity supplies, and to help address strategic positioning issues. The 

key strategic issues as outlined in this IRP include (1) addressing regulatory risks in the areas of 

climate change and renewable resource policies; (2) accounting for price risk and uncertainty in 

making resource acquisition decisions; (3) load uncertainty; and (4) determining the appropriate 

level and timing of long-term transmission expansion investments, accounting for the regulatory 

risks and uncertainties outlined above.
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Table 9.2 – Near-term and Long-term Resource Acquisition Paths 

Trigger Event

Planning 

Scenario(s)

Near-Term Resource 

Acquisition Strategy

(2013-2022)

Long Term Resource Acquisition 

Strategy

(2023-2032)

Higher sustained 

load growth

High economic 

drivers and 

increased demand 

from industrial 

customers

Increase acquisition of FOTs

Increase acquisition of Class 

1 DSM direct load control 

resources in the 2017 – 2020 

timeframe

Accelerate acquisition of a 

gas-fired thermal resource to 

2019

Increase acquisition of RECs 

to maintain compliance with 

RPS requirements consistent 

with load growth 

expectations by state

Accelerate acquisition of 

thermal resources to 2023

Increase acquisition of Class 1 

DSM direct load control 

resources.

Balance timing of thermal 

resource acquisition and Class 1 

DSM resources with FOTs and 

cost-effective Class 2 DSM 

energy efficiency resources

Evaluate cost effective RPS 

compliance strategies, including 

tradeoffs between resource 

acquisition and use of 

compliance flexibility 

mechanisms like banking and 

use of unbundled RECs

Lower sustained 

load growth

Low economic 

drivers suppress 

load requirements

Reduce acquisition of FOTs

Continue to purse Class 2 

DSM energy efficiency 

resources

Reduce acquisition of gas-fired 

thermal resources

Pursue peaking gas-fired 

resources to meet load growth

Balance timing of thermal 

resource acquisition and Class 1 

DSM resources with FOTs and 

cost-effective Class 2 DSM 

energy efficiency resources

Softening of the 

natural gas 

market combined 

with greenhouse 

gas policies that 

increase the cost 

of coal unit 

operation

Excess gas supply 

with increasing well 

productivity and/or 

technological 

innovation and 

dampened demand 

from limited use in 

the transportation 

sector and no 

liquefied natural gas 

exports.

Legislative action to 

implement new 

greenhouse gas 

polices or new 

regulations 

implemented with 

equivalent costs 

expected to 

approach $75/ton by 

2032.

Increase acquisition of FOTs 

and/or Class 2 DSM energy 

efficiency resources

Pursue strategic low cost gas 

conversion of existing coal 

units

Retire high cost coal units 

and accelerate acquisition of 

replacement natural gas-fired 

thermal resources

Accelerate acquisition of 

gas-fired thermal resources 

to 2019 to meet load growth 

expectations 

Pursue strategic low cost gas 

conversion of existing coal units

Retire high cost coal units and 

accelerate acquisition of 

replacement natural gas-fired 

thermal resources

Accelerate acquisition of costeffective renewable resources

Balance timing of thermal 

resource acquisition and Class 1 

DSM resources with FOTs and 

cost-effective Class 2 DSM 

energy efficiency resources
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Trigger Event

Planning 

Scenario(s)

Near-Term Resource 

Acquisition Strategy

(2013-2022)

Long Term Resource Acquisition 

Strategy

(2023-2032)

Strengthening of 

the natural gas 

market combined 

with greenhouse 

gas policies that 

increase the cost 

of coal unit 

operation

High oil prices 

support liquefied 

natural gas exports 

with lagging global 

shale development 

and demand for 

natural gas in the 

transportation sector 

increases beyond 

2020.

Legislative action to 

implement new 

greenhouse gas 

polices or new 

regulations 

implemented with 

equivalent costs in 

excess of $130/ton 

by 2032.

Increase acquisition of FOTs 

Accelerate acquisition of 

incremental Class 2 DSM 

energy efficiency resources

Accelerate and increase 

acquisition of renewable 

resources 

Pursue strategic low cost gas 

conversion of existing coal units

Retire high cost coal units and 

pursue acquisition of low 

emission replacement thermal 

resources such as nuclear and 

generating technologies with 

carbon capture and sequestration

Accelerate and increase 

acquisition of renewable 

resources.

Build additional transmission 

infrastructure to gain access to 

cost effective renewable 

resource opportunities.

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 

timeframe identified in the 2013 IRP. There may not be any cost-effective opportunities 

available through an RFP, the successful RFP bidder may experience delays in permitting and/or 

default on their obligations, or a material change in the market for fuels, materials, electricity, or 

environmental or other electric utility regulations, may change the Company’s entire resource 

procurement strategy.

Possible paths PacifiCorp could take if there was either a delay in the online 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 current RFP.

Issue an emergency RFP for a specific resource.

Move up the delivery date of a potential resource by negotiating with the 

supplier/developer.

Rely on near-term purchased power and transmission until a longer-term alternative is 

identified, acquired through PacifiCorp’s mini-RFPs or sole source procurement.

Install temporary generators to address some or all of the capacity needs.

Temporarily drop below the 13 percent planning reserve margin.

Implement load control initiatives, including calls for load curtailment via existing load 

curtailment contracts.
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IRP Action Plan Linkage to Business Planning

Resource differences between PacifiCorp’s 2013 IRP and the 2011 IRP Update relates primarily 

to a decreased load forecast and lower natural gas and power prices. These drivers result in a 

significant reduction of resources which include removal of natural gas, wind, FOT, DSM, and 

distributed generation resources. As compared to the 2011 IRP Update, the 2013 IRP preferred 

portfolio includes increased distributed solar due to the expanded Utah Solar Incentive Program. 

Table 9.3 compares the 2013 IRP preferred portfolio with the 2011 IRP Update portfolio for the 

10 years covered by both portfolios (2013-2022), indicating year by year capacity differences by 

major resource categories (yellow highlighted table). The major resource changes since the 2011 

IRP Update include the removal of two CCCT resources (CCCT F 2x1 and CCCT G 1x1) 

included in the portfolio by 2016 and 2019 respectively, reduction in DSM influenced by an 

updated resource potential study and additional detail in representing DSM in the current IRP 

modeling framework, increased distributed solar resources, and removal of wind resources. As 

discussed in Chapter 8 and identified in Table 9.1, renewable energy credits will be used to meet 

state RPS requirements.
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Table 9.3 – Portfolio Comparison, 2013 Preferred Portfolio versus 2011 IRP Update 

Portfolio

Table 9.4 provides a comparison between the 2013 Business Plan and the 2013 IRP Preferred 

Portfolio. The drivers of the differences between the 2013 IRP Preferred Portfolio and the 2013 

Business Plan include, reduced loads, removal of wind resources consistent with use of 

renewable energy credit purchase for RPS compliance, decreased DSM and FOTs due to 

decrease in load, and increase in distributed solar due to the Utah Solar Incentive Program.

2013 IRP Preferred Portfolio

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades 14 - - - - - - - - - 1 4

Gas - 645 - - - - - - - - 645 Wind - - - - - - - - - - -

Other Renewables / Solar 12 14 17 16 18 14 14 14 15 15 149

DSM, Class 1 - - - - - - - - - - -

DSM, Class 2 115 117 103 101 97 92 90 81 80 82 956

Distributed Generation 1 1 1 1 1 1 1 1 1 1 1 1

Total Long Term Resources 141 777 121 119 116 106 104 9 5 9 6 9 8 1,774

Utah Capacity Purchase * 200 - - - - - - - - - 200

East - Firm Market Purchases - - - - - 37 151 248 19 161 62 West - Firm Market Purchases 650 709 845 983 1,102 1,172 1,172 1,172 1,172 1,172 1,015

Firm Market Purchases 850 709 845 983 1,102 1,209 1,323 1,420 1,191 1,333 1,277

Study includes Naughton 3 gas conversion in 2015

FOT in resource total are 10-year averages

2013 IRP Preferred Portfolio less 2011 IRP Update (2012 Business Plan)

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades - - - - - - - - - - -

Gas - 8 - (597) - - (393) - - - (982)

Wind - - - - - - (225) (225) - (75) (525)

Other Renewables / Solar 7 11 14 16 18 14 14 14 15 15 138

DSM, Class 1 (57) (20) (97) - - - - - - - (174)

DSM, Class 2 4 (2) (19) (23) (29) (28) (32) (44) (45) (52) (269)

Distributed Generation (4) (4) (4) (4) (4) (4) (4) (4) (4) (4) (41)

Total Long Term Resources (50) (6) (106) (607) (16) (19) (640) (260) (34) (116) (1,853)

Utah Capacity Purchase * - - - - - - - - - - -

East - Firm Market Purchases (150) (300) (331) (300) (300) (263) (145) (52) (35) 23 (185) West - Firm Market Purchases (188) (52) (47) 416 506 437 639 377 458 446 299

Firm Market Purchases (338) (352) (378) 116 206 174 494 325 423 469 114

FOT in resource total are 10-year averages

2011 IRP Update (2012 Business Plan - Dec. 2011)

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades 19 14 - - - - - - - - - 1 4

Gas - - 637 - 597 - - 393 - - - 1,627 Wind - - - - - - - 225 225 - 75 525

Other Renewables / Solar 4 4 3 3 - - - - - - - 1 0

DSM, Class 1 70 57 20 97 - - - - - - - 174

DSM, Class 2 114 110 118 122 124 126 120 122 125 125 134 1,225

Distributed Generation 5 5 5 5 5 5 5 5 5 5 5 5 2

Total Long Term Resources 213 191 783 227 726 131 125 745 355 130 214 3,627

Utah Capacity Purchase * 200 200 - - - - - - - - - 20

East - Firm Market Purchases 17 150 300 331 300 300 300 296 300 54 138 247 West - Firm Market Purchases 927 838 761 892 567 596 735 533 795 714 726 716

Firm Market Purchases 1,145 1,188 1,061 1,223 867 896 1,035 829 1,095 768 864 983

FOT in resource total are 10-year averages

2013 IRP vs 2011 IRP Update
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Table 9.4 – Portfolio Comparison, 2013 Business Plan versus 2013 Preferred Portfolio

Resource Procurement Strategy

To acquire resources outlined in the 2013 IRP action plan, PacifiCorp intends to continue using 

competitive solicitation processes in accordance with the then-current law, rules, and/or 

guidelines in each of the states in which PacifiCorp operates. PacifiCorp will also continue to 

pursue opportunistic acquisitions identified outside of a competitive procurement process that 

provide clear economic benefits to customers. Regardless of the method for acquiring resources, 

the Company will use its IRP models to support resource evaluation as part of the procurement 

process, with updated assumptions including load forecasts, commodity prices, and regulatory 2013 IRP Preferred Portfolio

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades 14 - - - - - - - - - 1 4

Gas - 645 - - - - - - - - 645 Wind - - - - - - - - - - -

Other Renewables / Solar 12 14 17 16 18 14 14 14 15 15 149

DSM, Class 1 - - - - - - - - - - -

DSM, Class 2 115 117 103 101 97 92 90 81 80 82 956

Distributed Generation 1 1 1 1 1 1 1 1 1 1 1 1

Total Long Term Resources 141 777 121 119 116 106 104 9 5 9 6 9 8 1,774

Utah Capacity Purchase * 200 - - - - - - - - - 20

East - Firm Market Purchases - - - - - 37 151 248 19 161 62 West - Firm Market Purchases 650 709 845 983 1,102 1,172 1,172 1,172 1,172 1,172 1,015

Firm Market Purchases 850 709 845 983 1,102 1,209 1,323 1,420 1,191 1,333 1,097

Study includes Naughton 3 gas conversion in 2015

FOT in resource total are 10-year averages

2013 IRP Preferred Portfolio less 2013 Business Plan 

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades - - - - - - - - - - -

Gas - 7 - - - - - - - - 7

Wind - - - - - (100) (100) (100) (100) - (400)

Other Renewables / Solar 7 11 14 16 18 14 14 14 15 15 138

DSM, Class 1 - - - - - - (1) (100) - - (101)

DSM, Class 2 29 26 8 9 7 (4) (7) (19) (25) (29) (4)

Distributed Generation (4) (4) (4) (4) (4) (4) (4) (4) (4) (4) (41)

Total Long Term Resources 3 2 4 0 1 8 2 1 2 1 (94) (98) (209) (113) (17) (401)

Utah Capacity Purchase * - - - (200) (200) (200) (200) (200) - - (100)

East - Firm Market Purchases - (92) (51) (88) (72) (93) (95) (52) (62) 18 (59) West - Firm Market Purchases (268) (166) (233) (46) (66) (45) (45) (45) (45) (45) (100)

Firm Market Purchases (268) (258) (283) (335) (338) (337) (339) (297) (106) (27) (259)

FOT in resource total are 10-year averages

2013 Business Plan (December 2012)

Capacity (MW) Resource Totals

Resource 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2013-2022

Coal Plant Turbine Upgrades 19 14 - - - - - - - - - 1 4

Gas - - 638 - - - - - - - - 638 Wind - - - - - - 100 100 100 100 - 400

Other Renewables / Solar 4 4 3 3 - - - - - - - 1 0

DSM, Class 1 - - - - - - - 1 100 - - 101

DSM, Class 2 101 86 90 95 93 90 95 97 100 104 110 960

Distributed Generation 5 5 5 5 5 5 5 5 5 5 5 5 2

Total Long Term Resources 130 109 736 104 9 8 9 5 201 202 305 210 115 2,174

Utah Capacity Purchase * 200 200 - - 200 200 200 200 200 - - 120

East - Firm Market Purchases 62 - 92 51 88 72 130 246 300 81 143 120 West - Firm Market Purchases 1,055 918 875 1,078 1,029 1,168 1,217 1,217 1,217 1,217 1,217 1,115

Firm Market Purchases 1,317 1,118 967 1,128 1,318 1,440 1,546 1,662 1,717 1,297 1,360 1,355

Study includes Naughton 3 gas conversion in 2015

FOT in resource total are 10-year averages

2013 IRP vs 2013 Business Plan
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requirement information available at the time that the resource evaluations occur. This will 

ensure that the resource evaluations account for a long-term system benefit view in alignment 

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: renewable energy credits, DSM, thermal plants, distributed 

generation, and market purchases.

Renewable Energy Credits

The Company uses a shelf RFP as the primary mechanism under which the Company will issue 

subsequent RFPs to meet most of the renewable energy credit acquisition goals over the IRP 

action plan and business planning horizons. 

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. In 

other cases, PacifiCorp manages the program and contracts out specific tasks. A third method is 

to operate the program completely in-house. The business process used for any given program is 

based on operational expertise, performance risk and cost-effectiveness. 

To support the DSM procurement program, the IRP models are used for resource valuation 

purposes to gauge the cost-effectiveness of programs identified for procurement shortlists. For 

Class 2 DSM programs, PacifiCorp performs a “no cost” load shape decrement analysis to derive 

program values using its stochastic production cost model, Planning and Risk, similar to what 

was done for the 2011 IRP. The load shape decrement analysis is included in Volume II< 

Appendix N. 

Distributed Generation

Distributed generation, both solar and biomass, were found to be cost-effective resources in the 

context of IRP portfolio modeling. PacifiCorp’s procurement process will continue to provide an 

avenue for such new or existing resources to participate. These resources will be advantaged by 

being given a minimum bid amount (MW) eligibility that is appropriate for such an alternative, 

but that is also consistent with PacifiCorp’s then-current and applicable tariff filings (qualifying 

facility (QF) tariffs for example).

PacifiCorp will continue to participate with regulators and advocates in legislative and other 

regulatory activities that help provide tax or other incentives to renewable and distributed 

generation resources. The Company will also continue to improve representation of distributed 

generation resource in the IRP models.
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Assessment of Owning Assets versus Purchasing Power

As the Company acquires new resources, it will need to determine whether it is better to own a 

resource or purchase power from another party. While the ultimate decision will be made at the 

time resources are acquired, and will primarily be based on cost, there are other considerations 

that may be relevant. 

With owned resources, the Company would be in a better position to control costs, make life 

extension improvements, use the site for additional resources in the future, change fueling 

strategies or sources, efficiently address plant modifications that may be required as a result of 

changes in environmental or other laws and regulations, and utilize the plant at cost as long as it 

remains economic. In addition, by owning a plant, the Company can hedge itself from the 

uncertainty of relying on purchasing power from others. 

Depending on contract terms, purchasing power from a third party in a long term contract may 

help mitigate and may avoid any liabilities associated with closure of a plant. Short-term 

purchased power contracts could allow the Company to defer a long term resource acquisition. A 

long-term purchase power contract relinquishes control of construction cost, schedule, ongoing 

costs and compliance to a third party, and exposes the buyer to default events and contract 

remedies that will not likely cover the potential negative impacts. Finally, credit rating agencies 

impute debt associated with long-term resource contracts that may result from a competitive 

procurement process, and such imputation may affect the Company’s credit ratios and credit 

rating.

Managing Carbon Risk for Existing Plants

CO2 reduction regulations at the federal, regional, or state levels would prompt the Company to 

continue to look for measures to lower CO2 emissions of existing thermal plants through costeffective means. The cost, timing, and compliance flexibility afforded by CO2 reduction rules 

will impact what types of measures that would be cost-effective and practical from operational 

and regulatory perspectives. As noted earlier in the IRP, known and prospective environmental 

regulations can impact coal plant utilization and investment decisions. 

Under a cap-and-trade policy framework, examples of factors affecting carbon compliance 

strategies include the allocation of emission allowances, the cost of allowances in the market, 

and any flexible compliance mechanisms such as opportunities to use carbon offsets, 

allowance/offset banking and borrowing, and safety valve mechanisms. To lower the emission 

levels for existing thermal plants, options include economic early retirement, changing the fuel 

type, 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 

commercially proven. Indirectly, plant carbon risk can be addressed by acquiring offsets in the 

form of renewable generation and energy efficiency programs. Under an aggressive CO2

regulatory environment, and depending on fuel costs, coal plant idling and replacement strategies 

may become tenable options.

High CO2 costs would shift technology preferences both for new resources and existing 

resources to those with more efficient heat rates and also away from coal, unless carbon is 
PACIFICORP - 2013 IRP CHAPTER 9 –ACTION PLAN 

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sequestered. There may be opportunities to repower some of the existing coal fleet with a 

different less carbon-intensive fuel such as natural gas, as is currently being pursued for the 

Naughton Unit 3 generating unit. A major issue is whether new technologies will be available 

that can be exchanged for existing coal economically, particularly if market and policy drivers 

lead to large scale and abrupt early retirements across the region and the U.S. as a whole.

Purpose of Hedging

While PacifiCorp focuses every day on minimizing net power costs for customers, the Company 

also focuses every day on mitigating price risk to customers, which is done through hedging 

consistent with a robust risk management policy. For years the Company has followed a 

consistent hedging program that limits risk to customers, has tracked risk metrics assiduously 

and has diligently documented hedging activities. The Company’s risk management policy and 

hedging program exists to achieve the following goals: (1) to ensure that reliable power is 

available to serve customers; (2) to reduce net power cost volatility; and (3) to protect customers 

from significant risk. The purpose is solely to reduce customer exposure to net power cost 

volatility and adverse price movement. The Company does not speculatively trade commodities. 

Hedging is done solely for the purpose of limiting financial losses due to unfavorable wholesale 

market changes. Hedging modifies the potential losses and gains in net power costs associated 

with wholesale market price changes. The purpose of hedging is not to reduce or minimize net 

power costs. The Company cannot predict the direction or sustainability of changes in forward 

prices. Therefore, the Company hedges, in the forward market, to reduce the volatility of net 

power costs consistent with good industry practice as documented in the Company’s risk 

management policy.

Risk Management Policy and Hedging Program

PacifiCorp’s risk management policy and hedging program were designed to follow electric 

industry best practices and are periodically reviewed at least annually by the Company’s risk 

oversight committee. The risk oversight committee includes the Company’s chief financial 

officer, treasurer, director of risk management, assistant general counsel, controller, and senior 

vice president of commercial and trading. The risk oversight committee makes recommendations 

to the president of PacifiCorp Energy, who ultimately must approve any change to the risk 

management policy. The Company’s current policy is also consistent with the guidelines that 

resulted from collaborative hedging workshops with parties in Utah, Oregon, Idaho and 

Wyoming that took place in 2011 and 2012.

The main components of the Company’s risk management policy and hedging program are 

natural gas percent hedged volume limits, value-at-risk (VaR) limits and time to expiry VaR 

(TEVaR) limits. These limits force the Company to monitor the open positions it holds in power 

and natural gas on behalf of its customers on a daily basis and limit the size of these open 

positions by prescribed time frames in order to reduce customer exposure to price concentration 

and price volatility. The hedge program requires purchases of natural gas at fixed prices in 

gradual stages in advance of when it is required to reduce the size of this short position and 

associated customer risk. Likewise, on the power side, the Company either purchases or sells 
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power in gradual stages in advance of anticipated open short or long positions to manage price 

volatility on behalf of customers.

Since 2003, the Company’s hedge program has employed a portfolio approach of dollar cost 

averaging to progressively reduce net power cost risk exposure over a defined time horizon while 

adhering to best practice risk management governance and guidelines. The Company’s current 

portfolio hedging approach is defined by increasing risk tolerance levels represented by 

progressively increasing percentage of net power costs across the forward hedging period. The 

Company incorporated a time to expiry value at risk (TEVaR) metric in May 2010. In May 

2012, as a result of multiple hedging collaboratives, the Company reintroduced natural gas 

percent hedge volume limits of forecast requirements into its policy. There has been no conflict 

to-date between the new volume limits and the Company’s VaR and TEVaR limits, although the 

volume limits would supersede in such conflict, consistent with the guidelines from the hedging 

collaboratives.

The primary governance of the Company’s hedging activities is documented in the Company’s 

Risk Management Policy. In May 2010, the Company moved from hedging targets based on 

volume percentages to targets based on the “to expiry value-at-risk” or TEVaR metric. The 

primary goal of this change was to increase the transparency of the combined natural gas and 

power exposure by period. It enhances the progressive approach to hedging that the Company 

has employed for many years and provides the benefit of a more sophisticated measure of risk 

that responds to changes in the market and changes in open natural gas and power positions. 

Importantly, the TEVaR metric automatically reduces hedge requirements as commodity price 

volatility decreases and increases hedge requirements as correlations among commodities 

diverge, all the while maintaining the same customer risk exposure.

Dollar cost averaging is the term used to describe gradually hedging over a period of time rather 

than all at once. This method of hedging, which is widely used by many utilities, captures time 

diversification and eliminates speculative bursts of market timing activity. Its use means that at 

times the Company buys at relatively higher prices and at other times relatively lower prices, 

essentially capturing an array of prices at many levels. While doing so, the Company steadily 

and adaptively meets its hedge goals through the use of this technique while staying within VaR 

and TEVaR and natural gas percent hedge volume limits.

The result of these program changes in combination with changes in the market (such as reduced 

volatility to which the Company’s program automatically responds), has been a significant 

decrease in the Company’s longer-dated hedge activity, i.e., four years forward on a rolling 

basis. 

As a result of the hedging collaboratives, the Company made the following material changes to 

its policy in May 2012: (l) a reduction in the standard hedge horizon from 48 months to 36 

months and (2) a percent hedged range guideline for natural gas for each of the three forward l2-

month periods, which includes a minimum natural gas open position in each of the forward 12-

month periods. The percent hedged range guideline is greater for the first rolling twelve months 

and gradually smaller for the second and third rolling twelve-month periods. The Company also 

agreed to provide a new confidential semi-annual hedging report. 
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Cost Minimization

While hedging does not minimize net power costs, PacifiCorp takes many actions to minimize 

net power costs for customers. First, the Company is engaged in integrated resource planning to 

plan resource acquisitions that are anticipated to provide the lowest cost resources to our 

customers in the long-run. The Company then issues competitive requests for proposals to 

assure that the resources we acquire are the lowest cost resources available on a risk-adjusted 

basis. In operations, the Company optimizes its portfolio of resources on behalf of customers by 

maintaining and operating a portfolio of assets that diversifies customer exposure to fuel, power 

market and emissions risk and utilize an extensive transmission network that provides access to 

markets across the western United States. Independent of any natural gas and electric price 

hedging activity, to provide reliable supply and minimize net power costs for customers, the 

Company commits generation units daily, dispatches in real time all economic generation 

resources and all must-take contract resources, serves retail load, and then sells any excess 

generation to generate wholesale revenue to reduce net power costs for customers. The Company 

also purchases power when it is less expensive to purchase power than to generate power from 

our owned and contracted resources.

Hedging cannot be used to minimize net power costs. Hedging does not produce a different 

expected outcome than not hedging and therefore cannot be considered a cost minimization tool. 

Hedging is solely a tool to mitigate customer exposure to net power cost volatility and the risk of 

adverse price movement. However, the Company does minimize the cost of hedging by 

transacting in liquid markets and utilizing robust protections to mitigate the risk of counterparty 

default. In addition, the Company reduces the amount of hedging required to achieve a given 

risk tolerance through its portfolio hedge management approach, which takes into account 

offsetting exposures when these commodities are correlated, as opposed to hedging commodity 

exposures to natural gas and power in isolation without regard for offsets.

Portfolio

The Company has a short position in natural gas because of its ownership of gas-fired electric 

generation that requires it to purchase large quantities of natural gas to generate electricity to 

serve its customers. The Company may have short or long positions in power depending on the 

shortfall or excess of the Company’s total economic generation relative to customer load 

requirements at a given point in time.

The Company hedges its net energy (combined natural gas and power) position on a portfolio 

basis to take full advantage of any natural offsets between its long power and short natural gas 

positions. The Company’s 2011 IRP analysis shows that a “hedge only power” or “hedge only 

natural gas” approach results in higher risk (i.e., a wider distribution of outcomes). There is a 

natural need for an electric company with natural gas fired electricity generation assets to have a 

hedge program that simultaneously manages natural gas and power open positions with 

appropriate coordinated metrics. The Company’s risk management department incorporates 

daily updates of forward prices for natural gas, power, volatilities and correlations to establish 

daily changes in open positions and risk metrics which inform the hedging decisions made every 

day by Company traders. 
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The Company’s hedge program does not rely on a long power position. However, the 

Company’s hedge program takes into account the Company’s full portfolio and utilizes 

continuously updated correlations of natural gas and power prices and thereby takes advantage of 

offsetting natural gas and power positions in circumstances when prices are correlated and a 

forecast long power position offsets a forecast short natural gas position. This has the effect of 

reducing the amount of natural gas hedging that the Company would otherwise pursue. Ignoring 

this correlation would instead result in the need for more natural gas hedges to achieve the same 

level of customer risk reduction.

The Company’s customers have benefited from offsetting power and natural gas positions. 

Power and natural gas prices are closely related because natural gas is often the fuel on the 

margin in efficient dispatch, as is practiced throughout the western U.S. This means power sales 

tend to be more valuable in periods when natural gas is high cost, producing revenues that are a 

credit or offset to the high cost fuel. If spot natural gas prices depart from prior forward prices, 

power prices will tend to do so in the same direction, thereby naturally hedging some of the 

unexpected cost variance.

Effectiveness Measure

The goal of the hedging program is to reduce volatility in the Company’s net power costs 

primarily due to changes in market prices. The goal is not to “beat the market” and, therefore, 

should not be measured on the basis of whether it has made or lost money for customers. This 

reduction in volatility is calculated and reported in the Company’s confidential semi-annual 

hedging report which it began providing as a result of the hedging collaborative. 

Instruments

The Company’s hedging program allows the use of several instruments including financial 

swaps, fixed price physical and options for these products. The Company chooses instruments 

that generally have greater liquidity and lower transaction costs. The Company also considers, 

with respect to options, the likelihood of disallowance of the option premium in its six 

jurisdictions. There is no functional difference between financial swaps and fixed price physical 

transactions; both instruments are equally effective in hedging the Company’s fixed price 

exposure.

External Review

In the Company’s 2009 Utah General Rate Case, the Division of Public Utilities requested that 

Blue Ridge, a consulting firm knowledgeable with commodity hedging, review the Company’s 

hedging program. The Blue Ridge Report affirmatively concluded that the Company’s risk 

management policy and hedging program was well-documented, controlled and adhered to 

generally accepted industry standards as follows:

Overall, Blue Ridge found that the Company’s commercial trading and risk management 

programs (and the related hedging programs) are well-documented and controlled and 

adhere to generally accepted standards found elsewhere in the industry. The Company 

has well-stated goals and strategy that is aimed at mitigating price volatility. In addition, 
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our review of the Company’s internal documents showed that the Company is selfmonitoring compliance with accepted commercial trading and risk management 

procedures through its own internal audit function. 83

The question has been asked, “Why hedge?” The answer lies in one fundamental 

statement: prices and supplies for energy commodities (crude oil, natural gas, electricity, 

etc.) can and have been extremely volatile. The benefit of hedging is that when prices are 

rising (either rapidly in the short term or gradually in the long term), a hedged portfolio 

of supply should mitigate the effect of those increases. However, the opposite is also true. 

When prices fall suddenly, a hedged portion of the supply can cost the utility and its 

customers the difference between the prices that were available at the current time versus 

the hedged prices for that supply. This cost (when netted against any gains) along with 

the administrative costs associated to operate and manage the trading operations is 

considered the insurance premium associated with a hedged portfolio.

[H]aving a “no hedge” policy clearly exposes consumers to significant (and likely) price 

swings. Assuming that an upward price trend continues (despite recent price levels and 

short-term price forecasts), consumers are very likely to pay higher prices for energy 

absent some level of hedging and price volatility mitigation. 84

The National Regulatory Research Institute (NRRI) provided guidance related to natural gas 

hedging by utilities. The Utah Division of Public Utilities sponsored a presentation by NRRI to 

the Utah Commission in June 2009. The NRRI Report85 indicates that, for many years, state 

commissions have suggested that failure to engage in hedging (i.e., buying natural gas in the dayahead market or spot price) may be imprudent. The NRRI Report provides guidance on 

standards for determining the prudence of a utility’s hedging cost. The NRRI Report states, 

“Second-guessing and micromanaging should be avoided.” It explains, “Second-guessing is 

contrary to the traditional prudence standard, and in addition, creates distorted incentives for 

utility hedging.” Instead, it recommends that, “[a]ccording to the prudence standard, a 

commission should maintain authority to evaluate the reasonableness of (1) a hedging strategy ex 

ante, and (2) the execution of the strategy.” The NRRI Report suggests that a Commission could 

set an ex ante standard by, for example, defining an acceptable level of risk tolerance to price 

volatility. The Company agrees with the NRRI Report’s recommended approach to 

Commissions’ reviews of the prudence of the Company’s risk management policy and hedging 

program and welcomes direction from the Commissions on the Company’s risk management 

policy and hedging program on a going forward basis.

Dr. Frank Graves of The Brattle Group, retained by the Company to assess its risk management 

policy and hedging program, summarized his general findings and conclusions as follows:

 

83 Independent Third-Party Evaluation of Net Power Cost Evaluation Rocky Mountain Power 2009 General Rate 

Case, Prepared for Utah Division of Public Utilities, Prepared by Blue Ridge Consulting Services, Inc, Docket No. 

09-035-23 (Utah PSC October 7, 2009) at 2.

84 Id. at p 2 and 26.

85 Gas Hedging Presentation to The Public Service Commission of Utah Technical Conference, Ken Costello, The 

National Regulatory Research Institute, Docket No. 09-035-21 (Utah PSC June 3, 2009), available at: 

http://www.psc.utah.gov/utilities/electric/09docs/0903521/TechConf%206-3-09/Gas%20Hedging.ppt%20 

(UT%20PSC).pdf
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First, risk management is about controlling the potential width (and shape) of the 

distribution of future costs and not about minimizing costs. Even though it is possible to 

trim or avoid extreme prices with hedging, that trimming cannot reduce expected costs, 

because the risk protections come at a fair price. What you gain from hedging as 

avoided “downside” (bad) outcomes, you must lose as avoided “upside” (good) 

outcomes as well, and vice versa for your hedging counterparty. The two, corresponding 

positions must balance for no expected net gain. Thus, the minimization of energy costs 

has nothing to do with good risk management practices. 

Second, the Company’s hedging policies and practices, i.e. its analytic methods, risk 

metrics and controls, and hedging instruments, are fully in line with good industry 

practices. Like most electric utilities, the Company relies primarily on swaps purchased 

in regular installments over time. This avoids attempts to second-guess or “time” the 

market, while also assuring that hedges are steadily accrued, subject to risk-based 

guidelines for the needed quantity of total hedges. Consistent adherence to these 

methods, along with evidence of careful monitoring and control of the resulting risk 

metrics (keeping them within appropriate bounds), are the relevant standards for 

prudence review of the EBA costs the Company has incurred. 

Third, U.S. natural gas markets in the late 2007 through 2011 period (when PacifiCorp 

entered the hedges) were dominated by the unexpectedly rapid and inexpensive 

development of shale gas, compounded by the credit crisis and deep recession. During 

the first two years of this period there were few indications that shale gas would become 

a major component of U.S. gas supply. Only towards the end of the period did it become 

evident that shale gas would become a prominent and quite inexpensive part of the 

natural gas supply in the U.S. Even natural gas exploration and production firms 

aggressively leading the development of the hydraulic fracturing technology that caused 

this price drop have been badly surprised by the rapid price reductions.86 Therefore, the 

outlook for natural gas supply and prices were very different throughout the period 

during which the hedges were entered than it is today. It is imperative that the merits of 

a hedging program be evaluated based on the market conditions and information 

availability as of the time of the transaction. 

Fourth, it would not have been useful or normal for the Company to have liquidated any 

of its prior hedges in the middle of this price decline. It might appear so in hindsight, but 

the spot prices we ultimately observed are not similar to the way risks or expected costs 

appeared at any time in the hedge procurement period. Utility companies should not and 

do not generally liquidate hedges if/when the forward price curve shifts and causes prior 

hedges to become “out of the money” (i.e. to have a higher cost than replacement 

hedges). Because hedge positions are liquidated at prevailing prices, early liquidation 

cannot be expected to benefit the Company or its customers; the expected alternative cost 

(whether re-hedged or not) would have been the then prevailing forward prices – with no 

net savings likely. (As it turns out, liquidation and not re-hedging, i.e. dramatically 

 

86 For example, an August 2009 article in the New York Times cites senior management at exploration and 

production companies that the continual drop puts the viability of smaller companies at risk. See Clifford Krauss, 

“Natural Gas Price Plummet to a Seven-Year Low,” New York Times, August 21, 2009.
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increasing the Company’s risk exposure, would have been cheaper. But this can only be 

known in hindsight, and pursuing this strategy would have been very speculative, 

possibly in violation of company risk-control guidelines and prior regulatory agreements 

about hedging activity. 

Fifth, natural gas and power hedges should be considered together, which is what the 

Company does. The literature and common practice in hedging is solidly on the side of 

taking advantage of positions that predictably tend to offset each other, in order to 

reduce the cost and scope of hedging transactions that are needed. Electric and gas 

operations fit this model very nicely, in that they naturally tend to be correlated. 

Separating them for review would create perverse and untenable incentives for both 

regulation and operations.

Dr. Graves also described the purpose and overarching goal of risk management and hedging as 

follows:

A hedge is a trade designed to reduce risk, where risk is understood to mean the potential 

width (and shape) of the distribution of future costs (or revenues). Risk management is 

NOT about improving (reducing) the mean of this distribution of future costs (nor about 

increasing expected revenues). Risk also should not be confused with after-the-fact 

regret about whether a hedge proved to be necessary or attractive relative to remaining 

unhedged. In fact, risk and regret are mostly conflicting or competing goals, in that the 

more you lock down future prices (reduce ex ante risk) the greater the chance of 

eventually departing materially from the ex post cost of going unhedged. Conversely, if 

you wanted to have no regret about realized spot prices being lower than your hedges, 

than you should not hedge in the first place – but this would be risky! Some of the debate 

in regulatory review about risk management prudence involves confusion between these 

two concepts. However, the appropriate reference point is not the realized outcomes, 

which can only be known in hindsight (and which will only be better or worse than the 

hedges by luck), but the market information and outlook available at the time the hedges 

and risk reduction targets were committed.

Commission Review

Six out of six commissions that regulate PacifiCorp have approved net power costs for at least 

some portion of the 2012 calendar year period without any hedging disallowances. The Oregon 

Commission in the 2011 Transition Adjustment Mechanism, Docket No. UE 227, in the face of 

significant hindsight challenges from certain parties, found all of the Company’s hedge 

transactions to be prudent and praised the Company’s risk management policy and hedge 

program. Specifically, the Oregon Commission stated in the order:

The company's Risk Management Policy includes sound hedging goals, methodologies, 

and targets. Its policies and procedures were well articulated, and its specific hedging 

targets were made clear in advance to the company and its traders. Moreover, the 

company's hedging program appears to be robustly designed and well documented. The 

company provided ample contemporaneous documentation of the policies and 

procedures in effect at the time the hedges were executed, including its method of 

identifying, measuring, and managing risk, its hedging targets, its credit policies and 
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procedures, and its approved portfolio structures, as well as detailed procedures 

governing company enforcement of these policies. 87

Treatment of Customer and Investor Risks

The IRP standards and guidelines in Utah require that PacifiCorp “identify which risks will be 

borne by ratepayers and which will be borne by shareholders.” This section addresses this 

requirement. Three types of risk are covered: stochastic risk, capital cost risk, and scenario risk.

Stochastic Risk Assessment

Several of the uncertain variables that pose cost risks to different IRP resource portfolios are 

quantified in the IRP production cost model using stochastic statistical tools. The variables 

addressed with such tools include retail loads, natural gas prices, wholesale electricity prices, 

hydroelectric generation, and thermal unit availability. Changes in these variables that occur over 

the long-term are typically reflected in normalized revenue requirements and are thus borne by 

customers. Unexpected variations in these elements are normally not reflected in rates, and are 

therefore borne by investors unless specific regulatory mechanisms provide otherwise. 

Consequently, over time, these risks are shared between customers and investors. Between rate 

cases, investors bear these risks. Over a period of years, changes in prudently incurred costs will 

be reflected in rates and customers will 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 IRP. State commissions may determine that a portion of the cost of an asset was imprudent 

and therefore should not be included in the determination of rates. The risk of such a 

determination is borne by investors. To the extent that capital costs vary from those assumed in 

this IRP for 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 variables that are 

appropriately handled by scenario analysis as opposed to representation by a statistical process or 

expected-value forecast. The single most important scenario risks of this type facing PacifiCorp 

continues to be government actions related to CO2 emissions, renewable resources to meet 

compliance requirement, change in load and transmission infrastructure. These scenario risks 

relate to the uncertainty in predicting the scope, timing, and cost impact of CO2 emission and 

renewable standard compliance rules.

To address these risks, the Company evaluates resources in the IRP and for competitive 

procurements using a range of CO2 prices consistent with the scenario analysis methodology 

adopted for the Company’s IRP portfolio evaluation process. The Company’s use of IRP

sensitivity analysis covering different resource policy and cost assumptions also addresses the 

 

87 Order No. 11 435, Docket UE-227 (Ore. PUC [November 4, 2011]) at page 11.
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need for consideration of scenario risks for long-term resource planning. The extent to which 

future regulatory policy shifts do not align with the Company’s resource investments determined 

to be prudent by state commissions is a risk borne by customers.