20130430Volume II 2013 IRP.pdf

April 30, 2 0 1 3
Integrated
Resource
Plan
Volume II - Appendices
2 0 1 3
Let’s turn the answers on.

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
[phone]
[e-mail]
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 ........................................................................................................................................ V
INDEX OF FIGURES .................................................................................................................................... VII
APPENDIX A – LOAD FORECAST DETAILS ................................................................................................. 1
Introduction.............................................................................................................................................. 1
Summary Load Forecast ....................................................................................................................................... 1
Load Forecast Assumptions ..................................................................................................................... 3
Regional Economy by Jurisdiction ........................................................................................................................ 3
Utah ...................................................................................................................................................................... 4
Oregon .................................................................................................................................................................. 5
Wyoming ............................................................................................................................................................... 7
Washington ........................................................................................................................................................... 8
Idaho ..................................................................................................................................................................... 9
California ............................................................................................................................................................ 10
Weather .................................................................................................................................................. 10
Statistically Adjusted End-Use (“SAE”) ............................................................................................................. 11
Individual Customer Forecast ............................................................................................................................. 11
Actual Load Data ................................................................................................................................................ 11
System Losses ...................................................................................................................................................... 13
Forecast Methodology Overview ........................................................................................................... 13
Class 2 Demand-side Management Resources in the Load Forecast ................................................................. 13
Modeling overview .............................................................................................................................................. 13
Sales Forecast at the Customer Meter .................................................................................................... 15
Residential........................................................................................................................................................... 15
Commercial ......................................................................................................................................................... 16
Industrial ............................................................................................................................................................. 16
State Summaries .................................................................................................................................... 17
Oregon ................................................................................................................................................................ 17
Washington ......................................................................................................................................................... 17
California ............................................................................................................................................................ 18
Utah .................................................................................................................................................................... 18
Idaho ................................................................................................................................................................... 19
Wyoming ............................................................................................................................................................. 19
Alternative Load Forecast Scenarios ..................................................................................................... 19
APPENDIX B – IRP REGULATORY COMPLIANCE .................................................................................... 21
Introduction............................................................................................................................................ 21
General Compliance .............................................................................................................................. 21
California ............................................................................................................................................................ 22
Idaho ................................................................................................................................................................... 23
Oregon ................................................................................................................................................................ 23
Utah .................................................................................................................................................................... 23
Washington ......................................................................................................................................................... 23
Wyoming ............................................................................................................................................................. 24
APPENDIX C – PUBLIC INPUT PROCESS ................................................................................................... 55
Participant List ....................................................................................................................................... 56
Commissions ....................................................................................................................................................... 56
Stakeholders ........................................................................................................................................................ 56
Others .................................................................................................................................................................. 57
PACIFICORP - 2013 IRP TABLE OF CONTENTS
ii

Public Input Meetings ............................................................................................................................ 57
General Meetings ................................................................................................................................................ 58
May 7, 2012 – General Public Meeting ........................................................................................................... 58
June 20, 2012 – General Public Meeting ......................................................................................................... 58
July 13, 2012 – General Public Meeting .......................................................................................................... 58
August 2, 2012 – General Public Meeting ....................................................................................................... 58
August 13, 2012 – General Public Meeting ..................................................................................................... 58
September 14, 2012 – General Public Meeting ................................................................................................ 58
October 24, 2012 – General Public Meetings .................................................................................................. 59
November 5, 2012 – General Public Meeting .................................................................................................. 59
November 27, 2012 – General Public Meeting ................................................................................................ 59
January 31, 2013 – General Public Meeting .................................................................................................... 59
February 27, 2013 – General Public Meeting .................................................................................................. 59
March 21, 2013 – General Public Meeting ...................................................................................................... 59
April 5, 2013 – General Public Meeting .......................................................................................................... 60
April 17, 2013 – General Public Meeting ........................................................................................................ 60
April 17, 2013 – Confidential Meeting ............................................................................................................ 60
Public Conference Call Meetings ....................................................................................................................... 60
August 24, 2012 - Public Conference Call ....................................................................................................... 60
September 24, 2012 – Public Conference Call ................................................................................................. 60
October 3, 2012 – Public Conference Call ....................................................................................................... 60
December 6, 2012 – Public Conference Call ................................................................................................... 60
December 14, 2012 – Public Conference Call ................................................................................................. 60
December 18, 2012 – Public Conference Call ................................................................................................. 60
State Meetings ..................................................................................................................................................... 61
July 11, 2012 – Idaho State Stakeholder Meeting ............................................................................................ 61
July 12, 2012 – Wyoming State Stakeholder Meeting ..................................................................................... 61
July 19, 2012 – Oregon State Stakeholder Meeting ......................................................................................... 61
July 20, 2012 – Washington State Stakeholder Meeting .................................................................................. 61
August 14, 2012 – Utah State Stakeholder Meeting ........................................................................................ 61
Parking Lot Issues .................................................................................................................................. 61
Public Review of IRP Draft Document ................................................................................................. 61
Contact Information ............................................................................................................................... 62
APPENDIX D – DEMAND-SIDE MANAGEMENT AND SUPPLEMENTAL RESOURCES ................................ 63
Introduction............................................................................................................................................ 63
Class 2 Demand-Side Management Resource Ramping ....................................................................... 63
Assessment of Long-Term, System-Wide Potential for Demand-Side and Other Supplemental
Resources ............................................................................................................................................... 63
Class 3 Demand Side Management load impact market survey study .................................................. 64
Other Supplemental Resource Studies ................................................................................................... 65
Combined Heat and Power study ........................................................................................................................ 65
Solar Water Heating Market Potential and Associated Cost study ..................................................................... 65
Solar Photovoltaic Market Potential and Associated cost study ......................................................................... 65
APPENDIX E – CONSERVATION VOLTAGE REDUCTION .......................................................................... 67
Introduction............................................................................................................................................ 67
Washington Tier 1 study (2011) .......................................................................................................................... 67
Washington Tier 2 study (2012) .......................................................................................................................... 68
Washington pilot project results ......................................................................................................................... 68
Multi-state high-level screening effort ................................................................................................................ 69
Future Conservation Voltage Reduction ................................................................................................ 69
APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT ..................................................................... 71
Introduction............................................................................................................................................ 71
Flexible Resource Requirements Forecast ............................................................................................. 71
Contingency Reserve ........................................................................................................................................... 71
PACIFICORP - 2013 IRP TABLE OF CONTENTS
iii

Regulating Margin .............................................................................................................................................. 72
Flexible Resource Supply Forecast ........................................................................................................ 73
Flexible Resource Supply Planning ....................................................................................................... 76
APPENDIX G – PLANT WATER CONSUMPTION ........................................................................................ 77
APPENDIX H – WIND INTEGRATION STUDY ............................................................................................. 81
1. Introduction ............................................................................................................................... 84
Technical Review Committee .............................................................................................................................. 84
1.1 Executive Summary ....................................................................................................................................... 85
2. Data............................................................................................................................................ 86
2.1 Overview ....................................................................................................................................................... 86
2.2 Historical Load and Load Forecast Data ..................................................................................................... 87
2.3 Historical Wind Generation and Wind Generation Forecast Data .............................................................. 88
2.3.1 Overview of the Wind Generation Data Used in the Analysis ................................................................ 88
2.3.2 Historical Wind Generation Data ............................................................................................................ 88
3. Method ....................................................................................................................................... 91
3.1 Method Overview .......................................................................................................................................... 91
3.1.1 Operating Reserves ................................................................................................................................. 91
3.1.2 Method Steps ........................................................................................................................................... 92
3.2 Regulating Margin Requirements ................................................................................................................. 93
3.2.1 Ramp Reserve ......................................................................................................................................... 93
3.2.2 Regulation Reserve ................................................................................................................................. 93
3.2.3 Hypothetical Operational Forecasts ........................................................................................................ 94
3.2.4 Recording of Deviations .......................................................................................................................... 98
3.2.5 Analysis of Deviations ............................................................................................................................ 99
3.2.6 Backcasting ........................................................................................................................................... 105
3.3 Determination of Wind Integration Costs ................................................................................................... 116
3.3.1 Overview ............................................................................................................................................... 116
3.3.2 Calculating Operating Reserve Wind Integration Costs ........................................................................ 117
3.3.3 Calculating System Balancing Wind Integration Costs......................................................................... 118
3.3.4 Application of Study Results to Integrated Resource Plan Portfolio Modeling .................................... 118
3.3.5 Allocation of Operating Reserve Demand in PaR ................................................................................. 119
4. Results ..................................................................................................................................... 120
4.1 Production Cost Results .............................................................................................................................. 120
4.2 Additional Scenarios ................................................................................................................................... 121
Historical Evaluation ...................................................................................................................................... 121
Concurrent Evaluation ................................................................................................................................... 122
Reliability Based Control Market Structure ................................................................................................... 122
Combination of PACE and PACW ................................................................................................................ 123
5. Summary .................................................................................................................................. 123
APPENDIX I – STOCHASTIC LOSS OF LOAD STUDY ............................................................................... 127
APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION ........................................................... 145
Introduction.......................................................................................................................................... 145
Western Electricity Coordinating Council Resource Adequacy Assessment ...................................... 145
Pacific Northwest Resource Adequacy Forum’s Adequacy Assessment ............................................ 151
Customer versus Shareholder Risk Allocation .................................................................................... 151
APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS ................................................................. 153
Portfolio Case Build Tables ................................................................................................................. 153
APPENDIX L – STOCHASTIC PRODUCTION COST SIMULATION RESULTS ............................................ 267
Core Case Study Stochastic Results .................................................................................................... 267
Mean versus Upper-tail Mean PVRR Scatter-plot Charts ................................................................................ 267
Stochastic Risk and Other Portfolio Performance Measures ............................................................................ 267
PACIFICORP - 2013 IRP TABLE OF CONTENTS
iv

APPENDIX M – CASE STUDY FACT SHEETS ........................................................................................... 289
Introduction.......................................................................................................................................... 289
Case Fact Sheets Summary Tables ...................................................................................................... 290
Core Case Fact Sheets ........................................................................................................................ 292
Sensitivity Case Fact Sheets ................................................................................................................ 331
APPENDIX N – CLASS 2 DSM DECREMENT STUDY ............................................................................... 355
Modeling Approach ............................................................................................................................. 355
Generation Resource Capacity Deferral Benefit Methodology ........................................................................ 355
Class 2 DSM Decrement Value Results .............................................................................................. 356
APPENDIX O – WIND AND SOLAR PEAK CONTRIBUTION ...................................................................... 361
Overview ............................................................................................................................................. 361
Methodology ........................................................................................................................................ 361
Wind .................................................................................................................................................................. 362
Solar .................................................................................................................................................................. 363

PACIFICORP - 2013 IRP INDEX OF TABLES
v

INDEX OF TABLES
Table A.1 – Forecasted Annual Load Growth, 2013 through 2022 (Megawatt-hours) ................................................. 2
Table A.2 – Forecasted Annual Coincident Peak Load (Megawatts) ............................................................................ 2
Table A.3 – Annual Load Growth Change: November 2011 Forecast less July 2012 Forecast (Megawatt-hours) ...... 2
Table A.4 – Annual Coincident Peak Growth Change: November 2011 Forecast less July 2012 Forecast
(Megawatts) ......................................................................................................................................................... 3
Table A.5 Weather Normalized Jurisdictional Retail Sales 1997 through 2012 .......................................................... 12
Table A.6 Non-Coincident Jurisdictional Peak 1997 through 2012 ............................................................................ 12
Table A.7 Jurisdictional Contribution to Coincident Peak 1997 through 2012 ........................................................... 13
Table A.8 – System Annual Sales Forecast 2013 through 2022 .................................................................................. 15
Table A.9 – Forecasted Sales Growth in Oregon ........................................................................................................ 17
Table A.10 – Forecasted Sales Growth in Washington ............................................................................................... 17
Table A.11 – Forecasted Retail Sales Growth in California ........................................................................................ 18
Table A.12 – Forecasted Retail Sales Growth in Utah ................................................................................................ 18
Table A.13 – Forecasted Retail Sales Growth in Idaho ............................................................................................... 19
Table A.14 – Forecasted Retail Sales Growth in Wyoming ........................................................................................ 19
Table B.1 – Integrated Resource Planning Standards and Guidelines Summary by State........................................... 25
Table B.2 – Handling of 2011 IRP Acknowledgment and Other IRP Requirements .................................................. 29
Table B.3 – Oregon Public Utility Commission IRP Standard and Guidelines ........................................................... 36
Table B.4 – Utah Public Service Commission IRP Standard and Guidelines ............................................................. 45
Table B.5 – Washington Utilities and Transportation Commission IRP Standard and Guidelines (WAC 480-100-
238) .................................................................................................................................................................... 50
Table B.6 – Wyoming Public Service Commission IRP Standard and Guidelines (Docket 90000-107-XO-09) ........ 53
Table F.1 - Reserve Requirements (MW) .................................................................................................................... 73
Table F.2 - Flexible Resource Supply Forecast (MW) ................................................................................................ 74
Table G.1 – Plant Water Consumption with Acre-Feet Per Year ................................................................................ 78
Table G.2 – Plant Water Consumption by State (acre-feet) ........................................................................................ 79
Table G.3 – Plant Water Consumption by Fuel Type (acre-feet) ................................................................................ 79
Table G.4 – Plant Water Consumption for Plants Located in the Upper Colorado River Basin (acre-feet) ................ 80
Table H.1 - Average Annual Regulating Margin Reserves, 2012 Wind Study (MW) ................................................ 85
Table H.2 - Wind Integration Cost (2012$ per MWh of Wind Generation) ................................................................ 86
Table H.3 - Nominal Levelized Natural Gas and Power Prices Used in the 2010 and 2012 Wind Integration Studies
........................................................................................................................................................................... 86
Table H.4 - Historical Wind Production and Load Data Inventory ............................................................................. 87
Table H.5 - Load Data Anomalies and their Interpolated Solutions ............................................................................ 88
Table H.6 - Percentiles Dividing the June 2011 Load Regulating Forecasts into 20 Bins ........................................ 100
Table H.7 - Recorded Interval Load Regulating Forecasts and their Respective Errors, or Deviations, for June 2011
Operational Data from PACE .......................................................................................................................... 101
Table H.8 - Sample Reference Table for Load and Wind Following Component Reserves ..................................... 106
Table H.9 - Sample Reference Table for Load and Wind Regulating Component Reserves .................................... 107
Table H.10 - Interval Load Forecasts and Component Reserves Requirement Data for Hour-ending 11 AM, June 1,
2011 in PACE .................................................................................................................................................. 108
Table H.11 - Interval Wind Forecasts and Component Reserves Requirement Data for Hour-ending 11 AM June 1,
2011 in PACE .................................................................................................................................................. 108
Table H.12 - Results of Regression Analyses between Wind and Load Deviations .................................................. 112
Table H.13 - Wind Integration Cost Simulations in PaR ........................................................................................... 117
Table H.14 - Operating Reserve Categories Used by the PaR model ........................................................................ 119
Table H.15 - Regulating Margin Requirements Calculated for PACE and PACW (MW) ........................................ 120
Table H.16 - Nominal Levelized Production Cost Results for the 2012 and 2010 Wind Studies ............................. 121
Table H.17 - Historical Reserves Calculated throughout the Study Term (MW) ...................................................... 121
Table H.18. Incremental Reserves Due to Installed Wind Generation Capacity (MW) ............................................ 122
Table H.19 - Concurrent Netting of Load and Wind Errors Scenario Results (MW) ................................................ 122
Table H.20 - 30-minute Balancing Interval Scenario Results (MW) ......................................................................... 123
Table H.21 - Regulating Margin Requirements Calculated Assuming a Single PacifiCorp Balancing Authority Area
(MW)................................................................................................................................................................ 123
PACIFICORP - 2013 IRP INDEX OF TABLES
vi

Table H.22 - Regulating Margin Requirements Calculated for PacifiCorp’s System (MW) .................................... 125
Table H.23 - Wind Integration Costs ......................................................................................................................... 125
Table K.1 – Gateway Scenario Definitions ............................................................................................................... 153
Table K.2 – Core Case Definitions ............................................................................................................................ 155
Table K.3 – Sensitivity Case Definitions ................................................................................................................... 156
Table K.4 – Resource Name and Description ............................................................................................................ 157
Table K.5 – Core Case System Optimizer PVRR Results ......................................................................................... 161
Table K.6 – Sensitivity Case – EG2 System Optimizer PVRR Results .................................................................... 162
Table K.7 – Energy Gateway Scenario 1 – Case C-01 to C-18 ................................................................................. 163
Table K.8 – Energy Gateway Scenario 2 – Case C-01 to C-19 ................................................................................. 181
Table K.9 – Energy Gateway Scenario 3 – Case C-01 to C-19 ................................................................................. 201
Table K.10 – Energy Gateway Scenario 4 – Case C-01 to C-19 ............................................................................... 220
Table K.11 – Energy Gateway Scenario 5 – Case C-01 to C-19 ............................................................................... 239
Table K.12 – Sensitivity Cases under Energy Gateway Scenario 2, excluding S-04 and S-X that are included in
Confidential Volume III ................................................................................................................................... 259
Table L.1– Stochastic Mean PVRR by CO2 Tax Level, Core Case Portfolios .......................................................... 275
Table L.2 – Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios ......................................................... 276
Table L.2 – Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios (Continued) ..................................... 277
Table L.2 – Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios ......................................................... 278
Table L.3– Stochastic Risk Adjusted PVRR by CO2 Tax Level ............................................................................... 279
Table L.4 – Carbon Dioxide Emissions ..................................................................................................................... 280
Table L.5 –10-year Average Incremental Customer Rate Impact, Final Screen Portfolios ....................................... 281
Table L.6 – Average Annual Energy Not Served (2013 – 2032), Medium CO2 Initial Screen Portfolios ................ 281
Table L.6 – Average Annual Energy Not Served (2013 – 2032), Medium CO2 Initial Screen Portfolios (Continued)
......................................................................................................................................................................... 282
Table L.7 – Loss of Load Probability for a Major (> 25,000 MWh) July Event ....................................................... 282
Table L.8 – Average Loss of Load Probability during Summer Peak ....................................................................... 283
Table L.9 – Core Cases 1 through 19, Portfolio PVRR Cost Components (Zero CO2 Tax Level) ........................... 285
Table L.10 – Core Cases 1 through 19, Portfolio PVRR Cost Components (Medium CO2 Tax Level) .................... 286
Table L.11 – Core Cases 1 through 19, Portfolio PVRR Cost Components (High CO2 Tax Level) ........................ 287
Table M.1 – Core Case Definitions ........................................................................................................................... 290
Table M.2 – Sensitivity Case Definitions .................................................................................................................. 291
Core Case Fact Sheets – C-01 to C-19 ...................................................................................................................... 292
Sensitivity Case Fact Sheets – S-1 to S-10, S-X ........................................................................................................ 331
Table N.1 – Levelized Class 2 DSM Avoided costs, 20-Year Net Present Value (2013-2032) ................................ 357
Table N.2 – Annual Nominal Class 2 DSM Avoided Costs, 2013-2032 ................................................................... 358
Table N.2 – Annual Nominal Class 2 DSM Avoided Costs, 2013-2032 (Continued) ............................................... 359
Table O.1 – Wind and Solar Peak Contribution (% of nameplate capacity) ............................................................. 361
Table O.2 – Resources Included in the Wind Analysis ............................................................................................. 363

PACIFICORP - 2013 IRP INDEX OF FIGURES
vii

INDEX OF FIGURES
Figure A.1 – PacifiCorp Annual Retail Sales 1997 through 2012 ................................................................................. 3
Figure A.2 – West Region Employment Statistics 1997 through 2012 ......................................................................... 4
Figure A.3 – Growth Relative to the US Average (Average annual percent change, 2011 to 2013) ............................. 5
Figure A.4 – IHS Global Insight Utah Household and Employment forecasts from the November 2011 load forecast
and the July 2012 load forecast ............................................................................................................................ 5
Figure A.5 – Recession Recovery: Changes in Employment (Percent) ......................................................................... 6
Figure A.6 – IHS Global Insight Oregon service territory Household and Employment forecasts from the November
2011 load forecast and the July 2012 load forecast .............................................................................................. 6
Figure A.7 – Recession Recovery: Changes in Employment (Percent) ......................................................................... 7
Figure A.8 – IHS Global Insight Wyoming service territory Household and Employment forecasts from the
November 2011 load forecast and the July 2012 load forecast ............................................................................ 7
Figure A.9 – Yakima, WA Metropolitan Statistical Area Employment Statistics, 1997 through 2012 ......................... 8
Figure A.10 – IHS Global Insight Washington service territory Household and Employment forecasts from the
November 2011 load forecast and the July 2012 load forecast ............................................................................ 9
Figure A.11 - Recession Recovery: Changes in Employment (Percent) ....................................................................... 9
Figure A.12 - IHS Global Insight Idaho service territory Household and Employment forecasts from the November
2011 load forecast and the July 2012 load forecast ............................................................................................ 10
Figure A.13 – IHS Global Insight Idaho service territory Household and Employment forecasts from the November
2011 load forecast and the July 2012 load forecast ............................................................................................ 10
Figure A.14 – Load Forecast Scenarios for 1-in-20 Weather, High, Base Case and Low ........................................... 20
Figure F.1 - Comparison of Reserve Requirements and Resources, East Balancing Authority Area (MW) ............... 75
Figure F.2 - Comparison of Reserve Requirements and Resources, West Balancing Authority Area (MW) ............. 75
Figure H.1 - Representative Map of PacifiCorp Wind Generating Stations Used in this Study .................................. 89
Figure H.2 - Illustrative Load Following Forecast and Deviation ............................................................................... 95
Figure H.3 - Illustrative Wind Following Forecast and Deviation .............................................................................. 96
Figure H.4 - Illustrative Load Regulating Forecast and Deviation .............................................................................. 97
Figure H.5 - Illustrative Wind Regulating Forecast and Deviation ............................................................................. 98
Figure H.6 - Illustrative Example of Independent Load and Wind Regulating Deviations ......................................... 99
Figure H.7 - Histogram of Deviations Occurring About a June 2011 PACE Load Regulating Forecast of 6,097 MW
......................................................................................................................................................................... 102
Figure H.8 - Load Following Component Reserve Profile; Operational Data from June 2011 ................................. 104
Figure H.9 - Wind Following Component Reserve Profile; Operational Data from June 2011 ................................ 105
Figure H.10 - Depiction of the Parallelogram Law ................................................................................................... 110
Figure H.11 - PACE Following Regression Plot ....................................................................................................... 113
Figure H.12 - PACE Regulating Regression Plot ...................................................................................................... 114
Figure H.13 - PACW Following Regression Plot ...................................................................................................... 115
Figure H.14 - PACW Regulating Regression Plot ..................................................................................................... 116
Figure J.1 – WECC Forecasted Power Supply Margins, 2007 to 2011 ..................................................................... 147
Figure J.2 – 2012 WECC Forecasted Planning Reserve Margins ............................................................................. 147
Figure J.3 – Basin Forecasted Power Supply Margins .............................................................................................. 148
Figure J.4 – Desert Southwest Forecasted Power Supply Margins ........................................................................... 149
Figure J.5 – Rockies Forecasted Power Supply Margins ........................................................................................... 150
Figure O.1 – Wind Peak Contribution, in top 100 summer load hours...................................................................... 362
Figure O.2 – Solar Resource Peak Contribution, in top 100 summer load hours ...................................................... 364
PACIFICORP – 2013 IRP INDEX OF FIGURES
viii

PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
1

APPENDIX A – LOAD FORECAST DETAILS
Introduction

This appendix reviews the load forecast used in the modeling and analysis of the 2013 Integrated
Resource Plan (“IRP”), including scenario development for case sensitivities. The load forecast
used in the IRP is an estimate of the energy sales, and peak demand over a 20-year period. The
20-year horizon is important to anticipate electricity demand in order to develop timely response
of resources.

In the development of its load forecast PacifiCorp employs econometric models that use
historical data and inputs such as regional and national economic growth, weather, seasonality,
and other customer usage and behavior changes. The forecast is divided into classes that use
energy for similar purposes and at comparable retail rates. The different classes are modeled
separately using variables specific to their usage patterns. For residential customers, typical
energy uses include space heating, water heating, lighting, cooking, refrigeration, dish washing,
laundry washing, televisions and various other end use appliances. Commercial and industrial
customers use energy for production and manufacturing processes, space heating, air
conditioning, lighting, computers and other office equipment.

Jurisdictional peak load forecasts are developed using econometric equations that relate observed
monthly peak loads, peak producing weather and the weather-sensitive loads for all classes. The
system coincident peak forecast, which is used in portfolio development, is the maximum load
required on the system in any hourly period and is extracted from the hourly forecast model.
Summary Load Forecast
The Company updated its load forecast in July 2012. Relative to the load forecast prepared for
the 2011 IRP update, PacifiCorp system sales decreased approximately 0.8 percent in average
annual growth through 2022. The lower load forecast is driven by reduced industrial sector loads
in Utah and Wyoming that reflect load request cancellations and postponements prompted by
prolonged recessionary impacts and permitting issues. The most current load forecast also
incorporates projections of increased industrial self-generation driven largely by lower wholesale
gas prices. Finally, the Company’s new industrial load forecast uses regression analysis in place
of probability assessment of customer-provided forecasts.

Tables A.1 and A.2 show the annual load and coincident peak load forecast excluding load
reduction projections from new energy efficiency measures (Class 2 DSM).1 Tables A.3 and A.4
show the forecast changes relative to the 2011 IRP update load forecast for loads and coincident
system peak, respectively.

1 Class 2 DSM load reductions are included as resources in the System Optimizer model.
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

2

Table A.1 – Forecasted Annual Load Growth, 2013 through 2022 (Megawatt-hours)

Table A.2 – Forecasted Annual Coincident Peak Load (Megawatts)

Table A.3 – Annual Load Growth Change: November 2011 Forecast less July 2012
Forecast (Megawatt-hours)

Year Total OR WA CA UT WY ID SE-ID
2013 61,556,386 14,877,800 4,453,504 903,816 25,153,750 10,190,043 3,740,820 2,236,653
2014 62,698,447 15,150,179 4,479,048 905,134 25,718,951 10,408,489 3,779,427 2,257,219
2015 63,527,998 15,371,114 4,510,405 908,752 26,010,382 10,626,524 3,819,927 2,280,894
2016 63,431,505 15,638,182 4,561,495 916,004 26,478,252 10,856,135 3,868,348 1,113,089
2017 63,246,311 15,821,900 4,587,861 918,237 27,010,019 11,012,432 3,895,861
2018 64,219,328 16,003,367 4,630,207 923,755 27,542,259 11,188,259 3,931,482
2019 65,183,187 16,181,469 4,672,594 928,941 28,073,752 11,360,999 3,965,432
2020 66,226,672 16,377,833 4,722,544 935,083 28,622,538 11,563,805 4,004,870
2021 66,917,769 16,491,188 4,746,086 935,580 29,021,169 11,698,580 4,025,165
2022 67,814,244 16,652,789 4,784,841 938,914 29,514,597 11,866,488 4,056,614
2013-2022 1.08%1.26%0.80%0.42%1.79%1.71%0.90%
Average Annual Growth Rate for 2013-2022
Year Total OR WA CA UT WY ID SE-ID
2013 10,135 2,329 743 143 4,632 1,277 685 327
2014 10,331 2,377 752 140 4,745 1,302 684 331
2015 10,494 2,408 758 141 4,826 1,326 701 334
2016 10,359 2,457 765 143 4,930 1,349 714
2017 10,513 2,492 772 144 5,014 1,371 721
2018 10,687 2,522 803 145 5,100 1,390 727
2019 10,815 2,547 786 146 5,194 1,410 732
2020 10,972 2,576 795 144 5,290 1,429 737
2021 11,133 2,604 801 145 5,387 1,448 748
2022 11,280 2,631 807 146 5,475 1,467 754
2013-2022 1.20%1.36%0.92%0.23%1.88%1.56%1.07%
Average Annual Growth Rate for 2013-2022
Year Total OR WA CA UT WY ID SE-ID
2013 (1,734,236) (462) (71,339) (41,408) (1,456,454) (76,649) (53,890) (34,034)
2014 (2,500,990) (65,008) (83,667) (44,776) (1,828,067) (261,914) (173,476) (44,082)
2015 (3,234,992) (54,370) (86,451) (45,926) (2,173,032) (572,064) (249,858) (53,291)
2016 (3,933,522) (12,540) (93,075) (47,494) (2,616,993) (803,790) (327,267) (32,363)
2017 (5,299,846) (100,262) (96,937) (65,836) (3,032,564) (1,615,158) (389,090)
2018 (5,513,237) (96,772) (99,309) (65,757) (3,148,301) (1,690,539) (412,558)
2019 (5,740,510) (93,880) (100,878) (66,020) (3,248,967) (1,807,650) (423,115)
2020 (6,015,091) (99,673) (102,183) (67,092) (3,423,365) (1,888,205) (434,572)
2021 (6,284,160) (94,696) (103,330) (68,142) (3,583,213) (1,991,980) (442,800)
2022 (6,682,754) (218,649) (151,116) (71,341) (3,739,231) (2,051,017) (451,401)
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
3

Table A.4 – Annual Coincident Peak Growth Change: November 2011 Forecast less July
2012 Forecast (Megawatts)

Load Forecast Assumptions
Regional Economy by Jurisdiction
The PacifiCorp electric service territory is comprised of six states and within those states the
Company serves a total of 90 counties. The level of retail sales for each state and county is
correlated with economic conditions and population statistics for each area. The Company uses
both economic data, such as employment, and population information, such as household data, to
forecast its retail sales. Looking at historical sales data for PacifiCorp, 1997 through 2012, in
Figure A.1 and Western Regional historical employment data in Figure A.2, it is apparent that
the Company’s retail sales are correlated to economic conditions in its service territory, and most
recently the 2008-2009 recession.2

Figure A.1 – PacifiCorp Annual Retail Sales 1997 through 2012

2 The historical sales data provide in Figure A.1 is annual weather normalized retail sales for the PacifiCorp system.
Year Total OR WA CA UT WY ID SE-ID
2013 (283) (19) (17) (16) (169) (28) (15) (18)
2014 (403) (29) (18) (16) (240) (46) (34) (20)
2015 (491) (25) (24) (18) (295) (63) (49) (17)
2016 (521) (5) (24) (19) (321) (90) (63)
2017 (687) (17) (24) (24) (375) (173) (73)
2018 (707) (14) (4) (24) (408) (180) (77)
2019 (763) (16) (25) (24) (429) (190) (79)
2020 (804) (18) (25) (24) (463) (196) (79)
2021 (843) (15) (26) (25) (485) (209) (83)
2022 (887) (38) (25) (20) (497) (222) (84)
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

4

Figure A.2 – West Region Employment Statistics 1997 through 2012
Source: United States Department of Labor, Bureau of Labor Statistics

Given the correlation between employment and electricity usage, it is important to understand
the changes in the employment and household formation forecasts that contributed to the
decrease in the 2013 IRP load forecast. The majority of economic and household formation
forecasts provided by IHS Global Insight in its February 2012 forecast were lower than the
February 2011 forecast. The primary reason for the decrease across all states is
underperformance relative to the prior forecast, and the economy not recovering in a manner that
was as anticipated, or at a more protracted rate of growth. The effect of the decrease in the
forecasts provided by IHS Global Insight is that it lowers the expected retail sales forecast.
Following is a discussion by state of IHS Global Insights expectations and change in their
forecast relative to the 2011 IRP Update.
Utah
The Utah economy continues to benefit from a relatively young, well educated, and well-
qualified workforce to attract employers, and ranks highly in quality-of-life measures, which
contributes to population growth. Utah is expected to remain among the leading states in terms
of job growth over the next five years, with payrolls increasing an average of 2.2 percent
annually. Figure A.3 below shows the growth in Utah relative to the United States average.3

3 Source: IHS Globe Insight, April 2012
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
5

Figure A.3 – Growth Relative to the US Average (Average annual percent change, 2011 to
2013)

PacifiCorp serves 26 of the 29 counties in the state of Utah. The Company expects retail sales to
continue to grow in the state, with increases in the construction sector from a housing recovery
and continued strong growth in the extraction industries. A risk to the load forecast is
commodity prices, such as oil and natural gas, where volatility in prices and profitability can lead
to swings in production and employment which translates to potential swings in the retail sales
forecast.

To gain an understanding of one of the drivers of the changes in the Company retail sales
forecast for Utah, Figure A.4, below, shows the change in household and employment forecasts
for the 2011 IRP Update relative to the 2013 IRP load forecast. IHS Global Insight lowered its
forecast of household formation and employment for Utah relative to the November 2011 load
forecast citing slowed job gains at the end of 2011 and beginning of 2012.

Figure A.4 – IHS Global Insight Utah Household and Employment forecasts from the
November 2011 load forecast and the July 2012 load forecast

Oregon
The Oregon economy has faced a slow recovery from the 2008-2009 recession. Most of the
employment gains in 2010 were tepid and not enough to pull Oregon out of the deep hole the
recession had dug. The construction sector has been performing well relative to the country, due
HH in Thousands
Emp in Thousands
GSP in 2005 Million $
800.0
850.0
900.0
950.0
1,000.0
1,050.0
1,100.0
1,150.0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Utah Household Forecasts
November 2011 July 2012
1,100.00
1,200.00
1,300.00
1,400.00
1,500.00
1,600.00
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Utah Employment Forecast
November 2011 July 2012
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

6

to commercial construction projects, however, it is still dependent on the rebound of the
residential market. PacifiCorp serves 25 of the 36 counties in Oregon, but only 28 percent of
ultimate electric retail sales in the state of Oregon.4 Medford Oregon is the largest metropolitan
area served by PacifiCorp in Oregon and has seen tepid growth, less than 0.4 percent, since the
5.8 percent decline in gross domestic product (“GDP”) in 2009.5

Figure A.5 is an illustration of Oregon’s economic recovery relative to the Pacific and National
regions.

Figure A.5 – Recession Recovery: Changes in Employment (Percent)
Source: Globe Insight, April 2012

IHS Global Insight provides county level economic data to reflect the PacifiCorp service
territory in Oregon. A comparison of the IHS Global Insight forecast for the Company’s Oregon
service territory showing a decrease in household formation and employment from the 2013 IRP
load forecast relative to the 2011 IRP update provided in Figure A.6 below.

Figure A.6 – IHS Global Insight Oregon service territory Household and Employment
forecasts from the November 2011 load forecast and the July 2012 load forecast

4 Source: Oregon Public Utility Commission, 2011 Oregon Utility Statistics. 5 Source: Bureau of Economic Analysis.
950.0
1,000.0
1,050.0
1,100.0
1,150.0
1,200.0
1,250.0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Oregon Household Forecast
November 2011 July 2012
1,050
1,100
1,150
1,200
1,250
1,300
1,350
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Oregon Employment Forecast
November 2011 July 2012
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
7

Wyoming
Economic activity in Wyoming is expected to moderate significantly over the medium term.
Between 2012 and 2013, employment will expand just 1.0 percent annually on average. The
state’s employment growth was generally faster than the U.S. average since the recovery began,
however, the mining and extraction sector, which has been the main driver of growth in recent
years, will contract over the medium term despite a recent uptick in mining activity to serve
global growth. IHS Global Insight’s expects that federal permitting issues, land use policies, and
environmental concerns will restrain new exploration in the state.6 Figure A.7 is an illustration
of Wyoming’s economic recovery relative to the Mountain and National regions.

Figure A.7 – Recession Recovery: Changes in Employment (Percent)
Source: Globe Insight, April 2012

The Company serves 15 of the 23 counties in Wyoming, with the largest metropolitan area
served by the Company being Casper, Wyoming. A comparison of the IHS Global Insight
forecast for the Wyoming service territory household formation and employment from the 2011
IRP update and the 2013 IRP load forecast is provided in Figure A.8 below.

Figure A.8 – IHS Global Insight Wyoming service territory Household and Employment
forecasts from the November 2011 load forecast and the July 2012 load forecast

6 IHS Global Insight.
120
125
130
135
140
145
150
155
160
165
170
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Wyoming Household Forecast
November 2011 July 2012
120
130
140
150
160
170
180
190
200
210
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Wyoming Employment Forecast
November 2011 July 2012
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

8

The national level outlook for household formation was lowered in the February 2012 forecast,
which resulted in a lower household forecast for Wyoming. Housing starts in Wyoming will
increase over the medium-term, but from low levels, and despite the growth, they will remain
below their pre-recession peak levels. Employment growth was stronger than expected in 2011
due to the mining sector, while manufacturing finished weaker. Overall, there was not much
change in forecasted job growth in either manufacturing or total employment over the next five
years.7
Washington
The national recession took its toll on the Washington economy and reduced output and income
growth during the end of 2007. Washington’s best short-term strength is the presence of large
companies such as Boeing and Microsoft, which drive employment growth in their respective
industries and also create a local base of skilled labor that generates new companies. Nearly 60
percent of jobs in Washington are in the Seattle metro area, while PacifiCorp serves only the
following counties in Washington state: Benton, Columbia, Garfield, Klickitat, Walla Walla, and
Yakima. Yakima is the most populated area that the Company serves in Washington State and
has a large concentration in agriculture and food processing. Figure A.9 below shows the
changes in employment in Yakima since 1997, and the slow economic recovery since the
recession.8

Figure A.9 – Yakima, WA Metropolitan Statistical Area Employment Statistics, 1997
through 2012
Source: Bureau of Labor Statistics

IHS Global Insight projects near term reductions in gross state product and the food sector was
lower than their expectations in 2011, which pushed the forecast lower, especially near 2016. A
comparison of the IHS Global Insight forecast for the Washington service territory household
formation and employment from the 2011 IRP update and the 2013 IRP load forecast is provided
in Figure A.10 below.
7 Id. 8 Id.
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
9

Figure A.10 – IHS Global Insight Washington service territory Household and
Employment forecasts from the November 2011 load forecast and the July 2012 load
forecast

Idaho
The Company serves 14 of the 44 counties in the state of Idaho, with the majority of the
Company’s service territory in rural Idaho. Idaho’s recession recovery has been difficult, with
shut down’s in wood product manufacturing in 2009 and overseas job exports in the computer
and electronic manufacturing. According to the Idaho Department of Labor, rural counties have
been hit hardest in Idaho with a decline of 0.6 percent in gross state product in 2011 while urban
counties grew 1.1 percent. Figure A.11 is an illustration of Idaho’s economic recovery relative
to the West North Central and National regions.

Figure A.11 - Recession Recovery: Changes in Employment (Percent)
Source: IHS Global Insight, April, 2012

Idaho’s household growth has been weaker during the recession, and was therefore lowered in
the near-term forecast. The construction sector has continued to lag behind the national
economic recovery, but it is starting to show signs of growth.9

9 Id.
150
160
170
180
190
200
210
220
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Washington Household Forecast
November 2011 July 2012
140
150
160
170
180
190
200
210
220
230
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Washington Employment Forecast
November 2011 July 2012
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

10

Figure A.12 - IHS Global Insight Idaho service territory Household and Employment
forecasts from the November 2011 load forecast and the July 2012 load forecast

California
The California counties served by PacifiCorp are: Del Norte, Modoc, Shasta and Siskiyou. The
sectors that will drive growth over the next decade in the northern California counties served by
PacifiCorp are the professional and business services, trade and transportation, and construction.

Figure A.13 – IHS Global Insight Idaho service territory Household and Employment
forecasts from the November 2011 load forecast and the July 2012 load forecast

Weather

The Company’s load forecast is based on normal weather defined by the 20-year time period of
1992-2011. The Company updated its temperature spline models to the five-year time period of
2007-2011. The Company’s spline models are used to model the commercial and residential
class temperature sensitivity at varying temperatures.

75.0
80.0
85.0
90.0
95.0
100.0
105.0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Idaho Household Forecast
November 2011 July 2012
80.00
85.00
90.00
95.00
100.00
105.00
110.00
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Idaho Employment Forecast
November 2011 July 2012
25
27
29
31
33
35
37
39
41
43
45
47
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
California Household Forecast
November 2011 July 2012
-
5
10
15
20
25
30
35
40
45
50
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
California Employment Forecast
November 2011 July 2012
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
11

Statistically Adjusted End-Use (“SAE”)
The Company models sales per customer for the residential class using the SAE model, which
combines the end-use modeling concepts with traditional regression analysis techniques. Major
drivers of the SAE-based residential model are heating and cooling related variables, equipment
shares, saturation levels and efficiency trends, and economic drivers such as household size,
income and energy price. The Company uses ITRON for its load forecasting software and
services, as well as SAE. To predict future changes in the efficiency of the various end uses for
the residential class, an excel spreadsheet model obtained from ITRON was utilized. That model
includes appliance efficiency trends based on appliance life and past and future efficiency
standards. The model embeds all currently applicable laws and regulations regarding appliance
efficiency, along with life cycle models of each appliance. The life cycle models are based on the
decay and replacement rates, which are necessary to estimate how fast the existing stock of any
given appliance turns over and newer more efficient equipment replaces older less efficient
equipment. The underlying efficiency data is based on estimates of energy efficiency from the
US Department of Energy’s Energy Information Administration (EIA). The EIA estimates the
efficiency of appliance stocks and the saturation of appliances at the national level and for the
Census Regions.
Individual Customer Forecast
The Company updated its load forecast of a select group of large industrial customers, self-
generation facilities of large industrial customers, and data center forecasts within the respective
jurisdictions. Customer forecasts are provided by the customer to the Company through a
customer account manager (“CAM”).
Actual Load Data
The Company uses actual load data from January 1997 through March 2012, except for the
industrial class, for its monthly retail sales forecast. The historical data period used to develop
the industrial monthly sales is from January 2002 through March 2012.

The following tables are the annual actual retail sales, non-coincident peak, and coincident peak
by state that were used in calculating the 2013 IRP retail sales forecast.
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

12

Table A.5 Weather Normalized Jurisdictional Retail Sales 1997 through 2012

Table A.6 Non-Coincident Jurisdictional Peak 1997 through 2012

Year California Idaho Oregon Utah Washington Wyoming System
1997 768 3,032 13,551 16,647 3,978 7,391 45,367
1998 757 2,994 14,303 16,989 4,027 7,213 46,283
1999 774 3,077 13,736 17,998 4,059 7,250 46,894
2000 782 3,065 14,046 18,806 4,043 7,412 48,154
2001 787 3,003 13,380 18,613 4,005 7,716 47,504
2002 814 3,194 12,997 18,587 3,956 7,318 46,865
2003 836 3,197 13,222 18,997 4,141 7,640 48,033
2004 845 3,291 13,169 19,775 4,075 7,820 48,975
2005 839 3,237 13,209 20,233 4,229 8,028 49,775
2006 847 3,291 13,851 21,070 4,137 8,301 51,497
2007 878 3,400 14,026 21,861 4,060 8,499 52,724
2008 867 3,360 13,756 22,467 4,012 9,307 53,768
2009 827 2,956 13,093 22,053 4,073 9,193 52,195
2010 843 3,357 12,921 22,577 4,047 9,690 53,436
2011 798 3,432 12,923 23,317 3,996 9,771 54,236
2012 780 3,465 12,789 23,624 4,052 9,503 54,214
1997-2012 0.10%0.89%(0.38%)2.36%0.12%1.69%1.19%
*System retail sales do not include sales for resale
System Retail Sales - Gigawatt-hours (GWh)*
Average Annual Growth Rate
Year California Idaho Oregon Utah Washington Wyoming
1997 178 697 2,799 3,071 863 1,157
1998 212 686 3,118 3,213 863 1,063
1999 229 711 2,574 3,270 809 1,011
2000 176 686 2,605 3,721 785 1,062
2001 162 616 2,739 3,516 755 1,124
2002 174 713 2,639 3,810 771 1,113
2003 169 722 2,452 4,038 788 1,126
2004 193 708 2,525 3,900 920 1,111
2005 189 753 2,722 4,119 844 1,224
2006 180 723 2,724 4,357 822 1,208
2007 187 789 2,856 4,615 834 1,230
2008 187 759 2,922 4,523 923 1,339
2009 193 688 3,121 4,448 917 1,383
2010 176 777 2,553 4,491 893 1,366
2011 177 770 2,686 4,640 854 1,404
2012 159 800 2,551 4,764 797 1,338
1997-2012 -0.75%0.93%-0.62%2.97%-0.53%0.97%
*Non-coincident peak's do not include sales for resale
Average Annual Growth Rate
Non-Coincident Peak - Megawatts (MW)*
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
13

Table A.7 Jurisdictional Contribution to Coincident Peak 1997 through 2012

System Losses
System line losses were updated to reflect actual losses for the 5-years ending December 31,
2011.
Forecast Methodology Overview
Class 2 Demand-side Management Resources in the Load Forecast
PacifiCorp modeled Class 2 DSM as a resource option to be selected as part of a cost-effective
portfolio resource mix using the Company’s capacity expansion optimization model, System
Optimizer. The load forecast used for IRP portfolio development excluded forecasted load
reductions from Class 2 DSM. System Optimizer then determines the amount of Class 2 DSM—
expressed as supply curves that relate incremental DSM quantities with their costs—given the
other resource options and inputs included in the model. The use of Class 2 DSM supply curves,
along with the economic screening provided by System Optimizer, determines the cost-effective
mix of Class 2 DSM for a given scenario.
Modeling overview
The load forecast is developed by forecasting the monthly sales by customer class for each
jurisdiction. The residential and commercial class sales forecast by jurisdiction is developed as a
use per customer times the forecasted number of customers.

The customer forecasts are based on a combination of regression analysis and exponential
smoothing techniques using historical data from January 1997 to March 2012. For the residential
class, the Company forecasts the number of customers using IHS Global Insight’s forecast of
each state’s number of households as the major driver. For the commercial class, the Company
Year California Idaho Oregon Utah Washington Wyoming System
1997 174 616 2,799 3,014 843 1,129 7,770
1998 190 647 2,900 3,166 810 1,046 8,354
1999 214 697 2,547 3,242 804 983 7,972
2000 166 651 2,602 3,721 770 1,014 8,480
2001 152 573 2,739 3,514 724 1,091 7,899
2002 162 689 2,621 3,758 771 1,096 8,549
2003 156 594 2,452 4,038 774 1,083 8,922
2004 167 619 2,525 3,869 886 1,098 8,628
2005 173 681 2,501 4,056 844 1,182 8,937
2006 170 666 2,684 4,140 816 1,192 9,322
2007 178 701 2,844 4,473 793 1,230 9,775
2008 171 727 2,903 4,253 865 1,325 9,501
2009 193 517 3,121 4,394 891 1,361 9,420
2010 157 712 2,513 4,371 809 1,336 9,418
2011 154 747 2,510 4,638 798 1,384 9,431
2012 156 782 2,444 4,756 786 1,316 9,831
1997-2012 -0.73%1.60%-0.90%3.09%-0.47%1.03%1.58%
*Coincident peak's do not include sales for resale
Coincident Peak - Megawatts (MW)*
Average Annual Growth Rate
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

14

develops the forecast for number of customers with the forecasted residential customer numbers
used as the major driver.

The Company models sales per customer for the residential class using the SAE model discussed
above, which combines the end-use modeling concepts with traditional regression analysis
techniques.

For the commercial class, the Company forecasts sales per customer using regression analysis
techniques with non-manufacturing employment used as the major economic driver, in addition
to weather-related variables. As already described, the sales forecast for the residential and
commercial classes is the product of the number of customer forecast and the use per customer
forecast. The development of the forecast of monthly commercial sales involves an additional
step. To reflect the addition of a large “lumpy” change in sales such as a new data center,
monthly commercial sales are increased based on input from the Company’s CAM’s. Although
the scale is much smaller, the treatment of large commercial additions is similar to the previous
methodology for large industrial customer sales, which is discussed below.

Monthly sales for irrigation and street lighting are forecasted directly from historical sales
volumes, not as a product of the use per customer and number of customers.

The majority of industrial customers are modeled using regression analysis with trend and
economic variables. Manufacturing employment is used as the major economic driver. For a
small number of industrial customers, the largest on the Company’s system, the Company
individually forecasts these customers based on input from the customer and information
provided by the CAM’s.

Previously, the Company separated the industrial class into three categories: (1) existing
customers tracked by CAMs; (2) new large customers or expansions by existing large customers;
and (3) industrial customers that are not monitored by CAMs. The Company developed the
forecast for the first two categories through the usage data gathered by the CAMs based on direct
input from the customers, forecasted load factors, and the probability of the project occurrence.
The third category was forecasted using regression analysis consistent with how the total
industrial class is now forecast.

The Company has changed the way that it forecasts the majority of its large industrial customer
due to the fact that for existing large industrial customers and for new large industrial customers,
the Company found that the inputs provided by customers for their existing loads and for new
load tended to be overly optimistic and ultimately overstated. Therefore, the Company uses a
regression analysis for the entire industrial class, excluding those largest industrial customers and
taking into consideration historical patterns of industrial growth. The Company believes this is a
reasonable means of forecasting existing customer load and future growth. The Company
continues to monitor new load requests and planned expansions of existing customers for
significant changes that would require an adjustment to the forecast.

After the Company develops the forecasts of monthly energy sales by customer class, a forecast
of hourly loads is developed in two steps. First, monthly peak forecasts are developed for each
state. The monthly peak model uses historical peak-producing weather for each state, and
incorporates the impact of weather on peak loads through several weather variables that drive
heating and cooling usage. These weather variables include the average temperature on the peak
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
15

day and lagged average temperatures from up to two days before the day of the forecast. The
peak forecast is based on average monthly historical peak-producing weather for the 20-year
period 1992 through 2011. Second, the Company develops hourly load forecasts for each state
using hourly load models that include state-specific hourly load data, daily weather variables, the
20-year average temperatures identified above, a typical annual weather pattern, and day-type
variables such as weekends and holidays as inputs to the model. The hourly loads are adjusted to
match the monthly peaks from the first step above. Also, the hourly loads are adjusted so the
monthly sum of hourly loads equals monthly sales plus line losses.

After the hourly load forecasts are developed for each state, hourly loads are aggregated to the
total system level. The system coincident peaks can then be identified, as well as the
contribution of each jurisdiction to those monthly peaks.
Sales Forecast at the Customer Meter

This section provides total system and state-level forecasted retail sales summaries measured at
the customer meter by customer class including load reduction projections from new energy
efficiency measures from the Preferred Portfolio.

Table A.8 – System Annual Sales Forecast 2013 through 2022

Residential
Average annual growth of the residential class sales forecast declined from 0.7 percent in the
2011 IRP to 0.6 percent in the 2013 IRP. Residential use per customer across all six of
PacifiCorp’s states is changing due to changes in lighting efficiency standards resulting from the
2007 Federal Energy legislation and other energy efficiency and conservation programs.

The number of residential customers across PacifiCorp’s system is expected to grow at an annual
average rate of 0.7 percent with Rocky Mountain Power states adding 0.9 percent per year and
Pacific Power states adding 0.5 percent per year reaching approximately 1.6 million customer’s
by 2022. New customer’s on PacifiCorp’s system will contribute to declining average use of the
Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 15,892,523 16,972,872 19,240,051 1,245,659 141,420 278,110 53,770,635
2014 15,891,128 17,304,602 19,495,342 1,245,013 141,650 276,500 54,354,234
2015 15,961,243 17,579,339 19,486,869 1,244,379 141,720 275,360 54,688,910
2016 16,119,367 17,856,944 19,633,350 1,243,744 142,200 274,640 55,270,245
2017 16,178,084 18,036,974 19,858,482 1,242,654 141,830 273,960 55,731,984
2018 16,320,488 18,178,182 20,096,253 1,241,766 141,880 273,570 56,252,140
2019 16,467,391 18,285,923 20,362,319 1,240,676 141,930 273,270 56,771,509
2020 16,631,788 18,452,865 20,663,756 1,239,860 142,380 273,150 57,403,799
2021 16,689,586 18,514,785 20,855,752 1,238,940 142,050 272,920 57,714,033
2022 16,821,408 18,630,240 21,104,262 1,237,944 142,090 272,810 58,208,753
2013-22 0.63%1.04%1.03%-0.07%0.05%0.00%0.89%
Average Annual Growth Rate
System Retail Sales – Gigawatt-hours (GWh)
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

16

residential class due to the expectation that new single-family homes are likely to use gas for
space and water heating and use more efficient appliances than the existing customer base.
Commercial
Average annual growth of the commercial class sales forecast declined from 1.9 percent annual
average growth to 1.0 percent expected annual growth. The Company lowered its data center
load expectations in Utah and Oregon in the 2013 IRP load forecast due to lower than expected
initial loads and additional energy efficiency gains in the technology industry. Commercial loads
related to non-manufacturing employment are also lower, shown by the lower IHS Global Insight
forecast used in the July 2012 load forecast relative to the November 2011 forecast.

PacifiCorp commercial customers are expected to grow at an annual average rate of 0.8 percent,
reaching 231,818 customers in 2022. Rocky Mountain Power is expected to add commercial
customers at 1.1 percent annually, and Pacific Power is forecasted to add 0.4 percent annually.
Industrial
Industrial sales have decreased in the July 2012 load forecast to 1.0 percent average annual
growth through 2022. The November 2011 load forecast projected average annual growth of 1.9
percent for the industrial class, which reflected expected growth in the Utah and Wyoming
industrial extraction and manufacturing industries.

A portion of the Company’s industrial load is in the oil and natural gas business in Utah and
Wyoming, therefore, changes in natural gas and oil prices can impact the Company’s load
forecast. With the decline in natural gas prices over the last several years the Company has seen
several large industrial customers cancel expected new loads. Specifically, Wyoming’s mining
and natural resource sector is facing falling employment and over the past six month’s jobs in the
sector declined 0.8 percent.10 In addition, environmental legislation may impact new exploration
in the future. However, if natural gas prices were to increase in the short-term the Company may
face higher growth rates than currently reflected. The risk to the Company’s load forecast due to
commodity price changes is reflected in the high economic growth scenario discussed below.

Self-generation elections by some of the Company’s largest industrial customer’s reduced the
load forecast in the 2013 IRP. However, the majority of the load decreases also remove the
customer owned qualifying generation facility (QF) as a resource in the load resource balance.
For example, if 100 MW of load is now offset by a company’s QF generation that was
previously used to provide power to the PacifiCorp system, it is a zero net change to the load
resource balance.

As previously discussed, PacifiCorp changed the methodology that it uses to forecast the
majority of its large industrial customers and uses a regression methodology versus using
probability weighted customer forecasts. The change in methodology of the industrial load
forecast had a minimal impact on the industrial forecast.

10 IHS Global Insight.
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
17

State Summaries
Oregon
Table A.9 summarizes Oregon state forecasted retail sales growth by customer class.

Table A.9 – Forecasted Sales Growth in Oregon

Washington
Table A.10 summarizes Washington state forecasted retail sales growth by customer class.

Table A.10 – Forecasted Sales Growth in Washington

Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 5,411,440 5,258,837 2,147,544 238,210 36,750 0 13,092,781
2014 5,381,652 5,378,564 2,132,753 238,210 36,940 0 13,168,119
2015 5,380,412 5,440,133 2,137,674 238,210 36,960 0 13,233,388
2016 5,407,424 5,523,431 2,136,728 238,240 37,070 0 13,342,893
2017 5,402,600 5,576,598 2,134,157 238,210 36,960 0 13,388,526
2018 5,429,131 5,602,093 2,131,611 238,210 36,960 0 13,438,005
2019 5,463,250 5,630,591 2,131,077 238,210 36,960 0 13,500,088
2020 5,504,944 5,677,591 2,132,199 238,240 37,070 0 13,590,044
2021 5,510,144 5,690,504 2,134,050 238,210 36,960 0 13,609,867
2022 5,540,019 5,715,827 2,134,811 238,210 36,960 0 13,665,827
2013-22 0.26%0.93%-0.07%0.00%0.06%0.00%0.48%
Oregon Retail Sales – Gigawatt-hours (GWh)
Average Annual Growth Rate
Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 1,604,806 1,393,879 787,342 157,950 9,930 0 3,953,907
2014 1,596,722 1,396,080 783,374 157,950 9,870 0 3,943,996
2015 1,593,870 1,398,210 779,487 157,950 9,880 0 3,939,397
2016 1,601,704 1,402,674 780,101 157,960 9,910 0 3,952,349
2017 1,599,472 1,399,530 776,337 157,950 9,880 0 3,943,170
2018 1,608,223 1,401,755 775,894 157,950 9,880 0 3,953,702
2019 1,617,306 1,403,765 775,473 157,950 9,880 0 3,964,373
2020 1,628,171 1,409,972 777,641 157,960 9,910 0 3,983,654
2021 1,627,509 1,408,601 775,425 157,950 9,880 0 3,979,365
2022 1,634,603 1,410,691 775,362 157,950 9,880 0 3,988,486
2013-22 0.20%0.13%-0.17%0.00%-0.06%0.00%0.10%
Washington Retail Sales – Gigawatt-hours (GWh)
Average Annual Growth Rate
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

18

California
Table A.11 summarizes California state forecasted sales growth by customer class.

Table A.11 – Forecasted Retail Sales Growth in California

Utah
Table A.12 summarizes Utah state forecasted sales growth by customer class.

Table A.12 – Forecasted Retail Sales Growth in Utah

Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 380,422 274,429 24,148 95,740 2,480 0 777,219
2014 377,522 274,946 23,399 95,740 2,480 0 774,087
2015 376,263 275,410 22,500 95,740 2,480 0 772,392
2016 377,322 275,948 22,440 95,760 2,480 0 773,951
2017 375,569 275,028 22,247 95,740 2,480 0 771,063
2018 376,273 275,115 22,165 95,740 2,480 0 771,773
2019 377,028 275,052 22,082 95,740 2,480 0 772,382
2020 378,117 275,582 22,074 95,760 2,480 0 774,013
2021 375,925 274,252 21,912 95,740 2,480 0 770,309
2022 375,445 273,446 21,824 95,740 2,480 0 768,935
2013-22 -0.15%-0.04%-1.12%0.00%0.00%0.00%-0.12%
Average Annual Growth Rate
California Retail Sales – Gigawatt-hours (GWh)
Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 6,720,885 7,979,093 7,754,583 187,500 77,610 278,110 22,997,781
2014 6,734,483 8,145,495 7,894,805 187,500 77,650 276,500 23,316,432
2015 6,782,580 8,315,720 7,753,540 187,500 77,650 275,360 23,392,350
2016 6,875,135 8,460,421 7,760,376 187,520 77,870 274,640 23,635,961
2017 6,928,116 8,563,743 7,912,169 187,500 77,650 273,960 23,943,138
2018 7,015,004 8,648,996 8,054,146 187,500 77,650 273,570 24,256,866
2019 7,099,052 8,701,692 8,225,171 187,500 77,650 273,270 24,564,335
2020 7,191,309 8,783,756 8,399,911 187,520 77,870 273,150 24,913,516
2021 7,241,742 8,820,185 8,525,736 187,500 77,650 272,920 25,125,732
2022 7,324,392 8,889,035 8,681,001 187,500 77,650 272,810 25,432,388
2013-22 0.96%1.21%1.26%0.00%0.01%-0.21%1.12%
Utah Retail Sales – Gigawatt-hours (GWh)
Average Annual Growth Rate
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST
19

Idaho
Table A.13 summarizes Idaho state forecasted sales growth by customer class.

Table A.13 – Forecasted Retail Sales Growth in Idaho

Wyoming
Table A.14 summarizes Wyoming state forecasted sales growth by customer class.

Table A.14 – Forecasted Retail Sales Growth in Wyoming

Alternative Load Forecast Scenarios

The purpose of the alternative load forecast cases is to determine the resource type and timing
impacts resulting from a change in the economy or system peaks as a result of higher than
normal temperatures.

Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 705,895 438,865 1,711,758 545,899 2,710 0 3,405,127
2014 717,289 448,476 1,716,591 545,153 2,770 0 3,430,279
2015 731,279 458,456 1,719,879 544,399 2,810 0 3,456,823
2016 748,393 469,083 1,726,161 543,584 2,890 0 3,490,112
2017 760,771 476,315 1,720,329 542,504 2,920 0 3,502,838
2018 774,717 483,775 1,720,487 541,526 2,970 0 3,523,475
2019 787,131 490,076 1,720,573 540,336 3,020 0 3,541,136
2020 799,309 497,675 1,725,216 539,330 3,070 0 3,564,601
2021 806,807 502,048 1,719,649 538,390 3,140 0 3,570,035
2022 816,694 507,401 1,720,681 537,314 3,180 0 3,585,271
2013-22 1.63%1.63%0.06%-0.18%1.79%0.00%0.57%
Idaho Retail Sales – Gigawatt-hours (GWh)
Average Annual Growth Rate
Year Residential Commercial Industrial Irrigation Lighting Other Total
2013 1,069,076 1,627,768 6,814,676 20,360 11,940 0 9,543,819
2014 1,083,460 1,661,040 6,944,420 20,460 11,940 0 9,721,321
2015 1,096,840 1,691,410 7,073,790 20,580 11,940 0 9,894,559
2016 1,109,388 1,725,387 7,207,544 20,680 11,980 0 10,074,979
2017 1,111,556 1,745,760 7,293,243 20,750 11,940 0 10,183,249
2018 1,117,141 1,766,449 7,391,950 20,840 11,940 0 10,308,320
2019 1,123,623 1,784,748 7,487,944 20,940 11,940 0 10,429,195
2020 1,129,938 1,808,290 7,606,714 21,050 11,980 0 10,577,972
2021 1,127,459 1,819,195 7,678,982 21,150 11,940 0 10,658,726
2022 1,130,254 1,833,840 7,770,582 21,230 11,940 0 10,767,847
2013-22 0.62%1.33%1.47%0.47%0.00%0.00%1.35%
Wyoming Retail Sales – Gigawatt-hours (GWh)
Average Annual Growth Rate
PACIFICORP – 2013 IRP APPENDIX A – LOAD FORECAST

20

The July 2012 forecast is the baseline (Medium) scenario. For the high and low economic growth
scenarios assumptions from IHS Global Insight were applied to the economic drivers in the
Company’s load forecasting models. These growth assumptions were extended for the entire
forecast horizon.

Recognizing the volatility associated with the oil and gas extraction industries, PacifiCorp
applied additional assumptions for the Utah and Wyoming industrial class load forecasts in the
high and low scenario. Specifically, the Company analyzed the increased uncertainty of the
industrial load forecast as it moves further out in time. In order to capture this increased
uncertainty the Company modeled 100 possible annual loads for each year based on the standard
error of the medium scenario regression equation. The 100 load values are then ranked and the
Company selected the 95th percentile and 5th percentile of the Utah and Wyoming industrial
loads for both the low and high growth scenarios. Lastly, in the high growth scenario the
Company removed the assumption that a large customer owned generation facility was
constructed in 2015.

For the 1-in-20 year (5 percent probability) extreme weather scenario, the Company used 1-in-20
year peak weather for summer (July) months for each state. The 1-in-20 year peak weather is
defined as the year for which the peak has the chance of occurring once in 20 years.

Figure A.14 shows the comparison of the above scenarios relative to the Base Case scenario.

Figure A.14 – Load Forecast Scenarios for 1-in-20 Weather, High, Base Case and Low

PACIFICORP – 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

21

APPENDIX B – IRP REGULATORY COMPLIANCE
Introduction

This appendix describes how PacifiCorp’s 2013 IRP complies with (1) the various state
commission IRP standards and guidelines, (2) specific analytical requirements stemming from
acknowledgment orders for the Company’s last IRP (“2011 IRP”), and (3) state commission IRP
requirements stemming from other regulatory proceedings.

Included in this appendix are the following tables:

● Table B.1 – Provides an overview and comparison of the rules in each state for which IRP
submission is required.11
● Table B.2 – Provides a description of how PacifiCorp addressed the 2011 IRP
acknowledgement requirements and other commission directives.
● Table B.3 – Provides an explanation of how this plan addresses each of the items contained
in the Oregon IRP guidelines, including new guidelines issued in January 2012 for assessing
flexible resource demand and supplies.
● Table B.4 – Provides an explanation of how this plan addresses each of the items contained
in the Public Service Commission of Utah IRP Standard and Guidelines issued in June 1992.
● Table B.5 – Provides an explanation of how this plan addresses each of the items contained
in the Washington Utilities and Trade Commission IRP guidelines issued in January 2006.
● Table B.6 – Provides an explanation of how this plan addresses each of the items contained
in the Wyoming Public Service Commission IRP guidelines.
General Compliance

PacifiCorp prepares the IRP on a biennial basis and files the IRP with state commissions. The
preparation of the IRP is done in an open public process with consultation between all interested
parties, including commissioners and commission staff, customers, and other stakeholders. This
open process provides parties with a substantial opportunity to contribute information and ideas
in the planning process, and also serves to inform all parties on the planning issues and approach.
The public input process for this IRP, described in Volume I, Chapter 2 (Introduction), as well as
Volume II, Appendix C (Public Input Process) fully complies with IRP Standards and
Guidelines.

The IRP provides a framework and plan for future actions to ensure PacifiCorp continues to
provide reliable and least-cost electric service to its customers. The IRP evaluates, over a twenty-
year planning period, the future loads of PacifiCorp customers and the capability of existing
resources to meet this load.
11 California guidelines exempt a utility with less than 500,000 customers in the state from filing an IRP. However,
PacifiCorp files its IRP and IRP supplements with the California Public Utilities Commission to address the
Company plan for compliance with the California RPS requirements.
PACIFICORP – 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

22

To fill any gap between changes in loads and existing resources, while taking into consideration
potential early retirement of existing coal units as an alternative to investments that achieve
compliance with environmental regulations, the IRP evaluates a broad range of available
resource options, as required by state commission rules. These resource alternatives include
supply-side, demand-side, and transmission alternatives. The evaluation of the alternatives in the
IRP, as detailed in Volume I, Chapters 7 (Modeling and Portfolio Evaluation Approach) and
Chapter 8 (Modeling and Portfolio Selection Results) meets this requirement and includes the
impact to system costs, system operations, supply and transmission reliability, and the impacts of
various risks, uncertainties and externality costs that could occur. To perform the analysis and
evaluation, PacifiCorp employs a suite of models that simulate the complex operation of the
PacifiCorp system and its integration within the Western Interconnection. The models allow for a
rigorous testing of a reasonably broad range of commercially feasible resource alternatives
available to PacifiCorp on a consistent and comparable basis. The analytical process, including
the risk and uncertainty analysis, fully complies with IRP Standards and Guidelines, and is
described in detail in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach).

The IRP analysis is designed to define a resource plan that is least cost, after consideration of
risks and uncertainties. To test resource alternatives and identify a least-cost, risk adjusted plan,
portfolio resource options were developed and tested against each other. This testing included
examination of various tradeoffs among the portfolios, such as average cost versus risk,
reliability, customer rate impacts, and average annual CO2 emissions. This portfolio analysis and
the results and conclusions drawn from the analysis are described in Volume I, Chapter 8
(Modeling and Portfolio Selection Results).

Consistent with the IRP Standards and Guidelines of Oregon, Utah, and Washington, this IRP
includes an Action Plan in Volume I, Chapter 9 (Action Plan). The Action Plan details near-term
actions that are necessary to ensure PacifiCorp continues to provide reliable and least-cost
electric service after considering risk and uncertainty. Volume I, Chapter 9 (Action Plan) also
provides a progress report on action items contained in the 2011 IRP and 2011 IRP Update.

The 2013 IRP and the related Action Plan are filed with each commission with a request for
prompt acknowledgment. Acknowledgment means that a commission recognizes the IRP as
meeting all regulatory requirements at the time the acknowledgment is made. In the case where a
commission acknowledges the IRP in part or not at all, PacifiCorp works with the commission to
modify and re-file an IRP that meets acknowledgment standards.

State commission acknowledgment orders or letters typically stress that an acknowledgment
does not indicate approval or endorsement of IRP conclusions or analysis results. Similarly, an
acknowledgment does not imply that favorable ratemaking treatment for resources proposed in
the IRP will be given.
California
Subsection (i) of California Public Utilities Code, Section 454.5, states that utilities serving less
than 500,000 customers in the state are exempt from filing an Integrated Resource Plan for
California. The number of PacifiCorp customers, located in the most northern parts of the state,
fall below this threshold. PacifiCorp filed for and received an exemption on July 10, 2003.
PACIFICORP – 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

23

Idaho
The Idaho Public Utilities Commission’s Order No. 22299, issued in January 1989, specifies
integrated resource planning requirements. The Order mandates that PacifiCorp submit a
Resource Management Report (RMR) on a biennial basis. The intent of the RMR is to describe
the status of IRP efforts in a concise format, and cover the following areas:

Each utility's RMR should discuss any flexibilities and analyses considered during
comprehensive resource planning, such as: (1) examination of load forecast
uncertainties; (2) effects of known or potential changes to existing resources; (3)
consideration of demand and supply side resource options; and (4) contingencies
for upgrading, optioning and acquiring resources at optimum times (considering
cost, availability, lead time, reliability, risk, etc.) as future events unfold.

This IRP is submitted to the Idaho PUC as the Resource Management Report for 2013, and fully
addresses the above report components. The IRP also evaluates demand side management
(DSM) using a load decrement approach, as discussed in Volume I, Chapter 6 (Resource
Options) and Volume II, Appendix D (Demand-Side Management and Supplemental Resources).
This approach is consistent with using an avoided cost approach to evaluating DSM as set forth
in IPUC Order No. 21249.
Oregon
This IRP is submitted to the Oregon PUC in compliance with its planning guidelines issued in
January 2007 (Order No. 07-002). The Commission’s IRP guidelines consist of substantive
requirements (Guideline 1), procedural requirements (Guideline 2), plan filing, review, and
updates (Guideline 3), plan components (Guideline 4), transmission (Guideline 5), conservation
(Guideline 6), demand response (Guideline 7), environmental costs (Guideline 8, Order No. 08-
339), direct access loads (Guideline 9), multi-state utilities (Guideline 10), reliability (Guideline
11), distributed generation (Guideline 12), resource acquisition (Guideline 13), and flexible
resource capacity (Order No. 12-01312). Consistent with the earlier guidelines (Order 89-507),
the Commission notes that acknowledgment does not guarantee favorable ratemaking treatment,
only that the plan seems reasonable at the time acknowledgment is given.

Table B.3 provides detail on how this plan addresses each of the requirements.
Utah
This IRP is submitted to the Public Service Commission of Utah in compliance with its 1992
Order on Standards and Guidelines for Integrated Resource Planning (Docket No. 90-2035-01,
“Report and Order on Standards and Guidelines”). Table B.4 documents how PacifiCorp
complies with each of these standards.
Washington
This IRP is submitted to the Washington Utilities and Transportation Commission (WUTC) in
compliance with its rule requiring least cost planning (Washington Administrative Code 480-
12 Public Utility Commission of Oregon, Order No. 12-013, Docket No. 1461, January 19, 2012.
PACIFICORP – 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

24

100-238), and the rule amendment issued on January 9, 2006 (WAC 480-100-238, Docket No.
UE-030311). In addition to a least cost plan, the rule requires provision of a two-year action plan
and a progress report that “relates the new plan to the previously filed plan.”

The rule requires PacifiCorp to submit a work plan for informal commission review not later
than 12 months prior to the due date of the plan. The work plan is to lay out the contents of the
IRP, the resource assessment method, and timing and extent of public participation. PacifiCorp
filed a work plan with the Commission on March 28, 2012.

Table B.5 provides detail on how this plan addresses each of the rule requirements.

Wyoming
In 2008, Wyoming proposed draft rule 253 for any utility serving Wyoming to file its Integrated
Resource Plan with the commission. The rule went into effect in September 2009.

Rule 253: Integrated Resource Planning.
Any utility serving in Wyoming required to file an integrated resource plan (IRP) in any
jurisdiction, shall file that IRP with the Wyoming Public Service Commission. The
Commission may require any utility serving in Wyoming to prepare and file an IRP when
the Commission determines it is in the public interest. Commission advisory staff shall
review the IRP as directed by the Commission and report its findings to the Commission
in open meeting. The review may be conducted in accordance with guidelines set from
time to time as conditions warrant.

PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

25

Table B.1 – Integrated Resource Planning Standards and Guidelines Summary by State
Topic Oregon Utah Washington Idaho Wyoming
Source Order No. 07-002,
Investigation Into
Integrated Resource
Planning, January 8, 2007,
as amended by Order No.
07-047.

Order No. 08-339,
Investigation into the
Treatment of CO2 Risk in
the Integrated Resource
Planning Process, June 30,
2008.

Order No. 09-041, New
Rule OAR 860-027-0400,
implementing Guideline 3,
“Plan Filing, Review, and
Updates”.

Order No. 12-013,
“Investigation of Matters
related to Electric
Vehicle Charging”,
January 19, 2012.

Docket 90-2035-01
Standards and
Guidelines for Integrated
Resource Planning June
18, 1992.
WAC 480-100-251 Least
cost planning, May 19,
1987, and as amended
from WAC 480-100-238
Least Cost Planning
Rulemaking, January 9,
2006 (Docket # UE-
030311)
Order 22299
Electric Utility
Conservation Standards
and Practices
January, 1989.
Wyoming General
Regulations, Chapter 2
(Introduction), Section
253.
Filing
Requirements Least-cost plans must be
filed with the Commission.
An Integrated Resource
Plan (IRP) is to be
submitted to
Commission.
Submit a least cost plan to
the Commission. Plan to
be developed with
consultation of
Commission staff, and
with public involvement.
Submit “Resource
Management Report”
(RMR) on planning
status. Also file progress
reports on conservation,
low-income programs,
lost opportunities and
capability building.
Any utility serving in
Wyoming required to file
an integrated resource plan
(IRP) in any jurisdiction,
shall file that IRP with the
Wyoming Public Service
Commission.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

26

Topic Oregon Utah Washington Idaho Wyoming
Frequency Plans filed biennially,
within two years of its
previous IRP
acknowledgment order. An
annual update to the most
recently acknowledged IRP
is required to be filed on or
before the one-year
anniversary of the
acknowledgment order
date. While informational
only, utilities may request
acknowledgment of
proposed changes to the
action plan.

File biennially. File biennially. RMR to be filed at least
biennially. Conservation
reports to be filed
annually. Low income
reports to be filed at least
annually. Lost
Opportunities reports to
be filed at least annually.
Capability building
reports to be filed at least
annually.
The Commission may
require any utility serving
in Wyoming to prepare and
file an IRP when the
Commission determines it
is in the public interest.
Commission
Response
Least-cost plan (LCP)
acknowledged if found to
comply with standards and
guidelines. A decision
made in the LCP process
does not guarantee
favorable rate-making
treatment. The OPUC may
direct the utility to revise
the IRP or conduct
additional analysis before
an acknowledgment order
is issued.

Note, however, that Rate
Plan legislation allows pre-
approval of near-term
resource investments.
IRP acknowledged if
found to comply with
standards and guidelines.
Prudence reviews of new
resource acquisitions
will occur during rate
making proceedings.
The plan will be
considered, with other
available information,
when evaluating the
performance of the utility
in rate proceedings.

WUTC sends a letter
discussing the report,
making suggestions and
requirements and
acknowledges the report.
Report does not constitute
pre-approval of proposed
resource acquisitions.

Idaho sends a short letter
stating that they accept
the filing and
acknowledge the report as
satisfying Commission
requirements.
Commission advisory staff
shall review the IRP as
directed by the
Commission and report its
findings to the
Commission in open
meeting.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

27

Topic Oregon Utah Washington Idaho Wyoming
Process The public and other
utilities are allowed
significant involvement in
the preparation of the plan,
with opportunities to
contribute and receive
information. Order 07-002
requires that the utility
present IRP results to the
OPUC at a public meeting
prior to the deadline for
written public comments.
Commission staff and
parties should complete
their comments and
recommendations within
six months after IRP filing.
Competitive secrets must
be protected.

Planning process open to
the public at all stages.
IRP developed in
consultation with the
Commission, its staff,
with ample opportunity
for public input.
In consultation with
Commission staff,
develop and implement a
public involvement plan.
Involvement by the public
in development of the
plan is required.
PacifiCorp is required to
submit a work plan for
informal commission
review not later than 12
months prior to the due
date of the plan. The work
plan is to lay out the
contents of the IRP,
resource assessment
method, and timing and
extent of public
participation.
Utilities to work with
Commission staff when
reviewing and updating
RMRs. Regular public
workshops should be part
of process.
The review may be
conducted in accordance
with guidelines set from
time to time as conditions
warrant.

The Public Service
Commission of Wyoming,
in its Letter Order on
PacifiCorp’s 2008 IRP
(Docket No. 2000-346-EA-
09) adopted Commission
Staff’s recommendation to
expand the review process
to include a technical
conference, an expanded
public comment period,
and filing of reply
comments.
Focus 20-year plan, with end-
effects, and a short-term
(two-year) action plan. The
IRP process should result
in the selection of that mix
of options which yields, for
society over the long run,
the best combination of
expected costs and
variance of costs.
20-year plan, with short-
term (four-year) action
plan. Specific actions
for the first two years
and anticipated actions
in the second two years
to be detailed. The IRP
process should result in
the selection of the
optimal set of resources
given the expected
combination of costs,
risk and uncertainty.
20-year plan, with short-
term (two-year) action
plan.
The plan describes mix of
resources sufficient to
meet current and future
loads at “lowest
reasonable” cost to utility
and ratepayers. Resource
cost, market volatility
risks, demand-side
resource uncertainty,
resource dispatchability,
ratepayer risks, policy
impacts, and
environmental risks, must
be considered.
20-year plan to meet load
obligations at least-cost,
with equal consideration
to demand side resources.
Plan to address risks and
uncertainties. Emphasis
on clarity,
understandability,
resource capabilities and
planning flexibility.
Identification of least-
cost/least-risk resources
and discussion of
deviations from least-cost
resources or resource
combinations.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

28

Topic Oregon Utah Washington Idaho Wyoming
Elements Basic elements include:
 All resources evaluated on
a consistent and
comparable basis.
 Risk and uncertainty must
be considered.
 The primary goal must be
least cost, consistent with
the long-run public
interest.
 The plan must be
consistent with Oregon and
federal energy policy.
 External costs must be
considered, and quantified
where possible. OPUC
specifies environmental
adders (Order No. 93-695,
Docket UM 424).
 Multi-state utilities should
plan their generation and
transmission systems on an
integrated-system basis.
 Construction of resource
portfolios over the range of
identified risks and
uncertainties.
 Portfolio analysis shall
include fuel transportation
and transmission
requirements.
 Plan includes conservation
potential study, demand
response resources,
environmental costs, and
distributed generation
technologies..
 Avoided cost filing
required within 30 days of
acknowledgment.
IRP will include:
 Range of forecasts of
future load growth
 Evaluation of all
present and future
resources, including
demand side, supply
side and market, on a
consistent and
comparable basis.
 Analysis of the role of
competitive bidding
 A plan for adapting to
different paths as the
future unfolds.
 A cost effectiveness
methodology.
 An evaluation of the
financial, competitive,
reliability and
operational risks
associated with
resource options, and
how the action plan
addresses these risks.
 Definition of how
risks are allocated
between ratepayers
and shareholders
 DSM and supply side
resources evaluated at
“Total Resource Cost”
rather than utility cost.
The plan shall include:
 A range of forecasts of
future demand using
methods that examine the
effect of economic forces
on the consumption of
electricity and that address
changes in the number, type
and efficiency of electrical
end-uses.
 An assessment of
commercially available
conservation, including
load management, as well
as an assessment of
currently employed and
new policies and programs
needed to obtain the
conservation improvements.
 Assessment of a wide range
of conventional and
commercially available
nonconventional generating
technologies
 An assessment of
transmission system
capability and reliability.
 A comparative evaluation
of energy supply resources
(including transmission and
distribution) and
improvements in
conservation using “lowest
reasonable cost” criteria.
 Integration of the demand
forecasts and resource
evaluations into a long-
range (at least 10 years)
plan.
 All plans shall also include
a progress report that relates
the new plan to the
previously filed plan.
Discuss analyses
considered including:
 Load forecast
uncertainties;
 Known or potential
changes to existing
resources;
 Equal consideration of
demand and supply side
resource options;
 Contingencies for
upgrading, optioning
and acquiring resources
at optimum times;
 Report on existing
resource stack, load
forecast and additional
resource menu.
Proposed Commission
Staff guidelines issued on
January 2009 cover:
 Sufficiency of the
public comment
process
 Utility strategic goals
and preferred portfolio
 Resource need and
changes in expected
resource acquisitions
 Environmental
impacts
 Market purchase
evaluation
 Reserve margin
analysis
 Demand-side
management and
energy efficiency
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

29

Table B.2 – Handling of 2011 IRP Acknowledgment and Other IRP Requirements
Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
Idaho
Order No. PAC-E-
11-10, p. 10.
[T]he Commission orders the Company
to advise the Commission of any changes
made to its system-wide IRP
methodology or IRP results emanating
from the review conducted by another
state utility Commission.
PacifiCorp summarizes its IRP methodology in
Volume I, Chapter 7 of the 2013 IRP, which is
consistent with methods used in the 2011 IRP. While
advancements in modeling methods have been
implemented, they were done so at the discretion of the
Company.

Order No. 12-082,
p. 9-10.
We direct PacifiCorp to continue
discussions with Staff and other parties,
started during review of the company’s
2011 IRP, to prepare for the company’s
next IRP cycle. In particular, we direct
PacifiCorp to convene two workshops to
address concerns in two related areas.

The first workshop should address the
development of candidate resource
portfolios for the next IRP. PacifiCorp
currently uses the System Optimizer
model to develop the candidate resource
portfolios it will consider in an IRP. The
company identifies future scenarios
comprised of key model inputs and the
System Optimizer model selects an
"optimal" resource portfolio for each
scenario. We are concerned that the
resource portfolio with the best
combination of cost and risk for the
utility and its ratepayers may not be
"optimal" for any one particular scenario.
In other words, the best portfolio may be
one that performs well across a wide
range of future scenarios but is not
"optimal" for any one scenario. We are
concerned that the process used by
PacifiCorp to develop candidate resource
portfolios may be limiting the diversity of
portfolios considered in the IRP.

The second workshop should address the
development of the company's load and
resource balances for both capacity and
energy and the appropriate capacity
planning reserve margin. The workshop
should also address the development of
an IRP action plan that identifies the
contribution of each planned resource to
the company's capacity and energy
balances. In PacifiCorp's IRP it is often
difficult to identify the contribution of
PacifiCorp held a “portfolio development roundtable”
discussion at the June 20, 2012 public meeting to
address the first workshop requirement. The Company
outlined its goals to enhance resource diversity among
portfolios and requested input from Oregon
Commission staff and other meeting participants on an
enhanced portfolio development framework.
Incorporating stakeholder comments, the Company
introduced draft core case definitions at the August 13,
2012 a public meeting and discussed with parties
transmission scenarios and benefit analysis. Further
discussions on portfolio development were held at the
September 14, 2012 public meeting. One outcome of
the discussions was PacifiCorp’s proposal to include
stakeholder-defined portfolio development scenarios to
achieve greater resource diversity. A subsequent public
meeting was held on January 31, 2013 to review the
core portfolio results with an update on modeling
results at the February 27, 2013 public meeting.
Discussion of stochastic modeling results of portfolios
was done at the March 21, 2013 and April 5, 2013
public meetings. Sensitivity case results were reviewed
with parties at the April 17, 2013 public meeting.

The workshop to discuss the planning reserve margin
and development of load & resource balances (both
capacity and energy) was held during the August 2,
2012, public input meeting. The major issues identified
by public stakeholders for the 2011 IRP planning
reserve margin study were addressed through the 2013
IRP study design. The Company held a conference call
on September 24, 2012 to discuss planning reserve
margin modeling. At the public meeting on November
27, 2013 the study results and recommendation were
reviewed by the stakeholders. The Company discussed
with parties at the August 2, 2012 public input meeting
different ways to report the energy contribution from
preferred portfolio resources. Volume I, Chapter 8
(Modeling and Portfolio Selection Results) of the 2013
IRP contains figures showing how preferred portfolio
resources contribute to growing loads over time.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

30

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
each planned resource to the energy
balance. Our overall concern is that it is
difficult to identify how the planned
resource actions are matched to meeting
the capacity and energy needs of the
company.
Order No. 12-493,
p.33.
We expect a utility to fully evaluate all
major investments that have implications
for the utility’s resource mix – including
those where the investment will extend
the useful life of an asset and where a
plant shutdown is an option – in its IRP.
Although the IRP process is not a legal
prerequisite for a utility to seek recovery
of investment in rates, we have repeatedly
stated that the IRP process serves as a
complement to the rate-making process
and reduces the uncertainty of recovery.
We give considerable weight to actions
that are consistent with an acknowledged
IRP, and consistency with the plan is
evidence to support favorable rate-
making treatment of the action. If a utility
seeks rate recovery of a significant
investment that has not been included in
an IRP, we will hold the utility to the
same level of rigorous review required by
the IRP to demonstrate the prudence of a
project.

Regardless of whether a utility intends to
use the IRP process for a resource
decisions, we expect to be kept informed
about anticipated majority utility
investment.
The Company has analyzed in the 2013 IRP major
environmental investments required to meet known and
prospective compliance obligations across PacifiCorp’s
existing coal fleet.

Building upon modeling techniques developed in the
2011 IRP and the 2011 IRP Update, environmental
investments specific to individual coal units required to
achieve compliance with known and prospective federal
and state environmental regulations have been integrated
into the portfolio modeling process in the 2013 IRP.
Potential alternatives to coal unit environmental
investments 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. See Volume I, Chapters 7 (Modeling
and Portfolio Evaluation Approach), and Chapter 8
(Modeling and Portfolio Selection Results).

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.

Utah
Order, Docket No. 11-
2035-01, p. 17.
We generally accept the Company’s
approach [on externality cost values] and
suggest continued discussion in the IRP
public input process to determine a
reasonable and manageable range of
values. This could also include the notion
that once a permit has been obtained, the
external costs addressed through the permit
are internalized; all other values should be
treated as uncertainties through scenario
development and a range of potential
values.
PacifiCorp discussed the approach for modeling
externality costs with CO2 price scenarios. The
Company discussed with stakeholders CO2 price levels
and in the context of defining portfolio case definitions
and in interpreting model results at several public
meetings (6/20/12, 7/13/12, 9/14/12, 1/13/2013,
3/21/2013, 4/5/2013, 4/17/2013). The Company worked
closely with stakeholders, adopting numerous
recommendations, in defining assumptions for portfolio
development cases and sensitivities.

Costs for adding pollution control equipment to meet
current and potential environmental regulations are
explicitly incorporated into the cost for affected
generating assets, whether new or existing. See Volume
I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) and Volume II, Appendix M (Case Study
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

31

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
Fact Sheets).
Order, Docket No. 11-
2035-01, p. 15.
[A]ny Potentials Study used to inform the
IRP should be filed concurrently with the
IRP.
The Demand-side Management Potentials study is
posted to PacifiCorp’s IRP website, referenced in
Volume II, Appendix D (Demand-Side Management and
Supplemental Resources). 13

An updated stochastic loss of load probability study
prepared by Ventyx, is included in Volume II, Appendix
I (Stochastic Loss of Load Study).

A 2011 Geothermal Information Request was posted for
stakeholder review on PacifiCorp’s IRP website.14

An energy storage screening study for integrating
variable energy resources was posted for stakeholder
review on the PacifiCorp IRP website.15
Order, Docket No. 11-
2035-01, p. 21.
The Company should conduct a meeting to
explain its development of DSM resource
bundles. This meeting could be in an IRP
technical conference, a DSM Advisory
Group meeting or an IRP public input
meeting. The Company should address its
plans to closely monitor DSM resource
acquisitions for adherence to IRP forecasts
in its next IRP.
The topic of modeling energy efficiency resources was
covered at the June 20, 2012 public input meeting, and
was also discussed at the Utah stakeholder meeting held
August 14, 2012. PacifiCorp distributed a paper on
energy efficiency ramping assumptions October 10,
2012. Monitoring of DSM resource acquisitions is
covered in Volume I, Chapter 9 (Action Plan).
Order, Docket No. 11-
2035-01, p. 20.
The Company should consider hosting a
public input meeting to discuss the
objectives of and options for addressing
long-term load volatility and long-term
load-growth uncertainty and to respond to
the five GDS recommendations. The
Company should provide interested parties
with any analysis it performs regarding the
five GDS recommendations in advance of
the meeting.
GDS recommendations:
1. PacifiCorp should obtain and
examine economic forecasts from one
or two vendors in addition to IHS
Global Insights.
2. GDS continues to contend that use of
a measure of commercial and industrial
output (e.g., retail sales or gross
regional product) would be a better
PacifiCorp held a public meeting on September 14,
2012, to discuss the GDS report and PacifiCorp's plans
for addressing the recommendations.

13http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/2013
IRP_EnergyEfficiencyResourceRamping_10-22-2012.pdf 14http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/Pacif
iCorp_GIR_Report-PUBLIC_04-16-12.pdf 15http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/Repo
rt_Energy-Storage-Screening-Study2012.pdf
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

32

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
theoretical driver in the commercial and
industrial sales models.
3. We recommend that PacifiCorp
initiate an investigation into line losses
for Utah and Oregon, specifically, and
for any other jurisdictions that
exhibiting a strong trend over the last
seven years and adjust their line loss
projections accordingly.
4. GDS recommends the Company
review economic range forecasts
prepared by other utilities and produce
ranges that have greater uncertainty
built into them as the forecast horizon
expands.
5. GDS recommends the Company
move from a 1-in-10 year weather
scenario to a 1-in-20 year weather
scenario to produce an even more
extreme weather case.
Order, Docket No.
11-2035-01, p. 20.
[W]e have also found the state historic
load information contained in IRPs to be
valuable and prefer the Company include
a ten year history of monthly energy,
coincident peak, and non-coincident
peak, by state, in all future IRPs.
State historical load information is reported in Volume
II, Appendix A (Load Forecast Details).
Order, Docket No.
11-2035-01, pp. 7-8.
For acknowledgement in the future, the
Company should provide all stochastic
portfolio performance measures for the
Preferred Portfolio and identify the
additional cost associated with addressing
the non-modeled objectives cited by the
Company, e.g., social concerns, and cost
recovery risk of geothermal resources. As
required by Guideline 4.h., the Company
should identify who will bear this
financial risk, shareholders or customers.
PacifiCorp provided stochastic results for the preferred
portfolio in Volume I, Chapter 8 (Modeling and
Portfolio Selection Results). Volume II, Appendices K
(Detailed Capacity Expansion Results) and L
(Stochastic Production Cost Simulation Results)
provide details on portfolio results and stochastic
modeling results. The Company provides costs for
additional modeling completed to inform selection of
the preferred portfolio in Volume I, Chapter 8
(Modeling and Portfolio Selection Results).
Order, Docket No.
11-2035-01, p. 13.
The Company should fully vet changes in
methods or evaluation criteria with public
participants. The public input process
schedule needs to be better managed to
fully consider comments provided on the
draft IRP.
PacifiCorp’s portfolio selection methodology and
performance criteria were fully vetted with stakeholders
at the November 5, 2012 public input meeting.
Enhanced modeling methods used in the portfolio
development process related to analysis of renewable
resources were vetted with stakeholders at the August
13, 2012 public input meeting. DSM modeling
improvements were reviewed with stakeholders at the
June 20, 2012 public input meeting. Transmission
benefit modeling tools were reviewed with
Stakeholders at the July 13, 2012, November 5, 2012,
and February 27, 2013 public input meetings. Analysis
of coal unit environmental investments were reviewed
in the context of developing core and sensitivity case
definitions, reviewed with stakeholders at several
public input meetings. Improvements were made to the
public comment and response process, including
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

33

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
establishment of a stakeholder communications Web
page for logging comments and PacifiCorp responses.
Moreover, opportunities for stakeholder involvement
were greatly expanded for the 2013 IRP, which
included 15 public input meetings (more than twice the
number of meetings held for the 2011 IRP public
process), communications with stakeholders through
several conference calls, and five state meetings.
Order, Docket No.
11-2035-01, pp. 13-
14.
Going forward, the Company, in its next
IRP, should spend more effort developing
comparable cases and ensuring consistent
and comparable evaluation of alternative
resources.
-- The Company should allow public
input for developing a strategy to specify
cases, and alternative “future” scenarios.
-- The Company should also ensure this
strategy provides a sufficient number of
cases with common sets of inputs, with
consistent assumptions, to perform
meaningful comparisons of cases and
scenarios.
-- The next IRP should identify the cost
tradeoffs to achieve different levels of
performance with respect to the public
interest criteria.
-- Criteria the Company previously
identified and addressed by manually
modifying a given portfolio at the end of
the evaluation process should be
identified at the beginning of the IRP
process. Cases should then be developed
and evaluated using all criteria to
determine cost, risk and reliability
consequences.
We will evaluate the success of this
approach when the next IRP process
concludes.
PacifiCorp worked collaboratively with stakeholders to
produce core case definitions applied uniformly among
five different Energy Gateway transmission scenarios
and to produce sensitivity case definitions incorporating
comments from a broad range of stakeholder interests.
Comments from stakeholders were logged, responses
by the Company generated, and discussion held on core
case definitions among three public input meetings
(6/20/12, 7/13/12, and 9/14/12). Through this process,
the Company solicited specific case definition request
from all stakeholders. See Volume I, Chapter 7
(Modeling and Portfolio Evaluation Approach) for a
description of the core and sensitivity case definitions
used in the 2013 IRP.

Public interest criteria include "resource diversity" and
"generator CO2 emissions". PacifiCorp compared
portfolios on the basis of these criteria. Costs for CO2
emissions are incorporated into portfolios where CO2
prices are assumed, allowing for a direct comparison of
how emissions differences among portfolios
contribution to system costs. See Chapter 8 (Modeling
and Portfolio Selection Results).

The Company did not perform manual modification of
portfolios at the end of the portfolio evaluation process.
Supplemental analysis, showing cost and risk metrics,
were used to inform final selection of the preferred
portfolio.
Order, Docket No.
11-2035-01, pp. 13-
21.
UAE suggests the next IRP include the
cost increase of alternative acquisition
strategies. The Company should explore
this suggestion. (From UAE comments:
..."the next IRP should also include the
estimated increase in cost of the
alternative near and long term acquisition
strategies" [shown in Table 9.2])
Costs for portfolios, representing alternate acquisition
strategies, are summarized in in Volume I, Chapter 8
(Modeling and Portfolio Selection Results) and in
Volume II, Appendix K (Detailed Capacity Expansion
Results) and Appendix L (Stochastic Production Cost
Simulation Results).
Order, Docket No.
11-2035-01, p. 35.
In the future, the Company is directed to
omit from its core cases any resource for
which it does not already have a signed
final procurement contract or certificate of
public convenience and necessity.
However, this does not preclude the
Company from including such resources
in sensitivity cases. This will assist with
The Company complies with this directive. See Volume
I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) and Chapter 8 (Modeling and Portfolio
Selection Results) as well as Volume II, Appendix K
(Detailed Capacity Expansion Results), and Appendix
L (Stochastic Production Cost Simulation Results).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

34

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
the consistent and comparable treatment
of resources going forward.
Order, Docket No.
11-2035-01, p. 13.
The Company argues steps to address
model transparency will be expensive and
time consuming. Rather, the Company
recommends stakeholders identify
specific modeling or assumption
development concerns which the
Company could investigate based on a
clearly defined scope of work,
considering schedules and analytical
priorities, in the next IRP. This could
involve additional model runs. The
Company argues this type of validation
strategy would be on-going and makes
sense given evolving models and study
requirements. We generally concur with
the Company’s suggested approach for
the next IRP.
PacifiCorp and Ventyx established a Ventyx model
support opportunity where stakeholders can pay time
and material rates for Ventyx to run PacifiCorp's
models and answer technical questions on model
operations. So far no stakeholders have expressed
interest beyond requesting more information on the
opportunity.
Order, Docket No.
11-2035-01, p. 11.
UAE [Utah Association of Energy Users]
notes IRP 2011 provides no discussion of
rate design as required in Guideline 4.g.
The Company should include this
information in future IRPs.
The information is included in Volume I, Chapter 3
(The Planning Environment).
Order, Docket No.
11-2035-01, p. 10.
We find the Company has provided
insufficient information in [the] IRP 2011
regarding the cost impacts to customers
associated with the change from
geothermal to wind resources in its
Preferred Portfolio. This incremental cost
of replacing the geothermal resources
with wind resources could be included by
the Company in its IRP update, along
with a statement regarding whether the
customer or shareholder should bear this
cost.
PacifiCorp’s renewable acquisition analysis and
strategy is outlined in Volume I, Chapter 7 (Modeling
and Portfolio Evaluation Approach), Chapter 8
(Modeling and Portfolio Selection Results), and
Chapter 9 (Action Plan), and in Volume II, Appendix K
(Detailed Capacity Expansion Results) and Appendix L
(Stochastic Production Cost Simulation Results).

Geothermal resources, modeled as a power purchase
agreement, were not included the top performing
portfolios analyzed in the 2013 IRP and are not in the
preferred portfolio.
Order, Docket No.
11-2035-01, p. 11.
In its next IRP, the Company should
evaluate the geothermal resource cost
recovery risk directly. Since the
geothermal cost already includes a
development cost estimate, the Company
in future IRPs could evaluate higher
estimates, and compare this risk with the
risks of other portfolios. Finally, we note
the action plan contains no action item to
address the cost recovery risk issue. The
Company should also identify the actions
it is taking to address this issue i.e.,
obtaining regulatory or legislative relief
in other states, and include an action plan
item in the IRP update to this end.
Geothermal resource recovery risk is addressed by
assuming that geothermal resource acquisition would
be in the form of Power Purchase Agreements (PPA)
with size and location of these resources based on data
received from a recent Request for Information. See
Volume I, Chapter 6 (Resource Options). The
Company developed proxy PPA geothermal resources
using bids submitted for the all-source RFP for a 2016
resource. Core case C16 includes geothermal PPA
resource options as described in Volume I, Chapter 7
(Modeling Results and Resource Analysis) and Volume
II, Appendix M (Case Study Fact Sheets).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

35

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
Order, Docket No.
11-2035-01, p. 15.
The Company should perform sensitivity
and scenario analyses around key
renewable resource cost assumptions in its
next IRP.
PacifiCorp evaluated the core cases with and without
renewable portfolio standard requirements to isolate the
effect of these obligations on renewable resource
selection. Case definitions also reflected different
federal tax incentive assumptions, which influence the
cost of new renewable resources. See Volume I,
Chapter 7 (Modeling Results and Resource Analysis)
and Volume II, Appendix M (Case Study Fact Sheets).
In addition stakeholder input influenced cost
assumptions for solar resources, which are assumed to
experience real de-escalation in cost.
Order, Docket No.
11-2035-01, p. 18.
The Company should continue to provide
the western market analysis in support of
its reliance on market purchases.
See Volume II, Appendix J (Western Resource
Adequacy Evaluation).
Order, Docket No.
11-2035-01, p. 18.
We accept a 13 percent planning reserve
as reasonable for this IRP and
recommend continued analysis of this
issue [of the appropriate PRM level], both
through LOLP and tradeoff analysis, and
the testing of the 1.5 percent adjustment
[for reserve sharing among Northwest
Power Pool participants].
See Volume II, Appendix I (Stochastic Loss of Load
Study). PacifiCorp’s planning reserve margin study
focused on estimating the marginal cost of reliability
for different planning reserve margin levels, using the
stochastic Expected Unserved Energy (EUE) measure.
The reliability impact of reserve sharing among
Northwest Power Pool members was explicitly
incorporated in the production cost modeling.
Order, Docket No.
11-2035-01, p. 21.
The Company should continue to provide
sensitivity analysis [on the assumed cost
of Energy Not Served] and to discuss this
issue in future meetings. This reliability
measure is intended to identify the cost
differences between portfolios. The
Company could host a discussion
regarding this measure and the extent to
which the ENS measure is accomplishing
this goal.
PacifiCorp held a public conference call (9/24/12) and a
public meeting (11/27/12) to discuss the methodology
and results of planning reserve margin study, one
purpose of which is to measure the cost of avoiding
Energy Not Served. See Volume II, Appendix I
(Stochastic Loss of Load Study). ENS assumptions
tied to FERC market cap levels, are incorporated in all
portfolio simulations.

Washington
UE-100514, pp. 3-4. The next Plan should contain more
analysis and discussion of the timing of
the acquisition of the resources called for
in the Company's preferred portfolio. For
instance, the Plan could examine how
lower load growth affects resource
acquisition or risk-to-market exposure.
This is addressed in the Acquisition Path Analysis
section in Volume I, Chapter 9 (Action Plan).
UE-100514, p. 2. [T]he Company should provide more
analysis and explanation of how it intends
to meet the RPS requirements in
Washington just as it describes the depth
of its length (or shortage) in meeting
capacity and energy.
The 2013 IRP incorporates a more detailed evaluation
of state RPS requirements and compliance strategies
including Washington. See Volume I, Chapter 8
(Modeling and Portfolio Selection Results) and Chapter
9 (Action Plan). Additional analysis of compliance
with Washington’s RPS requirements directly informed
final selection of the preferred portfolio.
UE-100514, p. 2. [T]he Company should consider in future
Plans the addition of more localized
resources, such as anaerobic digesters that
may develop in Yakima, Grant, Benton
and Franklin counties. Since the Company
Distributed generation resources are addressed in
Volume I, Chapter 6 (Resource Options) and Chapter 9
(Action Plan).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

36

Reference IRP Requirement or Recommendation
How the Requirement or Recommendation is
Addressed in the 2013 IRP
states that West Control Area resources
options reflect its recent cost studies and
project experience, we believe it should
monitor opportunities to purchase the
output of biodigesters in this part of its
service territory.
UE-100514, p. 3. Wallula to McNary (Energy Gateway
Segment A): While we recognize that the
Company is obligated to provide
sufficient transmission capacity to
interconnect such generators pursuant to
FERC policies, the IRP should conduct a
detailed and separate analysis on how this
additional transmission capacity benefits
native load customers, whether it is
necessary to meet increased load in this
service territory or to provide enhanced
reliability.
The Company is modeling individual transmission
segments. See Volume I, Chapter 4 (Transmission),
Chapter 7 (Modeling and Portfolio Evaluation
Approach), and Chapter 9 (Action Plan) for details on
how transmission investments were analyzed in the
2013 IRP and the specific actions the Company will
take over the next two to four years based on this
analysis.
UE-100514, p. 3. West of Hemingway (Energy Gateway
Segment H): At a minimum, we
encourage the Company to participate
actively in the various regional and sub-
regional transmission planning efforts
currently underway that are relevant to
Hemingway to better inform its planning.
The Transmission Section, Chapter 4 (Transmission
Planning and Investment) addresses all Energy
Gateway evaluations and the Company’s participation
in other regional and sub regional transmission
planning efforts.
Wyoming
The Wyoming Public Service Commission provided the following comment in its Letter Order (Docket No. 20000-394-EA-
11, record No. 12813, dated 12/8/2011) on PacifiCorp’s 2011 IRP:
Pursuant to open meeting action taken on November 17, 2011, PacifiCorp d/b/a Rocky Mountain Power’s 2011 Integrated
Resource Plan (IRP) is hereby placed in the Commission’s files. No further action will be taken and this docketed matter is
closed.

Table B.3 – Oregon Public Utility Commission IRP Standard and Guidelines

Guideline 1. Substantive Requirements
1.a.1 All resources must be evaluated on a consistent
and comparable basis:
All known resources for meeting the utility’s
load should be considered, including supply-
side options which focus on the generation,
purchase and transmission of power – or gas
purchases, transportation, and storage – and
demand-side options which focus on
conservation and demand response.
PacifiCorp considered a wide range of resources including
renewables, demand-side management, distributed
generation, energy storage, power purchases, thermal
resources, and transmission. Volume I, Chapter 4
(Transmission Planning), Chapter 6 (Resource Options),
and Chapter 7 (Modeling and Portfolio Evaluation
Approach) document how PacifiCorp developed these
resources and modeled them in its portfolio analysis. All
these resources were established as resource options in the
Company’s capacity expansion optimization model,
System Optimizer, and selected by the model based on
load requirements, relative economics, resource size,
availability dates, and other factors.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

37

No. Requirement
How the Guideline is Addressed in the 2013
IRP
1.a.2 All resources must be evaluated on a consistent
and comparable basis:
Utilities should compare different resource fuel
types, technologies, lead times, in-service dates,
durations and locations in portfolio risk
modeling.
All portfolios developed with System Optimizer were
subjected to Monte Carlo production cost simulation.
These portfolios contained a variety of resource types with
different fuel types (coal, gas, biomass, nuclear fuel, “no
fuel” renewables), lead-times (ranging from front office
transactions to nuclear plants), in-service dates, life-times,
and locations. See Volume I, Chapter 7 (Modeling and
Portfolio Evaluation Approach), Chapter 8 (Modeling and
Portfolio Selection Results), and Volume II, Appendix K
(Detail Capacity Expansion Results) and Appendix L
(Stochastic Production Cost Simulation Results).
1.a.3 All resources must be evaluated on a consistent
and comparable basis:
Consistent assumptions and methods should be
used for evaluation of all resources.
PacifiCorp fully complies with this requirement. The
company developed generic supply-side resource attributes
based on a consistent characterization methodology. For
demand-side resources, the company used the Cadmus
Group’s supply curve data developed in 2012 for
representation of DSM and distributed generation
resources, which was also based on a consistently applied
methodology for determining technical, market, and
achievable DSM potentials. All portfolio resources were
evaluated using the same sets of price and load forecast
inputs. These inputs are documented in Volume I, Chapter
5 (Resource Needs Assessment), Chapter 6 (Resource
Alternatives), and Chapter 7 (Modeling and Portfolio
Evaluation Approach) as well as Volume II, Appendix D
(Demand-Side Management and Supplemental Resources).
1.a.4 All resources must be evaluated on a consistent
and comparable basis:
The after-tax marginal weighted-average cost
of capital (WACC) should be used to discount
all future resource costs.
PacifiCorp applied its nominal after-tax WACC of 6.88
percent to discount all cost streams.
1.b.1 Risk and uncertainty must be considered:
At a minimum, utilities should address the
following sources of risk and uncertainty:
1. Electric utilities: load requirements,
hydroelectric generation, plant forced outages,
fuel prices, electricity prices, and costs to
comply with any regulation of greenhouse gas
emissions.
Each of the sources of risk identified in this guideline is
treated as a stochastic variable in Monte Carlo production
cost simulation with the exception of CO2 emission
compliance costs, which are treated as a scenario risk.
Additional scenario risk is used to evaluate load
sensitivities. See Volume I, Chapter 7 (Modeling and
Portfolio Evaluation Approach).
1.b.2 Risk and uncertainty must be considered:
Utilities should identify in their plans any
additional sources of risk and uncertainty.
Resource risk mitigation is discussed in Volume I, Chapter
9 (Action Plan). Regulatory and financial risks associated
with resource and transmission investments are highlighted
in several areas in the IRP document, including Volume I,
Chapter 3 (The Planning Environment), Chapter 4
(Transmission), Chapter 7 (Modeling and Portfolio
Evaluation Approach), and Chapter 8 (Modeling and
Portfolio Selection Results).
1.c The primary goal must be the selection of a
portfolio of resources with the best combination
of expected costs and associated risks and
uncertainties for the utility and its customers
(“best cost/risk portfolio”).
PacifiCorp evaluated cost/risk tradeoffs for each of the
portfolios considered. See Volume I, Chapter 8 (Modeling
and Portfolio Selection Results), Chapter 9 (Action Plan),
and Volume II, Appendix K (Detailed Capacity Expansion
Results) and Appendix L (Stochastic Production Cost
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

38

No. Requirement
How the Guideline is Addressed in the 2013
IRP
Simulation Results) for the Company’s portfolio cost/risk
analysis and determination of the preferred portfolio.
1.c.1 The planning horizon for analyzing resource
choices should be at least 20 years and account
for end effects. Utilities should consider all
costs with a reasonable likelihood of being
included in rates over the long term, which
extends beyond the planning horizon and the
life of the resource.
PacifiCorp used a 20-year study period (2013-2032) for
portfolio modeling, and a real levelized revenue
requirement methodology for treatment of end effects.
1.c.2 Utilities should use present value of revenue
requirement (PVRR) as the key cost metric.
The plan should include analysis of current and
estimated future costs for all long-lived
resources such as power plants, gas storage
facilities, and pipelines, as well as all short-
lived resources such as gas supply and short-
term power purchases.
Volume I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) provides a description of the PVRR
methodology.
1.c.3.1 To address risk, the plan should include, at a
minimum:
1. Two measures of PVRR risk: one that
measures the variability of costs and one that
measures the severity of bad outcomes.
PacifiCorp uses the standard deviation of stochastic
production costs as the measure of cost variability. For the
severity of bad outcomes, the company calculates several
measures, including stochastic upper-tail mean PVRR
(mean of highest five Monte Carlo iterations) and the 95th
percentile stochastic production cost PVRR.
1.c.3.2 To address risk, the plan should include, at a
minimum:
2. Discussion of the proposed use and impact
on costs and risks of physical and financial
hedging.
A discussion on hedging is provided in Volume I, Chapter
9 (Action Plan).
1.c.4 The utility should explain in its plan how its
resource choices appropriately balance cost and
risk.
Volume I, Chapter 8 (Modeling and Portfolio Selection
Results) summarizes the results of PacifiCorp’s cost/risk
tradeoff analysis, and describes what criteria the Company
used to determine the best cost/risk portfolios and the
preferred portfolio.
1.d The plan must be consistent with the long-run
public interest as expressed in Oregon and
federal energy policies.
PacifiCorp considered both current and potential state and
federal energy/pollutant emission policies in portfolio
modeling. Volume I, Chapter 7 describes the decision
process used to derive portfolios, which includes
consideration of state and federal resource policies and
regulations that are summarized in Volume I, Chapter 3
(The Planning Environment). Volume I, Chapter 8
(Modeling and Portfolio Selection Results) provides the
results. Volume I, Chapter 9 (Action Plan) presents an
acquisition path analysis that describes resource strategies
based on regulatory trigger events.
Guideline 2. Procedural Requirements
2.a The public, which includes other utilities,
should be allowed significant involvement in
the preparation of the IRP. Involvement
includes opportunities to contribute information
and ideas, as well as to receive information.
Parties must have an opportunity to make
PacifiCorp fully complies with this requirement. Volume I,
Chapter 2 (Introduction) provides an overview of the
public process, all public meetings held for the 2013 IRP,
which are documented in Volume II, Appendix C (Public
Input Process).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

39

No. Requirement
How the Guideline is Addressed in the 2013
IRP
relevant inquiries of the utility formulating the
plan. Disputes about whether information
requests are relevant or unreasonably
burdensome, or whether a utility is being
properly responsive, may be submitted to the
Commission for resolution.
2.b While confidential information must be
protected, the utility should make public, in its
plan, any non-confidential information that is
relevant to its resource evaluation and action
plan. Confidential information may be
protected through use of a protective order,
through aggregation or shielding of data, or
through any other mechanism approved by the
Commission.
2013 IRP Volumes I and II provide non-confidential
information the Company used for portfolio evaluation, as
well as other data requested by stakeholders. PacifiCorp
also provided stakeholders with non-confidential
information to support public meeting discussions via
email. Volume III of the 2013 IRP is confidential and will
be protected through the use of a protective order.
2.c The utility must provide a draft IRP for public
review and comment prior to filing a final plan
with the Commission.
PacifiCorp distributed draft IRP materials for external
review throughout the process prior to each of the public
input meetings and solicited/and received feedback at
various times when developing the 2013 IRP. The
materials shared with stakeholders at these meetings,
outlined in Volume I Chapter 2 (Introduction), is consistent
with materials presented in Volumes I, II, and III of the
2013 IRP report.

PacifiCorp requested and responded to comments from
stakeholders in developing core case definitions. The
Company considered comments received following the
April 5, 2013 and April 17, 2013 public input meetings in
developing its final plan.

Guideline 3: Plan Filing, Review, and Updates
3.a A utility must file an IRP within two years of
its previous IRP acknowledgment order. If the
utility does not intend to take any significant
resource action for at least two years after its
next IRP is due, the utility may request an
extension of its filing date from the
Commission.
The 2013 IRP complies with this requirement.
3.b The utility must present the results of its filed
plan to the Commission at a public meeting
prior to the deadline for written public
comment.
This activity will be conducted subsequent to filing this
IRP.
3.c Commission staff and parties must complete
their comments and recommendations within
six months of IRP filing.
This activity will be conducted subsequent to filing this
IRP.
3.d The Commission will consider comments and
recommendations on a utility’s plan at a public
meeting before issuing an order on
acknowledgment. The Commission may
provide the utility an opportunity to revise the
IRP before issuing an acknowledgment order.
This activity will be conducted subsequent to filing this
IRP.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

40

No. Requirement
How the Guideline is Addressed in the 2013
IRP
3.e The Commission may provide direction to a
utility regarding any additional analyses or
actions that the utility should undertake in its
next IRP.
Not applicable.
3.f (a) Each energy utility must submit an annual
update on its most recently acknowledged
IRP. The update is due on or before the
acknowledgment order anniversary date.
Once a utility anticipates a significant
deviation from its acknowledged IRP, it
must file an update with the Commission,
unless the utility is within six months of
filing its next IRP. The utility must
summarize the update at a Commission
public meeting. The utility may request
acknowledgment of changes in proposed
actions identified in an update.
This activity will be conducted subsequent to filing this
IRP.
3.g Unless the utility requests acknowledgment of
changes in proposed actions, the annual update
is an informational filing that:
(a)Describes what actions the utility has taken
to implement the plan;
(b) Provides an assessment of what has
changed since the acknowledgment order
that affects the action plan to select best
portfolio of resources, including changes in
such factors as load, expiration of resource
contracts, supply-side and demand-side
resource acquisitions, resource costs, and
transmission availability; and
(c) Justifies any deviations from the
acknowledged action plan.
This activity will be conducted subsequent to filing this
IRP.
Guideline 4. Plan Components (at a minimum, must include…)
4.a An explanation of how the utility met each of
the substantive and procedural requirements.
The purpose of this table is to comply with this guideline.
4.b Analysis of high and low load growth scenarios
in addition to stochastic load risk analysis with
an explanation of major assumptions.
PacifiCorp developed low, high, and extreme peak
temperature (one-in-twenty probability) load growth
forecasts for scenario analysis using the System Optimizer
model. Stochastic variability of loads was also captured in
the risk analysis. See Volume I, Chapters 5 (Resource
Needs Assessment) and Chapter 7 (Modeling and Portfolio
Evaluation Approach), and Volume II, Appendix A (Load
Forecast) for load forecast information.
4.c For electric utilities, a determination of the
levels of peaking capacity and energy capability
expected for each year of the plan, given
existing resources; identification of capacity
and energy needed to bridge the gap between
expected loads and resources; modeling of all
existing transmission rights, as well as future
transmission additions associated with the
resource portfolios tested.
See Chapter 5 (Resource Need Assessment) for details on
annual capacity and energy balances. Existing transmission
rights are reflected in the IRP model topologies. Future
transmission additions used in analyzing portfolios are
summarized in Volume I, Chapter 4 (Transmission) and
Chapter 7 (Modeling and Portfolio Evaluation Approach)
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

41

No. Requirement
How the Guideline is Addressed in the 2013
IRP
4.d For gas utilities only Not applicable
4.e Identification and estimated costs of all supply-
side and demand side resource options, taking
into account anticipated advances in technology
Volume I, Chapter 6 (Resource Options) identifies the
resources included in this IRP, and provides their detailed
cost and performance attributes. Additional information on
energy efficiency resource characteristics is available in
Volume II, Appendix D (Demand-Side Management and
Supplemental Resources) referencing additional
information on PacifiCorp’s IRP Web, site see footnote 3
of this Appendix B.
4.f Analysis of measures the utility intends to take
to provide reliable service, including cost-risk
tradeoffs
In addition to incorporating a 13 percent planning reserve
margin for all portfolios evaluated, as supported by an
updated Stochastic Loss of Load Study in Volume II,
Appendix I), the Company used several measures to
evaluate relative portfolio supply reliability. These
measures (Energy Not Served and Loss of Load
Probability) are described in Volume I, Chapter 7
(Modeling and Portfolio Evaluation Approach).
4.g Identification of key assumptions about the
future (e.g., fuel prices and environmental
compliance costs) and alternative scenarios
considered
Volume I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) describes the key assumptions and alternative
scenarios used in this IRP. Volume II, Appendix M (Case
Study Fact Sheets) includes summaries of assumptions
used for each case definition analyzed in the 2013 IRP.
4.h Construction of a representative set of resource
portfolios to test various operating
characteristics, resource types, fuels and
sources, technologies, lead times, in-service
dates, durations and general locations – system-
wide or delivered to a specific portion of the
system
This Plan documents the development and results of
portfolios designed to determine resource selection under a
variety of input assumptions in Volume I, Chapters7
(Modeling and Portfolio Evaluation Approach) and
Chapter 8 (Modeling and Portfolio Selection Results).
4.i Evaluation of the performance of the candidate
portfolios over the range of identified risks and
uncertainties
Volume I, Chapter 8 (Modeling and Portfolio Selection
Results) presents the stochastic portfolio modeling results,
and describes portfolio attributes that explain relative
differences in cost and risk performance.
4.j Results of testing and rank ordering of the
portfolios by cost and risk metric, and
interpretation of those results.
Volume I, Chapter 8 (Modeling and Portfolio Selection
Results) provides tables and charts with performance
measure results, including rank ordering.
4.k Analysis of the uncertainties associated with
each portfolio evaluated.
See responses to 1.b.1 and 1.b.2 above.
4.l Selection of a portfolio that represents the best
combination of cost and risk for the utility and
its customers.
See 1.c above.
4.m Identification and explanation of any
inconsistencies of the selected portfolio with
any state and federal energy policies that may
affect a utility’s plan and any barriers to
implementation.
This IRP is designed to avoid inconsistencies with state
and federal energy policies therefore none are currently
identified.
An action plan with resource activities the
utility intends to undertake over the next two to
four years to acquire the identified resources,
regardless of whether the activity was
acknowledged in a previous IRP, with the key
Chapter 9 (Action Plan) presents the 2013 IRP action plan.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

42

No. Requirement
How the Guideline is Addressed in the 2013
IRP
attributes of each resource specified as in
portfolio testing.
Guideline 5: Transmission
5 Portfolio analysis should include costs to the
utility for the fuel transportation and electric
transmission required for each resource being
considered. In addition, utilities should consider
fuel transportation and electric transmission
facilities as resource options, taking into
account their value for making additional
purchases and sales, accessing less costly
resources in remote locations, acquiring
alternative fuel supplies, and improving
reliability.
PacifiCorp evaluated five Energy Gateway transmission
project configurations on a consistent and comparable
basis with respect to other resources. Fuel transportation
costs were factored into resource costs.
Guideline 6: Conservation
6.a Each utility should ensure that a conservation
potential study is conducted periodically for its
entire service territory.
A multi-state demand-side management potential study
was completed in 2012, and those results were
incorporated into this plan.
6.b To the extent that a utility controls the level of
funding for conservation programs in its service
territory, the utility should include in its action
plan all best cost/risk portfolio conservation
resources for meeting projected resource needs,
specifying annual savings targets.
PacifiCorp’s energy efficiency supply curves incorporate
Oregon resource potential. Oregon potential estimates were
provided by the Energy Trust of Oregon. See the demand-
side resource section in Volume I, Chapter 6 (Resource
Alternatives), the results in Volume I, Chapter 8 (Modeling
and Portfolio Selection Results) and the implementation
steps outlined in Volume I, Chapter 9 (Action Plan).
6.c To the extent that an outside party administers
conservation programs in a utility’s service
territory at a level of funding that is beyond the
utility’s control, the utility should:
1. Determine the amount of conservation
resources in the best cost/risk portfolio
without regard to any limits on funding of
conservation programs; and
2. Identify the preferred portfolio and action
plan consistent with the outside party’s
projection of conservation acquisition.

See the response for 6.b above.
Guideline 7: Demand Response
7 Plans should evaluate demand response
resources, including voluntary rate programs,
on par with other options for meeting energy,
capacity, and transmission needs (for electric
utilities) or gas supply and transportation needs
(for natural gas utilities).
PacifiCorp evaluated demand response resources (Class 1
and 3 DSM) on a consistent basis with other resources.
Guideline 8: Environmental Costs
8.a Base case and other compliance scenarios: The
utility should construct a base-case scenario to
reflect what it considers to be the most likely
regulatory compliance future for carbon dioxide
(CO2), nitrogen oxides, sulfur oxides, and
mercury emissions. The utility should develop
See Volume I, Chapter 7 (Modeling and Portfolio
Evaluation Approach).

“Medium” assumptions used to define core cases reflect
PacifiCorp’s base scenario considered to be the most likely
regulatory compliance scenario at this time.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

43

No. Requirement
How the Guideline is Addressed in the 2013
IRP
several compliance scenarios ranging from the
present CO2 regulatory level to the upper
reaches of credible proposals by governing
entities. Each compliance scenario should
include a time profile of CO2 compliance
requirements. The utility should identify
whether the basis of those requirements, or
“costs,” would be CO2 taxes, a ban on certain
types of resources, or CO2 caps (with or without
flexibility mechanisms such as allowance or
credit trading as a safety valve). The analysis
should recognize significant and important
upstream emissions that would likely have a
significant impact on resource decisions. Each
compliance scenario should maintain logical
consistency, to the extent practicable, between
the CO2 regulatory requirements and other key
inputs.

Multiple compliance scenarios were used in core case
definitions, including ranges in CO2 prices between zero
and those assumed to achieve an 80% reduction in power
sector emissions by 2050.

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.

PacifiCorp used both base case and stringent case
assumptions for future Regional Haze regulations requiring
investments to control nitrogen oxides and sulfur oxides.
All cases developed for the 2013 IRP include investments
required to achieve compliance with the Mercury and Air
Toxics Standards.
8.b Testing alternative portfolios against the
compliance scenarios: The utility should
estimate, under each of the compliance
scenarios, the present value revenue
requirement (PVRR) costs and risk measures,
over at least 20 years, for a set of reasonable
alternative portfolios from which the preferred
portfolio is selected. The utility should
incorporate end-effect considerations in the
analyses to allow for comparisons of portfolios
containing resources with economic or physical
lives that extend beyond the planning period.
The utility should also modify projected
lifetimes as necessary to be consistent with the
compliance scenario under analysis. In addition,
the utility should include, if material, sensitivity
analyses on a range of reasonably possible
regulatory futures for nitrogen oxides, sulfur
oxides, and mercury to further inform the
preferred portfolio selection.
Volume II, Appendix L (Stochastic Production Costs
Simulation Results) provides the Stochastic mean PVRR
versus upper tail mean less stochastic mean PVRR scatter
plot diagrams that for a broad range of portfolios
developed with a range of compliance scenarios as
summarized in 8.c above.

The Company considers end-effects in its use of Real
Levelized Revenue Requirement Analysis, as summarized
in Volume I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) and uses a 20-year planning horizon.

Early retirement and gas conversion alternatives to coal
unit environmental investments were considered in the
development of all resource portfolios.

Alternate scenarios were applied in the 2013 IRP to
capture the possibility of more stringent Regional Haze
compliance obligations.
8.c Trigger point analysis: The utility should
identify at least one CO2 compliance “turning
point” scenario, which, if anticipated now,
would lead to, or “trigger” the selection of a
portfolio of resources that is substantially
different from the preferred portfolio. The
utility should develop a substitute portfolio
appropriate for this trigger-point scenario and
compare the substitute portfolio’s expected cost
See Volume I, Chapter 7 (Modeling and Portfolio
Evaluation Approach) for a description of core case
definitions. Several of these core case definitions
“triggered” portfolios with extensive coal unit retirements
and gas conversions that differ substantially from the
preferred portfolio. Comparative analysis of results is
included in Volume I, Chapter 8 (Modeling and Portfolio
Selection Results).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

44

No. Requirement
How the Guideline is Addressed in the 2013
IRP
and risk performance to that of the preferred
portfolio – under the base case and each of the
above CO2 compliance scenarios. The utility
should provide its assessment of whether a CO2
regulatory future that is equally or more
stringent that the identified trigger point will be
mandated.
Oregon compliance portfolio: If none of the
above portfolios is consistent with Oregon
energy policies (including state goals for
reducing greenhouse gas emissions) as those
policies are applied to the utility, the utility
should construct the best cost/risk portfolio that
achieves that consistency, present its cost and
risk parameters, and compare it to those the
preferred and alternative portfolios.
Several portfolios yield system emissions aligned with
state goals for reducing greenhouse gas emissions. These
cases are summarized in Volume I, Chapter 8 (Modeling
and Portfolio Selection Results).
Guideline 9: Direct Access Loads
9 An electric utility’s load-resource balance
should exclude customer loads that are
effectively committed to service by an
alternative electricity supplier.
PacifiCorp continues to plan for load for direct access
customers.
Guideline 10: Multi-state Utilities
10 Multi-state utilities should plan their generation
and transmission systems, or gas supply and
delivery, on an integrated system basis that
achieves a best cost/risk portfolio for all their
retail customers.
The 2013 IRP conforms to the multi-state planning
approach as stated in Volume I, Chapter 2 under the
section “The Role of PacifiCorp’s Integrated Resource
Planning”. The Company notes the challenges in
complying with multi-state integrated planning given
differing state energy policies and resource preferences.
Guideline 11: Reliability
11 Electric utilities should analyze reliability
within the risk modeling of the actual portfolios
being considered. Loss of load probability,
expected planning reserve margin, and expected
and worst-case unserved energy should be
determined by year for top-performing
portfolios. Natural gas utilities should analyze,
on an integrated basis, gas supply,
transportation, and storage, along with demand-
side resources, to reliably meet peak, swing,
and base-load system requirements. Electric
and natural gas utility plans should demonstrate
that the utility’s chosen portfolio achieves its
stated reliability, cost and risk objectives.
See the response to 1.c.3.1 above. Volume I, Chapter 8
(Modeling and Portfolio Selection Results) walks through
the role of reliability, cost, and risk measures in
determining the preferred portfolio. Scatter plots of
portfolio cost versus risk at different CO2 cost levels were
used to inform the cost/risk tradeoff analysis.
Guideline 12: Distributed Generation
12 Electric utilities should evaluate distributed
generation technologies on par with other
supply-side resources and should consider, and
quantify where possible, the additional benefits
of distributed generation.
PacifiCorp evaluated several types of distributed
generation resources, including combined heat and power
(CHP) and solar photovoltaic systems. The results of these
evaluations are documented in Chapter 8 (Modeling and
Portfolio Selection Results).
Guideline 13: Resource Acquisition
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

45

No. Requirement
How the Guideline is Addressed in the 2013
IRP
13.a An electric utility should, in its IRP:
1. Identify its proposed acquisition strategy for
each resource in its action plan.
2. Assess the advantages and disadvantages of
owning a resource instead of purchasing
power from another party.
3. Identify any Benchmark Resources it plans to
consider in competitive bidding.
Chapter 9 (Action Plan) outlines the procurement
approaches for resources identified in the preferred
portfolio.

A discussion of the advantages and disadvantages of
owning a resource instead of purchasing it is included in
Chapter 9 (Action Plan).

There are no Benchmark Resources in Chapter 9 (Action
Plan).
13.b For gas utilities only Not applicable
Flexible Capacity Resources
1 Forecast the Demand for Flexible Capacity:
The electric utilities shall forecast the balancing
reserves needed at different time intervals (e.g.
ramping needed within 5 minutes) to respond to
variation in load and intermittent renewable
generation over the 20-year planning period.
See Volume II, Appendix F (Flexible Resource Needs
Assessment).
2 Forecast the Supply of Flexible Capacity: The
electric utilities shall forecast the balancing
reserves available at different time intervals
(e.g. ramping available within 5 minutes) from
existing generating resources over the 20-year
planning period.
See Volume II, Appendix F (Flexible Resource Needs
Assessment).
3 Evaluate Flexible Resources on a Consistent
and Comparable Basis: In planning to fill any
gap between the demand and supply of flexible
capacity, the electric utilities shall evaluate all
resource options, including the use of EVs, on a
consistent and comparable basis.
See Volume II, Appendix F (Flexible Resource Needs
Assessment).

Table B.4 – Utah Public Service Commission IRP Standard and Guidelines

Procedural Issues
1 The Commission has the legal authority to
promulgate Standards and Guidelines for
integrated resource planning.
Not addressed; this is a Public Service Commission of
Utah responsibility.
2 Information Exchange is the most reasonable
method for developing and implementing
integrated resource planning in Utah.
Information exchange has been conducted throughout the
IRP process.
3 Prudence reviews of new resource acquisitions
will occur during ratemaking proceedings.
Not an IRP requirement as the Commission acknowledges
that prudence reviews will occur during ratemaking
proceedings, outside of the IRP process.
4 PacifiCorp's integrated resource planning process
will be open to the public at all stages. The
Commission, its staff, the Division, the
PacifiCorp’s public process is described in Volume I,
Chapter 2 (Introduction). A record of public meetings is
provided in Volume II, Appendix C (Public Input Process).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

46

No. Requirement
How the Standards and Guidelines are
Addressed in the 2013 IRP
Committee, appropriate Utah state agencies, and
other interested parties can participate. The
Commission will pursue a more active-directive
role if deemed necessary, after formal review of
the planning process.
5 Consideration of environmental externalities and
attendant costs must be included in the integrated
resource planning analysis.
PacifiCorp used a scenario analysis approach along with
externality cost adders to model environmental externality
costs. See Volume I, Chapter 7 (Modeling and Portfolio
Evaluation Approach) for a description of the methodology
employed, including how CO2 cost uncertainty is factored
into the determination of relative portfolio performance.
6 The integrated resource plan must evaluate
supply-side and demand-side resources on a
consistent and comparable basis.

Supply, transmission, and demand-side resources were
evaluated on a comparable basis using PacifiCorp’s
capacity expansion optimization model. Also see the
response to number 4.b.ii below.
7 Avoided cost should be determined in a manner
consistent with the Company's Integrated
Resource Plan.
Consistent with the Utah rules, PacifiCorp determination
of avoided costs in Utah will be handled in a manner
consistent with the IRP, with the caveat that the costs may
be updated if better information becomes available.

8 The planning standards and guidelines must meet
the needs of the Utah service area, but since
coordination with other jurisdictions is important,
must not ignore the rules governing the planning
process already in place in other jurisdictions.
This IRP was developed in consultation with parties from
all state jurisdictions, and meets all formal state IRP
guidelines.
9 The Company's Strategic Business Plan must be
directly related to its Integrated Resource Plan.
Volume I, Chapter 9 (Action Plan) describes the linkage
between the 2013 IRP preferred portfolio and 2013
business plan resources approved in December 2012.
Significant resource differences are highlighted.

Standards and Guidelines
1 Definition: Integrated resource planning is a
utility planning process which evaluates all
known resources on a consistent and comparable
basis, in order to meet current and future customer
electric energy services needs at the lowest total
cost to the utility and its customers, and in a
manner consistent with the long-run public
interest. The process should result in the selection
of the optimal set of resources given the expected
combination of costs, risk and uncertainty.
Volume I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) outlines the portfolio performance evaluation
and preferred portfolio selection process, while Chapter 8
(Modeling and Portfolio Selection Results) chronicles the
modeling and preferred portfolio selection process. This
IRP also addresses concerns expressed by Utah
stakeholders and the Utah commission concerning
comprehensiveness of resources considered, consistency in
applying input assumptions for portfolio modeling, and
explanation of PacifiCorp’s decision process for selecting
top-performing portfolios and the preferred portfolio.
2 The Company will submit its Integrated Resource
Plan biennially.
The company submitted its last IRP on March 31, 2011,
and filed this IRP on April 30, 2013, after requesting a one
month filing extension. PacifiCorp normally files the IRP
with all commissions on March 31 in each odd-numbered
year.
3 IRP will be developed in consultation with the
Commission, its staff, the Division of Public
Utilities, the Committee of Consumer Services,
appropriate Utah state agencies and interested
PacifiCorp’s public process is described in Volume I,
Chapter 2 (Introduction). A record of public meetings is
provided in Volume II, Appendix C (Public Input Process).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

47

No. Requirement
How the Standards and Guidelines are
Addressed in the 2013 IRP
parties. PacifiCorp will provide ample opportunity
for public input and information exchange during
the development of its Plan.
4.a PacifiCorp's integrated resource plans will
include: a range of estimates or forecasts of load
growth, including both capacity (kW) and energy
(kWh) requirements.
PacifiCorp implemented a load forecast range for both
capacity expansion optimization scenarios as well as for
stochastic variability, covering both capacity and energy.
Details concerning the load forecasts used in the 2013 IRP
are provided in Volume I, Chapter 5 (Resource Needs
Assessment) and Volume II, Appendix A (Load Forecast
Details).
4.a.i The forecasts will be made by jurisdiction and by
general class and will differentiate energy and
capacity requirements. The Company will include
in its forecasts all on-system loads and those off-
system loads which they have a contractual
obligation to fulfill. Non-firm off-system sales are
uncertain and should not be explicitly
incorporated into the load forecast that the utility
then plans to meet. However, the Plan must have
some analysis of the off-system sales market to
assess the impacts such markets will have on risks
associated with different acquisition strategies.
Load forecasts are differentiated by jurisdiction and
differentiate energy and capacity requirements. See
Volume I, Chapter 5 (Resource Needs Assessment) and
Volume II, Appendix A (Load Forecast Details). Non-firm
off-system sales are not incorporated into the load forecast.
Off-system sales markets are included in IRP modeling
and are used for system balancing purposes.
4.a.ii Analyses of how various economic and
demographic factors, including the prices of
electricity and alternative energy sources, will
affect the consumption of electric energy services,
and how changes in the number, type and
efficiency of end-uses will affect future loads.
Volume II, Appendix A (Load Forecast Details)
documents how demographic and price factors are used in
PacifiCorp’s load forecasting methodology.

4.b An evaluation of all present and future resources,
including future market opportunities (both
demand-side and supply-side), on a consistent and
comparable basis.
Resources were evaluated on a consistent and comparable
basis using the System Optimizer model and Planning and
Risk production cost model using both supply side and
demand side alternatives. See explanation in Volume I,
Chapter 7 (Modeling and Portfolio Evaluation Approach)
and the results in Volume I, Chapter 8 (Modeling and
Portfolio Selection Results). Resource options are
summarized in Volume I, Chapter 6 (Resource Options).
4.b.i An assessment of all technically feasible and cost-
effective improvements in the efficient use of
electricity, including load management and
conservation.
PacifiCorp included supply curves for Class 1 DSM
(dispatchable/schedulable load control) and Class 2 DSM
(energy efficiency measures) in its capacity expansion
model. Details are provided in Volume I, Chapter 6
(Resource Options). A sensitivity study of demand-
response programs (Class 3 DSM) was also conducted and
reported in Volume I, Chapter 8 (Modeling and Portfolio
Selection Results).
4.b.ii An assessment of all technically feasible
generating technologies including: renewable
resources, cogeneration, power purchases from
other sources, and the construction of thermal
resources.
PacifiCorp considered a wide range of resources including
renewables, cogeneration (combined heat and power),
power purchases, thermal resources, energy storage, and
Energy Gateway transmission configurations. Volume I,
Chapters 6 (Resource Options) and 7 (Modeling and
Portfolio Evaluation Approach) contain assumptions and
describe the process under which PacifiCorp developed
and assessed these technologies and resources.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

48

No. Requirement
How the Standards and Guidelines are
Addressed in the 2013 IRP
4.b.iii The resource assessments should include: life
expectancy of the resources, the recognition of
whether the resource is replacing/adding capacity
or energy, dispatchability, lead-time requirements,
flexibility, efficiency of the resource and
opportunities for customer participation.
PacifiCorp captures and models these resources attributes
in its IRP models. Resources are defined as providing
capacity, energy, or both. The DSM supply curves and
distributed generation resources used for portfolio
modeling explicitly incorporate estimated rates of program
and event participation. Replacement capacity is
considered in the case of early coal unit retirements as
evaluated in this IRP as an alternative to coal unit
environmental investments.

Dispatchability is accounted for in both IRP models used;
however, the Planning and Risk model provides a more
detailed representation of unit dispatch than System
Optimizer, and includes modeling of unit commitment and
reserves.
4.c An analysis of the role of competitive bidding for
demand-side and supply-side resource
acquisitions
A description of the role of competitive bidding and other
procurement methods is provided in Volume I, Chapter 9
(Action Plan).
4.d A 20-year planning horizon. This IRP uses a 20-year study horizon (2013-2032)
4.e An action plan outlining the specific resource
decisions intended to implement the integrated
resource plan in a manner consistent with the
Company's strategic business plan. The action
plan will span a four-year horizon and will
describe specific actions to be taken in the first
two years and outline actions anticipated in the
last two years. The action plan will include a
status report of the specific actions contained in
the previous action plan.
The IRP action plan is provided in Volume I, Chapter 9
(Action Plan). A status report of the actions outlined in the
previous action plan (2011 IRP update) is provided in
Volume I, Chapter 9 (Action Plan).

In Volume I, Chapter 9 (Action Plan) Table 9.1 identifies
actions anticipated in the next two years and in the next
four years.
4.f A plan of different resource acquisition paths for
different economic circumstances with a decision
mechanism to select among and modify these
paths as the future unfolds.
Volume I, Chapter 9 (Action Plan) includes an acquisition
path analysis that presents broad resource strategies based
on regulatory trigger events, change in load growth,
extension of federal renewable resource tax incentives and
procurement delays.
4.g An evaluation of the cost-effectiveness of the
resource options from the perspectives of the
utility and the different classes of ratepayers. In
addition, a description of how social concerns
might affect cost effectiveness estimates of
resource options.
PacifiCorp provides resource-specific utility and total
resource cost information in Volume I, Chapter 6
(Resource Options).

The IRP document addresses the impact of social concerns
on resource cost-effectiveness in the following ways:
● Portfolios were evaluated using a range of CO2 cost
futures.
● A discussion of environmental policy status and
impacts on utility resource planning is provided in
Volume I, Chapter 3 (The Planning Environment).
● State and proposed federal public policy preferences
for clean energy are considered for development of the
preferred portfolio, which is documented in Volume I,
Chapter 8 (Modeling and Portfolio Selection Results).
● Volume II, Appendix G (Plant Water Consumption) of
reports historical water consumption for PacifiCorp’s
thermal plants.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

49

No. Requirement
How the Standards and Guidelines are
Addressed in the 2013 IRP
4.h An evaluation of the financial, competitive,
reliability, and operational risks associated with
various resource options and how the action plan
addresses these risks in the context of both the
Business Plan and the 20-year Integrated
Resource Plan. The Company will identify who
should bear such risk, the ratepayer or the
stockholder.
The handling of resource risks is discussed in Volume I,
Chapter 9 (Action Plan), and covers managing
environmental risk for existing plants, risk management
and hedging and treatment of customer and investment
risk. Transmission expansion risks are discussed in
Chapter 4 (Transmission).

Resource capital cost uncertainty and technological risk is
addressed in Volume I, Chapter 6 (Resource Options).

For reliability risks, the stochastic simulation model
incorporates stochastic volatility of forced outages for new
thermal plants and hydro availability. These risks are
factored into the comparative evaluation of portfolios and
the selection of the preferred portfolio upon which the
action plan is based.

Identification of the classes of risk and how these risks are
allocated to ratepayers and investors is discussed in
Volume I, Chapter 9 (Action Plan).
4.i Considerations permitting flexibility in the
planning process so that the Company can take
advantage of opportunities and can prevent the
premature foreclosure of options.
Flexibility in the planning and procurement processes is
highlighted in Volume I, Chapter 9 (Action Plan),
specifically, Table 9.1.
4.j An analysis of tradeoffs; for example, between
such conditions of service as reliability and
dispatchability and the acquisition of lowest cost
resources.
PacifiCorp examined the trade-off between portfolio cost
and risk, taking into consideration a broad range of
resource alternatives defined with varying levels of
dispatchability. This trade-off analysis is documented in
Volume I, Chapter 8 (Modeling and Portfolio Selection
Results), and highlighted through the use of scatter-plot
graphs showing the relationship between stochastic mean
and upper-tail mean stochastic PVRR.
4.k A range, rather than attempts at precise
quantification, of estimated external costs which
may be intangible, in order to show how explicit
consideration of them might affect selection of
resource options. The Company will attempt to
quantify the magnitude of the externalities, for
example, in terms of the amount of emissions
released and dollar estimates of the costs of such
externalities.
PacifiCorp incorporated environmental externality costs
for CO2 and costs for complying with current and proposed
U.S. EPA regulatory requirements. For CO2 externality
costs, the company used scenarios with various cost levels
to capture a reasonable range of cost impacts. These cost
assumptions are described in Volume I, Chapter 7
(Modeling and Portfolio Evaluation Approach).
4.l A narrative describing how current rate design is
consistent with the Company's integrated resource
planning goals and how changes in rate design
might facilitate integrated resource planning
objectives.
See Volume I, Chapter 3 (The Planning Environment). The
role of Class 3 DSM (price response programs) at
PacifiCorp and how these resources are modeled in the IRP
are described in Volume I, Chapter 6 (Resource Options).

5 PacifiCorp will submit its IRP for public
comment, review and acknowledgment.
PacifiCorp distributed draft IRP materials for external
review throughout the process prior to each of the public
input meetings and solicited/and received feedback at
various times when developing the 2013 IRP. The
materials shared with stakeholders at these meetings,
outlined in Volume I Chapter 2 (Introduction), is consistent
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

50

No. Requirement
How the Standards and Guidelines are
Addressed in the 2013 IRP
with materials presented in Volumes I, II, and III of the
2013 IRP report.

PacifiCorp requested and responded to comments from
stakeholders in developing core case definitions. The
Company considered comments received following the
April 5, 2013 and April 17, 2013 public input meetings in
developing its final plan.
6 The public, state agencies and other interested
parties will have the opportunity to make formal
comment to the Commission on the adequacy of
the Plan. The Commission will review the Plan
for adherence to the principles stated herein, and
will judge the merit and applicability of the public
comment. If the Plan needs further work the
Commission will return it to the Company with
comments and suggestions for change. This
process should lead more quickly to the
Commission's acknowledgment of an acceptable
Integrated Resource Plan. The Company will give
an oral presentation of its report to the
Commission and all interested public parties.
Formal hearings on the acknowledgment of the
Integrated Resource Plan might be appropriate but
are not required.
Not addressed; this is a post-filing activity.
7 Acknowledgment of an acceptable Plan will not
guarantee favorable ratemaking treatment of
future resource acquisitions.
Not addressed; this is not a PacifiCorp activity.
8 The Integrated Resource Plan will be used in rate
cases to evaluate the performance of the utility
and to review avoided cost calculations.
Not addressed; this refers to a post-filing activity.

Table B.5 – Washington Utilities and Transportation Commission IRP Standard and
Guidelines (WAC 480-100-238)
(4) Work plan filed no later than 12 months
before next IRP due date.
PacifiCorp filed the IRP work plan on March 28, 2012 in Docket
No. UE-120416, given an anticipated IRP filing date of March 31,
2013.
(4) Work plan outlines content of IRP. See pages 1-2 of the Work Plan document for a summarization of
IRP contents.
(4) Work plan outlines method for assessing
potential resources. (See LRC analysis
below)
See pages 3-6 of the Work Plan document for a summarization of
resource analysis.
(5) Work plan outlines timing and extent of
public participation.
See pages 6-7 of the Work Plan. Figure 2, page 6, document for the
IRP schedule.
(4) Integrated resource plan submitted
within two years of previous plan.
The Commission issued an Order on December 11, 2008, under
Docket no. UE-070117, granting the Company permission to file its
IRP on March 31 of each odd numbered year. PacifiCorp requested
a one-month filing extension on January 8, 2013 (“PacifiCorp's
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

51

No. Requirement
How the Standards and Guidelines are Addressed in
the 2013 IRP
Petition for Modification of Filing Date for its Integrated Resource
Plan Pursuant to WAC 480-100-238”). PacifiCorp filed the 2013
IRP on April 30, 2013.
(5) Commission issues notice of public
hearing after company files plan for
review.
This activity is conducted subsequent to filing this IRP.
(5) Commission holds public hearing. This activity is conducted subsequent to filing this IRP.
(2)(a) Plan describes the mix of energy supply
resources.
Volume I, Chapter 5 (Resource Need Assessment) describes the mix
of existing resources, while Volume I, Chapter 8 (Modeling and
Portfolio Selection Results) describes the 2013 IRP preferred
portfolio.
(2)(a) Plan describes conservation supply. See Volume I, Chapter 6 (Resource Options) for a description of
how conservation supplies are represented and modeled, and
Volume I, Chapter 8 (Modeling and Portfolio Selection Results) for
conservation supply in the preferred portfolio. Additional
information on energy efficiency resource characteristics is
available on PacifiCorp’s IRP Web site. See Footnote 3 of this
Appendix.

(2)(a) Plan addresses supply in terms of
current and future needs at the lowest
reasonable cost to the utility and its
ratepayers.
The 2013 IRP preferred portfolio was based on a resource needs
assessment that accounted for forecasted load growth, expiration of
existing power purchase contracts, resources under construction,
contract, or reflected in the Company’s capital budget, as well as a
capacity planning reserve margin. Details on PacifiCorp’s findings
of resource need are described in Volume I, Chapter 5 (Resource
Needs and Assessment).
(2)(b) Plan uses lowest reasonable cost (LRC)
analysis to select the mix of resources.
PacifiCorp uses portfolio performance measures based on the
Present Value of Revenue Requirements (PVRR) methodology. See
the section on portfolio performance measures in Volume I, Chapter
7 (Modeling and Portfolio Evaluation Approach) and Volume I
Chapter 8 (Modeling and Portfolio Selection Results).
(2)(b) LRC analysis considers resource costs. Volume I, Chapter 6 (Resource Options), provides detailed
information on costs and other attributes for all resources analyzed
for the IRP.
(2)(b) LRC analysis considers market-
volatility risks.
PacifiCorp employs Monte Carlo production cost simulation with a
stochastic model to characterize market price and gas price
volatility. Volume I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) provides a summary of the modeling approach.
(2)(b) LRC analysis considers demand side
resource uncertainties.
PacifiCorp captured demand-side resource uncertainties through the
development of numerous portfolios based on different sets of input
assumptions.
(2)(b) LRC analysis considers resource
dispatchability.
PacifiCorp uses two IRP models that simulate the dispatch of
existing and future resources based on such attributes as heat rate,
availability, fuel cost, and variable O&M cost. The chronological
production cost simulation model also incorporates unit
commitment logic for handling start-up, shutdown, ramp rates,
minimum up/down times, and run up rates, and reserve holding
characteristics of individual generators.
(2)(b) LRC analysis considers resource effect
on system operation.
PacifiCorp’s IRP models simulate the operation of its entire system,
reflecting dispatch/unit commitment, forced/unforced outages,
access to markets, and system reliability and transmission
constraints.

PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

52

No. Requirement
How the Standards and Guidelines are Addressed in
the 2013 IRP
(2)(b) LRC analysis considers risks imposed
on ratepayers.
PacifiCorp explicitly models risk associated with uncertain CO2
regulatory costs, wholesale electricity and natural gas price
escalation and volatility, load growth uncertainty, resource
reliability, renewable portfolio standard requirement uncertainty,
plant construction cost escalation, and resource affordability. These
risks and uncertainties are handled through stochastic modeling and
scenarios depicting alternative futures.

In addition to risk modeling, the IRP discusses a number of resource
risk topics not addressed in the IRP system simulation models. For
example, Volume I, Chapter 9 (Action Plan) covers the following
topics: (1) managing carbon risk for existing plants, (2) assessment
of owning vs. purchasing power, (3) purpose of hedging, (4)
procurement delays and (5) treatment of customer and investor
risks. Volume I, Chapter 4 (Transmission) covers similar risks
associated with transmission system expansion.
(2)(b) LRC analysis considers public policies
regarding resource preference adopted
by Washington state or federal
government.
In Volume I, Chapter 7 (Modeling and Portfolio Evaluation) the
IRP modeling incorporates resource expansion constraints tied to
renewable portfolio standards (RPS) currently in place for
Washington. PacifiCorp also evaluated various CO2 regulatory
schemes, including different levels of CO2 price assumptions and
future Regional Haze compliance requierments. The I-937
conservation requirements are also explicitly accounted for in
developing Washington conservation resource costs.
(2)(b) LRC analysis considers cost of risks
associated with environmental effects
including emissions of carbon dioxide.
See (2)(b) above.
(2)(c) Plan defines conservation as any
reduction in electric power consumption
that results from increases in the
efficiency of energy use, production, or
distribution.
A description of how PacifiCorp classifies and defines energy
conservation is provided in Volume I, Chapter 6 (Resource
Options).
(3)(a) Plan includes a range of forecasts of
future demand.
PacifiCorp implemented a load forecast range. Details concerning
the load forecasts used in the 2013 IRP (high, low, and extreme
peak temperature) are provided in Volume I, Chapters 5 (Resource
Needs Assessment) and Volume II, Appendix A (Load Forecast
Details).
(3)(a) Plan develops forecasts using methods
that examine the effect of economic
forces on the consumption of electricity.
PacifiCorp’s load forecast methodology employs econometric
forecasting techniques that include such economic variables as
household income, employment, and population. See Volume II,
Appendix A (Load Forecast Details) for a description of the load
forecasting methodology.
(3)(a) Plan develops forecasts using methods
that address changes in the number, type
and efficiency of electrical end-uses.
Residential sector load forecasts use a statistically-adjusted end-use
model that accounts for equipment saturation rates and efficiency.
See Volume II, Appendix A (Load Forecast Details), for a
description of the residential sector load forecasting methodology.
(3)(b) Plan includes an assessment of
commercially available conservation,
including load management.
PacifiCorp updated the system-wide demand-side management
potential study in 2012, which served as the basis for developing
DSM resource supply curves for resource portfolio modeling. The
supply curves account for technical and achievable (market)
potential, while the IRP capacity expansion model identifies a cost-
effective mix of DSM resources based on these limits and other
model inputs. The 2012 DSM potentials study is available on
PacifiCorp’s IRP Web site. See footnote 3 in this Appendix.
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

53

No. Requirement
How the Standards and Guidelines are Addressed in
the 2013 IRP
(3)(b) Plan includes an assessment of currently
employed and new policies and
programs needed to obtain the
conservation improvements.
A description of the current status of DSM programs and on-going
activities to implement current and new programs is provided in
Volume I, Chapter 5 (Resource Needs Assessment).
(3)(c) Plan includes an assessment of a wide
range of conventional and commercially
available nonconventional generating
technologies.
PacifiCorp considered a wide range of resources including
renewables, cogeneration (combined heat and power), customer
standby generation, power purchases, thermal resources, energy
storage, and transmission. Volume I, Chapters 6 (Resource Options
and Chapter 7 (Modeling and Portfolio Evaluation Approach)
document how PacifiCorp developed and assessed these
technologies.
(3)(d) Plan includes an assessment of
transmission system capability and
reliability; to the extent such
information can be provided consistent
with applicable laws.
PacifiCorp modeled transmission system capability to serve its load
obligations, factoring in updates to the representation of major load
and generation centers, regional transmission congestion impacts,
import/export availability, external market dynamics, and
significant transmission expansion plans explained in Volume I,
Chapter 4 (Transmission) and Chapter 7 (Modeling and Portfolio
Evaluation Approach). System reliability given transmission
capability was analyzed using stochastic production cost simulation
and measures of insufficient energy and capacity for a load area
(Energy Not Served and Unmet Capacity, respectively).
(3)(e) Plan includes a comparative evaluation
of energy supply resources (including
transmission and distribution) and
improvements in conservation using
LRC.
PacifiCorp’s capacity expansion optimization model (System
Optimizer) is designed to compare alternative resources—including
transmission expansion options—for the least-cost resource mix.
System Optimizer was used to develop numerous resource
portfolios for comparative evaluation on the basis of cost, risk,
reliability, and other performance attributes. The DSM potentials
study considered improvements in conservation distribution
considered alternative transmission expansion options.
(3)(f) Plan includes integration of the demand
forecasts and resource evaluations into a
long range integrated resource plan
describing the mix of resources that is
designated to meet current and project
future needs at the lowest reasonable
cost to the utility and its ratepayers.
PacifiCorp integrates demand forecasts, resources, and system
operations in the context of a system modeling framework described
in Volume I, Chapter 7(Modeling and Portfolio Evaluation
Approach). The portfolio evaluation covers a 20-year period (2013-
2032). PacifiCorp developed its preferred portfolio of resources
judged to be least-cost after considering load requirements, risk,
uncertainty, supply adequacy/reliability, and government resource
policies in accordance with this rule.
(3)(g) Plan includes a two-year action plan that
implements the long range plan.
See Table 9.1 in Volume I, Chapter 9 (Action Plan), for
PacifiCorp’s 2013 IRP action plan.
(3)(h) Plan includes a progress report on the
implementation of the previously filed
plan.
A status report on action plan implementation is provided as in
Volume I, Chapter 9 (Action Plan).

Table B.6 – Wyoming Public Service Commission IRP Standard and Guidelines (Docket
90000-107-XO-09)
No. Requirement How the Guideline is Addressed in the 2013 IRP
A
The public comment process
employed as part of the
formulation of the utility’s IRP,
including a description, timing
and weight given to the public
process;
PacifiCorp’s public process is described in Volume I, Chapter 2
(Introduction) and in Volume II, Appendix C (Public Input Process).
PACIFICORP - 2013 IRP APPENDIX B – IRP REGULATORY COMPLIANCE

54

No. Requirement How the Guideline is Addressed in the 2013 IRP
B
The utility’s strategic goals and
resource planning goals and
preferred resource portfolio;
Volume I, Chapter 8 (Modeling and Portfolio Selection Results)
documents the preferred resource portfolio and rationale for
selection. Volume I, Chapter 9 (Action Plan) constitutes the IRP
action plan and the descriptions of resource strategies and risk
management.
C
The utility’s illustration of
resource need over the near-term
and long-term planning
horizons;

See Volume I, Chapter 5 (Resource Needs Assessment).
D
A study detailing the types of
resources considered;

Volume, I Chapter 6 (Resource Options), presents the resource
options used for resource portfolio modeling for this IRP.
F
Changes in expected resource
acquisitions and load growth
from that presented in the
utility’s previous IRP;

A comparison of resource changes relative to the 2011 IRP Update is
presented in Volume I, Chapter 9 (Action Plan). A chart comparing
the peak load forecasts for the 2011 IRP, 2011 IRP Update, and 2013
IRP is included in Volume II, Appendix A (Load Forecast Details).

G
The environmental impacts
considered;
Portfolio comparisons for CO2 and a broad range of environmental
impacts are considered, including prospective early retirement of
existing coal units as an alternative to environmental investments.
See Volume I, Chapter 7 (Modeling and Portfolio Evaluation
Approach) and Chapter 8 (Modeling and Portfolio Selection) as well
as Volume II, Appendix L (Stochastic production Cost Simulation
Results).

H Market purchases evaluation;

Modeling of firm market purchases (front office transactions) and
spot market balancing transactions is included in this IRP.
I
Reserve Margin analysis; and

PacifiCorp’s planning reserve margin study, which documents
selection of a capacity planning reserve margin is in Volume I,
Appendix I (Stochastic Loss of Load Study).
J
Demand-side management and
conservation options;
See Volume I, Chapter 6 (Resource Options) for a detailed
discussion on DSM and conservation resource options. Additional
information on energy efficiency resource characteristics is available
on the Company’s website. See footnote 3 in this Appendix.

PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

55
APPENDIX C – PUBLIC INPUT PROCESS
A critical element of this resource plan is the public input process. PacifiCorp has pursued an
open and collaborative approach involving the Commissions, customers and other stakeholders
in PacifiCorp’s planning process prior to making resource planning decisions. Since these
decisions can have significant economic and environmental consequences, conducting the
resource plan with transparency and full participation from Commissions and other interested
and affected parties is essential.

The public has been involved in this resource plan from its earliest stages and at each decisive
step. Participants have both shared comments and ideas and received information. As reflected in
the report, many of the comments provided by the participants have been adopted by PacifiCorp
and have contributed to the quality of this resource plan. PacifiCorp will adopt further comments
going forward, either as elements of the Action Plan or as future refinements to the planning
methodology.

The cornerstone of the public input process has been full-day public input meetings held
approximately throughout the year-long plan development period. These meetings have been
held jointly in two locations—Salt Lake City, Utah and Portland Oregon—using telephone and
video conferencing technology.

The IRP public process continued with state stakeholder dialogue sessions from July through
August 2012. The goal of these sessions, targeting a state-specific audience, were to (1) capture
key resource planning issues of most concern to each state, and discuss how these can be tackled
from a system planning perspective, (2) ensure that stakeholders understand PacifiCorp’s
planning principles and the logic behind its planning process, and (3) set expectations for what
can be accomplished in the current IRP/business planning cycle. These State focused meetings
continued to enhance interaction with stakeholders in the planning cycle, and provided a forum
to directly address stakeholder concerns regarding equitable representation of state interests
during general public meetings.

As far as agenda setting is concerned, PacifiCorp solicited recommendations from the state
stakeholders in advance of the session, as well as allowing open time to ensure that participants
had adequate time for dialogue. Some follow-up activities arising from the sessions were
addressed in subsequent public meetings.

In response to stakeholder requests, PacifiCorp has introduced an additional IRP comments
website intended for PacifiCorp’s IRP public participants only at the following link -
(http://www.pacificorp.com/es/irp/irpcomments.html).

PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

56
Participant List

Among the organizations that were represented and actively involved in this collaborative effort
were:
Commissions
 Idaho Public Utilities Commission
 Oregon Public Utilities Commission
 Public Service Commission of Utah
 Washington Utilities and Transportation Commission
 Wyoming Public Service Commission
Stakeholders
 Attorney General of Washington
 Blue Castle Holdings, Inc.
 Bonneville Power Administration
 Brigham Young University
 Citizen’s Utility Board of Oregon
 Committee for Consumer Services State of Utah
 Encana Corporation
 enXco
 Energy Trust of Oregon
 Energy Strategies, LLC
 E-Quant Consulting
 First Wind
 GE Energy
 HEAL Utah and Utah Physicians for a Healthy Environment
 Health Environment Alliance of Utah (HEAL)
 Horizon Wind Energy
 Iberdrola Renewables
 Idaho Conservation League
 Industrial Customers of Northwest Utilities
 Interwest Energy Alliance
 Kennecott Utah Copper
 Magnum Energy
 Monsanto Company
 National Renewable Energy Laboratory
 Northwest Power and Conservation Council
 Northwest Pipeline GP
 NW Energy Coalition
 Oregon Department of Energy
 Powder River Basin Resource Council
 Renewables Northwest Project
 Salt Lake City
PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

57
 Salt Lake Community Action Program
 Sierra Club Environmental Law Program
 Synapse Energy Economics
 The Energy Project
 Utah Associated Municipal Power Systems (UAMPS)
 Utah Clean Energy
 Utah Division of Public Utilities
 Utah Industrial Energy Consumers (UIEC)
 Utah Municipal Power Agency (UMPA)
 Utah Office of Consumer Services (OCS)
 Washington Legislature (Representative Dist. 40)
 Western Clean Energy Campaign (WCEC)
 Western Electricity Coordination Council (WECC)
 Western Resource Advocates
 West Wind Wires
 Wyoming Industrial Energy Consumers
 Wyoming Office Of Consumer Advocacy
Others
 Avista Utilities
 Cadmus Group Inc.
 GDS Associates
 Idaho Power Company
 John Klingele (Washington Customer)
 Peter Ashcroft
 Portland General Electric (PGE)
 Ventyx

PacifiCorp extends its gratitude for the time and energy these participants have given to the
resource plan. Their participation has contributed significantly to the quality of this plan, and
their continued participation will help as PacifiCorp strives to improve its planning efforts going
forward.
Public Input Meetings

PacifiCorp hosted 15 full-day public input meetings, five public conference calls, and five state
meetings during the 2012-2013. During the 2013 IRP process presentations and discussions
covered various issues including inputs and assumptions, risks, modeling techniques, and
analytical results. Below are the agendas from the public input meetings and the technical
workshops.

PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

58
General Meetings
May 7, 2012 – General Public Meeting
 Introductions
 IRP Group and Support Team
 IRP preparation schedule
 2013 IRP regulatory compliance
 Public process
 Modeling Methodology Changes
 Resource Acquisition Activities
 2012 Wind Integration Study
 Action Plan status update: coal, demand-side management, transmission

June 20, 2012 – General Public Meeting
 Energy efficiency modeling workshop
 2012 Wind Integration Study workshop
 Portfolio development roundtable discussion

July 13, 2012 – General Public Meeting
 Portfolio Case Development
 “Strawman” portfolio cases
 Stakeholder comments and next steps
 Transmission Scenarios in Portfolio Case Development
 Energy Gateway Scenarios
 Prior perspectives on IRP/transmission
 Action items and goals from 2011 IRP
 Inclusion of transmission projects
 Transmission Benefit Analysis
 Drivers and objectives
 FERC Order 1000
 Benefit identification and valuation example

August 2, 2012 – General Public Meeting
 Conservation Voltage Reduction Project Update
 Resource Adequacy Workshop
 Planning Reserve Margin
 Load and Resource Balance
 Portfolio Case Development Comment Update

August 13, 2012 – General Public Meeting
 Utility-scale Supply-Side Resources
 Renewable Portfolio Standards
 Wind Integration Study Update

September 14, 2012 – General Public Meeting
 Public Input Meeting Schedule Update
PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

59
 Environmental Compliance Update
 Portfolio Development Cases
 Load Forecast
 IRP Scenarios
 GRD Recommendations
 Load Forecast (continued)
 Capacity Load and Resource Balance

October 24, 2012 – General Public Meetings
 IRP modeling schedule update
 Utility-scale resource option updates
 Wind Integration Study Update
 Planning reserve margin development using the WECC building block approach
 Portfolio development case fact sheets

November 5, 2012 – General Public Meeting
 Transmission benefit evaluation
 2011 IRP Action Plan commitment
 Transmission System Benefits Tool
 Overview
 Review of Sigurd-Red Butte benefits evaluation
 Segment D preview
 Stochastic modeling and preferred portfolio selection approach

November 27, 2012 – General Public Meeting
 Planning reserve margin (PRM) recommendation and study results
 Methodology update overview

January 31, 2013 – General Public Meeting
 Status Update
 Core Case Portfolio Results
 Wind Integration Update

February 27, 2013 – General Public Meeting
 Transmission System Benefits Tool
 IRP modeling and results update
 Class 2 Demand-Side Management supply curves review

March 21, 2013 – General Public Meeting
 Draft Preferred Portfolio Overview
 Initial screening
 Final screening
 Portfolio selection
 Other results
 PaR RPS analysis
 PaR Energy Gateway Segment D update
PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

60

April 5, 2013 – General Public Meeting
 Updated PaR Analysis
 Draft Preferred Portfolio Update
 Action Plan
 Next Steps

April 17, 2013 – General Public Meeting
 Sensitivity Studies
 Draft IRP Document
 DSM Decrement
 Filing Update

April 17, 2013 – Confidential Meeting
 Discussion on Volume 3

Public Conference Call Meetings
August 24, 2012 - Public Conference Call
 Distributed Generation Resource Assumptions

September 24, 2012 – Public Conference Call
 Planning Reserve Margin Methodology
 Price Scenarios / Modeling Methodology
 Natural Gas
 Carbon dioxide tax
 Electricity

October 3, 2012 – Public Conference Call
 Utility-scale costs of single-axis solar PV resources
 Updated Cadmus distributed solar PV memo (September 28th, 2012)

December 6, 2012 – Public Conference Call
 Brief on forthcoming action from U.S. Environmental Protection Agency
 IRP Filing Schedule Update

December 14, 2012 – Public Conference Call
 Smart Grid Update

December 18, 2012 – Public Conference Call
 Update on IRP Filing Schedule
 Update on Core Case Fact Sheets and Price Curve Scenarios

PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

61
State Meetings
July 11, 2012 – Idaho State Stakeholder Meeting
July 12, 2012 – Wyoming State Stakeholder Meeting
July 19, 2012 – Oregon State Stakeholder Meeting
July 20, 2012 – Washington State Stakeholder Meeting
August 14, 2012 – Utah State Stakeholder Meeting

Parking Lot Issues

During the course of the public input meetings, certain concerns or questions needed additional
follow-up from PacifiCorp. These questions or issues were taken off-line and addressed in a
meeting report or at a subsequent public input meeting or workshop.

Public Review of IRP Draft Document

PacifiCorp received comments from many of our stakeholders submitted throughout our public
process addressing many of the key assumptions and methodologies used in our portfolio
evaluations. Stakeholder written comment is noted on the IRP comment website from the
following parties:

 Citizen’s Utility Board of Oregon
 Encana Corporation
 HEAL Utah and Utah Physicians for a Healthy Environment
 Idaho Public Utility Commission Staff
 Interwest Energy Alliance
 NW Energy Coalition
 Oregon Department of Energy
 Oregon Public Utilities Commission Staff
 Powder River Basin Resource Council
 Renewable Northwest Project
 Sierra Club
 Utah Association of Energy Users
 Utah Clean Energy
 Utah Division of Public Utilities
 Utah Office of Consumer Services
 Utah Public Service Commission Staff
 U.S. Department of Energy - Northwest Clean Energy Application Center
 U.S. Department of Energy - Intermountain Clean Energy Application Center
 Washington Utility and Transportation Commission Staff
 Western Resource Advocates

Many of the clarifications and information requested through the written comments, verbal
suggestions, public meetings, teleconference calls and data requests, have been incorporated into
PACIFICORP - 2013 IRP APPENDIX C – PUBLIC INPUT PROCESS

62
the final version of the IRP. Many of the Company’s inputs were modified based on stakeholder
comments received, such as, , Solar photovoltaic costs, Solar water heating costs, higher wind
capacity factors, the geothermal request for information (RFI), DSM Ramping, DSM cost
bundles, suggestions for study assumptions, recommendations on development of portfolio
cases, and prioritization of case studies. In addition, the technical review committee has provided
comments on the wind integration study.

Contact Information

PacifiCorp’s IRP internet website contains many of the documents and presentations that support
recent Integrated Resource Plans. To access it, please visit the company’s website at
http://www.PacifiCorp.com click on the menu “Energy Sources” and select “Integrated Resource
Planning”.

PacifiCorp requests that any informal request be sent in writing to the following address or email
address below.

PacifiCorp
IRP Resource Planning Department
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232

Electronic Email Address:
[e-mail]

Phone Number:
[phone]

PACIFICORP – 2013 IRP APPENDIX D – ENERGY EFFICIENCY
63

APPENDIX D – DEMAND-SIDE MANAGEMENT AND
SUPPLEMENTAL RESOURCES
Introduction

Appendix D reviews the studies and reports used to support the demand-side management and
supplemental resource information used in the modeling and analysis of the 2013 Integrated
Resource Plan (IRP).
Class 2 Demand-Side Management Resource Ramping

This document presents the methods used by The Cadmus Group, Inc. (Cadmus) and the Energy
Trust of Oregon (Energy Trust) to develop reasonable estimates of annual Class 2 Demand-Side
Management (DSM) (energy-efficiency) potential available for acquisition in PacifiCorp’s
service territory for consideration in PacifiCorp 2013 IRP. The Energy Trust method is applied
to resources in Oregon while the Cadmus method applies to the other five states PacifiCorp
serves. Though the mechanics of the two methods differ, the objectives are the same – to
estimate the amount of reasonably achievable Class 2 DSM potential in each year of the 20-year
study period.

Please find the report at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl
an/2013IRP/2013IRP_EnergyEfficiencyResourceRamping_10-22-2012.pdf
Assessment of Long-Term, System-Wide Potential for Demand-Side and
Other Supplemental Resources

Since 1989, PacifiCorp has developed biennial IRPs to identify an optimal mix of resources that
balance considerations of cost, risk, uncertainty, supply reliability/deliverability, and long-run
public policy goals. The optimization process accounts for capital, energy, and ongoing
operation costs as well as the risk profiles of various resource alternatives, including: traditional
generation and market purchases, renewable generation, and DSM resources such as energy
efficiency, and demand response or capacity-focused resources. Since the 2008 IRP, DSM
resources have competed directly against supply-side options, allowing the IRP model to guide
decisions regarding resource mixes, based on cost and risk.

This study, conducted by Cadmus, in collaboration with Nexant, Inc., primarily seeks to develop
reliable estimates of the magnitude, timing, and costs of DSM resources likely available to
PacifiCorp over a 20-year planning horizon, beginning in 2013. The study focuses on resources
realistically achievable during the planning horizon, given normal market dynamics that may
hinder resource acquisition. Study results were incorporated into PacifiCorp’s 2013 IRP and will
be used to inform subsequent DSM planning and program design efforts. This study serves as an
update of similar studies completed in 2007 and 2011.
PACIFICORP – 2013 IRP APPENDIX D – ENERGY EFFICIENCY

64

For resource planning purposes, PacifiCorp classifies DSM resources into four categories,
differentiated by two primary characteristics: reliability and customer choice. These resources
can be defined as: Class 1 DSM (firm, capacity focused), Class 2 DSM (energy efficiency), Class
3 DSM (non-firm, capacity focused), and Class 4 DSM (educational).

From a system-planning perspective, Class 1 DSM resources can be considered the most reliable,
as they can be dispatched by the utility. In contrast, behavioral changes, resulting from voluntary
educational programs included in Class 4 DSM, tend to be the least reliable. With respect to
customer choice, Class 1 DSM and Class 2 DSM resources should be considered involuntary in
that, once equipment and systems have been put in place, savings can be expected to flow. Class
3 and Class 4 DSM activities involve greater customer choice and control. This assessment
estimates potential from Class 1, 2, and 3 DSM.

In addition to the three DSM resource classifications, this study also estimates potential from
supplemental resources, which fall outside PacifiCorp’s classification of DSM and include
renewable and nonrenewable customer-sited generation. For this study, supplemental resources
include: combined heat and power (CHP), solar photovoltaics (PV), and solar water heaters
(SWH).

This study excludes an assessment of Oregon’s Class 2 DSM potential and supplemental
resource potential for SWHs, as this potential has been captured in assessment work conducted
by the Energy Trust, which provides energy-efficiency potential in Oregon to PacifiCorp for
resource planning purposes.

The study can be found at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Demand_Side_Manage
ment/DSM_Potential_Study/PacifiCorp_DSMPotential_FINAL_Vol%20I.pdf
The appendices for the study can be found at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Demand_Side_Manage
ment/DSM_Potential_Study/PacifiCorp_DSMPotential_Vol-II_Mar2013.pdf
Class 3 Demand Side Management load impact market survey study

In its 2011 IRP, PacifiCorp did not include Class 3 options as a base resource for planning
purposes. In its action plan update, PacifiCorp committed to have a third-party consultant review
and report on how other utilities treat price-responsive products in their resource planning
process, and prepare a recommendation on how the Company might apply contributions from
price products to help defer investments in other resource options cost-effectively.

To inform the treatment of Class 3 in PacifiCorp’s 2013 IRP, PacifiCorp engaged Cadmus , to
conduct a survey addressing how other utilities typically incorporate the incremental load impact
of similar, non-dispatchable, demand response/focused DSM resources (Class 3) in their
integrated resource plans. This memorandum reports the results of that survey.

The memo can be found at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl
an/2013IRP/2013IRP_TOUMemo-09-04-2012.pdf
PACIFICORP – 2013 IRP APPENDIX D – ENERGY EFFICIENCY
65

Other Supplemental Resource Studies
Combined Heat and Power study
Cadmus, under contract to PacifiCorp, prepared a study that calculated the levelized cost and
produced supply curves for combined heat and power (CHP) systems projected to be installed in
PacifiCorp territory over the next 20 years as part of the 2013 IRP. The Cadmus memo in
particular completed the following: 1) explain the sources referenced for this analysis, 2) present
data used in the analysis, and 3) provide the results.

Cadmus presented draft results to stakeholders on August 24, 2012. Stakeholder input was
considered in refining the analysis. The final results were presented in a memo, with responses to
stakeholder comments included at the end.

The memo can be found at following:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl
an/2013IRP/2013IRP_CHP-Memo-LCOEexcel_10-04-12.pdf
Solar Water Heating Market Potential and Associated Cost study
Cadmus, under contract to PacifiCorp, calculated the total market potential and associated
levelized cost for SWH systems projected to be installed in PacifiCorp territory over the next 20
years. The results of this analysis are used in PacifiCorp’s 2013 IRP.

This memorandum discusses the assumptions, data sources, results, and updates to Cadmus’
analysis. It also addresses the feedback from the public stakeholder meeting held on August 24,
2012, at which preliminary results were presented.

The memo can be found at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl
an/2013IRP/PAC%202013IRP_SWH%20Memo_10-05-12.pdf
Solar Photovoltaic Market Potential and Associated cost study
Cadmus, under contract to PacifiCorp, calculated the predicted technical potential, market
potential, and levelized cost of energy for PV systems installed and operating in PacifiCorp
territory from 2013-2032. The results of this analysis are used in PacifiCorp’s 2013 IRP.

This memorandum outlines the assumptions, data sources, and preliminary results of Cadmus’
analysis. Preliminary results were discussed at a stakeholder meeting on August 24, 2012. Based
on feedback received at that meeting, this memorandum reflects relevant updates to assumptions,
methodology, and results.

The memo can be found at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl
an/2013IRP/PAC_2013IRP_Memo_PVInputs_09282012.pdf

PACIFICORP – 2013 IRP APPENDIX D – ENERGY EFFICIENCY

66

PACIFICORP – 2013 IRP APPENDIX E – CONSERVATION VOLTAGE REDUCTION
67

APPENDIX E – CONSERVATION VOLTAGE REDUCTION
Introduction
Conservation Voltage Reduction (CVR) and Voltage Optimization (VO) have seen renewed
industry interest in recent years as stakeholders strive to experience greater system efficiencies.
These terms refer to the reduction in energy usage realized by operating the distribution system
and customer equipment at a reduced, but still satisfactory, voltage. In response to a voter-
approved initiative in Washington, PacifiCorp (the Company) began detailed analysis of
distribution circuits there in order to ascertain what energy savings might be achievable from
CVR. Commission staff in Oregon also requested the Company screen distribution circuits in its
other major states to determine whether cost effective energy savings potential existed elsewhere
in the Company’s service territory. The Company’s recent progress in CVR analysis has centered
on the four areas described below.
Washington Tier 1 study (2011)
The scope of this study was to identify all cost-effective, reliable and feasible system
improvements on 19 circuits at 12 substations in Yakima, Sunnyside and Walla Walla. The
circuits were chosen based on what the Company thought would be likely to yield energy
savings from voltage reduction. In some cases the analyzed circuits were adjacent to16 other
circuits not part of the study, which generated improvement recommendations which could not
be incorporated without additional analysis. Three different levels of investment (low-cost non-
capital improvements, medium-cost capital improvements and high-cost communication-based
capital improvements) were studied to determine whether additional investment could be
justified by the associated incremental energy savings.

Fourteen of the nineteen circuits showed potential for cost-effective energy savings, and four of
them were chosen for the 2012 pilot implementation. The other ten were adjacent to unstudied
circuits. Implementation on these would be postponed until the adjacent circuits could be
studied, in order to avoid risk16 and quantify any additional savings.

The completed study and subsequent CVR factor adjustments based on customer classes yielded
a net forecast of 0.24 aMW in energy savings from the recommended projects (0.09 aMW from
the four pilot circuits (Clinton substation in Yakima and Mill Creek substation in Walla Walla)
and 0.16 aMW from the other ten circuits).

The recommended improvements on the four pilot circuits included a total of eleven single phase
swaps (two on 5Y608, four on 5Y610 and five on 5W127) and the addition of one line capacitor
16 “Adjacent circuits” refers to multiple circuits regulated by the same device. For instance, if Circuits C1 and C2 are
regulated by Regulator R1, C1 may have been studied in detail because it was a short urban circuit. Circuit C2 may
not have been studied because it was long or had existing low voltage issues. Recommended improvements for
Circuit C1 might include minor improvements and a lower voltage setting. There is a risk that Circuit C2 would be
adversely affected by the lower voltage setting, and therefore C1 and C2 should be studied together. In the Tier 1
study, the Company picked what it thought were the most promising circuits to determine the magnitude of potential
energy savings in the region. In those cases where improvements were forecast to be cost effective and adjacent
circuits had not been included, the group of circuits was added to the Tier 2 study.
PACIFICORP – 2013 IRP APPENDIX E – CONSERVATION VOLTAGE REDUCTION

68

(600 kVAR on 5W127). Substation voltage band centers, 121 volts at Clinton and 122.75 volts at
Mill Creek, were lowered to 119 volts. The median band center in Washington is 121 volts.
Interval metering at the start and end of each feeder was also included.
Washington Tier 2 study (2012)
The scope of this study, defined after the Tier 1 study was complete, was to identify all cost-
effective, reliable and feasible system improvements on 25 circuits in Yakima and Sunnyside.
All Walla Walla savings had been identified. Eleven of the 25 chosen circuits had been studied
in Tier 1; the other 14 were adjacent to those eleven. In sum, nine regulated substation buses
were studied at seven substations: Grandview, Nob Hill, North Park, Orchard, River Road,
Sunnyside and Wiley.

Of the nine buses, three were identified as potentially cost effective for voltage reduction
improvements given the assumptions in the study. The forecast energy savings were 0.10 aMW
at Orchard substation (two buses) and 0.07 aMW at Sunnyside substation (one bus).

The primary reason for the difference in results between studies is the analysis of adjacent
circuits. As an example, North Park substation’s 5Y356 was predicted to yield cost-effective
savings in Tier 1. When studied with the adjacent 5Y398 in Tier 2, no cost-effective solution for
the pair existed. The improvements necessary to make 5Y398 compliant with voltage reduction
were high enough to cause the pair of circuits to be non-cost effective.
Washington pilot project results
Of the 0.09 aMW predicted to be acquired through the four 2012 pilot circuits, less than 0.01
aMW was achieved. All four circuits failed to meet the protocol efficiency thresholds both
before and after voltage reduction. This meant that energy savings could not be verified by an
approved method, since the Simplified Protocol scope requires that the thresholds be met. The
estimated savings from the metered data, ignoring the threshold violations, is 0.017 aMW at
Clinton and zero or negative energy savings at Mill Creek.

The Clinton 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, a value 23%
higher than the marginal (avoided) purchase energy rate used in Washington. These values come
with the caveat that protocol thresholds were violated and confidence in both the voltage
reduction value and energy savings value are consequently very low. For the purposes of
reporting savings toward the Company’s 2012-13 conservation target17 in Washington, zero
energy savings will be claimed for both Clinton and Mill Creek on account of the threshold
violations and resulting inapplicability of protocol scope.
17 In Washington, the Company files its ten-year achievable conservation potential and biennial conservation target
every two years. For the 2012-13 biennium, the target for the distribution efficiency portion of the portfolio was
filed as a range (0 to 0.346 aMW), because the ability of the Company to achieve its forecast voltage reduction
energy savings was unknown.
PACIFICORP – 2013 IRP APPENDIX E – CONSERVATION VOLTAGE REDUCTION
69

Multi-state high-level screening effort
Using the results of both studies, a statistical principal component analysis of circuit parameters
and energy availability was conducted in 2012 and early 2013. Using system knowledge and
sound engineering principles, strong correlations were found between cost-effective energy
savings and key indicators such as maximum circuit length, total line miles and residential
energy usage.

Two key lessons from the studies 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 repeatedly
measured due to the dynamic interplay between the system and the customers’
requirements.

In 2012 and 2013, 100% of the active distribution circuits in Oregon, Idaho, Wyoming and Utah
were screened by the statistical method described above, and pilot project results were applied
where possible to ensure realistic projections. Without identifying the improvements required,
this analysis suggests that between 0 and 0.2 aMW of CVR energy savings might exist within the
Company’s service territory in those four states. The cost of this energy is likely to exceed the
Company’s marginal purchase cost, and accurate measurement does not appear to be possible at
this time.
Future Conservation Voltage Reduction
Future investment decisions regarding voltage reduction as an energy resource must take into
account the cost effectiveness, reliability and feasibility of such project. The Company will not
pursue distribution efficiency projects that do not meet all three of these criteria. The 2012 pilot
on four of the most promising circuits in Washington shows that voltage reduction as a
distribution efficiency measure is not cost effective at PacifiCorp.
With regard to reliability of energy savings from voltage reduction, the pilot has also provided
valuable information. Actual energy savings appear to be less than one tenth of that predicted by
rigorous and detailed system analysis. The Tier 2 study also called out limitations in circuit
analysis as a project risk. Additionally, future system reconfiguration needs identified around
Clinton substation highlight the danger of long-term energy savings predictions. At this time,
energy savings from voltage reduction cannot be reliably acquired at PacifiCorp.
With regard to feasibility of energy savings from voltage reduction, the pilot has helped the
Company to better appreciate the difficulty in accurately predicting feeder voltages at varying
load levels. State estimation and Advanced Metering Infrastructure research conducted by the
Electric Power Research Institute and the Institute of Electrical and Electronic Engineers Energy
in 201218 highlighted the critical nature of this industry hurdle. The Tier 2 report also
acknowledged that load variations create challenges in measuring small voltage and energy
18 R.F. Arritt, R.C. Dugan, R.W. Uluski and T.F. Weaver, “Investigating Load Estimation Methods with the Use of
AMI Metering for Distribution System Analysis,” IEEE, 978-1-4673-0338, 2012.
PACIFICORP – 2013 IRP APPENDIX E – CONSERVATION VOLTAGE REDUCTION

70

changes. Without more accurate load allocation and voltage modeling technology, the Company
has concluded that energy savings from voltage reduction cannot be feasibly measured on its
system at this time.

PACIFICORP – 2013 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT
71

APPENDIX F – FLEXIBLE RESOURCE NEEDS
ASSESSMENT
Introduction
In its Order No. 12013 issued on January 19, 2012 in Docket No. UM 1461 on “Investigation of
matters related to Electric Vehicle Charging,” the Oregon Public Utility Commission (OPUC)
adopted the OPUC staff’s proposed IRP guideline:

1. Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the
balancing reserves needed at different time intervals (e.g. ramping needed within 5
minutes) to respond to variation in load and intermittent renewable generation over the
20-year planning period;

2. Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the
balancing reserves available at different time intervals (e.g. ramping available within 5
minutes) from existing generating resources over the 20-year planning period; and

3. Evaluate Flexible Resources on a Consistent and Comparable Basis: In planning to fill
any gap between the demand and supply of flexible capacity, the electric utilities shall
evaluate all resource options including the use of EVs, on a consistent and comparable
basis.
In this appendix, the Company first identifies its flexible resource needs for the IRP study period
of 2013 through 2032, as well as the calculation method used to estimate the requirements. Then,
the Company identifies its supply of flexible capacity in accordance with the Western Electricity
Coordinating Council (WECC) operating reserves guidelines from its generation resources and
demonstrates that PacifiCorp has sufficient flexible resources to meet its requirements.
Flexible Resource Requirements Forecast
PacifiCorp estimated its flexible resource needs as being its requirements for operating reserves
over the planning horizon to maintain reliability and in compliance with the North American
Electric Reliability Corporation (NERC) regional reliability standards. NERC regional
reliability standard BAL-STD-002-019 requires each balancing authority, such as PacifiCorp East
and PacifiCorp West, to carry sufficient operating reserve at all times. Operating reserve
consists of contingency reserve and regulating margin. Each of these types of operating reserves
is further defined below.
Contingency Reserve
Contingency reserve is the capacity of resources that a balancing authority holds in reserve that
can be used to respond to contingency events on the bulk power system (e.g., an instantaneous
trip of a large generator). The amount of required contingency reserve is defined in NERC BAL-
STD-002-0. Contingency reserve may not be applied to manage other system fluctuations such
19 http://www.nerc.com/files/BAL-STD-002-0.pdf
PACIFICORP – 2013 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT
72

as changes in load or output from variable energy resources, which are mainly wind generation
resources on PacifiCorp’s system.
Regulating Margin
Regulating margin is the additional capacity that a balancing authority holds in reserve to ensure
that it has adequate reserves at all times to meet the NERC Control Performance Criteria in
BAL-007-120. In the current IRP, regulating margin is composed of ramp reserve and regulation
reserve, which are discussed in more details in Volume II, Appendix H, PacifiCorp’s 2012 Wind
Integration Study. Briefly,

Ramp Reserve: This category of reserves is to follow net balancing area load changes
from minute-to-minute, hour-to-hour continuously at all times. The variability in net
balancing area load is assumed to be perfectly known for future time intervals (as though
the operator would know exactly what the net balancing area load would be a minute
from now, ten minutes from now, and an hour from now) defines the ramp of the system.

Regulation Reserve: Variations in load or wind generation from their respective forecasts
are not considered contingency events, yet these events still require generating capacity
be set aside in order to follow the variations.
As operating reserves include separate and distinct components, PacifiCorp estimated the
forward requirements for each component separately. The contingency reserve requirements are
from the stochastic simulation study of the preferred portfolio in the Planning and Risk model, as
it is affected by the hourly interchange and generation dispatch represented in the study. The
regulating margin requirements, which reflect the additional reserve capacity requirement from
the flexible resources and are part of the inputs to the Planning and Risk model, are calculated
applying the methods developed in PacifiCorp’s 2012 Wind Integration Study (Volume II,
Appendix H). Given the similar requirements of regulating margins in terms of response time,
they are grouped together with spinning reserves for modeling in this IRP. PacifiCorp has two
balancing authority areas, east and west. The reserve requirements for the two balancing
authority areas are shown in Table F.1.

20 NERC Standard BAL-007-1: http://www.nerc.com/docs/standards/sar/BAL-007-011_clean_last_posting_30-
day_Pre-ballot_06Feb07.pdf.
WECC Operating Committee extended the field trial for one year at the meeting on February 8, 2013:
https://www.wecc.biz/committees/StandingCommittees/MIC/10102012/Lists/Presentations/1/OC%20Oct%202012
%20Highlights%20-%20Paul%20Rice.pdf

PACIFICORP – 2013 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT
73

Table F.1 - Reserve Requirements (MW)

Flexible Resource Supply Forecast
Requirements by NERC and the Western Electricity Coordinating Council (WECC) dictate types
of resources that can be used to serve reserve requirements. At least one half of the contingency
reserve requirements must be spinning reserves, and the remainder is non-spinning reserves:

 Spinning reserves can only be served by resources currently online and synchronized to
the transmission grid.

 Non-spinning reserves may be served by fast-start resources that are capable of being
online and synchronized to the transmission grid within ten minutes. Interruptible load
can only serve non-spinning reserves. Non-spinning reserves may be served by resources
that are capable of providing spinning reserves.
The resources that PacifiCorp employs to serve its reserve requirements include owned hydro
resources that have storage, owned thermal resources, and purchased power contracts that
provide the Company with reserve capabilities.

Hydro resources are generally deployed first to meet the spinning reserve requirements because
of their flexibility and ability to quickly respond to changes. The amount of reserves that these
East West
Year Spin Req Non-Spin Req Spin Req Non-Spin Req
2013 435 194 329 209
2014 443 199 332 211
2015 467 221 334 212
2016 457 214 337 214
2017 462 218 339 215
2018 468 222 342 217
2019 474 226 342 218
2020 480 230 344 219
2021 487 234 346 220
2022 493 238 347 221
2023 498 242 349 222
2024 540 246 350 223
2025 564 250 352 224
2026 571 254 354 225
2027 577 258 355 226
2028 581 261 357 227
2029 586 265 359 229
2030 591 268 359 229
2031 598 273 357 227
2032 599 274 362 231
PACIFICORP – 2013 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT
74

resources can provide depends upon the difference between their expected capacities and
generation at the time. The hydro resources that PacifiCorp may use to serve reserve
requirements in the PacifiCorp West balancing authority area include its facilities on the Lewis
River, and Klamath River, as well as purchase contracts for generation from the Mid-Columbia
projects. In the PacifiCorp East balancing authority area, the Company may use facilities on the
Bear River to provide spinning reserves.

Thermal resources are also used to meet the spinning reserve requirements when they are online.
The amount of reserves provided by these resources is determined by their ability to ramp up
within a 10-minute interval. For natural gas-fired thermal resources, the amount of reserves can
be close to the differences between their nameplate capacities and their minimum generation
levels. In the current IRP, PacifiCorp’s reserves are served from not only existing coal- and gas-
fired resources that the Company operates, but also from Lake Side 2 that will be online in 2014
and the additional new gas-fired resources selected in the preferred portfolio.

Table F.2 lists the annual capacity of resources that are capable of serving reserves on the east
and west side of PacifiCorp’s system. All the resources included in the calculation are capable
of providing spinning reserves, which can also be used to serve non-spinning reserves. The non-
spinning reserve resources under contract with third parties are excluded in the calculations. The
changes in supply reflect retirement of existing resources, addition of new preferred portfolio
resources, variation in hydro capability due to stream-flow conditions, and expiration of
contracts for capacity from the Mid-Columbia projects that are reflected in the preferred
portfolio.

Table F.2 - Flexible Resource Supply Forecast (MW)

Year East Supply West Supply
2013 1,086 586
2014 1,181 764
2015 1,150 756
2016 1,150 753
2017 1,150 760
2018 1,151 749
2019 1,151 738
2020 1,150 722
2021 1,150 706
2022 1,150 732
2023 1,149 728
2024 1,341 722
2025 1,341 722
2026 1,341 722
2027 1,340 718
2028 1,607 726
2029 1,608 722
2030 1,949 722
2031 1,948 718
2032 2,039 722
PACIFICORP – 2013 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT
75

Figures F.1 and F.2 graphically display the balances of reserve requirements and capability of
spinning reserve resources in PacifiCorp’s East and West balancing authority areas. The graphs
clearly demonstrate that PacifiCorp’s system has sufficient resources to serve its reserve
requirements through the IRP planning period.

Figure F.1 - Comparison of Reserve Requirements and Resources, East Balancing
Authority Area (MW)

Figure F.2 - Comparison of Reserve Requirements and Resources, West Balancing
Authority Area (MW)

0
500
1,000
1,500
2,000
2,500
MW
Spin Req Non-Spin Req East Supply
0
100
200
300
400
500
600
700
800
900
MW
Spin Req Non-Spin Req West Supply
PACIFICORP – 2013 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT
76

Flexible Resource Supply Planning
In actual operations, PacifiCorp has been able to serve its reserve requirements and has not
experienced any incidences where it was short of reserves. PacifiCorp manages its resource
requirements to meet its reserve obligation in the same manner as is done to meet its load
obligation, through long term planning, market transactions and operational activities that are
performed on an economic basis considering utilization of the transmission capability between
the two balancing authority areas.

In addition, as discussed in Volume I, Chapter 3 of the 2013 IRP report, PacifiCorp has signed a
memorandum of understanding with the California Independent System Operator Corporation
February 12, 2013 to outline terms for the implementation of an energy imbalance market (EIM)
by October 2014. The implementation of the EIM is expected to provide alternatives to more
economic dispatch of PacifiCorp’s resources and may eventually reduce regulating margin
requirements.

As indicated in the OPUC order, electric vehicle technologies may be able to meet flexible
resource needs at some point in the future. However, given the electric vehicle technology and
market have not been developed sufficiently to provide data for the present study, and given
PacifiCorp’s analysis shows there is no gap between projected demand and supply of flexible
resources over the IRP planning horizon, PacifiCorp’s study has not attempted to specifically
address how electric vehicles could be used to meet future flexible resource needs.

PACIFICORP – 2013 IRP APPENDIX G – PLANT WATER CONSUMPTION

77

APPENDIX G – PLANT WATER CONSUMPTION
The information provide in this appendix is for PacifiCorp owned plants. Total water
consumption and generation includes all owners for jointly-owned facilities

PACIFICORP – 2013 IRP APPENDIX G – PLANT WATER CONSUMPTION

78

Table G.1 – Plant Water Consumption with Acre-Feet Per Year
**Gadsby includes a mix of both rankine steam units and peaking gas turbines
Plants Owned and Operated by PacifiCorp
Total water consumption and generation includes all owners for jointly-owned facilities

1 acre-foot of water is equivalent to: 325,851 Gallons or
43,560 Cubic Feet

Plant Name
Zero
Discharge
Cooling
Media 2008 2009 2010 2011 Average 2008 2009 2010 2011
Gals/
MWH
GPM/
MW
Carbon Water 2,199 2,349 2,193 2,458 2,300 1,204,984 1,211,875 1,296,004 1,332,218 594 9.9
Chehalis Air - - - - -715,441 1,750,041 1,296,741 664,323 - -
Currant Creek Yes Air 82 108 82 78 88 2,799,585 2,464,463 2,536,660 2,397,142 11 0.2
Dave Johnston Water 7,746 6,983 6,604 7,233 7,141 5,638,807 5,017,794 4,704,694 5,059,927 456 7.6
Gadsby **Water 426 680 893 864 716 482,903 607,387 359,404 194,389 567 9.5
Hunter Yes Water 19,380 19,300 18,941 16,961 18,645 10,246,965 9,438,683 8,785,827 8,719,300 653 10.9
Huntington Yes Water 11,385 10,922 9,549 9,069 10,231 7,148,850 6,753,764 6,107,379 5,961,371 513 8.6
Jim Bridger Yes Water 27,322 25,361 20,757 22,282 23,931 15,303,508 15,188,184 14,828,906 12,771,611 537 8.9
Lake Side Water 1,821 1,287 1,533 1,154 1,449 2,863,246 2,099,013 2,537,046 1,845,528 200 3.3
Naughton Water 10,992 10,846 13,354 14,157 12,337 5,114,409 4,752,632 5,339,385 5,102,251 754 12.6
Wyodak Yes Air 446 365 396 367 393 2,811,590 2,732,796 2,565,341 1,831,459 48 0.8
81,799 78,201 74,302 74,622 78,101 54,330,288 52,016,632 50,357,387 45,879,519 497 8.3
Acre-Feet Per Year MWhs Per Year
TOTAL
PACIFICORP – 2013 IRP APPENDIX G – PLANT WATER CONSUMPTION

79

Table G.2 – Plant Water Consumption by State (acre-feet)
Percent of total water consumption = 43.3%

Percent of total water consumption = 56.7%

Table G.3 – Plant Water Consumption by Fuel Type (acre-feet)
Percent of total water consumption = 97.1%

UTAH PLANTS
Plant Name 2008 2009 2010 2011
Carbon 2,199 2,349 2,193 2,458
Currant Creek 82 108 82 78
Gadsby 426 680 893 864
Hunter 19,380 19,300 18,941 16,961
Huntington 11,385 10,922 9,549 9,069
Lake Side 1,821 1,287 1,533 1,154
TOTAL 35,293 34,646 33,191 30,583
WYOMING PLANTS
Plant Name 2008 2009 2010 2011
Dave Johnston 7,746 6,983 6,604 7,233
Jim Bridger 27,322 25,361 20,757 22,282
Naughton 10,992 10,846 13,354 14,157
Wyodak 446 365 396 367
TOTAL 46,506 43,555 41,111 44,039
COAL FIRED PLANTS
Plant Name 2008 2009 2010 2011
Generation
Capacity Ac-ft/MW
Carbon 2,199 2,349 2,193 2,458 172 13.4
Dave Johnston 7,746 6,983 6,604 7,233 762 9.4
Hunter 19,380 19,300 18,941 16,961 1,341 13.9
Huntington 11,385 10,922 9,549 9,069 903 11.3
Jim Bridger 27,322 25,361 20,757 22,282 2,118 11.3
Naughton 10,992 10,846 13,354 14,157 700 17.6
Wyodak 446 365 396 367 335 1.2
TOTAL 79,470 76,126 71,794 72,526 Average 11.2
PACIFICORP – 2013 IRP APPENDIX G – PLANT WATER CONSUMPTION

80

Percent of total water consumption = 2.9%

Table G.4 – Plant Water Consumption for Plants Located in the Upper Colorado River
Basin (acre-feet)
Percent of total water consumption = 87.3%
NATURAL GAS FIRED PLANTS
Plant Name 2008 2009 2010 2011
Generation
Capacity Ac-ft/MW
Currant Creek 82 108 82 78 537 0.2
Gadsby 426 680 893 864 351 2.0
Lake Side 1,821 1,287 1,533 1,154 544 2.7
TOTAL 2,329 2,075 2,508 2,096 Average 1.6
Plant Name 2008 2009 2010 2011
Hunter 19,380 19,300 18,941 16,961
Huntington 11,385 10,922 9,549 9,069
Carbon 2,199 2,349 2,193 2,458
Naughton 10,992 10,846 13,354 14,157
Jim Bridger 27,322 25,361 20,757 22,282
TOTAL 71,278 68,778 64,794 64,927
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

81

APPENDIX H – WIND INTEGRATION STUDY

This appendix provides the 2012 Wind Integration Study conducted during the 2013 IRP
planning process. A draft version of this study was sent to participants in November 2012. The
2012 Wind Integration Study will be presented to the Technical Review Committee for approval
in May 2013.

PACIFICORP – 2013 IRP APPENDIX G – PLANT WATER CONSUMPTION

82

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

83

PACIFICORP
2012 WIND INTEGRATION RESOURCE STUDY

APRIL 30, 2013
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
84

1. Introduction
The purpose of this study is to estimate the operating reserves required to maintain PacifiCorp’s
system reliability and comply with North American Electric Reliability Corporation (NERC)
reliability standards. The Company must provide sufficient operating reserves to allow the
Balancing Authority to meet NERC’s control performance criteria (See BAL-007-121) at all
times, incremental to contingency reserves which the Company maintains to comply with NERC
Standard BAL-002-022. These incremental operating reserves are necessary to maintain area
control error23 within required parameters, apart from disturbance events that are addressed
through contingency reserves, due to sources outside direct operator control including intra-hour
changes in load demand and wind generation. The study results in an estimate of operating
reserve volume and estimated cost of these operating reserves required to manage load and wind
generation variation in PacifiCorp’s Balancing Authority Areas (BAAs).

The operating reserves contemplated within this study represent regulating margin, which is
comprised of ramp reserve extracted directly from operational data, and regulation reserve,
which is estimated based on operational data. The study calculates regulating margin demand
over two common operational timeframes: ten-minute intervals, called regulating; and one-hour-
intervals, called following. The regulating margin requirements are calculated from operational
data recorded during PacifiCorp’s operations from January 2007 through December 2011 (Study
Term). The regulating margin requirements for load variation, and separately for load variation
combined with wind variation, are then applied in PacifiCorp’s Planning and Risk (PaR)
production cost model to isolate the effect additional reserve requirements due to wind
generation have on overall system costs. This cost is attributed to the integration of wind
generation resources and will change over time with changes in market prices for power and
natural gas, changes in PacifiCorp’s resource portfolio and potential changes in regional market
design, such as an energy imbalance market.
Technical Review Committee
In order to ensure the Company’s study is performed according to current best practices and
benefits from guidance provided by individuals with diverse wind integration study experience,
PacifiCorp used a Technical Review Committee (TRC) for its 2012 Study. The TRC was
involved during the Study process, and their recommendations are reflected in the Study method
and scenarios addressed. All study results have been presented to and reviewed by the TRC.
The members of the TRC are:

 Andrea Coon - Director, Western Renewable Energy Generation Information System
(WREGIS) for the Western Electricity Coordinating Council (WECC)
 Randall Falkenberg – President, RFI Consulting, Inc.
 Matt Hunsaker - Manager, Renewable Integration for the Western Electricity
Coordinating Council (WECC)
 Michael Milligan - Lead research for the Transmission and Grid Integration Team at the
National Renewable Energy Laboratory (NREL)

21 NERC Standard BAL-007-1:http://www.nerc.com/docs/standards/sar/BAL-007-011_clean_last_posting_30-
day_Pre-ballot_06Feb07.pdf. 22 NERC Standard BAL-002-0: http://www.nerc.com/files/BAL-002-0.pdf 23 “Area Control Error” is defined in the NERC glossary here: http://www.nerc.com/files/Glossary_12Feb08.pdf
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

85

 J. Charles Smith - Executive Director, Utility Variable-Generation Integration Group
(UVIG)
 Robert Zavadil - Executive Vice President of Power Systems Consulting, EnerNex

The study method incorporates improvements resulting from recommendations made by TRC
members as well as analyses requested by them. The Company thanks all the TRC members for
their reviews of the study method and professional feedback.
1.1 Executive Summary
The 2012 Wind Integration Study (the “Wind Study”) estimates the regulating margin
requirement from historical load and wind generation production data. The regulating margin is
required to manage variations to area control error due to load and wind variations within
PacifiCorp’s BAAs. The Wind Study estimates the regulating margin requirement based on load
combined with wind variation and separately estimates the regulating margin requirement based
solely on load variation. The difference between these two calculations, with and without the
estimated regulating margin required to manage wind variability and uncertainty, provides the
amount of incremental operating reserves required to maintain system reliability due to the
presence of wind generation in the PacifiCorp’s BAAs. The resulting regulating margin
requirement was evaluated deterministically in PaR, a production cost model used in the
Company’s Integrated Resource Plan (IRP) to evaluate stochastic risk in selection of a preferred
resource portfolio, so that the incremental cost of the regulating margin required to manage wind
resource variability and uncertainty can be reported on a dollar per megawatt hour (MWh) of
wind generation basis.24

Table H.1 depicts the combined PacifiCorp BAA annual average regulating margin calculated in
this Wind Study, and separates the regulating margin due to load from the regulating margin due
to wind.

Table H.1 - Average Annual Regulating Margin Reserves, 2012 Wind Study (MW)

Table H.2 depicts the cost to integrate wind generation in PacifiCorp’s BAAs. The cost to
integrate wind includes the incremental regulating margin reserves to manage intra-hour
variances as outlined above and the costs associated with day-ahead forecast variances that affect
daily system balancing. Each of these component costs were calculated using PacifiCorp’s PaR
model. A series of PaR simulations were completed to isolate each wind integration cost
component by using a “with and without” approach. For instance, PaR was first used to calculate
system costs solely with the regulating margin requirement due to load variations, and then again
24 The PaR model can be run with stochastic variables in Monte Carlo simulation mode or in deterministic mode
whereby variables such as natural gas and power prices do not reflect random draws from probability distributions.
For purposes of the Wind Study, the intention is not to evaluate stochastic portfolio risk, but to estimate production
cost impacts of incremental operating reserves required to manage wind generation on the system based on current
projections of future market prices for power and natural gas.
West BAA East BAA Combined
Load-Only Regulating Margin 147 247 394
Incremental Wind Regulating Margin 54 131 185
Total Regulating Margin 202 378 579
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
86

with the increased regulating margin requirements due to load combined with wind generation.
The change in system costs between the two PaR simulations results in the wind integration cost.

Table H.2 - Wind Integration Cost (2012$ per MWh of Wind Generation)

The 579 megawatts of regulating margin identified in this study (in Table H.1) is comparable to
the 530 megawatts of regulating margin identified in the prior wind integration study developed
for the 2011 IRP. While overall operating reserve levels are similar, this Study shows the
estimated costs of these operating reserves are lower, and that the reduced cost is primarily
driven by declining natural gas and power market prices. Table H.3 compares natural gas and
power price assumptions used in the 2010 Wind Integration Study to those used in the 2012
Wind Integration Study.

Table H.3 - Nominal Levelized Natural Gas and Power Prices Used in the 2010 and 2012
Wind Integration Studies
Palo Verde High Load
Hour Power
Palo Verde Low Load
Hour Power
Opal Natural Gas
2010 Wind Study $51.26 $35.60 $5.36
2012 Wind Study $37.05 $25.74 $3.43

The effect of changing power and natural gas prices on the cost of wind integration is significant,
even if the volume of wind being integrated does not change. The value of reserves is often the
opportunity cost of a lost sale at a given generation station. This opportunity cost is foregone
margin (which is equal to the lost revenue from the wholesale sale) less the variable cost to run
the generation plant at a higher level, which is primarily the cost of fuel. Second to hydro
generation, natural gas generation is often used to meet the Company’s reserve requirements and
to manage variability and uncertainty in wind and retail load. This is because gas-fired
generation typically has less economic impact when used for reserves than coal-fired generation
and has the operational flexibility to ramp up and down as the load and wind fluctuate. As
natural gas prices have fallen, the costs of holding reserve capacity have correspondingly
dropped even though the quantity of regulating margin requirement has increased.
2. Data
2.1 Overview
The calculation of regulating margin reserve requirement was based entirely on actual historical
load and wind production data over the Study Term from January 2007 through December 2011.
No simulated wind production data was incorporated in the Wind Study, which is a change from
prior studies that did not have the benefit of a more complete historical data set. Table H.4
Study 2010 Wind Integration Study 2012 Wind Integration Study
Wind Capacity Penetration 2046 MW 2126 MW, 2011 Operational Data
Tenor of Cost 3-year levelized, 2010$1 year levelized, 2012$
Hourly Reserve ($/MWh)$8.85 $2.19
Interhour/System Balancing ($/MWh)$0.86 $0.36
Total Wind Integration ($/MWh)$9.70 $2.55
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

87

shows that the ten-minute interval data for wind resources grew substantially during this period
as wind resources came online in PacifiCorp’s BAAs.

Table H.4 - Historical Wind Production and Load Data Inventory

2.2 Historical Load and Load Forecast Data
The historical hourly day-ahead load forecasts and day-ahead hourly wind forecasts used to
operate the generation system through the Study Term (2007-2011) were retrieved from
Company records. Historical load data for the PacifiCorp East (PACE) and PacifiCorp West
(PACW) BAAs were collected for the Study Term from the PacifiCorp PI system25. These data

25 The PI system collects load and generation data and is supplied to PacifiCorp by OSISoft. The Company Web site
is http://www.osisoft.com/software-support/what-is-pi/what_is_PI_.aspx .
Nameplate Beginning End of
Capacity of Data Data Location
Wind Plants within PacifiCorp BAAs
Chevron Wind 17 12/1/2009 12/31/2011 East
Combine Hills 41 1/1/2007 12/31/2011 West
Dunlap I Wind 111 10/1/2010 12/31/2011 East
Foote Creek Generation 85 1/1/2007 12/31/2011 East
Glenrock Wind 99 1/1/2009 12/31/2011 East
Glenrock III Wind 39 1/17/2009 12/31/2011 East
High Plains Wind 99 9/13/2009 12/31/2011 East
Marengo I 140 8/3/2007 12/31/2011 West
Marengo II 70 6/26/2008 12/31/2011 West
McFadden Ridge Wind 29 9/29/2009 12/31/2011 East
Mountain Wind 1 QF 61 7/2/2008 12/31/2011 East
Mountain Wind 2 QF 80 9/29/2008 12/31/2011 East
Oregon Wind Farm QF 65 3/31/2009 12/31/2011 West
Rock River I 50 1/1/2007 12/31/2011 East
Rolling Hills Wind 99 1/17/2009 12/31/2011 East
Seven Mile Wind 99 12/31/2008 12/31/2011 East
Seven Mile II Wind 20 12/31/2008 12/31/2011 East
Spanish Fork Wind 2 QF 19 7/31/2008 12/31/2011 East
Stateline Contracted Generation 150 1/1/2007 12/31/2011 West
Three Buttes Wind 99 12/1/2009 12/31/2011 East
Top of the World Wind 200 10/1/2010 12/31/2011 East
Wolverine Creek 65 1/1/2007 12/31/2011 East
Long Hollow Wind 1/1/2007 12/31/2011 East
Stateline Transmission Customer 1/1/2007 12/31/2011 West
Campbell Wind 12/1/2009 12/31/2011 West
Jolly Hills 1 10/1/2010 12/31/2011 East
Jolly Hills 2 10/1/2010 12/31/2011 East
Wind Plants out of PacifiCorp BAAs
Goodnoe Hills Wind 94 5/31/2008 12/31/2011 West - out of BAA
Leaning Juniper 1 101 1/1/2007 12/31/2011 West - out of BAA
Load Data
PACW Load 1/1/2007 12/31/2011 West
PACE Load 1/1/2007 12/31/2011 East
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
88

were used for all the calculations involving historical load in the Study. The raw load data were
reviewed for anomalies prior to further use. Data anomalies can include:

 Incorrect or reversal of sign (recorded data switching from positive to negative)
 Significant and unexplainable changes in load from one ten-minute interval to the next
 Excessive load values

After such review, out of 262,944 ten-minute intervals in the Wind Study, only three ten-minute
intervals were identified as representing spurious data; each had extremely high load values that
would have been impossible to serve. As depicted in Table H.5, these values were corrected by
interpolating the values of the prior and successive ten-minute periods to create a smooth line
across the spurious intervals. Since reserves demands are created by sudden, unexpected
changes from one period to the next, this correction was intended to mitigate the impacts of
spurious data on the calculation of the eventual reserve requirements and costs in this study. No
other load data issues were encountered in this study.

Table H.5 - Load Data Anomalies and their Interpolated Solutions

2.3 Historical Wind Generation and Wind Generation Forecast Data
2.3.1 Overview of the Wind Generation Data Used in the Analysis
Over the Study Term, ten-minute interval wind generation data were available for the wind sites
as summarized in Table H.4. The wind output data were collected from the PI system. In
addition to historical wind generation data, the Wind Study requires historical day-ahead wind
forecasts. All of these data sets were needed to establish wind integration costs using the PaR
model, and are discussed in turn below.

2.3.2 Historical Wind Generation Data
As shown in Figure H.1, a cluster of PacifiCorp owned and contracted wind generation plants is
located in PACW and another cluster is located in PACE. It is worth noting that three wind sites,
Wolverine Creek in Idaho, Spanish Fork in Utah, and Mountain Wind in Wyoming, are within
PACE, but are geographically distant from both the western and the eastern clusters.

Time Original Final Replacement
8/12/2010 9:10 2,654.20 2,654.20
8/12/2010 9:20 -288,687,072.00 2,669.24 Average of 9:10 and 9:30
8/12/2010 9:30 2,684.28 2,684.28
2/3/2011 9:50 3,135.41 3,135.41
2/3/2011 10:00 409,630.75 3,103.82 9:50 + 1/3 of (10:20 minus 9:50)
2/3/2011 10:10 213,667.91 3,072.23 9:50 + 2/3 of (10:20 minus 9:50)
2/3/2011 10:20 3,040.65 3,040.65
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

89

Figure H.1 - Representative Map of PacifiCorp Wind Generating Stations Used in this
Study

The wind data collected from the PI system is grouped into a series of sampling points, or nodes,
each of which may represent one or more wind plants’ output. In consideration of occasional
irregularities in the system collecting the data, the raw wind data was reviewed for
reasonableness considering the following criteria:

 Incorrect or reversal of sign (recorded data switching from positive to negative)
 Commercial operation date of wind facilities
 Output greater than expected for the wind generation capacity being collected at a given
node
 Wind generation appearing constant over a period of days or weeks at a given node

Some PI system data streams exhibit large negative generation output readings in excess of that
attributable to station service. These readings reflect positive generation and a reversed polarity
on the meter, rather than negative generation or system load. The meter polarity generally
remains constant for a long period, and in such instances, the sign was reversed for all data in the
period of polarity reversal.

Most of the wind plants in the Wind Study first came online within the Study Period. To reduce
one-time impacts due to startup testing or partial facility output as individual wind generators at
a given plant were commissioned, wind generation prior to each facility’s commercial operation
date was not included in the Wind Study.

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
90

The PI system ten-minute interval data streams also sometimes exhibit unduly long periods of
unchanged or “stuck” values for a given node. Because reserve requirements are driven by large,
sudden changes in either wind or load, these data anomalies needed to be addressed. To address
these anomalies, the values were held constant when “stuck” values were observed but for the
last hour of “stuck” output to smooth the transition to the rest of the data series. For example, if
a node’s measured wind generation output was 50 megawatts (MW) for three weeks and the first
new, fluctuating data value was 75 MW, the value of the last hour of “stuck” data would be
replaced with the average of 50 MW and 75 MW. The Company investigated the impact of
replacing some of the stuck values with corresponding hourly generation data on the Mountain
Wind and Spanish Fork wind plants. As the effect of substituting Mountain Wind and Spanish
Fork wind data for some of the stuck values was ascertained to be minimal (less than a tenth of a
percent change in the resulting component reserve requirement), the operational data used for the
Wind Study was not changed other than the instances described above.26 In total, the wind
generation data adjusted for stuck values represented only 0.5 percent of the wind data used in
the Wind Study.

2.3.3 Historical Day-ahead Wind Generation Forecasts
Day-ahead wind forecasts for all owned and contracted wind resources were collected from daily
historical records maintained by PacifiCorp commercial operations as well as from the
Company’s third party wind forecast service provider, Garrad Hassan Co. From year 2007 to
year 2009 the same sets of historical day-ahead wind forecast data that were used for the
Company’s 2010 wind integration study were used again for the 2012 study for consistency.
From year 2010 to the end of year 2011, Garrad Hassan provided complete data sets for the
historical day-ahead wind forecasts. For transmission customers’ resources the Company used
the actual hourly wind generation data, eliminating the contribution of day-ahead “forecast error”
from these resources, which is consistent with the fact PacifiCorp does not schedule transmission
customers’ resources located within the Company’s BAAs.

During the review process of the 2010 and 2011 data sets, PacifiCorp found the following issues:

 Negative wind generation forecast for a period of consecutive hours
 Wind forecast data shown before the wind resources’ official operational dates
 Missing forecast on some hours or on consecutive days

Only one resource had a negative generation forecast, Goodnoe Hills, for the 3-day period
10/3/2011 through 10/6/2011. After confirming the resource was not in station service or
maintenance, the sign was corrected and reversed to positive. Any forecast generation before the
official commercial operational date was removed from the data series of then newly added
resources, consistent with the practice adopted for actual generation as described in the section
above.

In the 2010 and 2011 day-ahead forecast data sets, 1.3 percent of the forecast hours were missing
data, from one hour up to a week consecutive. If only one hour was missing, that hour forecast
was created using the average of the previous hour forecast and the next hour forecast in order to
smooth out the fluctuation in the data set. If several days’ forecasts were missing, then the latest
26 By leaving stuck values in place but for the last interval, variability and uncertainty in wind generation from a
facility was removed for those intervals in which “stuck” values were observed, which all else equal would result in
understating regulation margin requirements.
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

91

24 hours of forecast data immediately before the missing days were copied and repeated to fill in
the days-long gap. This approach is intended to preserve the smoothness of forecast data while
trying not to reduce intermittency in real wind generation forecasts.

3. Method
3.1 Method Overview
This section presents the approach used to establish regulating margin reserve requirements and
the method for calculating the associated wind integration costs. Ten-minute interval load and
wind data was used to estimate the amount of regulating margin reserves, both up and down,
needed to manage variation in load and wind generation within PacifiCorp’s BAAs.

3.1.1 Operating Reserves
In order to clarify this requirement, this section discusses the NERC regional reliability standard
operating reserve requirement and how it fits into this study. NERC regional reliability standard
BAL-STD-002-027 requires each Balancing Authority, such as PacifiCorp, to carry sufficient
operating reserve at all times. Operating reserve consists of contingency reserve and regulating
margin. These reserve requirements necessitate available generation surplus to that required to
meet load obligations. Each of these types of operating reserve is further defined below.

Contingency reserve is capacity the Company holds in reserve that can be used to respond to
contingency events on the bulk power system (e.g., an instantaneous trip of a large
generator). The amount of required contingency reserve is defined in NERC BAL-STD-002-
0. Contingency reserve may not be applied to manage other system fluctuations such as changes
in load or wind generation output. Therefore, this study focuses on the operating reserve
component to manage load and wind generation variations, which is incremental to contingency
reserve, and also referred to in NERC BAL-STD-002-0 as regulating margin.

Regulating margin is the additional capacity the Company holds in reserve to ensure it has
adequate reserve at all times to meet the NERC Control Performance Criteria in BAL-007-128.
NERC Control Performance Criteria require the Company to carry regulating reserves
incremental to contingency reserves to maintain reliability. However, these additional regulating
reserves are not defined by a simple formula, but rather are the amount of reserves required by
each BA to meet the control performance standards. Since the Company’s 2010 Wind Integration
Study29, the performance standards have evolved from a calculated Control Performance
Standard 2 (CPS2)30 mandated by NERC BAL-001-031 to a more dynamic regime mandated by
27 http://www.nerc.com/files/BAL-STD-002-0.pdf 28 NERC Standard BAL-007-1:http://www.nerc.com/docs/standards/sar/BAL-007-011_clean_last_posting_30-
day_Pre-ballot_06Feb07.pdf. According to WECC Operating Committee meeting highlights (page 4, item 5), the
field trial of this standard has been extended an additional year. The highlights are published here:
http://www.wecc.biz/committees/StandingCommittees/OC/20130108/Lists/Agendas/1/OC%20Voting%20Record%
20January%202013_Final_Revised.pdf 29
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/Wind_Integratio
n/PacifiCorp_2010WindIntegrationStudy_090110.pdf, page 11 30 PacifiCorp has not controlled to CPS2 since March 1, 2010. 31 http://www.nerc.com/files/BAL-001-0_1a.pdf
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
92

NERC BAL-007-1, called Balancing Authority ACE Limit (BAAL), in which the Company’s
performance standard can be affected by the frequency of the interconnection. This new standard
allows a greater ACE during periods when the ACE is helping frequency. However, the
Company cannot plan on knowing when ACE will help or exacerbate frequency so the L10 is
used for the bandwidth in both directions of the ACE. Thus the Company determines, based on
the unique level of wind and load variation in its system, and the prevailing operating conditions,
the unique level of incremental operating reserve it must carry. This reserve, or regulating
margin, must respond to follow load and wind changes throughout the delivery hour. PacifiCorp
further segregates regulating margin into two components to assist in the analysis: ramp reserve
and regulation reserve.

Ramp Reserve: Due to a number of factors (fluctuations in customer demand, spot
transactions, varying amounts of generation produced by variable resources such as wind and
solar generation) the net balancing area load changes from minute-to-minute, hour-to-hour
continuously at all times. This variability (increasing and decreasing load) requires ready
capacity to follow continuously, through short deviations, at all times. Treating this
variability as though it is perfectly known for future time intervals (as though the operator
would know exactly what the net balancing area load would be a minute from now, ten
minutes from now, and an hour from now) defines the ramp of the system.

Regulation Reserve: Changes in load or wind generation are not considered contingency
events, yet these events still require that capacity be set aside. The Company has defined two
types of regulation reserve – regulating and following reserves. Regulating reserve covers
short term variations (seconds to minutes, normally using automatic generation control) in
system load and wind, whereas following reserve covers uncertainty across an hour normally
using manual generation control.

To summarize, regulating margin represents operating reserves the Company holds over and
above the mandated contingency reserve requirement to maintain moment-to-moment system
balance between load and generation. The regulating margin is the sum of two parts; ramp
reserve and regulation reserve. The ramp reserve represents a minimum amount of flexibility
required to follow the actual net system load (load minus wind generation output) with
dispatchable generation. The regulation reserve represents flexibility maintained to manage
intra-hour and hourly forecast errors about the net system load, and consists of four components:
load following, load regulating, wind following, and wind regulating.

3.1.2 Method Steps
The regulating margin requirements are calculated for each of the Company’s BAAs from
production data via a five step process, each described in more detail later in this section. The
five steps include:

1. Calculation of the ramp reserve from the historical data (with and without wind
generation).
2. Creation of hypothetical forecasts from historical load and wind production data.
3. Compare actual generation and load values in each ten-minute interval of the study term
to the hypothetical forecast values, and record the differences as deviations.
4. Group these deviations into bins that can be analyzed for the reserves requirements per
forecast value of wind and load, respectively, such that a specified percentage (or
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

93

tolerance level) of these deviations would be covered by some level operating reserves.
5. Apply the reserve requirements noted for the various wind and load forecast values are
then applied back to the operational data, enabling an average reserves requirement to be
calculated for any chosen time interval within the Study Term.

Once the amount of regulating margin is estimated, the cost of holding the specified reserves on
PacifiCorp’s system is estimated using the PaR model. In addition to using PaR for evaluating
operating reserve cost, the PaR model is also used to estimate wind integration cost associated
with daily system balancing activities. These system balancing costs result from the
unpredictable nature of wind generation on a day-ahead basis and can be characterized as system
costs borne from committing generation resources against a forecast of load and wind generation
and then dispatching generation resources under actual load and wind conditions as they occur in
real time.
3.2 Regulating Margin Requirements
As noted above, ten-minute interval wind generation and load data drives the calculation of the
regulating margin requirement for ramp reserve and regulation reserve. The approach for
calculating regulating margin requirements necessary to supply adequate operational capacity is
based on merging current operational practice with a survey of papers on wind integration32 and
input from the TRC.

3.2.1 Ramp Reserve
The ramp reserve represents the minimal amount of flexible system capacity required to follow
the net load requirements without any error or deviation; in other words, if a system operator had
the gift of perfect foresight for following changes in load and wind generation from minute-to-
minute, and hour-to-hour. These amounts are as follows:

 If system is ramping down: [(Net Area Load Hour H – Net Area Load Hour (H+1))/2]
 If system is ramping up: [(Net Area Load Hour (H+1)– Net Area Load Hour H)/2]

Essentially, the ramp reserve is half the absolute value of the difference between the net
balancing area load at the top of one hour minus the net balancing load at the top of the prior
hour.

The ramp reserve is calculated for load using only the load values for each BAA at the top of
each hour. The ramp reserve for load and wind is calculated using the net load (load minus wind
generation output) at the top of each hour. The ramp reserve required for wind is the difference
between that for load and that for load and wind.

3.2.2 Regulation Reserve
As ramp reserves represent the system flexibility required to follow the system’s requirements
without any uncertainty or error, the regulation reserve is necessary to cover uncertainty ever-
present in power system operations. Very short-term fluctuations in weather, load patterns, wind
generation output and other system conditions cause short term forecasts to change at all times.
32 Many of the external studies PacifiCorp has relied on can be found on the Utility Variable Integration Group
(UVIG) website at the following link: http://www.uwig.org/opimpactsdocs.html
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
94

Therefore, system operators rely on regulation reserve to allow for the unpredictable changes
bound to occur between the time the next hour’s schedule is made and the arrival of the next
hour, or the ability to follow net load. Also, these very same sources of instability are active
throughout each hour, requiring flexibility to regulate the generation output to the myriad ups
and downs of customer demand, fluctuations in wind generation, and other system disturbances.
To assess the regulation reserve requirements for PacifiCorp’s BAAs, the Company compared
the operational data to hypothetical forecasts as described below.

3.2.3 Hypothetical Operational Forecasts
Regulation reserve consists of two components: (1) regulating, which is developed using the ten-
minute interval data, and (2) following, which is calculated using the same data but estimated on
an hourly basis. The Study Term load data and wind generation data are applied individually to
calculate estimated reserve requirements for each month in the Study Term. For purposes of the
Study, the regulating calculation compares observed ten-minute interval load and wind
generation production to a ten-minute interval forecast, and following compares observed hourly
averages to an average hourly forecast. Therefore, the calculation of regulation reserve
requirements begins with the development of four component requirements: load following,
wind following, load regulating, and wind regulating.
3.2.3.1 Hypothetical Load Following Operational Forecast
PacifiCorp maintains system balance by optimizing its operations to an hourly forecast every
hour with changes in generation and market activity. This planning interval represents hourly
changes in generation that are assessed roughly 20 minutes into each hour to account for a
bottom-of-the-hour (30 minutes after the hour) scheduling deadline. Taking into account the
conditions of the present and the expected load and wind generation, PacifiCorp must schedule
generation to meet demands with an expectation of how much higher or lower load (net of wind
generation) may be.

PacifiCorp's real-time desk updates the next hour’s load forecast forty minutes prior to each
operating hour. This forecast is created by comparing the current hour load to the load of a
similar-load-shaped day. The hour-to-hour change in load from the similar day and hours (the
load difference or “delta”) is applied to the “current” hour load and the sum is used as the
forecast for the ensuing hour. For example, on a given Monday the PacifiCorp real-time desk
operator may be forecasting hour to hour changes in system load by referencing the hour to hour
changes on the prior Monday, a similar-load-shaped day. If the hour to hour load
change between the same hours that occurred from the prior Monday's was 5 percent, the
operator will use a 5 percent change in load as the next hour’s following forecast. For purposes
of the calculation made in this Wind Study, the load forecast was modeled per the approximation
described above with a shaping factor calculated using the day from one week prior, and
applying a prior Sunday to shape any NERC holiday schedules. The differences observed
between hourly average load and the load following forecasts comprise the load following
deviations. Figure H.2 shows an illustrative example of a load following deviation using
operational data from PACW, depicted by the black arrow.

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

95

Figure H.2 - Illustrative Load Following Forecast and Deviation

3.2.3.2 Hypothetical Wind Following Operational Forecast
For the corresponding short term hourly operational wind forecast, the hourly wind forecast is
prepared based on the concept of persistence; applying the instantaneous sample of the wind
generation output 20 minutes past the current hour to the next hour as a forecast and balancing
the system to that point. For purposes of the calculation made in this study, the hourly wind
forecast consisted of the 20th minute output from the prior hour, and this output is assumed to be
the volume of wind produced in the ensuing hour. For example, if the wind generation is
producing 200 MW of power at 1:20pm in PACW, then it is assumed that 200 megawatt-hour
(MWh) of power will be generated from the wind plants between 2:00pm and 3:00pm that day.
The difference observed between hourly average wind generation and the wind following
forecast represents the wind following deviation. Figure H.3 shows an illustrative example of a
wind following deviation using operational data from PACW, depicted by the black arrow.
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
96

Figure H.3 - Illustrative Wind Following Forecast and Deviation

3.2.3.3 Hypothetical Load Regulating Operational Forecast
Separate from the variations in the hourly scheduled loads, the ten-minute load variability and
uncertainty was analyzed by comparing the ten-minute actual load values to a line of intended
schedule, which was represented by a line interpolated between an actual top-of-the-hour load
value and the next hour’s load forecast target at the bottom of that (next) hour. A sample of how
the intended schedule compares to actual load data is shown in Figure H.4, with the trend of the
line of intended schedule tracking the orange line toward the load following forecast at the
middle of the ensuing hour as based upon data from PACW from December 2010. The method
approximates the real time operations process for each hour. At the top of the given hour, the
actual load is known and a forecast for the next hour was made. For the purposes of this study, a
line joining the two points was made to represent the ideal path for the ramp or decline expected
within the given hour. The actual ten-minute load values were compared to this straight line to
produce a corresponding strip of load regulating deviations at each ten-minute interval, with one
such deviation represented by the black arrow in Figure H.4.

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

97

Figure H.4 - Illustrative Load Regulating Forecast and Deviation

3.2.3.4 Hypothetical Wind Regulating Operational Forecast
To parse the ten-minute interval wind variability from the following analysis, a line of intended
schedule similar to that applied to load regulating deviations is developed. A line is drawn from
the top of the hour’s instantaneous wind output to the next hour’s wind-following forecast
output, but at the bottom (middle) of that next hour. This creates a line from the top of the hour
actual output toward the next hour’s average output. Figure H.5 shows an illustrative example
using operational data from PACW of a wind regulation deviation, as depicted by the black
arrow.

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
98

Figure H.5 - Illustrative Wind Regulating Forecast and Deviation

3.2.4 Recording of Deviations
The four hypothetical operational forecasts are netted against historical load and wind production
data to derive four component forecast deviations (load following, wind following, load
regulating, wind regulating). The deviations each represent different components (like vectors)
of forecast error which have to be covered by operating reserves. For example, if the difference
between the wind following forecast for a given hour is 550 MW, and the average wind
generation on the system only produces 400 MW for that hour, then 150 average MW will have
to be produced by other generation on the system to remedy the shortfall and maintain system
balance. This is an example of reserves being deployed upward (additional generation
dispatched) in real time. A similar effect happens when load exceeds the load forecast –
additional generation is dispatched to cover the shortfall due to changing forecasts or
unpredictable conditions. Figure H.6 shows an illustrative example of independent load and
wind regulating deviations from the PACE on June 1, 2011. Each time interval as represented on
the horizontal axis represents ten minutes. Note how the deviations are randomly constructive
(both positive or both negative) or destructive (opposing, one positive and one negative).

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

99

Figure H.6 - Illustrative Example of Independent Load and Wind Regulating Deviations

The deviations are calculated for each ten-minute interval in the Study Term, for each of the four
components of regulation reserves (load following, wind following, load regulating, wind
regulating). Across any given hourly time interval, the six ten-minute intervals within each hour
would have a common following deviation, but different regulation deviations. For example,
considering load deviations only, if the load forecast for a given hour was 300 MW below the
actual load realized in that hour, then a load following deviation of -300 MW would be recorded
for all six of the ten-minute periods within that hour. However, as the load regulation forecast
and the actual load recorded in each ten-minute interval vary, so will the deviations for load
regulation. The same trend holds for wind following and wind regulating deviations. The
following deviation is recorded as equal for the hour, and the regulating deviation varies each
ten-minute interval.

3.2.5 Analysis of Deviations
Since the recorded deviations represent the amount of unpredictable variation on the electrical
system, the key question becomes how much regulation reserve to hold in order to cover the
deviations, thereby maintaining system reliability. The deviations are analyzed by separating the
deviations into bins by their characteristic forecasts for each month in the Study Term. The bins
are defined by every 5th percentile of recorded forecasts, creating 20 bins for each month’s
deviations for each component hypothetical operational forecast. In other words, each month of
the Study Term will exhibit 20 bins of load following deviations, 20 of load regulating
deviations, and the same for wind following and wind regulating. Tables H.6 and H.7 depict this
process in action for June 2011.

Table H.6 depicts the calculation of percentiles (every 5 percent) among the load regulating
forecasts for June 2011 using PACE operational data. For example, a load regulating forecast of
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
100

4,403.7 MW represents the fifth percentile of such forecasts for that month. Any forecast values
below that value will be in Bin 20, along with the respective deviations recorded for those time
intervals. Any forecast values between 4,403.7 MW and 4,508.8 MW will land the deviation for
that particular interval in Bin 19.

Table H.6 - Percentiles Dividing the June 2011 Load Regulating Forecasts into 20 Bins

Table H.7 depicts a sample of the assignment of several intervals’ data into bins following the
definition of bins in Table H.6.
East
Bin Number Percentile Load Forecast
MAX 7,615.4
1 0.95 6,916.8
2 0.90 6,549.0
3 0.85 6,210.6
4 0.80 5,984.1
5 0.75 5,803.9
6 0.70 5,685.5
7 0.65 5,599.5
8 0.60 5,523.1
9 0.55 5,445.0
10 0.50 5,356.4
11 0.45 5,267.4
12 0.40 5,160.0
13 0.35 5,037.1
14 0.30 4,924.5
15 0.25 4,812.5
16 0.20 4,683.5
17 0.15 4,570.0
18 0.10 4,447.5
19 0.05 4,359.9
20 MIN 4,107.2
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

101

Table H.7 - Recorded Interval Load Regulating Forecasts and their Respective Errors, or
Deviations, for June 2011 Operational Data from PACE

The binned approach is necessary to prevent over-assignment of reserves in different system
states, owing to certain characteristics of load and wind generation. For example, when the
balancing area load is near the lowest values for any particular day, it is highly unlikely the load
deviation will require substantial down reserves to maintain balance because load will typically
drop only so far. Similarly, when the load is near the peak of the month’s load values, it is likely
perhaps to go only a little higher, but could drop substantially at any time. Similarly for wind,
when wind generation output is at the peak value for a system, there will not be a deviation
taking the wind value above that peak. In other words, the directional nature of the reserves
requirements can change greatly by the state of the load or wind output. At high load or wind
generation states, there is not likely to be a significant need for reserves covering a surprise
increase in those values. Similarly, at the lowest states, there is not likely to be a need for the
direction of reserves covering a significant shortfall in load or wind generation.

For example, consider the deviations grouped into one of the load regulating bins for June 2011
data in Figure H.7. The deviations in this bin all occurred in time intervals with a load regulating
forecast near 6,898 MW, from the PACE using June 2011 operational data. Most of the
deviations are within 80 MW of the actual load value (a little over one percent, plus or minus).
DATE / TIME LOAD REGULATION FORECAST LOAD REGULATION ERROR BIN ASSIGNMENT
06/01/2011 01:00 4,297.0 26.89 20
06/01/2011 01:10 4,277.7 12.17 20
06/01/2011 01:20 4,285.3 0.76 20
06/01/2011 01:30 4,292.9 57.93 20
06/01/2011 01:40 4,300.4 18.72 20
06/01/2011 01:50 4,308.0 -9.78 20
06/01/2011 02:00 4,315.6 25.25 20
06/01/2011 02:10 4,315.9 -3.19 20
06/01/2011 02:20 4,341.4 29.87 20
06/01/2011 02:30 4,366.9 16.33 19
06/01/2011 02:40 4,392.4 35.67 19
06/01/2011 02:50 4,417.9 32.28 19
06/01/2011 03:00 4,443.5 53.28 19
06/01/2011 03:10 4,429.4 15.66 19
06/01/2011 03:20 4,468.6 20.02 18
06/01/2011 03:30 4,507.8 11.52 18
06/01/2011 03:40 4,547.0 1.15 18
06/01/2011 03:50 4,586.2 18.98 17
06/01/2011 04:00 4,625.4 5.76 17
06/01/2011 04:10 4,658.2 -6.29 17
06/01/2011 04:20 4,696.8 20.29 16
06/01/2011 04:30 4,735.3 2.56 16
06/01/2011 04:40 4,773.9 -5.57 16
06/01/2011 04:50 4,812.5 -3.52 16
06/01/2011 05:00 4,851.0 -24.55 15
06/01/2011 05:10 4,905.0 -9.43 15
EAST
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
102

However, for load regulating deviations in this range, there is apparently a greater tendency
where actual load was lower (more negative deviations than positive in Figure H.7 below, and of
greater magnitude), which requires the system’s installed generation to have to increase its
output in a very short timeframe to balance, thus requiring what are called “up reserves”. It also
bears noting that the deviations form a statistical distribution which is not normally shaped; and
as more bins are examined, they also are not normally distributed and the longer tail can appear
on either side.

Figure H.7 - Histogram of Deviations Occurring About a June 2011 PACE Load
Regulating Forecast of 6,097 MW
Bin Analysis

Up and down deviations must be served by operating reserves, so the percentile equivalent to a
deviation tolerance was sampled above and below the median of each of the bins. The difference
between the target reliability percentiles and the median of the bins represents the implied
incremental load following service for regulation reserve demand within that bin for a given
tolerance level. The component reserve value for each bin, as a function of the tolerance target is
represented in Equation 1:

Equation 1. Derivation of the component reserves requirement as a function of deviations
recorded in each bin.

Component Reservej = f(Ptolerance (Forecast Bini))

Where:
Ptolerance = The percentile of a two-tailed distribution representing an operational tolerance
target
Forecast Bini = the component forecast errors in each bin

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

103

The tolerance level, per Equation 1, represents a percentage of component deviations intended to
be covered by the associated component reserve. As detailed in the method overview, section
3.1, the Company cannot apply contingency reserves to manage load and wind fluctuations, and
therefore must carry sufficient regulating margin to avoid dipping into contingency reserve for
this purpose. Any failure to manage these fluctuations can lead to disruption of services to
customers. Surveying other recent wind integration studies33, the company focused on two other
large regional entities grappling with the same concerns; BC Hydro and Bonneville Power
Administration (“BPA”). BC Hydro applies a 99.7 percent tolerance to respective load and wind
reserve requirements34, while the BPA customarily applies a 99.5 percent tolerance to its
balancing requirements35. Considering the actions of other major market participants, and the
requirement to maintain contingency reserves at all times, the Company has decided to apply a
99.7 percent tolerance in the calculation of component reserves, In doing so, the Company has
sought to plan for as many deviations as possible, while excluding the very largest data points to
allow for the potential existence of outlier values. However, in a departure from BC Hydro’s
and BPA’s approaches, the Company will also net the appropriate system L10 from the resulting
total reserves requirement36, effectively reducing the target reserve requirement to a more
aggressive level than those other market participants. The L10 represents a bandwidth of
acceptable deviation prescribed by WECC between the net scheduled interchange and the net
actual electrical interchange on the Company’s BAAs. Subtracting the L10 credits customers
with the natural buffering effect it entails. Despite exclusion of extreme deviations with the use
of the 99.7 percent tolerance, the Company’s system operators will still be expected to meet
reserve requirements without exceptions. The Company may also change the tolerance based on
operational and customer feedback in the future.

Taking the binned data illustrated in Figure H.7 as an example, approximately all of the
deviations fall between -180 MW of deviation and +270 MW of deviation. Therefore, at a 99.7
percent tolerance level, the load regulating up reserves recommended for time intervals reflecting
a load regulating forecast near 6,097 MW in the PACE in June 2011 is 173 MW. As each
respective bin also has an implied probability by the number of data points falling within it (five
percent), five percent of the ten-minute intervals in June 2011 will be assigned a load regulating
component reserves value of 210 MW up reserves and 130 MW down reserves. The very same
analysis is performed for each bin (20 in total) for wind regulating, load following, and wind
following component reserves.

The binned results can be reviewed for a month at a time, and patterns in the up- and down-
reserves requirements by forecast level become more apparent for load and for wind as shown in
Figures H.8 and H.9. For example, Figure H.9 can be used to further explain the calculation

33 PacifiCorp reviewed wind integration studies sponsored by other regional utilities (Portland General Electric,
Avista, Idaho Power, BC Hydro, BPA) and the National Renewable Electrical Laboratory. The more recent BC
Hydro and BPA approaches are consistent with the Company’s requirement to maintain contingency reserve
requirements at all times. 34 BC Hydro’s Wind Integration Study is part of its Integrated Resource Plan, Appendix 6E, page 6E-9:
http://www.bchydro.com/etc/medialib/internet/documents/planning_regulatory/iep_ltap/2012q2/draft_2012_irp_app
endix23.Par.0001.File.DRAFT_2012_IRP_APPX_6E.pdf 35 Pacific Northwest National Laboratory, page 5: http://energyenvironment.pnnl.gov/ei/pdf/NWPP%20report.pdf 36 The L10 of PacifiCorp’s balancing authority areas are 33.41MW for the West and 47.88 MW for the East. For
more information, please refer to:
http://www.wecc.biz/committees/StandingCommittees/OC/OPS/PWG/Shared%20Documents/Annual%20Frequenc
y%20Bias%20Settings/2012%20CPS2%20Bounds%20Report%20Final.pdf
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
104

method for the resulting component reserve demand. Bin 4 describes 36 hours (five percent of
June’s 720 hours) of wind generation forecast outcomes in the operational data from June, 2011.
The average hypothetical operational forecast modeled for these hours was 710 MW of
production, and 99.7 percent of the actual hourly production values would be between 305 MW
(the bottom of the green shaded area) and 955 MW (the top of the red shaded area). Therefore,
for these 36 hours, and other periods in the future where the PACE wind production forecast is
near 710 MW, this method recommends 405 MW of up reserves (710 – 305 = 405) in order to be
prepared for a shortfall in wind production compared to the hourly forecast.

Figure H.8 - Load Following Component Reserve Profile; Operational Data from June
2011

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

105

Figure H.9 - Wind Following Component Reserve Profile; Operational Data from June
2011

It is also useful to note the relatively small amount of up reserve required when the wind
generation is forecast to be low (Bins 19 and 20), and vice-versa when little wind generation is
forecast (Bins 1 and 2 in Figure H.9). This is how the bin analysis helps prevent over-assigning
reserves—by adjusting the reserves requirements per wind generation state. For instance, the
output of wind generators is less stable when the wind is picking up or slowing down, and the
wind generators are speeding up or slowing down accordingly. This behavior is represented in
Bins 3 through 15 in Figure H.9 above; the amount of wind following component reserve
recommended in those bins (represented by the distance between the red forecast line and the
blue and green lines) is greater than that needed at the higher and lower rates of production,
which represent either sustained wind or sustained calmer conditions.

The result of the bin analysis is four component forecast values (load following, wind following,
load regulating, wind regulating) for each ten-minute interval of the Study Period. The
component forecasts and reserves requirements are then applied to the operational data and
combined in the backcasting procedure described below.

3.2.6 Backcasting
Given the development of component reserves demands for regulating and following timeframes
shaped to system state in section 3.2.5, reserve requirements were then assigned to each ten-
minute interval in the Study term according to their respective hypothetical operational forecasts
(created in the Wind Study’s prior steps) to simulate the combination of the component reserves
values as they would have happened in real-time operations. Doing so results in a total reserves
requirement for each interval informed by the data.

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
106

To perform the backcasts, the component reserves requirements calculated from the bin analysis
described above are first turned into reference tables. Table H.8 shows a sample (June 2011,
PACE) reference tables for load and wind following reserves at varying levels of forecasted load
and wind generation. Table H.9 shows a sample (June 2011, PACE) reference table for load and
wind regulating reserves at varying forecast levels.

Table H.8 - Sample Reference Table for Load and Wind Following Component Reserves

East East
Bin Up Load Down Up Wind Down
Forecast Forecast
163 10000 335 365 5000 151
1 163 6953 335 365 1029 151
2 172 6544 278 324 893 115
3 182 6240 289 327 801 331
4 233 5954 291 405 710 245
5 199 5802 153 252 645 316
6 138 5699 182 325 589 342
7 126 5601 99 256 540 227
8 223 5526 147 265 495 327
9 345 5432 126 253 459 281
10 123 5362 138 255 420 449
11 245 5260 120 184 377 340
12 189 5151 89 161 333 304
13 113 5033 137 158 302 348
14 145 4931 180 141 262 235
15 179 4809 120 158 224 243
16 213 4694 117 111 187 266
17 62 4551 102 86 155 246
18 119 4437 85 89 112 200
19 85 4338 97 44 77 234
20 90 4098 94 44 9 122
90 0 94 44 0 122
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

107

Table H.9 - Sample Reference Table for Load and Wind Regulating Component Reserves

Each of the relationships recorded in the table is then applied to hypothetical operational
forecasts. Building on the reference tables above, the hypothetical operational forecasts
described in sections 3.2.3.1 through 3.2.3.4 are then used to calculate a reserves requirement for
each interval of historical operational data. This is clarified in the example below.

Application to component forecasts
Each interval’s component forecasts are used, in conjunction with Tables H.8 and H.9, to derive
a recommended reserve requirement informed by the load and wind generation conditions for the
time interval. This process is most easily explained with an example using the tables shown
above, and hypothetical operational forecasts from June 2011 operational data for PACE. Table
H.10 illustrates the outcome of the process for the load following and regulating components:
East East
Bin Up Load Down Up Wind Down
Forecast Forecast
171 10000 263 244 10000 152
1 171 6917 263 244 1025 152
2 183 6549 251 302 902 224
3 177 6211 163 353 794 237
4 173 5984 272 224 713 180
5 204 5804 130 317 649 270
6 155 5686 156 263 585 450
7 219 5600 114 202 539 352
8 239 5523 146 260 501 394
9 159 5445 134 270 461 244
10 235 5356 124 190 425 299
11 170 5267 115 182 378 251
12 170 5160 112 149 334 265
13 239 5037 151 153 299 260
14 116 4925 138 148 261 172
15 126 4812 162 86 224 288
16 161 4683 103 122 188 287
17 98 4570 113 105 149 174
18 97 4448 95 60 112 144
19 82 4360 101 38 76 150
20 72 4107 92 39 10 82
72 0 92 39 0 82
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
108

Table H.10 - Interval Load Forecasts and Component Reserves Requirement Data for
Hour-ending 11 AM, June 1, 2011 in PACE

The load following forecast for this particular hour is 5,509.68 MW, which designates reserves
requirements from Bin 9 as depicted (with shading for emphasis) in Table H.8. Note the same
following forecast is applied to each interval in the hour for the purpose of developing reserves
requirements. The first ten minutes of the hour exhibits a load regulating forecast of 5,500.6
MW, which designates reserves requirements from Bin 9 as depicted in Table H.9. Note that the
regulating forecast changes every ten minutes, and as a result, the regulating component reserve
requirement may do so as well. In this particular case, the second interval’s forecast shifts the
component reserves requirement from Bin 9 to Bin 8 (per Table H.8), and so the component
reserves requirement changes accordingly. A similar process is followed for wind reserves,
illustrated in Table H.11:

Table H.11 - Interval Wind Forecasts and Component Reserves Requirement Data for
Hour-ending 11 AM June 1, 2011 in PACE

The wind following forecast for this particular hour is 485.0 MW, which designates reserves
requirements from Bin 9 under wind forecasts as depicted in Table H.8. Note the following
forecast is applied to each interval in the hour for the same of developing reserves requirements.
Meanwhile, the regulating forecast changes every ten minutes. The first ten minutes of the hour
exhibits a wind regulating forecast of 453.5 MW, which designates reserves requirements from
Bin 10 as depicted in Table H.9. As for load, the wind regulating forecast changes every ten
minutes, and as a result, the regulating component reserve requirement may do so as well. In this
particular case, the second interval’s forecast shifts the wind regulating component reserves
East East East East East East East East East
Time
Actual Load
(10-min Avg)
Actual Load
(Hourly Avg)
Following
Forecast
Load:
Load
Following Up
Reserves
Specified by
Tolerance
Level
Load
Following
Down
Reserves
Specified by
Tolerance
Level
Regulating
Load
Forecast:
Load
Regulating Up
Reserves
Specified by
Tolerance
Level:
Load
Regulating
Down
Reserves
Specified by
Tolerance
Level:
06/01/2011 10:00 5,533.04 5,543.46 5,509.68 344.8 126.2 5500.6 159.4 134.4
06/01/2011 10:10 5,525.38 5,543.46 5,509.68 344.8 126.2 5542.6 239.4 145.5
06/01/2011 10:20 5,525.54 5,543.46 5,509.68 344.8 126.2 5552.1 239.4 145.5
06/01/2011 10:30 5,550.23 5,543.46 5,509.68 344.8 126.2 5561.6 239.4 145.5
06/01/2011 10:40 5,551.93 5,543.46 5,509.68 344.8 126.2 5571.1 239.4 145.5
06/01/2011 10:50 5,574.64 5,543.46 5,509.68 344.8 126.2 5580.7 239.4 145.5
East East East East East East East East East
Time
Actual Wind
(10-min Avg)
Actual Wind
(Hourly Avg)
Following
Forecast
Wind:
Wind Follow
Up Reserves
Specified by
Tolerance
Level
Wind Follow
Down
Reserves
Specified by
Tolerance
Level
East Wind
Regulating
Forecast:
Wind
Regulating Up
Reserves
Specified by
Tolerance
Level:
Wind
Regulating
Down
Reserves
Specified by
Tolerance
Level:
06/01/2011 10:00 550.82 555.26 485.02 252.87 280.56 453.5 190.0 298.9
06/01/2011 10:10 557.30 555.26 485.02 252.87 280.56 548.5 201.5 352.2
06/01/2011 10:20 529.71 555.26 485.02 252.87 280.56 546.1 201.5 352.2
06/01/2011 10:30 550.40 555.26 485.02 252.87 280.56 543.8 201.5 352.2
06/01/2011 10:40 560.53 555.26 485.02 252.87 280.56 541.4 201.5 352.2
06/01/2011 10:50 582.79 555.26 485.02 252.87 280.56 539.1 259.7 394.0
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

109

requirement from Bin 10 into Bin 7 (per Table H.9), and so the component reserves requirement
changes accordingly.

The selection of component reserves using component hypothetical operational forecasts as
depicted above is replicated for each ten-minute interval, assigning four component reserves
requirements in each interval throughout the Study Term. The four components are combined
into a single regulating reserves requirement as defined below.

Total Regulating Reserves Requirement

After the assignment of the component reserves requirements, each ten-minute interval of the
Study Term exhibits values for load following reserves, wind following reserves, load regulating
reserves, and wind regulating reserves. Each of these values is derived by comparing a unique
component forecast to a unique actual value; in the case of load following, the load following
forecast is compared to the average load for a given hour. For load regulating reserves
requirements, the load regulating forecast is compared to the actual load observed at the same
time. However, while adjusting operations for each of the four component factors is critical to
maintaining system integrity, the components are not additive. Therefore, the wind and load
reserve requirements are combined using the root-sum-square (RSS) calculation in each direction
(up and down), assuming their variability in the short term independent or uncorrelated, by the
RSS relationship in Equation 2. Then, the appropriate system L10 is netted from the result.

Equation 2. Total Regulation Reserves calculated from four component reserves using the root-
sum-square formulation at time interval i:

Drawing from the first ten-minute interval in the example above as depicted in Table H.s 7 and 8,
the component up reserves requirements were as follows:

Load Following = 271.5 MW
Load Regulating = 142.4 MW
Wind Following = 242.5 MW
Wind Regulating = 238.1 MW
East System L10 = 47.9 MW

Applying Equation 2:

Per Equation 2, 409.8 MW of up reserves recommended for regulation reserve for the time
interval between 10:00am and 10:10am, June 1, 2011 in PACE. In this manner, the component
reserves requirements are used to calculate an overall reserves requirement for each ten-minute
interval of the Study Term. A similar calculation is also made for the regulation reserve
requirements pertaining only to the variability and uncertainty of load, which employs Equation
2 but applies zero reserves for the wind components. The incremental reserves assigned to wind

PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
110

generation demand are calculated as the difference between the total requirement and the load
requirement. The results of these calculations can be quoted in hourly or monthly requirements
by averaging the reserves requirements of all the ten-minute intervals within the specified hour
or month. Annual reserves requirements are quoted as the average of the twelve monthly
requirements.

Wind and Load Correlation
An important assumption underlying the application of Equation 2 is that there is no correlation
between wind and load deviations. To test this assumption, this section describes an analysis of
wind and load correlation.

The RSS equation is typically applied in the analysis engineering tolerances and supporting
statistical concepts, and is derived from the Parallelogram Law37.

Figure H.10 - Depiction of the Parallelogram Law

Equation 3. Vector combination as prescribed by the Parallelogram law in Figure H.10.
Resultant R = .

If P and Q act at right angles, α =90o, and cos(α)=0; R = , which is equivalent to
Equation 2.

The Parallelogram Law allows correlation to be constructive (with positive correlation) and
destructive (with negative correlation). In cases of constructive correlation, the resultant (R in
the illustration above, the parallelogram’s diagonal) is increased as the angle (α) between (Q)
and (P) is reduced. Destructive correlation causes the angle (α) to open wider, reducing the
diagonal of the parallelogram, and reducing the length of the diagonal, R. The Law of Cosines
can be used to illustrate a proof38 that the cosine of angle α equals the correlation between
vectors P and Q (cos(α) = ρPQ).

In cases of zero correlation, the Parallelogram Law reduces to the RSS formulation (and α is a
right angle, and the parallelogram is a square). For this Wind Study, rather than using two sides
of a parallelogram to form a resultant (R in the illustration), four uncorrelated vectors

37A proof of the parallelogram law is available at: http://www.unlvkappasigma.com/parallelogram_law/ 38 http://www.johndcook.com/blog/2010/06/17/covariance-and-law-of-cosines/
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

111

corresponding to the component reserves for load following, load regulating, wind following,
and wind regulating deviations are combined into a reserves requirement. The fact that there are
four dimensions rather than two makes the process difficult to illustrate, but the effect is the
same as in the two dimensional example above.

The Company applied the RSS formulation in its 2010 Wind Integration Study39 after reviewing
samples of the load and wind data used to perform the study40, and reviewing studies by Idaho
Power41 and the Eastern Wind Integration and Transmission Study42. Since that time, additional
studies have suggested use of this formulation directly43 or noted that short term deviations from
schedule in wind generation output and load are not correlated44. However, stakeholder interest
has encouraged the Company to further review the correlation between wind and load reserve
components.

Because reserves are intended to manage the deviations from expected load and wind generation
output, the question becomes not whether the raw wind generation output and balancing area
load are correlated, but rather whether the respective forecast errors between the Company’s
expected wind generation and load are correlated. These forecast errors drive the component
reserves in the Wind Study, and reflect the level of reserves needed in real time operations. The
analysis below assesses the correlation of deviations from forecasts for load and wind in both the
hourly (following) and sub-hourly (regulating) timeframes.

Correlation Analysis

The forecast deviations for wind generation and load in the Company’s BAAs were analyzed for
correlation by performing a linear regression using the load deviation as an independent variable
and the concurrent wind deviation as the dependent variable. Therefore, to estimate the East
Wind Following deviation for a given time period, the East load following deviation was used as
a predictive variable. The correlation between the two variables (load errors and wind errors)
would be represented by the slope of the regression, and the predictive capability by the r2 (or
goodness-of-fit). The procedure was followed for 2011 operational data applying the four
component forecasts detailed previously for PACE and PACW. The results appear in Table
H.12.

39
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/Wind_Integratio
n/PacifiCorp_2010WindIntegrationStudy_090110.pdf, p. 19 40
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/Wind_Integratio
n/PacifiCorp_2010WindIntegrationStudy_090110.pdf, Table 5, p. 6 41 http://www.idahopower.com/pdfs/AboutUs/PlanningForFuture/wind/Addendum.pdf, pages 12, 20 42http://www.nrel.gov/C821B4E9-F70E-4245-9C6D-D5CB68B670DC/FinalDownload/DownloadId-
286D6B0AF14A941F45E5F431BACF4DCF/C821B4E9-F70E-4245-9C6D-
D5CB68B670DC/wind/systemsintegration/pdfs/2010/ewits_final_report.pdf, page 145 43
http://www.bchydro.com/etc/medialib/internet/documents/planning_regulatory/iep_ltap/2012q2/draft_2012_irp_app
endix23.Par.0001.File.DRAFT_2012_IRP_APPX_6E.pdf, page 6E-9 44 http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_final_report.pdf, page 92
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
112

Table H.12 - Results of Regression Analyses between Wind and Load Deviations

The results indicate that while there is a calculable correlation between wind and load deviations
in the data, the relationships are so weak such that neither explains the other, and so this
relationship is not useful in an operational context. The value of the load deviation offers no
ability to explain the wind deviation, and so the two are unrelated. This is consistent with the
findings of wind studies noted above.

To illustrate the analysis, plots of the load and wind deviations (from their respective forecasts)
have been prepared using 2011 operational data in Figures H.11 through H.14 below. Each point
represents the respective deviation at any given time (a ten-minute interval for regulating
deviations, a given hour for following deviations) by magnitude of the forecast error of load and
wind, which would have to be managed by deploying reserves in real time operations. The
magnitude of the load deviations are recorded on the horizontal (x) axis and the wind deviations
on the vertical (y) axis. The correlation between the load and wind deviations is represented by
slope of the (red) regression trend lines; a strongly predictive correlation would have little scatter
about the line, while a weak, non-predictive correlation (with a low r2 value) would exhibit
significant and varying amounts of scatter about the trend line.

Figures H.11 through H.14 demonstrate highly variable clouds of data, and the extension of each
cloud along the horizontal axis suggest the load forecast deviations require more reserves than do
the wind deviations. Additionally, the data do not follow the regression trend lines well; there is
significant scatter and it varies from a dense population of occurrences in the middle to sparsely
populated data at the ends of the line. These cloud patterns suggest factors other than load
forecast error should be used to explain corresponding wind forecast error, and vice-versa.

For example, the greatest load deviations don’t necessarily seem to occur at the same time as
most of the greatest wind deviations, nor are the deviations necessarily small. The range about
the red regression line for East Following (in Figure H.11) exhibits several wind following
deviations of about +/- 300 MW at +100 MW load following deviation (line A) and a similar
amount and range at -100 MW load deviation (line B). The data suggest that increased forecast
errors in either direction for load neither increase nor decrease the expected error in the wind
forecast.
Slope r-Square
East Following -0.097 0.45%
East Regulating -0.087 0.63%
West Following 0.026 0.05%
West Regulating -0.007 0.00%
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

113

Figure H.11 - PACE Following Regression Plot

A
A
B
B
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
114

Figure H.12 - PACE Regulating Regression Plot25

25 Note cloud-like pattern of errors which is densest near zero, and the data does not tighten around the trend line.
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

115

Figure H.13 - PACW Following Regression Plot26

26 Note another cloud of errors, with the red trend line describing little of the variation from one point to the other.
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
116

Figure H.14 - PACW Regulating Regression Plot27

3.3 Determination of Wind Integration Costs
3.3.1 Overview
Owing to the variability and uncertainty of load and wind generation, each hour of power system
operations features a need to set aside operating reserve explicitly to cover load and contingency
events inherent to the PacifiCorp system with or without wind in addition to contingency
reserves. Additional costs are incurred with daily system balancing that is influenced by the
unpredictable nature of wind generation on a day-ahead basis. To characterize how wind
generation affects regulating margin costs and system balancing costs, the Study utilizes the PaR
model, and applies the regulating margin requirements calculated by the method detailed in
section 3.2.

27 The dispersion in this cloud of data about the red regression trend line seems only to depend on how many data
points are on either side of that line at any given point. Near the origin, there is a lot of data owing to most forecast
errors being small, while at high deviations, there are very few points with which to assess fit, but there is scatter
about the line.
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

117

PacifiCorp’s PaR model, developed and licensed by Ventyx, Inc. uses the PROSYM
chronological unit commitment and dispatch production cost simulation engine and is configured
with a detailed representation of the PacifiCorp system. For this study, PacifiCorp developed
five different PaR simulations. These simulations isolate wind integration costs associated with
regulation margin reserves and enables separate calculation of wind integration costs associated
with system balancing practice. The former reflects wind integration costs that arise from short-
term (within the hour and hour ahead) variability in wind generation and the latter reflects
integration costs that arise from errors in forecasting load and wind generation on a day-ahead
basis.

The five PaR simulations used in the Wind Study are summarized in Table H.13. The first two
simulations are used to tabulate operating reserve wind integration costs in forward planning
timeframes. The approach uses a “P50” or expected wind profiles28 and forecasted loads. The
remaining three simulations support the calculation of system balancing wind integration costs.
These simulations were run assuming operation in the 2013 calendar year, applying 2011 load
and wind data. This calculation method combines the benefits of using actual system data with
current forward price curves pertinent to calculating the costs for wind integration service on a
forward basis.29 PacifiCorp resources used in the simulations are based upon the 2011 IRP
Update resource portfolio.30

Table H.13 - Wind Integration Cost Simulations in PaR
PaR
Model
Simulation
Forward
Term
Load

Wind Profile

Incremental
Reserve
Day-ahead Forecast
Error
Regulating Margin Reserve Cost Runs
1 2013 2013 Load Forecast P50 Profiles No None
2 2013 2013 Load Forecast P50 Profiles Yes None
Regulating Margin Cost = System Cost from PaR Simulation 2 less System Cost from PaR Simulation 1
System Balancing Cost Runs
3 2013 2011 Day-ahead
Forecast
2011 Day-ahead
Forecast Yes None
4 2013 2011 Actual 2011 Day-ahead
Forecast Yes For Load*
5 2013 2011 Actual 2011 Actual Yes For Load and Wind**
Load System Balancing Cost = System Cost from PaR simulation 4 (which uses the unit commitment from Simulation 3) less
system cost from PaR simulation 3
Wind System Balancing Cost = System Cost from PaR simulation 5 (which uses the unit commitment from Simulation 4) less
system cost from PaR simulation 4

3.3.2 Calculating Operating Reserve Wind Integration Costs
To assess the effects of wind capacity added to the PacifiCorp system on regulating margin costs,

28 P50 signifies the probability exceedence level for the annual wind production forecast; at P50 generation is
expected to exceed the assumed generation levels half the time and to fall below the assumed generation levels half
the time. 29 The Study uses the June 29, 2012 official forward price curve. 30 The 2011 Integrated Resource Update report, filed with the state utility commissions on March 30, 2012 is
available for download from PacifiCorp’s IRP Web page using the following hyperlink:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2011IRPUpdate/
2011IRPUpdate_3-30-12_REDACTED.pdf.
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
118

the reserve requirements were simulated in PaR using 2013 load and P50 wind forecasts. Both
of the first two PaR simulations excluded system balancing costs. Simulation 1 applied only the
regulation reserves required for load obligations to 2013 forecast load and wind generation on
PacifiCorp’s systems with a 2013 resource profile. Simulation 2 used the same inputs except for
adding the incremental operating reserve demand created by the variable nature of wind
generation.

The system cost differences between these two simulations were divided by the total volume of
wind generation to derive the wind integration costs associated with having to hold incremental
operating reserve on a per unit of wind generation basis.

3.3.3 Calculating System Balancing Wind Integration Costs
PacifiCorp conducted another series of three PaR simulations to estimate daily system balancing
wind integration costs consistent with the resource portfolio, labeled as Simulations 3 through 5
in Table H.13. In this phase of the analysis, PacifiCorp generation assets were committed
consistent with a day-ahead forecast of wind and load, but dispatched against actual wind and
load. To simulate this operational behavior, the three additional PaR simulations included the
incremental reserves from Simulation 2 and the unit commitment states associated with
simulating the portfolio with the day-ahead forecasts.

Simulation 3 incorporated day-ahead forecasts for both load and wind, dispatching PacifiCorp’s
generation to the forecasts as though there were no day-ahead forecast error. This served as the
starting point for separately determining load and wind balancing impacts on total system
balancing costs. Simulation 4 paired 2011 actual loads with day-ahead forecasts for wind
generation, isolating the error due to load forecasting, and also applied the unit commitment state
generated by Simulation 3 to capture system operations based
on the day-ahead load forecasts. Simulation 5 incorporates actual wind generation output,
thereby including forecast error for load and wind, and applied the unit commitment state
generated by simulation 4. The change in system costs (Simulation 5 less Simulation 3)
represents the total cost of day-ahead balancing on PacifiCorp’s BAAs. Dividing the day-ahead
wind balancing costs (Simulation 5 minus Simulation 4) by the volume of wind generation in the
portfolio yields a system wind balancing cost on a per-unit of wind production basis.

3.3.4 Application of Study Results to Integrated Resource Plan Portfolio Modeling
The Study results are applied in the 2013 IRP portfolio development process as part of the costs
of wind generation resources. In the portfolio development process using the System Optimizer
(SO) model, the wind integration cost on a dollar per megawatt-hour basis is included as a cost to
each wind resource’s variable operation and maintenance cost. The exception is for prospective
wind resources that could be located in the Bonneville Power Administration (BPA) balancing
authority. The variable operation and maintenance adder for these resources includes BPA’s
variable integration charge31. The estimated wind integration cost is applied in the SO model
(rather than increasing regulating margin) because the SO model builds least cost resource
portfolios to meet system coincident peak loads with an assumed planning reserve margin. In
meeting this coincident system peak capacity requirement, the SO model does not explicitly
31 BPA’s Variable Energy Balancing Service for wind resources is modeled at $1.23/kW-month, per their 2012 rate
schedule, which at a 35% capacity factor equates to a charge of just over $4.80/MWh. The BPA rate schedule is
available at: http://transmission.bpa.gov/Business/Rates/documents/2012_rate_schedules.pdf
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

119

evaluate operating reserve requirements. While operating reserve requirements are not explicitly
in the SO model, the estimated cost of wind integration is accounted for in the development of
resource portfolios.

Once candidate portfolios are developed using the SO model, additional analyses are performed
using PaR, which can evaluate incremental operating reserve needs. Therefore, when
performing IRP risk analysis using PaR, specific operating reserve requirements consistent with
this wind study will be used.

When modeling the production costs and risk analyses of resource portfolios in the PaR model,
the incremental reserve requirements, due to additional wind plants, are incorporated as part of
the PaR model’s total reserve requirements. These incremental reserve requirements reflect the
amount of reserves required in PACE and PACW for the regulation of wind resources. The cost
impact of holding this incremental spin reserve requirement is embedded in the total production
cost, but cannot be isolated for reporting purposes.

3.3.5 Allocation of Operating Reserve Demand in PaR
The five PaR Simulations require operating reserve demand inputs consistent with the
Company’s supply portfolio are input to the model. The PaR model distinguishes reserve types
by the priority order for unit commitment scheduling, and optimizes them to minimize cost in
response to demand changes and the quantity of reserve required on an hour-to-hour basis. The
highest-priority reserve types are regulation up and regulation down followed in order by
spinning, non-spinning, and finally, 30-minute non-spinning.32 Table H.14 shows these reserve
categories and indicates which ones are used for the study. Reserve requirements calculated in
the study are allocated into these PaR reserve categories per below, and are supplemental to the
contingency requirements calculated within PaR.

Table H.14 - Operating Reserve Categories Used by the PaR model

The regulation up and regulation down reserves in PaR are considered spinning reserve that must
be met before traditional spinning and non-spinning reserve demands are met. The incremental
operating reserve demand needed to integrate wind generation was assigned in PaR as regulation
up. As down regulation reserves are a deployment of generation already committed to load, this
feature was omitted from the Study. The traditional spinning and non-spinning reserve inputs are
used for ramp and contingency reserve33 requirements. Contingency reserve requirements
32 In PaR, spinning reserve is defined as unloaded generation which is synchronized, ready to serve additional
demand and able to reach reserve amount within ten minutes. Non-spinning Reserve is defined as unloaded
generation which is non-synchronized and able to reach required generation amount within ten minutes.
33 Contingency Reserve is specified by the North American Electric Reliability Corporation in
http://www.nerc.com/files/BAL-STD-002-0.pdf .
Input Field Definition Reserve Requirements Entered
AS1 Up Regulation Regulation
AS2 Down Regulation not used
AS3 Spin Ramp and Contingency
AS4 NonSpin Contingency
AS5 30 Minute NonSpin not used
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
120

remain unchanged among all PaR simulations in the Study. The 30-minute non-spinning reserve
product is not represented in PacifiCorp’s supply portfolio, and thus it is not used. Unused
regulation up reserve supply can be used in PaR to satisfy spinning or non-spinning reserve
demand.

The PaR model balances the system hourly, committing adequate generation to serve the
forecasted net system load and meet each hour’s respective reserve requirements. In actual
operations, any deviation from the load forecast may cause the reserves specified to be deployed
(should the net system load be greater than expected) or for the amount of open generation
capacity to be increased (should the net system load be less than expected). Because the
direction of the deviation, greater or lesser, is unknown and random, this calculation of the cost
to hold reserves above the generation required to meet forecast load is assumed to be unbiased to
actual intra-hour outcomes.

4. Results
The regulating margin required to manage fluctuations in load and wind generation output are
the sum of the ramp and regulation reserve requirements. The ramp reserve is dependent only on
the observed load and wind generation in the operational data used throughout the Wind Study.
The regulation reserve requirement is calculated by the methods detailed in section 3.2. Table
H.15 below summarizes the regulating margin requirements as calculated by the Study.

Table H.15 - Regulating Margin Requirements Calculated for PACE and PACW (MW)

The operational data used to calculate these results is based on 589 MW of wind capacity
installed in PACW, and 1,526 MW in PACE. Additional wind resources added to resource
portfolios in the 2013 IRP contribute a pro-rated regulating margin requirement in PaR model
simulations based on these results34.
4.1 Production Cost Results
As described in section 3.3 and detailed in Table H.13, PacifiCorp applied the reserve
requirements calculated in this Wind Study to a production cost simulation in the Company’s
PaR model. For the regulating margin costs, the regulating margin required to manage
variability due to load and wind on PACE and PACW was applied using a “with and without”
approach; the margin required only to manage disturbances in load was modeled in a production
cost simulation, then compared to a simulation run with the regulating margin necessary to
manage load and wind disturbances. The regulating margin costs represents the costs incurred to
hold additional reserves for wind to manage hour-to-hour operational disturbances, whereas the
34 The regulating margin requirement added for potential West wind developments will be the ratio of calculated
incremental reserve requirement to total installed capacity, or 9.2% of the proposed generating capacity (54/589);
while for East wind developments it will be 8.6% (131/1526).
West BAA East BAA Combined
Load-Only Regulating Margin 147 247 394
Incremental Wind Regulating Margin 54 131 185
Total Regulating Margin 202 378 579
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

121

system balancing costs are incurred managing the deviation between the day ahead forecast for
wind production and actual recorded production on PacifiCorp’s Company-owned and
contracted wind resources. Transmission customers’ wind resources’ day-ahead variability and
uncertainty are excluded from the system balancing calculation. Wind integration costs are the
sum of the regulating margin and system balancing costs, as presented in Table H.16:

Table H.16 - Nominal Levelized Production Cost Results for the 2012 and 2010 Wind
Studies

The 2010 Wind Study’s production cost results are presented for comparison. The 2012 Study’s
analysis reflects a significantly depressed commodity price environment when compared to the
2010 Study; this is chiefly responsible for the cost differential. Additionally, the 2010 Wind
Study’s published system balancing cost includes day-ahead load forecast error, which should
not be attributed to wind resources.
4.2 Additional Scenarios
To further understand differences around the set-ups of the Study and respond to requests of IRP
stakeholders and the TRC, the Company has evaluated several scenario calculations to highlight
the effect of selected changes in assumptions on the calculated regulating margin requirements.
For the purposes of these scenarios, the same 99.7 percent tolerance level (and subtraction of
L10) was applied to the calculation method described above using 2011 operational data unless
specified otherwise.

Historical Evaluation
The operational data available throughout the Study Term permits the estimation of historical
reserves requirements. This may inform future planning, as the amount of wind generation
capacity installed in PacifiCorp’s system has steadily increased through the Study Term.
Applying the method above to all the operational data in the Study Term, the following historical
regulating margin requirements are calculated, as depicted in Table H.17. Table H.18 breaks out
the incremental operating reserves calculated to manage wind generation.

Table H.17 - Historical Reserves Calculated throughout the Study Term (MW)

Regulating Margin System Balancing Wind Integration
Cost ($/MWh)Cost ($/MWh)Cost ($/MWh)
2012 Wind Study $2.19 $0.36 $2.55
2010 Wind Study $8.85 $0.86 $9.70
Regulation
West
Regulation
East Ramp Total
Average Wind
Capacity, MW
2007 184 194 134 512 606
2008 184 193 122 499 787
2009 145 211 121 477 1364
2010 152 261 122 534 1810
2011 149 302 128 579 2126
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
122

Table H.18. Incremental Reserves Due to Installed Wind Generation Capacity (MW)

Concurrent Evaluation
The calculations in this scenario are made for the load and wind deviations combined
concurrently, by adding their concurrent errors, producing state bins and integrating the results
for following and regulating reserves for load and wind separately. Despite the estimation of
load and wind quantities separately in real time operations, and given no indication that short-
term changes in load and wind are correlated35, many stakeholders requested a calculation of the
estimated reserves with implied correlation and other characteristics that may be observed in the
short term variations of load and wind. The results of these calculations are presented in Table
H.19.

Table H.19 - Concurrent Netting of Load and Wind Errors Scenario Results (MW)

The combination of errors and system state were each made following the load minus wind
generation paradigm and the resulting differences were used to estimate reserves positions. This
approach imputes the spurious correlation mentioned in section 3.2.5 into the results.

Reliability Based Control Market Structure
A new control performance paradigm featuring a 30-minute balancing market is under regional
evaluation. Per current operational practice, the 60-minute market and operational paradigm is
the base of the Wind Study design. However, to assess the potential benefits of a 30-minute
clearing market for PacifiCorp’s customers, an alternate calculation has been prepared by
reducing the load and wind forecasting time interval to 30 minutes, and also reducing the
persistence forecast intervals for regulation to 30 minutes for wind and load demands. Table
H.20 compares the regulation reserves for the 30-minute balancing market scenario and the
default 60-minute balancing market case for PACE and PACW. This calculation assumes
adequate market depth at all 30-minute intervals such that the Company can rebalance system
deviations from the market. The ramp obligation is assumed to remain supplied by the
Company’s hourly generation planning.

35 Western Wind and Solar Integration Study, prepared by NREL, (May, 2010), p. 92. The report is available for
download from the following hyperlink:
http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_final_report.pdf
Regulation
West
Regulation
East Ramp Total
Average Wind
Capacity, MW
2007 15 11 2 28 606
2008 24 14 3 40 787
2009 31 45 4 80 1364
2010 40 78 6 124 1810
2011 50 126 9 185 2126
Regulation Regulation
West East Ramp Total
Scenario 160 279 128 567
2012 Study 149 302 128 579
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

123

Table H.20 - 30-minute Balancing Interval Scenario Results (MW)

Combination of PACE and PACW
The calculations can also estimate the effect of combining PacifiCorp’s two BAAs, into a single,
monolithic balancing authority area. This assumption is that these calculations would mimic the
effect of significant transmission development, eliminating the seams between the PACE and
PACW. The respective load and wind errors for following and regulation are combined
concurrently (East plus West) and the resulting component reserves demands are compared to
those required by the default method described above for separate BAAs in Table H.21.
However, the Company is uncertain at this time exactly how revised operational and forecasting
practices would affect this scenario, and so further updates are possible.

Table H.21 - Regulating Margin Requirements Calculated Assuming a Single PacifiCorp
Balancing Authority Area (MW)

5. Summary
The purpose of this Study is to determine the additional reserve requirement to integrate wind
resources into the Company’s existing resource portfolio and determine a cost that is used in the
portfolio development stage of the 2013 IRP.

The Study is based on actual historical data in ten-minute intervals for both load and wind
generation, as well as actual historical day-ahead load and wind generation forecasts, in the
Company’s east and west balancing authority areas. The data were reviewed for anomalies, and
revised prior to be applied in the Study.

The Study defined the two components of the regulating margin to include ramp and regulation
reserves:

1) Ramp: A number of factors (fluctuations in customer demand, spot transactions, varying
amounts of generation produced by variable resources such as wind and solar generation)
cause the net balancing load to change from minute-to-minute, hour-to-hour continuously at
all times. This variability (increasing and decreasing load) requires ready capacity to follow
continuously, through short deviations, at all times. Treating this variability as though it is
perfectly known (as though the operator would know exactly what the net balancing area
load would be a minute from now, ten minutes from now, and an hour from now) and
allowing just enough generation flexibility on hand to manage it defines the ramp reserves
requirement of the system. The amount of ramp reserve required is half the difference
Regulation Regulation
West East Ramp Total
Scenario 105 233 128 466
2012 Study 149 302 128 579
Regulation Ramp Total
Scenario 356 121 477
2012 Study 451 128 579
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
124

between the net balancing area load (load minus wind generation output) from the top of one
hour to the next.

2) Regulation: Deviations from forecasted load or wind generation are not considered
contingency events, yet these events still also require that capacity be set aside. Reserves
maintained to manage uncertainty around the net system load is called regulation
reserve. The Company has defined four components of regulation reserve (load following,
load regulating, wind following, and wind regulating), estimated by comparing actual data to
hypothetical forecasts. The four components are uncorrelated over operational generation
planning’s short time frames; and so the requirements to cover them are combined using a
root-sum-square method into a single regulation reserve requirement for each time interval.
The average regulation reserve requirement over any given timeframe expresses the
regulation requirement for that timeframe.

To summarize, regulating margin represents operating reserves the Company holds over and
above the mandated contingency reserve requirement to maintain moment-to-moment system
balance between load and generation. The regulating margin is the sum of two parts; ramp
reserve and regulation reserve. The ramp reserve represents a minimum amount of flexibility
required to follow the actual net system load (load minus wind generation output) with
dispatchable generation. The regulation reserve represents flexibility maintained to manage
intra-hour and hourly forecast errors about the net system load, and consists of four components:
load following, load regulating, wind following, and wind regulating.

The four components of the regulation reserves were calculated as the differences between the
respective hypothetical operational forecast and actual data, sampled at a 99.7th percentile. The
99.7th percentile is selected to remove the most extreme deviation values from the assessment of
the forward reserve requirements, while still providing sufficient reserve to prevent operations
from running out of regulating margin due to the uncertainties prevalent in hour-to-hour power
operations. In the past, the Company managed its balancing areas to a target called the Control
Performance Standard 2 (CPS2), which specified a limited number of excursions from a net
system interchange target. Since March 1, 2010, the PacifiCorp has been participating in a
regional field test of the Reliability Based Control standard, which replaces the system
interchange requirements with a regional frequency-based requirement. Among other changes,
this new operational paradigm means the Company responds to area control error depending on
whether their respective area control error is exacerbating or mitigating the frequency excursion
at the time. As the frequency depends on the instantaneous balance between loads and resources
throughout the entire Western Interconnection, the Company must plan to supply its own reserve
requirements assuming its area control error is exacerbating system frequency. This has modified
reserves planning from considering CPS2 to an avoidance of using contingency reserve for
anything other than specified contingency events, as that is not allowed. Therefore, the
regulating margin requirement evaluated in each time interval of the Wind Integration Study is
intended to cover all anticipated uncertainties in short term load and wind behavior, consistent
with the requirement of the Company to meet its firm load obligations and not deploy
contingency reserve to cover what it should manage with regulating margin.

The sampled component reserve requirements are then backcast against the hypothetical
operational forecasts and data for each ten-minute interval of the study. The resulting (selected)
component reserve requirements are then combined using the root-sum-square method to arrive
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION

125

at the total regulation requirement, by East and West BAA (PACE and PACW, respectively).
This requirement is reduced by each BAA’s respective L10 value3637.The total regulating margin
is the sum of the regulation requirement plus ramp reserve. Table H.22 below is a summary of
results.

Table H.22 - Regulating Margin Requirements Calculated for PacifiCorp’s System (MW)

The cost to hold the incremental regulating margin to integrate wind resources is estimated using
the Company’s PaR model (a production cost model set up to simulate the operation of
PacifiCorp’s electrical system)by calculating the difference in production costs with and without
the incremental reserves to integrate wind resources using the projected Company’s load and
resource portfolio in 2013. This calculation results in the intra-hour reserves costs detailed in
Table H.23. The day-ahead load and wind forecast data are used to commit the generation
resources in the PaR model, and then it is set to simulate operations serving the actual system
loads and received wind generation, isolating the effect of wind generation forecasts and actual
generation in a three-stage process. This calculation yields the inter-hour/system balancing cost,
also detailed in Table H.23:

Table H.23 - Wind Integration Costs

The costs calculated in this study reflect the current market conditions for natural gas and
electricity based on the June 29, 2012 official forward price curve. As these market conditions
change, so will the value of the operating reserves required to meet the systems’ regulating
margin requirements. The total wind integration costs displayed in Table H.23 are used in the
Company’s System Optimizer model for IRP portfolio development, while the incremental
regulating margin requirements for integrating wind displayed in Table H.22 are used to support
IRP portfolio production cost modeling using the PaR model.
36 The L10 represents a bandwidth of acceptable deviation prescribed by WECC between the net scheduled
interchange and the net actual electrical interchange on the Company’s BAAs. Subtracting the L10 credits customers
with the natural buffering effect it entails.
37 The L10 of PacifiCorp’s balancing authority areas are 33.41MW for the West and 47.88 MW for the East. For
more information, please refer to:
http://www.wecc.biz/committees/StandingCommittees/OC/OPS/PWG/Shared%20Documents/Annual%20Frequenc
y%20Bias%20Settings/2012%20CPS2%20Bounds%20Report%20Final.pdf
West East
Regulation Regulation Ramp Combined
Load-Only Reserves 99 176 119 394
Incremental Wind Reserves 50 126 9 185
Total Reserves 149 302 128 579
Study 2012 Wind Integration Study
Wind Capacity Penetration 2126 MW, 2011 Operational Data
System Assumption 2013 PacifiCorp System
Tenor of Cost 1 year levelized, 2012$
Hourly Reserve ($/MWh)$2.19
Interhour/System Balancing ($/MWh)$0.36
Total Wind Integration ($/MWh)$2.55
PACIFICORP – 2013 IRP APPENDIX H – WIND INTEGRATION
126

PACIFICORP - 2013 INTEGRATED RESOURCE PLAN APPENDIX I – STOCHASTIC LOSS OF LOAD STUDY

127

APPENDIX I – STOCHASTIC LOSS OF LOAD STUDY
This appendix contains the Cost and Reliability Analysis of Planning Reserve Margins Final
Report received from Ventyx as requested by PacifiCorp to support planning reserve margin
modeled in the 2013 Integrated Resource Plan.

Page 1 of 16

Cost and Reliability Analysis of Planning
Reserve Margins
Pacificorp
Final Report
27th February 2013 – Version 2.1

Prepared by:

Jason E. Christian, PhD
Ventyx Advisors

Pacificorp
Page 2 of 16
1 INTRODUCTION
1.1 Workflow Overview
Figure 1 below shows the general workflow for the analysis of reserve margins. The objective of the
study is to measure the costs and benefits of alternative reserve margins. The benefits, in terms of this
study, are the increased reliability associated with higher reserve margins as measured by the Planning
Figure 1. General Workflow for Reserve Margin Analysis
and Risk (PaR) Reliability Model (process A2 in Figure 1). The costs are (1) capital costs reported by the
System Optimizer (SO) capacity-expansion model (process A1 in the figure) and (2) expected production
costs reported from the PaR stochastic Production Cost model (process A3 in Figure 1). The general
workflow includes as well the analytic process A4 where the results of processes A1, A2, and A3 are
brought together and analyzed.

The general analysis illustrated in Figure 1 includes two distinct stochastic PaR models. The Reliability
Model differs, in general, from the Production Cost model in that the Reliability Model assumes less (or
no) access to markets or other grid resources; the intent of the Reliability Model is to measure the ability
of a system to maintain reliability without relying on the rest of the grid. The self-reliance assumption is
not, in general, appropriate for estimation of production cost; for production cost modeling the expected
access to markets, to enable economy purchases or sales of generation, is modeled.

Reliability measures, including expected unserved energy (EUE, typically measured in MWh or GWh),
Loss of Load Hours (LOLH), and Loss of Load Probability (LOLP, typically measured in days of outage
per ten years) are available from both the Reliability Model and the Production Cost Model. Which
measure to use to evaluate the reserve margin choice depends in part upon the reliability policies of the
utility and its regulators and stakeholders, and in part upon the uses to which it will be put. For example,
in the case of Pacificorp, the company already assumes limited market access, substantially less than the
transmission-supported emergency-power facilities offered by the Northwest Power Pool (NWPP)
reserve-sharing arrangements. For the Reliability Model there is no market access outside of the firm
Front Office Transactions that are parts of the capacity-expansion process. See section 1.3.1 for further
discussion of the assumptions regarding different types of external power.

Pacificorp
Page 3 of 16
1.2 Major Assumptions
1.2.1 Market Access and Emergency Power in the Reliability and
Production Cost Models
This study, along with other elements of Pacificorp’s IRP modeling processes, makes a strong distinction
between the availability of external power for capacity-planning purposes and for forecasts of the
expected costs of operating that capacity. For capacity planning purposes, external purchases are limited
to Front Office Transactions (FOT’s), which in general require that Pacificorp have the firm capacity to
bring that power from an external trading point (such as the MidC hub) into its service territory, and that
there be sufficient available generating and transmission capacity to allow counterparties to reliably
deliver on those contracts to the trading point. The FOT capacity assumptions are, then, the capacity-
model equivalent of conditions for trading capacity in systems where there are formal capacity markets.
In contrast, in the stochastic production cost models, it is assumed that reasonably liquid markets exist at
various points around the system, and that in actual near-real-time operations (for example day-ahead)
sufficient transmission capacity will be available, at a price. To some extent lack of availability of
transmission near real time is reflected in the production cost model by energy price volatility. In
forecasting the expected costs of operating a portfolio, assumptions regarding the prices that are
available to generators are important, but for the purposes of planning, and satisfaction of planning
reserve requirements in particular, only the more restrictive assumptions embodied in the FOT
assumptions are used.

The restrictive assumptions used in the capacity expansion modeling are relaxed in the reliability
modeling specifically to capture the contributions to two measures of reliability---Loss of Load Hours
(LOLH) and Expected Unserved Energy (EUE) provided by the reserve-sharing arrangements of the
Northwest Power Pool (NWPP). The reliability impacts are one of the contributions of the NWPP
arrangements; a major production- cost savings, shared by Pacificorp and other members of the Pool, is
associated with sharing the burden of providing operating reserves against the single largest contingency
of the full pool, rather than having each participant holding reserves against its own largest contingency;
this effect is captured in the current modeling, as in the modeling in support of previous IRPs, through a
reduction in the modeled ancillary-services requirements. The reliability contribution is captured in two
ways: by approximating the energy delivered by the Pool in the first hour of each simulated loss-of-load
episode, and by reducing the number of LOLH by 1 per episode. It should be noted that the traditional
LOLP measure, which does not distinguish between episodes, is not effected by this calculation: each
time there is a simulated call on NWPP emergency energy counts as a reliability event (but of shorter
duration and smaller energy magnitude than otherwise). This allows an estimation of an additional cost
savings associated with participation in the NWPP arrangements: this participation allows the same
reliability to be achieved (as measured by LOLH or EUE) at a lower reserve margin.
1.2.2 Selection of Reliability Year
The objective of the modeling workflow is to estimate the cost and reliability consequences of different
reserve margins, supporting a reserve margin recommendation which can, if adopted, be used as a target
for future-year planning. As such it is neither necessary nor desirable to simulate every possible year. It
is sufficient to do the analyses for a single year. For this study we selected 2014 as the reliability year, as
it is the earliest year when a change in the Reserve Margin could have an effect, and it is the year when a
new combined cycle, whose construction is already committed, will come into service in Utah.

Pacificorp
Page 4 of 16
1.2.3 Topology
The various simulations used in this study used variants of the current Pacificorp planning topology
illustrated in Figure 2 below. The capacity expansion model and the production cost simulations used the
full detailed version, while the reliability model used the 5-zone aggregation indicated by the blue-shaded
areas in the figure. The reasoning behind this aggregation is discussed in section 3.2 below.

Figure 2. Pacificorp Planning Topology
1.2.4 Load Volatility calibration
Volatility of loads is one of the key drivers of the utility resource planning process and, therefore, of the
associated reliability and cost modeling. There are three major sources of fluctuations in demand: the
highly predictable hour-to-hour and day-to day shape, the short-term weather effects, also highly
predictable to the extent that the weather drivers are predictable, and the longer-term variability in the
size and composition of the utility’s customer base. In this study the Reliability Year is 2014 (see Section
1.3.2), near enough to eliminate most of the third source of volatility. The modeling therefore uses only
the mean-reverting short-term process that is at the core of the PaR stochastic model.

The core of a utility load forecast is a shape that includes an expected peak load. Suppose, for simplicity,
that the only source of load volatility is “weather;” in a summer-peaking system this might be the highest
daytime high temperature expected during a forecast period, that occurs on a weekday. The load
forecaster has good information on the distribution of daily high temperatures at a location; again, for
simplicity, assume they obey a normal distribution and the load (or weather) forecaster knows the mean
and standard deviation of the distribution. There are about 20 weekdays in a month; the expected high
temperature is therefore the expected maximum from 20 draws. The peak load forecast is a forecast of
this random variable, with a probability of being exceeded.

Pacificorp
Page 5 of 16
The stochastic reliability model performs Monte-Carlo experiments to simulate the ability of the power
system to serve loads during occasional high-impact events involving unusually high loads in combination
with major outages of generation. The model therefore needs to make draws from the distribution around
the expected peak with an appropriate frequency. One approach would be to use a weather-based load
model directly, take draws of the weather variables (such as heating-degree-days and cooling-degree-
days); this approach would, with a well-estimated load model, produce an appropriate distribution of loads
(and of the derived measure peak loads). The alternative approach used here is to compare two peak
load forecasts, with different probabilities of exceedence; the expected value of the peak load is the
higher-probability-of-exceedence forecast, which is shocked by a stochastic scalar that produces the
lower-probability-of-exceedence forecast from the higher-probability forecast with the frequency implied
by probabilities.

Pacificorp provided a 1-in-10 exceedence forecast for 2014 of 10,331 MW; this is the expected peak used
in this reliability study as well as in the rest of the IRP stochastic simulations. Pacificorp also furnished a
1-in-20 exceedence forecast of 10,712 MW for 2014. We model this by setting up a stochastic scalar,
with an expected value of 1, to reach a value of 10712/10331=1.0369. This should occur in 1/20 of the
Monte-Carlo scenarios; noting that we are doing daily draws, there are for each Monte-Carlo scenarios
about 20 weekday opportunities to reach this level. So we seek a distribution that has a mean of 1 and
that reaches the critical value of 1.0369 in 1/20 of the scenarios, where each scenario has 20 weekday
opportunities: we seek the distribution that has 1-(1/202) =99.75% of its values less than 1.0369. The
99.75th percentile of a standard normal distribution (mean of 0 and standard deviation of 1) can be
computed with the Excel formula =NORMINV(0.9975,0,1), which returns the value 2.807034. This allows
the computation of a target converged volatility ɐ୘ =ଵ.଴ଷ଺ଽିଵଶ.଼଴଻଴ଷସ =0.013148. To check, note that the Excel
formula =NORMINV(0.9975,1, 0.013148) returns the value 1.036907.

The stochastic model used for both the Reliability and the Production Cost model uses a mean-reverting
model with a mean reversion rate 0.4. The mean reversion rate was not estimated; rather it is an
approximate value, similar to other values estimated for power customers in the west, and is consistent
with the weather patterns in the region (where both winter and summer weather fluctuations tend to have
a duration of several days). It can be shown (Christian 2008a) that a mean reverting process with mean
reversion rate Į will, on multiple iterations, have a distribution with a standard deviation that converges to
a target ߪ் if it has a short-term volatility (the standard error of the shocks to the mean reverting process)
of ߪௌ =ߪ்ඥͳ െ (1 െ ߙ)ଶ.

Applying the converged target ߪ் we compute a short-term volatilityߪௌ =0.013148ඥͳ െ (0.6)ଶ
=0.0105183. This value, as well as the mean reversion rate of 0.4 was applied to all of the power
customers in the standard Pacificorp stochastic planning and risk model. The existing correlation
coefficients estimated for the prior IRP were retained, so as to capture the load diversity between load
areas.

Pacificorp
Page 6 of 16
2 CAPACITY EXPANSION MODEL

The capacity expansion model used in this study used the assumptions used in other parts of the
Pacificorp IRP process, but building to different reserve margins. The primary resource expansion
options used to satisfy the requirements for capacity expansion were a series of Front Office Transactions
(FOT), that are assumed to be able to reliably deliver power to several points around the Pacificorp
system (COB, Goshen, Mead, MidC, Mona, NOB, Portland, Utah, Willamette Valley, Southern
Oregon/California, and Yakima), as well as gas-fired CC-GT stations in Utah and in the Southern
Oregon/California zone. The FOT transactions are priced at the forward electricity prices forecast at their
zones, plus a zone-specific adder. The capacities that may be purchased of these FOTs reflect
Pacificorp planning assumptions. FOTs may be either for a fixed amount (determined by the System
Optimizer (SO) model) for the full year, or for Third-Quarter High Load Hours (Q3 HLH, the 16 hours
beginning at 6 am and ending at 10 pm). SO was then run 11 times, for each of the integer reserve
margin levels 10% through 20%.

The results of these runs are summarized in Table 1 below. Overall, the model has a preference for the
Q3-HLH variant of the Front Office Transactions, up to the assumed limits on those transactions. This is
not surprising, since the driver behind capacity expansion is increasing the reserve margin at the system
coincident peak, which in the model occurs in the third quarter, and these resources have no fixed cost
and only a small charge above market.

All expansion plans included the addition of one Class F CC-GT in the Southern Oregon-Northern
California zone, and one in the Utah-North zone, with a combined capacity of 1,719 MW. At reserve-
margin 16%, the model requires more capacity that can be provided by additional FOTs, so an additional
CC-GT is added in the Southern Oregon-Northern California zone. The attractiveness of this location can
be inferred from the topology map (Figure 2 above): this is a transmission hub on the Pacificorp system
with the ability to provide capacity to much of both the western and eastern parts of the system. When
the additional CC-GT is added at the 16% level, the solution plans’ selections of FOT falls to
accommodate the physical plant, then increases again as the reserve margin requirement increases.

Pacificorp
Page 7 of 16
Table 1. Expansion Plans as Reserve Margins Increase: 10%--20%
Reserve
Margin
Flat
FOT
Q3 HLH
FOT
Total
FOT
Physical
Plant Total
10 282 386 669 1,180 1,849
11 283 487 770 1,180 1,950
12 284 587 871 1,180 2,051
13 287 685 972 1,180 2,152
14 293 780 1,073 1,180 2,253
15 299 875 1,174 1,180 2,355
16 306 431 736 1,719 2,456
17 312 525 838 1,719 2,557
18 319 620 939 1,719 2,658
19 273 767 1,040 1,719 2,759
20 280 861 1,141 1,719 2,860

3 RELIABILITY MODEL
The Reliability Model allows an evaluation of the ability of a utility to serve its own loads with specified
resources, in this case a series of expansion plans (as described in the previous section) selected to
meet various reserve margins.
.
3.1 Reliability Model Description
The Reliability Model is a stochastic implementation of the Planning and Risk (PaR) chronological unit-
commitment and dispatch simulator, which finds a weekly dispatch of the Pacificorp portfolio for each of a
series of (a) weekly draws of outages of Pacificorp generating units and (b) daily draws of Pacificorp
loads. The model includes a proxy “ENS Station” station which is configured to “run” to meet loads after
actual generation (including, as appropriate, energy delivered by FOTs) are exhausted, and to “turn off”
otherwise. The reported generation of the ENS Station for each Monte Carlo iteration is therefore a
measure of the total energy not served by the combination of Pacificorp generation and FOT energy. The
number of starts reported for the ENS Station is then the number of episodes when FOT resources are
insufficient to meet loads. The number of hours of operation of the ENS Station is the number of hours
when FOT resources are insufficient to meet loads.

The configuration of the model to represent stochastic loads is described in more detail in section 1.2.4
above.

Generation outages are simulated through the comparison of each station’s designated forced outage
rate to a series of independent random draws, one per week per generating resource per Monte-Carlo
iteration, where the random numbers are drawn from a uniform distribution of numbers between 0 and 1.
If the drawn number for a station is less than its forced outage rate, then the station is removed from the
portfolio for the week.

In most of the Monte-Carlo draws, and in most weeks, Pacificorp has more resources than are required to
meet loads. Pacificorp, in common with most utilities, operates a portfolio that, in combination with
expected market and emergency power access, contains sufficient resources to meet loads unless there
are particularly adverse combinations of high loads and multiple simultaneous outages. A primary

Pacificorp
Page 8 of 16
challenge in performing this sort of analysis is to perform enough draws of outages (in particular) to
appropriately represent the frequency of the severe adverse combinations of station outages and high
load draws. It is helpful to think of the probability distribution of several MarginMWzt variables for zone z
and time t, computed as the zone’s available resources (including the lesser of the neighboring zone’s
margin and transmission into z), minus the zone’s loads. The reliability analysis involves various
measurements on the left-hand, negative, tail of this distribution, including in particular the frequency of
draws in the tail, which produces loss of load hours and probability, and the frequency-weighted area of
the tail, which produces expected unserved energy. To make reasonable estimates of any of these
measures requires sufficient draws to adequately represent the tail. In a reasonably reliable system
these tail events are rare, and it therefore requires many more draws to get a decent measurement.

To find an appropriate number of Monte-Carlo draws a fast-running highly simplified model was created.
The model made all resources must-run, and eliminated chronological constraints (minimum up and down
time, ramp rates and start costs were set to zero, and the model was set to run only across the summer
peak, at a 16% reserve margin. The model used the simplified Reliability-Model topology, summarized in
the next section, and was run using different numbers of draws. It was found that the Expected Unserved
Energy measure (the generation of the proxy ENS Stations) changed from run to run when less than 500
draws were performed, but that there was no large difference at higher numbers of draws. We therefore
used 500 draws for the subsequent reliability simulations.
3.2 Reliability-Model Topology
In preliminary simulations with the full Pacificorp planning topology, represented by the detailed bubble-
and-pipe diagram in Figure 2 above, unserved energy appeared almost entirely in the Utah North zone,
with a few instances in Goshen and in Yakima. The Pacificorp transmission system is quite robust within
the large blue-shaded regions in the diagram. We therefore rolled up the transmission areas within those
regions for the purposes of reliability measurement. While this reliability-model topology is not suitable for
production-cost analysis, as it would allow more within-region transmission of less expensive generation
and reduce the use of high-cost peaking resources below what would be expected, it does not materially
change the incidence and magnitude of simulated loss-of-load events, while making feasible the high
number of Monte-Carlo draws that is necessary for reasonably precise estimation of the tails of the
MarginMWzt distribution discussed in the previous section.
3.3 NWPP Reserve Pool Arrangements
Pacificorp’s participation in the Northwest Power Pool (NWPP) reserve-pool arrangements allow it to
receive energy from other participants in the pool for the first hour after a resource outage that would
cause a loss of load event. The use of Proxy ENS stations allows simulation of the operation of the pool
arrangements. The Reliability Model reports the gross output of the ENS stations, which we designate G.
In the absence of the reserve pool, the expected value of G would be the Expected Unserved Energy
reliability measure. The number of starts s of the Proxy ENS stations is the expected number of
episodes, from which the LOLP measure may be derived. Finally, the model reports the number of hours
h of “operation” of the Proxy ENS stations, which in the absence of the Reserve Pool would be Loss of
Load Hours (LOLH).

The impact of the Reserve Pool on LOLH is clear: we compute h* =h-s. To compute the contribution of
the pool to EUE, we assume that the outage energy is approximately equal across each episode, so that
the hours covered by the pool have the same energy as the residual hours h*. We can then compute the
reserve-pool energy as R=s/h G, and net EUE as N=G-R=(h-s)/h G=h*/h G.
3.4 Principal Results
This section reports the principal results of the Reliability Model simulations in section 3.4.1. These raw
simulations produce a decrease in reliability when perfectly-reliable FOT are replaced, at the 16% reserve

Pacificorp
Page 9 of 16
margin level, by an additional thermal station. In general the study is evaluating small magnitudes, so
changes such as this can produce seemingly anomalous results. To take advantage of the substantial
information within the simulation runs, we performed a series of regression-base post processes, which
are described in section 3.4.2. Section 3.4.3 analyzes the contribution of the NWPP Reserve Pool to
reliability.
3.4.1 Simulation Results
Table 2 shows the principal raw simulation results of the 11 Reliability-Model simulations, one for each of
the reserve-margin expansion plans produced by the capacity expansion runs (see section 2), for
reliability year 2014. Note that 2.4 Loss of Load Hours per year is equivalent to one day in ten years:
using an hours-based reliability measure the Pacificorp system meets this traditional reliability measure at
all reserve margins.

The reliability measures all increase (these are all measures of loss of load, so an increase indicates
reduced reliability) between reserve margins 13 and 14 and, more significantly, between reserve margins
15 and 16. A number of factors may account for this, of which the most important is that, between
reserve margins 15 and 16 SO adds a combined-cycle station, which has a forced outage rate, and
reduces the amount of perfectly-reliable FOT. In addition, this station is in the Southern-
Oregon/Northern-California zone, and may be unable to fully respond (due to transmission constraints) to

Table 2. Simulated Reliability and NWPP Reserve Pool Contributions at Reserve Margins 10%--20%
G:h:s:N=G-R
Reserve
Margin:
%
Gross EUE
MWh
Expected
Gross Loss
of Load
Hours
Expected
Loss of
Load
Episodes
NWPP
Reserve
Pool GWh
Net EUE
GWh
Expected
Net Loss
of Load
Hours
10 208.4 1.05 0.25 49.61 158.77 0.80
11 279.2 1.26 0.27 59.83 219.38 0.99
12 221.3 1.06 0.23 48.02 173.28 0.83
13 147.0 0.77 0.18 34.35 112.60 0.59
14 183.4 0.87 0.19 40.04 143.32 0.68
15 117.7 0.65 0.15 27.16 90.54 0.50
16 193.5 0.97 0.22 43.90 149.64 0.75
17 188.0 0.94 0.22 44.00 143.99 0.72
18 152.7 0.74 0.16 33.01 119.65 0.58
19 98.6 0.53 0.11 20.47 78.16 0.42
20 59.6 0.34 0.08 14.02 45.56 0.26
ܴ =ݏ݄ ܩ ܮܱܮܪ=݄ െ ݏ

adverse combinations of high loads and multiple station outages in the Northern Utah zone where most of
the unserved-energy appears. Above all, this is an issue of changes in a tail measurement that are small
in magnitude but large in relative terms. These sorts of noisy observations are found in real-world
observations as well as in simulations. In order to draw useful information for such processes we can use
regression techniques. This approach is developed in the next section.

Pacificorp
Page 10 of 16
3.4.2 Regression Post-Processing
Table 3 shows the principal results from the regressions of several reliability measures against the
reserve margin. EUE and Duration-Based LOLP were estimated both with and without the NWPP
Reserve Sharing estimates; the episode-based LOLP measure does not reflect these arrangements.

These are simple equations estimated over only 11 observations, so the R2 goodness-of-fit statistics
(which measure the percent of deviations of the reliability measure from their mean, across 11
observations, that are captured by the regression equation) are not particularly high. However, the t-
statistics on b1 (the Reserve-Margin coefficient) are all highly significant. Given the small samples, these
are useful regression equations.
Table 3. Reliability Smoothing Regression Results
Episode-Based LOLP
With Reserve
Sharing
Without Reserve
Sharing
With Reserve
Sharing
Without Reserve
Sharing
Without Reserve
Sharing
R G h-s h s
R2 0.585 0.599 0.628 0.641 0.668
b0 389.219 502.515 0.7459 0.96415 5.23791
se(b0)73.317 92.086 0.12333 0.15534 0.79850
t(b0)5.309 5.457 6.048 6.207 6.56
b1 -0.110 -0.142 -0.000202 -0.000262 -0.00143
se(b1)0.031 0.039 0.0000519 0.0000654 0.00034
t(b1)-3.548 -3.641 -3.892 -4.006 -4.206
Expected Unserved Energy Duration-Based LOLP
Reliability = b0 + b1 RM

Table 4 shows the fitted values from the equations described in Table 3, next to the simulated results
from which the regression equations were computed. The linear reliability curves for each of the three

Pacificorp
Page 11 of 16
reliability measure are then plotted in Figure 3, Figure 4, and Figure 5. Figure 3 highlights how the
regression equation smooths the anomalous discontinuity after the addition of a thermal station at
Reserve Margin 16.

Table 4. Simulated and Fitted Reliability, Reserve Margins 10%--20%
RM
%Simulated Fitted Simulated Fitted Simulated Fitted Simulated Fitted Simulated Fitted
10 159 186.0196 0.33333 0.371968 208 239.9342 0.43750 0.480111 2.50000 2.595443
11 219 174.9054 0.41250 0.351515 279 225.5721 0.52500 0.453637 2.70000 2.450911
12 173 163.7890 0.34583 0.331059 221 211.2071 0.44167 0.427157 2.30000 2.30635
13 113 152.6759 0.24583 0.310608 147 196.8464 0.32083 0.400684 1.80000 2.161832
14 143 141.5607 0.28333 0.290153 183 182.4829 0.36250 0.374207 1.90000 2.017285
15 91 130.4454 0.20833 0.269699 118 168.1193 0.27083 0.347729 1.50000 1.872739
16 150 119.3301 0.31250 0.249244 194 153.7558 0.40417 0.321252 2.20000 1.728193
17 144 108.2148 0.30000 0.228789 188 139.3923 0.39167 0.294775 2.20000 1.583646
18 120 97.0985 0.24167 0.208333 153 125.0273 0.30833 0.268294 1.60000 1.439085
19 78 85.9832 0.17500 0.187878 99 110.6638 0.22083 0.241817 1.10000 1.294539
20 46 74.8668 0.10833 0.167421 60 96.29883 0.14167 0.215337 0.80000 1.149978
With NWPP Reserve Sharing Without NWPP Reserve Sharing
Without NWPP
Reserve Sharing
LOLP Duration LOLP Duration Based LOLP Episode BasedEUEEUE

Figure 3. Simulated and Fitted Relationship of EUE to Reserve Margins
-
50
100
150
200
250
9 14 19
EUE (MWh)
Reserve Margin %
Simulated
Fitted

Pacificorp
Page 12 of 16
Figure 4. Simulated and Fitted Relationship of Duration-Based LOLP to Reserve Margins

Figure 5. Simulated and Fitted Relationship of Episode-Based LOLP to Reserve Margins

0.00
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
9 14 19
LOLP (Days per 10 Years)
Reserve Margin %
Simulated
Fitted
-
0.50000
1.00000
1.50000
2.00000
2.50000
3.00000
9 14 19
LOLP (Days per 10 Years)
Reserve Margin %
Simulated
Fitted

Pacificorp
Page 13 of 16
3.4.3 Contribution of Reserve Pool to Reliability
The comparison of the regression equations with and without NWPP Reserve Sharing allows analysis of
the reliability contributions of the Reserve Pool. It should be noted that this is only part of the benefit to
Pacificorp of the Pool. Reliable operations generally involve maintaining contingency reserves based on
the larger of a percentage of load (adjusted for the thermal/hydro mix of the system) and the largest
single contingency; the reserve pool arrangement allows the largest-contingency requirement to be
shared across multiple members, with each member’s share of this requirement less than its own largest
contingency. The evaluation here does not include the cost savings associated with carrying lower levels
of reserves. Such an evaluation is a straightforward production-cost modeling exercise. Here we are
concerned only with identifying the reduction in reserve margins that, holding reliability constant, is
possible given participation in the reserve pool. To illustrate the effect, find the EUE measure at Reserve
Margin 13% with Reserve Sharing, which from Table 4 is about 152.7 MWh. Comparing to the value
without Reserve Sharing, this is a bit more than the 153.8 MWh produced by a 16% reserve margin. It is
straightforward to calculate that a 16.1% Reserve Margin in the absence of reserve sharing would
produce the same level of reliability as a 13% Reserve Margin: the Pool gives the same reliability
benefits as a 3.1% increase in the reserve margin. Similar computations comparing the duration-based
LOLP measures produce a 3.4% reserve-margin equivalence.

Figure 6. Reliability With and Without Reserve-Pool Arrangements
4 PRODUCTION COST MODEL
Table 5 reports the single-year capital costs and expected production costs of operating the portfolios in
2014 produced by the expansion plans summarized in Table 1 above. The expected production costs is
from a stochastic production cost model that, in addition to the plant outage and hydro and load
0
50
100
150
200
250
300
9 14 19
EUE (MWh)
Reserve Margin %
Without NWPP Reserve Sharing
With NWPP Reserve Sharing
3.1%

Pacificorp
Page 14 of 16
stochastics used for the reliability model, include stochastic natural gas and power prices. This is the
same stochastic configuration used elsewhere in Pacificorp’s resource planning activities. The model
also inherits the market access assumptions that Pacificorp uses elsewhere, allowing, in particular,
substantial economy market purchases which are excluded from the Reliability Model, while at the same
time not assuming any emergency-power deliveries associated with the NWPP reserve-sharing
arrangements, since those are not substitutes for expected commercial transactions.

It is worth noting that, except for the interval from 15 to 16 %, production costs steadily increase as the
Reserve Margin increases due to the increased purchases of FOTs which are, by construction, out of the
market. The production-cost curve shifts down at 16% when FOT purchases fall to accommodate the
additional Southern-Oregon/Northern-California CCGT; this decrease is more than outweighed by the
increase in capital costs associated with that station

Table 5. Capital and Production Costs at Different Planning Reserve Margins, 11%-18%
Reserve
Margin
Expected
Production
Cost
Proposed
Station Capital
Costs Total
%
11 640,918 84,370 725,288
12 644,747 84,370 729,117
13 650,186 84,370 734,556
14 654,651 84,370 739,021
15 660,530 84,370 744,900
16 639,891 136,720 776,611
17 643,345 136,720 780,065
18 761,961 136,720 898,681
$ '000

5 ANALYSIS
The combination of reliability results from different reserve margins, from section 3.4.2, and of the costs of
acquiring and operation those reserve margins, from section 4, provides a basis for a recommendation
regarding the reserve margin level. Table 6 contains all the elements necessary to compute both the full
additional costs of moving from one reserve margin to the next, and the per-MWh cost of saved unserved
energy. Figure 7 shows the per-MWh incremental cost in graphical form; this can be understood as a
supply curve for reliability.

Pacificorp
Page 15 of 16
Table 6. Incremental Cost of Reliability, Reserve Margins 12-17%
MWAdded
With NWPP
Reserve Pool
Without NWPP
Reserve Pool
With NWPP
Reserve Pool
Without NWPP
Reserve Pool
(percent)(MWh)(MWh)($ '000)($ '000)($/MWh EUE) ($/MWh EUE)
2,051 12 164 211 729,117 3,828 344 267
2,152 13 153 197 734,556 5,439 489 379
2,253 14 142 182 739,021 4,466 402 311
2,355 15 130 168 744,900 5,879 529 409
2,456 16 119 154 776,611 31,711 2,853 2,208
2,557 17 108 139 780,065 3,455 311 241
Expected Unserved
Energy (fitted)
Incremental Cost of
Reliability
Reserve
Margin
Expected Total
Cost With NWPP
Reserve Pool
Expected
Incremental
Cost

The latter information provides, in principal, a strong basis of a reserve-margin recommendation. If we
knew the value to consumers of incremental reliability (which is strongly related to the willingness of loads
to voluntarily curtail), or some other form of a demand curve for energy, then we could select the reserve
margin level where this reliability supply curve crosses a reliability demand curve.

Figure 7. Incremental Cost of Reliability

Such information is not now available. However, as DSM programs are developed, such information will
also become available for this sort of analysis, both directly in the case of price-strike dispatchable load
reductions, and indirectly through analysis of the costs required to produce other voluntary load
reductions.

-
200.0
400.0
600.0
800.0
1,000.0
1,200.0
1,400.0
1,600.0
1,800.0
11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0
$/MWh of EUE Reduction
Reserve Margin Levels (%)

Pacificorp
Page 16 of 16
In the absence of strong information about the incremental value to load of reliability, one cannot make a
strong recommendation for a single point solution to the reserve-margin selection problem. However,
there is one very strong conclusion from this analysis: increasing the Reserve Margin to 16% involves a
substantial increase in cost (as it calls into the plan an additional thermal station), while producing only a
moderate gain in reliability. Lacking strong evidence that there is little ability of loads to curtail at prices
less than $1000/MWh, we cannot recommend an increase in reserve margins to this level. This is seen in
the diagram as the sharp upward jump in the curve in Figure 7, from values in the $400/MWh range that
are not inconsistent with the energy prices around the West during the California crisis, to values over
three times as high. We cannot recommend a move into that reserve-margin region without serious
investigation of other options. In particular, one would want to be sure that at prices above $1,000/MWh
there weren’t additional demand responses available.

The incremental cost of reliability at lower reserve margins do not differ significantly, making it impossible
(even in the presence of information about the value to loads of reliability) to select among the 12%, 13%,
14% and 15% reserve-margin levels. It is important to recognize, however, that across the range of
reserve margin levels increasing reserve margin levels are associated with increasing reliability. While
the costs of those margins are not changing consistently, their impacts are, and their reliability impacts
are felt primarily in a single area, the Utah-North zone. To reduce reserve margins from their current 13%
level would be to impose a reliability cost upon loads in that region, while saving the entire system less
that 1% of total expected cost. Conversely, we note that Pacificorp is engaged in the reinforcement of
transmission into the Utah North zone, which will directly improve reliability in that region, without
requiring an increase in reserve margins. The efficiency of transmission reinforcements in improving
reliability in that zone, the disparate impact of reductions in the reserve margins below 13%, and the lack
of a strong contrary measure of incremental cost of reliability combine to support a finding that it is
reasonable for Pacificorp to retain its current practice, and continue to plan to a 13% Reserve Margin
level. This is our recommendation.

REFERENCES

Christian, J. 2008a. Deriving the Converged Volatility of the EnerPrise Short Term Stochastic Model. Ventyx
Knowledge Base Article, Ventyx ABB.

Christian, J. 2008b. Using an Instantaneously-Converged Mean Reverting Index to Simulate a Target Volatility.
Ventyx Knowledge Base Article, Ventyx ABB.

Lauckhart, R. and C. Kulkarni. 2008. Analysis of “Loss of Load Probability” (LOLP) at various Planning Reserve
Margins, Ventyx Consulting Report, Ventyx ABB.

PACIFICORP – 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

145

APPENDIX J – WESTERN RESOURCE ADEQUACY
EVALUATION
Introduction

The Utah Commission, in its 2008 IRP acknowledgment order, directed the Company to conduct
two analyses pertaining to the Company’s ability to support reliance on market purchases:

Additionally, we direct the Company to include an analysis of the adequacy of the
western power market to support the volumes of purchases on which the Company
expects to rely. We concur with the Office [of Consumer Services], the WECC is a
reasonable source for this evaluation. We direct the Company to identify whether
customers or shareholders will be expected to bear the risks associated with its
reliance on the wholesale market. Finally, we direct the Company to discuss
methods to augment the Company’s stochastic analysis of this issue in an IRP
public input meeting for inclusion in the next IRP or IRP update.58

To fulfill the first requirement, PacifiCorp evaluated the Western Electricity Coordinating
Council (WECC) Power Supply Assessment reports to glean trends and conclusions from the
supporting analysis. This evaluation, along with a discussion on risk allocation associated with
reliance on market purchases, is provided below. As part of this evaluation, the Company also
reviewed the status of resource adequacy assessments prepared for the Pacific Northwest by the
Pacific Northwest Resource Adequacy Forum.

Finally, this appendix describes in the 2011 IRP, the Company conducted a study that involved
the development and stochastic simulation of a market “stress” scenario. In developing this
study, the Company received input from participants at the June 29, 2010 Utah IRP stakeholder’s
meeting, and described its proposed study approach at the October 5, 2010, IRP general public
input meeting. This Appendix H from the 2011 IRP describes the study methodology and
presents results of the stochastic simulations.
Western Electricity Coordinating Council Resource Adequacy Assessment

The Western Electricity Coordinating Council (WECC) 2012 Power Supply Assessment (PSA)
shows a planning reserve margin (PRM, as a percentage) calculated as a percentage of resources
(generation and transfers) and load, and is the percentage of capacity above demand. The PRM
indicates sufficient resources when the PRM is equal to or greater than the target reserve margin.
The 2012 PSA shows WECC needing additional resources in 2020 (see Figure 2). Prior to the
2012 PSA report, WECC instead calculated a power supply margin (PSM, in MW amount)
measuring ability to meet load requirement with resources and transfers. Since 2007, each
subsequent PSA study defers resource need to later years. This deferment is a function of net

58 Public Service Commission of Utah, PacifiCorp 2008 Integrated Resource Plan, Report and Order, Docket No.
09-2035-01, p. 30.
PACIFICORP - 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

146

changes to: load growth expectations, class I capacity entrants, scheduled retirements, resource
performance, transfer capabilities and modeling convention.59

In WECC Power Supply Assessments, the region and subregion target reserve margins are
calculated using a building block methodology created by WECC. As such, they do not reflect a
criteria-based margin determination process and do not reflect any balancing authority or load
serving entity level requirements that may have been established through other processes (e.g.,
state regulatory authorities). They are not intended to supplant any of those requirements.

The building block methodology is comprised of four elements:
1. Contingency Reserves – An additional amount of operating reserves sufficient to reduce
area control error to zero following loss of generating capacity, which would result from
the most severe single contingency.
2. Regulating Reserves – The amount of spinning reserves responsive to automatic
generation control that is sufficient to provide normal regulating margin. The regulating
component of this guideline was calculated using data provided in WECC’s annual loads
and resources data request responses.
3. Additional Forced Outages – Reserves for additional forced outages beyond what might
be covered by operating reserves in order to cover second contingencies are calculated
using the forced outage data supplied to WECC through the loads and resources data
request responses. Ten years of data are averaged to calculate both a summer (July) and
winter (December) forced outage rate. The same forced outage rate is used for all
balancing authorities in WECC when calculating the building block margin.
4. Temperature Adders – Using historic temperature data for up to 20 years, the annual
maximum and minimum temperature for each balancing authority’s area was identified.
That data was used to calculate the average maximum (summer) and minimum (winter)
temperature and the associated standard deviation.

As seen in Figure J.1, there were two significant capacity deferments: from 2012 (per 2008
PSA) to 2016 (per 2009 PSA) followed by 2019 as seen in WECC’s 2010 PSA. While the
forecast power supply margins (PSM) of the studies from 2007 through 2009 are comparable, the
2010 PSA employed a different, and superior, modeling convention. Namely, PROMOD IV, a
chronological production cost model, was used beginning with the 2010 PSA to assess WECC
resource adequacy60. PROMOD IV, unlike WECC’s previous model, uses coincident peak
demand and employs a more robust optimization of sub-regional transfers.

59 The 2012 PSA defines Class I as existing generation that is available (in-service) as of December 31, 2011, and
net generation additions/retirements that were reported to be under active construction as of December 31, 2011 and
are projected to be in-service/retired prior to January 2017. The 2011, 2010, 2009 and 2008 PSA defined Class I to
included generation online by 2016, 2014, 2013, and 2012, respectively. 60 PROMOD IV is electricity market simulation software licensed through Ventyx, an ABB Company.
http://www.ventyx.com/analytics/promod.asp
PACIFICORP – 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

147

Figure J.1 – WECC Forecasted Power Supply Margins, 2007 to 2011
Note: WECC Power Supply Assessments include Class 1 Planned Resources Only

Figure J.2 shows the planning reserve margin calculated in the 2012 WECC Power Supply
Assessment report. The 2012 WECC power reserve margin results show that there is not a
resource need until 2020, which compares to the 2011 assessment which projects a resource need
in 2019.

Figure J.2 – 2012 WECC Forecasted Planning Reserve Margins
Note: 2012 WECC Power Supply Assessment, including Class 1 Planned Resources Only

Basin is a summer peaking WECC subregion comprised of Utah, Idaho, and northern Nevada. A
review of PSA studies from 2007 through 2011 reveals a similar pattern to that of WECC for the
same period. The 2011 WECC Power Supply Assessment shows a resource need in 2018. When
including the addition of the Company’s Lake Side 2 resource, this resource need would be
deferred to 2020. As seen in Figure J.3, the target reserve margin is maintained at the “zero”
Subregion
Target Reserve
Margin 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Northwest 17.9%20.4%19.5%20.5%24.2%21.1%19.3%19.4%19.5%19.5%19.7%
Basin 12.6%32.0%32.5%29.9%25.6%24.7%20.9%17.2%16.2%14.5%16.6%
Rockies 14.7%27.8%25.7%21.5%19.3%17.4%15.6%17.0%17.1%16.1%15.2%
Desert Southwest 13.5%45.0%40.9%42.8%44.7%40.6%40.7%36.5%29.8%26.4%26.0%
WECC Total 14.6%25.4%23.2%22.1%19.3%17.4%15.7%15.1%13.3%11.5%9.3%
Summer; Existing and Class 1 ResourcesPlanning Reserve Margin
PACIFICORP - 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

148

horizontal axis. The PSA’s target reserve margins, as developed by WECC, are not mandated.
Instead, they serve as a reasonable proxy for expected target reserve margins in WECC’s
modeling construct.

Figure J.3 – Basin Forecasted Power Supply Margins
Note: WECC Power Supply Assessments include Class 1 Planned Resources Only. Lake Side 2 is currently under
construction but was not included in the 2011 Power Supply Assessment for Class 1 resources. The chart above
shows the 2011 power supply margin with and without Lake Side 2. The 2012 Power Supply Assessment also does
not include Lake Side 2 for Class 1, since it was not under construction in time to meet definition of Class 1 for the
2012 WECC report.

Consistent with the planning reserve margins calculated for Rockies (Colorado and Wyoming)
and Desert Southwest (Arizona, New Mexico and southern Nevada) subregions in the 2012
WECC Power Supply Assessment, Figures J.4 and J.5, showing the 2011 WECC report results,
also show resource deferment until 2020 for the Desert Southwest subregion and after 2020 for
the Rockies subregion.

PACIFICORP – 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

149

Figure J.4 – Desert Southwest Forecasted Power Supply Margins
Note: WECC Power Supply Assessments include Class 1 Planned Resources Only.

PACIFICORP - 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

150

Figure J.5 – Rockies Forecasted Power Supply Margins
Note: WECC Power Supply Assessments include Class 1 Planned Resources Only.

Market depth refers to a market’s ability to accept individual transactions without a perceptible
change in market price. While different from market liquidity61 the two are linked in that a deep
market tends to be a liquid market. Market depth in electricity markets is a function of the
number of economic agents, market period, generating capacity, transmission capability,
transparency, and institutional and/or physical constraints. Based on the 2012 PSA, WECC
maintains a positive PSM through 2019. The Basin, Desert Southwest, Northwest62, and
Rockies subregions are forecasted to maintain sufficient planning reserve margins through 2022.
In total, known market transactions, generation resources, load requirements, and the
optimization of transfers within WECC show adequate market depth to maintain positive target
reserve margins for several years.

61 Market liquidity refers to having ready and willing buyers and sellers for large transactions. 62 The Northwest is comprised of the Pacific Northwest and Montana.
PACIFICORP – 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

151

Pacific Northwest Resource Adequacy Forum’s Adequacy Assessment

The Pacific Northwest Resource Adequacy Forum issued resource adequacy standards in April
2008, which were subsequently adopted by the Northwest Power and Conservation Council. The
standard calls for assessments three and five years out, conducted every year. In a November
2012 report, the Forum concluded that the likelihood of a shortfall between the region’s power
supply and forecasted load growth in 5 years out had increased from 5 percent to 6.6 percent.63
This means that the region will have to acquire additional resources in order to maintain an
adequate power supply, a finding that supports acquisition actions currently being taken by
regional utilities. Between 2015 and 2017, the region’s electricity loads, net of planned energy
efficiency savings, are expected to grow by about 300 average megawatts or about a 0.7 percent
annual rate. Since the last assessment, 114 megawatts of new thermal capacity and about 1,200
megawatts of new wind capacity have been added along with about 250 megawatts of small
hydro and hydro upgrades.

The majority of potential future issues are short-term capacity shortfalls. The most critical
months are January and February and, to a lesser extent, August. This is a different result from
the 2015 assessment, which indicated that August was the most critical month. The major reason
for this shift is the use of an updated stream flow record, which contains 10 more years of
historical flows, new irrigation withdrawal amounts and various updates to reservoir operations
both in the U.S. and Canada. The net result yields a higher average stream flow in August, thus
improving summer adequacy.
Customer versus Shareholder Risk Allocation

Market purchase costs are reflected in rates. Consequently, customers bear the price risk of the
Company’s reliance on a given level of market purchases. However, customers also bear the cost
impact of the Company's decision to build or acquire resources if those resources exceed market
alternatives and result in an increase in rates. These offsetting risks stress the need for robust IRP
analysis, efficient RFPs and ability to capture opportunistic procurement opportunities when they
arise.

63 Pacific Northwest Power Supply Adequacy Assessment for 2017, at
http://www.nwcouncil.org/media/30104/2012_12.pdf
PACIFICORP - 2013 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION

152

PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

153

APPENDIX K – DETAILED CAPACITY EXPANSION
RESULTS
Portfolio Case Build Tables

This section provides the System Optimizer portfolio build tables for each of the case scenarios as
described in the portfolio development section of Chapter 7. There are 19 core cases, and each
was run under the five Energy Gateway scenarios. One exception is that Case C-19, on alternative
to Segment D of the Energy Gateway, is not applicable to EG1 that does not include segment D,
so there is no study required.

Table K.1 – Gateway Scenario Definitions
Scenario Segments Description
EG1 C, and G Reference – Mona-Oquirrh-Terminal, 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

PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
155

Table K.2 – 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

PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

156

Table K.3 – 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.

PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
157

Table K.4 – Resource Name and Description
Resource List Detailed Description
East Resources
CCCT F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing
CCCT FD 1x1 Combine Cycle Combustion Turbine FD-Machine 1x1 with Duct Firing
CCCT FD 2x1 Combine Cycle Combustion Turbine FD-Machine 2x1 with Duct Firing
CCCT GH 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing
CCCT GH 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing
CCCT J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing
IC Aero UT Inter-cooled Simple Cycle Combustion Turbine Aero - Utah
IC Aero WYAE Inter-cooled Simple Cycle Combustion Turbine Aero - Wyoming
IC Aero WYNE Inter-cooled Simple Cycle Combustion Turbine Aero - Wyoming
IC Aero WYSW Inter-cooled Simple Cycle Combustion Turbine Aero - Wyoming
SCCT Aero UT Simple Cycle Combustion Turbine Aero - Utah
SCCT Aero WYNE Simple Cycle Combustion Turbine Aero - Wyoming
SCCT Frame ID Simple Cycle Combustion Turbine Frame - Idaho
SCCT Frame UT Simple Cycle Combustion Turbine Frame - Utah
SCCT Frame WYAE Simple Cycle Combustion Turbine Frame - Wyoming
SCCT Frame WYNE Simple Cycle Combustion Turbine Frame - Wyoming
SCCT Frame WYSW Simple Cycle Combustion Turbine Frame - Wyoming
Lake Side II Lake Side II
Nuclear Nuclear
Geothermal, Greenfield Geothermal, Greenfield
WY IGCC CCS Integrated Gasification Combined Cycle with Carbon Capture & Sequestration - Wyoming
Coal Ret_UT - Gas RePower Coal Plant conversion to Gas Plant - Utah (Cholla, Hunter, or Huntington)
Fly Wheel Fly Wheel
CAES Compressed Air Energy Storage
Battery Storage Battery Storage
Pump Storage Pump Storage
Utility Solar - PV Utility Solar - Photovoltaic
Micro Solar - PV Micro Solar - Photovoltaic
Micro Solar - Water Heating Micro Solar - Water Heating
Wind, GO, 29 Wind, Goshen Idaho, 29% Capacity Factor
Wind, UT, 29 Wind, Utah, 29% Capacity Factor
Wind, WYAE, 40 Wind, Wyoming, 40% Capacity Factor
CHP - Biomass Combined Heat and Power - Biomass
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

158

Resource List Detailed Description
CHP - Reciprocating Engine Combined Heat and Power - Reciprocating Engine
CHP - Other Combined Heat and Power - Other
DSM, Class 1, ID-Curtail DSM Class 1, Curtailment - Idaho
DSM, Class 1, ID-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - Idaho
DSM, Class 1, ID-DLC-RES DSM Class 1, Direct Load Control-Residential - Idaho
DSM, Class 1, ID-Irrigate DSM Class 1, Direct Load Control-Irrigation - Idaho
DSM, Class 1, UT-Curtail DSM Class 1, Curtailment - Utah
DSM, Class 1, UT-DLC-RES DSM Class 1, Direct Load Control-Residential - Utah
DSM, Class 1, UT-Irrigate DSM Class 1, Direct Load Control-Irrigation - Utah
DSM, Class 1, WY-Curtail DSM Class 1, Curtailment - Wyoming
DSM, Class 1, WY-DLC-RES DSM Class 1, Direct Load Control-Residential - Wyoming
DSM, Class 1, WY-Irrigate DSM Class 1, Direct Load Control-Irrigation - Wyoming
DSM, Class 3, UT-TOU-RES DSM, Class 3, Time of Use, Residential - Utah
DSM, Class 3, WY-TOU-IRR DSM, Class 3, Time of Use, Irrigation - Wyoming
DSM, Class 3, WY-TOU-RES DSM, Class 3, Time of Use, Residential - Wyoming
DSM, Class 2, ID DSM, Class 2, Idaho
DSM, Class 2, UT DSM, Class 2, Utah
DSM, Class 2, WY DSM, Class 2, Wyoming
FOT Mead Q3 Front Office Transaction - 3rd Quarter HLH Product - Mead
FOT Mona Q3 Front Office Transaction - 3rd Quarter HLH Product - Mona

Resource List Detailed Description
West Resources
CCCT F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing
CCCT GH 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing
CCCT GH 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing
CCCT J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing
IC Aero WV Inter-cooled Simple Cycle Combustion Turbine Aero - Willamette Valley
IC Aero WW Inter-cooled Simple Cycle Combustion Turbine Aero - Walla Walla
IC Aero PO Inter-cooled Simple Cycle Combustion Turbine Aero - Portland/North Coast
IC Aero SO-CAL Inter-cooled Simple Cycle Combustion Turbine Aero - Southern Oregon/California
SCCT Aero PO Simple Cycle Combustion Turbine Aero - Portland/North Coast
SCCT Aero WV Simple Cycle Combustion Turbine Aero - Willamette Valley
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
159

Resource List Detailed Description
SCCT Aero WW Simple Cycle Combustion Turbine Aero - Walla Walla
SCCT Frame OR Simple Cycle Combustion Turbine Frame - Oregon
SCCT Frame WW Simple Cycle Combustion Turbine Frame - Walla Walla
Coal Ret_Bridger -Gas RePower Coal Plant conversion to Gas Plant - Jim Bridger
Geothermal, Greenfield Geothermal, Greenfield
Fly Wheel Fly Wheel
Battery Storage Battery Storage
Pump Storage Pump Storage
Utility Solar - PV Utility Solar - Photovoltaic
Micro Solar - PV Micro Solar - Photovoltaic
Micro Solar - Water Heating Micro Solar - Water Heating
OR Solar (Util Cap Standard & Cust Incentive Prgm) OR Solar (Util Cap Standard & Cust Incentive Prgm)
Utility Biomass Utility Biomass
Wind, HM, 29 Wind, Hemmingway, 29% Capacity Factor
Wind, WV, 29 Wind, Willamette Valley, 29% Capacity Factor
CHP - Biomass Combined Heat and Power - Biomass
CHP - Reciprocating Engine Combined Heat and Power - Reciprocating Engine
CHP - Other Combined Heat and Power - Other
DSM, Class 1, CA-Curtail DSM Class 1, Curtailment - California
DSM, Class 1, CA-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - California
DSM, Class 1, CA-DLC-RES DSM Class 1, Direct Load Control-Residential - California
DSM, Class 1, OR-Curtail DSM Class 1, Curtailment - Oregon
DSM, Class 1, OR-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - Oregon
DSM, Class 1, OR-DLC-RES DSM Class 1, Direct Load Control-Residential - Oregon
DSM, Class 1, WA-Curtail DSM Class 1, Curtailment - Washington
DSM, Class 1, WA-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - Washington
DSM, Class 1, WA-DLC-RES DSM Class 1, Direct Load Control-Residential - Washington
DSM, Class 3, CA-TOU-IRR DSM, Class 3, Time of Use, Irrigation - California
DSM, Class 3, CA-TOU-RES DSM, Class 3, Time of Use, Residential - California
DSM, Class 3, OR-TOU-IRR DSM, Class 3, Time of Use, Irrigation - Oregon
DSM, Class 3, OR-TOU-RES DSM, Class 3, Time of Use, Residential - Oregon
DSM, Class 3, WA-TOU-IRR DSM, Class 3, Time of Use, Irrigation - Washington
DSM, Class 3, WA-TOU-RES DSM, Class 3, Time of Use, Residential - Washington
DSM, Class 2, CA DSM, Class 2, California
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

160

Resource List Detailed Description
DSM, Class 2, OR DSM, Class 2, Oregon
DSM, Class 2, WA DSM, Class 2, Washington
FOT COB Flat Front Office Transaction - 3rd Quarter Flat Product - COB
FOT COB Q3 Front Office Transaction - 3rd Quarter HLH Product - COB
FOT Mid Columbia Flat Front Office Transaction - 3rd Quarter Flat Product - Mid Columbia
FOT MidColumbia Q3 Front Office Transaction - 3rd Quarter HLH Product - Mid Columbia
FOT MidColumbia Q3 - 2 Front Office Transaction - 3rd Quarter HLH Product - Mid Columbia
FOT NOB Q3 Front Office Transaction - 3rd Quarter HLH Product - Nevada Oregon Border

PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
161

Table K.5 – Core Case System Optimizer PVRR Results
PVRR for cases under EG2 to EG5 are adjusted for $655 System Operational and Reliability Benefits Tool (SBT) benefit of Segment D
($ millions)
Base, No RPS 30,983 31,237 31,885 31,878 32,506
Base, State RPS 31,504 31,540 32,204 32,171 32,842
Base, State & Federal RPS 31,605 31,583 32,235 32,208 32,866

Base Regional Haze, Low Gas, High CO2 & Coal, No RPS 32,516 32,755 33,360 33,344 33,973
Base Regional Haze, Low Gas, High CO2 & Coal, With RPS 33,136 33,104 33,713 33,675 34,336
Base Regional Haze, High Gas, No CO2, Low Coal, No RPS 27,011 27,269 27,920 27,896 28,553
Base Regional Haze, High Gas, No CO2, Low Coal, With RPS 27,568 27,516 28,181 28,145 28,814
Stringent Regional Haze, Low Gas, High CO2 & Coal, No RPS 32,778 33,039 33,667 33,612 34,266
Stringent Regional Haze, Low Gas, High CO2 & Coal, With RPS 33,365 33,348 33,959 33,926 34,599
Stringent Regional Haze, Med Gas, Med CO2 & Coal, No RPS 31,533 31,772 32,459 32,419 33,075
Stringent Regional Haze, Med Gas, Med CO2 & Coal, With RPS 32,138 32,135 32,760 32,748 33,410
Stringent Regional Haze, High Gas, No CO2, Low Coal, No RPS 27,563 27,818 28,469 28,450 29,095
Stringent Regional Haze, High Gas, No CO2, Low Coal, With RPS 28,121 28,073 28,730 28,699 29,370
Base Regional Haze, Med Gas, U.S. Hard Cap, Med Coal, With RPS 43,141 43,114 43,626 43,653 44,146

No Thermal Base Load 31,425 31,394 32,050 32,016 32,688
Geothermal RPS Strategy 31,581 31,644 32,304 32,274 32,937
Market Price Spike 31,519 31,488 32,239 32,199 32,867
Clean Energy Bookend 48,406 48,173 48,358 48,563 48,799

Energy Gateway Segment D Alternative N/A 31,589 32,281 32,242 32,900

PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

162

Table K.6 – Sensitivity Case – EG2 System Optimizer PVRR Results
PVRR are adjusted for $655 SBT benefit for Segment D ($ millions)
Low Load Forecast 30,656
High Load Forecast 33,129
1 in 20 Load 31,978
PTC/ITC Ext. (No RPS) 31,237
PTC/ITC Ext. (With RPS) 31,485
Endogenous RPS Comp. 31,603
Targeted Renewables 38,996
Class 3 DSM 31,586

The next section of Appendix K provides the detail portfolio tables for each of the System Optimizer Case studies and are divided into
the following sections:

Table K.7 – Energy Gateway Scenario 1 – Case C-01 to C-18
Table K.8 – Energy Gateway Scenario 2 – Case C-01 to C-19
Table K.9 – Energy Gateway Scenario 3 – Case C-01 to C-19
Table K.10 – Energy Gateway Scenario 4 – Case C-01 to C-19
Table K.11 – Energy Gateway Scenario 5 – Case C-01 to C-19
Table K.12 – Sensitivity Cases under Energy Gateway Scenario 2, excluding S-04 and S-X that are included in Confidential Volume III

Note: Front office transaction amounts reported in the portfolios reflect one-year transaction periods, are not additive, and are reported
as a 10/20-year annual average.

PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
163

Table K.7 – Energy Gateway Scenario 1 – Case C-01 to C-18

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - 661 - - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - 181 - - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, UT, 29 - - - - - - - - - - - - - - - 3 - - - - - 3
Total Wind - - - - - - - - - - - - - - - 3 - - - - - 3
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - 9 - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - 85 - - - 7 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 3 - 7 - 4 - 15
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 10 9 - - - 6 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 1 - - - 10 106 - 7 - 18 - 142
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 30 581 937
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 170 263 141 106 221 299 300 40 148 198 299 65 133
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - 1 - - - 1 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 7 44 1 - - - 4 - 55
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 21 23 22 22 22 22 22 22 22 22 23 282 504
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 28 28 27 27 27 28 26 26 26 26 27 360 627
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 83 297 297 297 182 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 100 95 96 96 85 266 743 88 135 924 736 504 74 96
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,342 1,435 1,313 1,278 1,393 1,471 1,472 998 1,320 1,370 1,471
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,431 1,523 1,295 1,438 1,520 1,579 2,021 1,481 1,606 2,396 1,734 1,824 1,444 1,567
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-01
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

164

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
SCCT Frame WYAE - - - - - - - - - - - - - - - - - - 181 - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - 181 - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 29 12 - - 442 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - 3 - - - - - 203
Total Wind - - - 70 47 29 12 - - 442 - 200 - - - 3 - - - - 600 803
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 9 - - - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - 1 - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 7 77 - - - - 3 - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - 4 - - - 3 - - - - 4 - 11
DSM, Class 1, UT-Irrigate - - - - - - - 0 - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 22 - - - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, WY-Irrigate - - - - - - - - - - 0 - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - 1 - - 4 - 31 7 81 - - - - 11 1 135
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 67 61 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 504 762
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 56 126
DSM, Class 2 Total 73 67 61 59 58 57 58 52 52 51 39 42 39 38 37 35 33 32 31 30 590 947
Utility Solar - PV - - - - - - - - - - - - - 28 - - - - - - - 28
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.1 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 33 147 243 14 152 240 263 181 247 298 249 190 294 186 294 59 152
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 15 - - - - - - 0 - 16
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 1 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - 3 8 15 45 1 - - - - 3 - 75
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 26 24 21 20 23 23 22 22 22 22 22 22 22 23 23 286 510
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 69 106
DSM, Class 2 Total 45 49 41 41 38 34 31 28 27 30 28 27 27 28 28 26 26 26 27 27 365 635
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 103 223 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 205 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 188 161 135 116 96 96 540 91 294 790 162 163 997 256 735 256 88
Annual Additions, Short Term Resources 646 705 840 978 1,098 1,205 1,319 1,415 1,186 1,324 1,412 1,435 1,353 1,419 1,470 1,421 1,362 1,466 1,358 1,466
Total Annual Additions 791 1,482 961 1,166 1,259 1,340 1,435 1,511 1,282 1,864 1,503 1,729 2,143 1,581 1,633 2,418 1,618 2,201 1,614 1,554
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-02
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
165

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - - 423 - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame ID - - - - - - - - - - - - - - 181 - - - - - - 181
SCCT Frame WYNE - - - - - - - - - - 181 - - - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - 3 - - - - - 203
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - 3 - - - - 600 803
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 9 - - - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - 1 - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 77 - - - 7 4 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - - 26 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - 0 - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 22 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.1 - - - - 0 - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - 10 77 - - - 7 26 32 - 153
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 56 54 51 49 47 45 40 42 40 30 33 30 28 27 25 23 22 21 20 487 745
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 61 59 57 55 54 49 52 51 39 42 39 38 37 35 33 32 31 30 570 926
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 44 163 263 35 175 114 141 300 300 278 105 204 300 300 300 68 151
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 15 - - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 6 - 6
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - 4 - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 21 - - - - 22 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - 3 - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - 4 - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - 2 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - 26 21 - - - - 24 10 - 82
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 20 20 20 20 22 22 22 19 22 22 22 22 26 279 499
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 27 26 27 25 27 27 27 24 26 26 26 26 30 357 622
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 113 233 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 183 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 213 349 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 334 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 772 121 187 160 133 112 90 95 534 262 709 119 407 258 1,164 76 743 124 210
Annual Additions, Short Term Resources 650 713 849 988 1,108 1,216 1,335 1,435 1,207 1,347 1,286 1,313 1,472 1,472 1,450 1,277 1,376 1,472 1,472 1,472
Total Annual Additions 790 1,485 970 1,175 1,268 1,349 1,447 1,525 1,302 1,881 1,548 2,022 1,591 1,879 1,708 2,441 1,452 2,215 1,596 1,682
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-03
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

166

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - (450) - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 - 661 661 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - 423 423 846 411 - 411 - - - - - - - 1,692 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 55 51 48 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 477 735
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 68 62 58 56 57 55 53 49 50 51 39 42 38 38 37 35 33 32 31 30 560 915
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 182 68 177 - 111 176 224 - 12 34 34 119 40 40 48 98 220 105 85
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 20 19 19 19 22 19 22 22 22 23 275 482
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 66 102
DSM, Class 2 Total 45 49 41 40 38 33 29 26 24 26 25 24 24 24 27 23 26 26 26 27 351 602
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 268 297 297 297 277 297 132 297 297 297 297 297 297 297 249 264
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 59 100 1 100 100 100 100 100 93
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (719) (682) 8 - - - - (434) - (338) (74) -
Annual Additions, Long Term Resources 140 771 117 113 774 103 757 1,175 514 940 492 83 490 78 80 810 75 497 74 74
Annual Additions, Short Term Resources 651 714 1,222 1,354 1,240 1,349 1,143 1,283 1,348 1,396 1,152 1,184 1,041 1,165 1,291 1,113 1,212 1,220 1,270 1,392
Total Annual Additions 791 1,485 1,339 1,467 2,014 1,452 1,900 2,458 1,862 2,336 1,644 1,267 1,531 1,243 1,371 1,923 1,287 1,717 1,344 1,466
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-04
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
167

Resource Totals 1/
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - (450) - - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 - 661 661 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - - - - 736 - - 736
CCCT J 1x1 - - - - - - - 423 423 423 834 - 411 - - 423 - - - - 1,269 2,937
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - - - - - - - 200
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - - - - - - 600 800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - - 3 - 3
DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 3 - 3
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 2 2 28 55
DSM, Class 2, UT 63 55 51 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 20 20 480 738
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 55 123
DSM, Class 2 Total 68 62 58 59 57 55 53 49 50 51 39 42 39 38 37 35 33 32 29 29 564 915
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 178 64 172 - 106 - 162 - - 34 34 81 193 292 300 61 61 79 93
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 36 40 33 32 29 26 22 19 20 19 20 19 19 22 22 22 22 22 18 19 277 483
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 66 103
DSM, Class 2 Total 45 49 41 40 38 33 29 26 26 26 25 24 24 27 27 26 26 26 22 22 353 603
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 263 297 68 297 267 296 119 294 297 297 297 297 - 74 226 225
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 23 100 100 100 100 51 100 100 94
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (269) (682) (442) - - - - (434) - (338) (74) -
Annual Additions, Long Term Resources 140 771 117 187 821 133 770 1,175 516 957 915 283 490 308 80 501 76 497 804 71
Annual Additions, Short Term Resources 651 714 1,222 1,350 1,236 1,344 1,138 1,278 943 1,334 1,142 1,171 1,028 1,126 1,253 1,365 1,464 1,472 887 1,010
Total Annual Additions 791 1,485 1,339 1,537 2,057 1,477 1,908 2,453 1,459 2,291 2,057 1,454 1,518 1,434 1,333 1,866 1,540 1,969 1,691 1,081
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)EG-1 Case C-05
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

168

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
CCCT J 1x1 - - - - - - - - - - - 411 - - 423 846 - - - - - 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, UT, 29 - - - - - - - - - - - - - - - - - - 31 - - 31
Total Wind - - - - - - - - - - - - - - - - - - 31 - - 31
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - 1 - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - - - 47 - 47
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - - 0 - - 0
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 1 48 - 49
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 56 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 494 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 56 126
DSM, Class 2 Total 69 63 61 59 59 57 57 52 52 51 39 42 39 38 37 35 33 32 32 31 581 938
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 42 157 254 25 169 263 - 160 282 68 121 220 256 300 298 65 131
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - - - 16 - 16
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - - 46 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - - - - - 1 1 - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - - 2 - 2
DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 1 73 - 75
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 19 19 22 22 22 22 23 26 26 285 508
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 3 4 3 3 3 71 111
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 25 25 27 28 26 26 27 30 30 365 638
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 134 251 267 297 297 297 297 297 297 297 260 297 297 297 297 297 297 297 297 257 275
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 311 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 318
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 121 118 116 106 103 95 96 95 84 495 80 82 504 924 76 812 112 198
Annual Additions, Short Term Resources 650 713 849 988 1,108 1,214 1,329 1,426 1,197 1,341 1,435 1,135 1,332 1,454 1,240 1,293 1,392 1,428 1,472 1,470
Total Annual Additions 791 1,485 970 1,106 1,224 1,320 1,432 1,521 1,293 1,436 1,519 1,630 1,412 1,536 1,744 2,217 1,468 2,240 1,584 1,668
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-06
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
169

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - - - 661 - - - 661
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - - - - - 423 - - 423 - - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 169 - - - - - - 31 - - 200
Total Wind - - - 70 47 30 13 - - 440 - 169 - - - - - - 31 - 600 800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - 37 15 - - 51
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 37 15 - - 51
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 2 3 3 3 3 3 3 2 27 52
DSM, Class 2, UT 63 56 54 51 50 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 492 751
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 56 125
DSM, Class 2 Total 69 63 61 59 58 56 54 52 51 50 39 41 38 37 37 35 33 32 32 29 574 928
Utility Solar - PV - - - - - - - - - - - - - 247 - - - - - - - 247
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 158 256 28 169 263 - 146 244 40 136 234 290 300 266 65 129
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - 8 - - - 8
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - 21 - - 21
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - 1 - - - 1
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 9 21 - - 30
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 19 22 22 22 23 23 26 26 22 285 513
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 111
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 25 28 28 28 28 28 30 30 26 365 643
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 133 250 271 297 297 297 297 297 297 297 248 297 297 287 297 297 297 297 297 257 274
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 216 309 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 121 188 162 136 113 94 95 534 84 675 82 328 504 815 77 785 145 253
Annual Additions, Short Term Resources 650 712 848 987 1,106 1,213 1,330 1,428 1,200 1,341 1,435 1,123 1,318 1,416 1,202 1,308 1,406 1,462 1,472 1,438
Total Annual Additions 791 1,484 969 1,175 1,268 1,349 1,443 1,522 1,295 1,875 1,519 1,798 1,400 1,744 1,706 2,123 1,483 2,247 1,617 1,691
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-07
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

170

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - (106) - - - - - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 1,322 - - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - 736 - - - - - - - - - - 736 736
CCCT J 1x1 - - - - - - 423 846 - - - - 411 - - 423 - 423 - - 1,269 2,526
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 2 2 2 2 2 27 47
DSM, Class 2, UT 63 55 50 48 45 43 42 39 36 35 27 32 29 27 26 25 23 22 21 20 457 709
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 6 7 7 7 7 7 7 54 120
DSM, Class 2 Total 68 62 58 56 54 52 51 48 45 45 35 40 37 36 35 33 32 30 30 29 538 876
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 184 73 176 132 263 108 - 147 183 43 169 300 40 78 91 144 270 105 126
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - - (74) - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 35 40 33 32 29 26 22 19 17 17 17 17 17 18 18 18 18 19 19 19 271 452
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 64 99
DSM, Class 2 Total 43 48 41 40 37 33 29 25 24 24 22 22 22 23 23 22 22 23 23 22 344 568
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 38 65 342 297 297 297 297 297 297 112 297 297 297 297 297 232 297 297 297 297 234 262
FOT NOB Q3 100 100 100 100 100 100 100 100 100 96 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 151 270 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 346
Existing Plant Retirements/Conversions - - (582) 8 (378) (1,279) (205) (816) (74) (220) (268) - - - - (328) - (338) (74) -
Annual Additions, Long Term Resources 138 770 116 113 770 1,421 517 936 86 821 74 79 486 76 75 918 71 493 69 68
Annual Additions, Short Term Resources 652 716 1,224 1,356 1,245 1,348 1,304 1,435 1,280 983 1,319 1,355 1,215 1,341 1,472 1,147 1,250 1,263 1,316 1,442
Total Annual Additions 790 1,486 1,340 1,469 2,015 2,769 1,821 2,371 1,366 1,804 1,393 1,434 1,701 1,417 1,547 2,065 1,321 1,756 1,385 1,510
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-08
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
171

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - (106) - - - - - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 1,322 - - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
CCCT J 1x1 - - - - - - 423 846 - 423 411 - 411 - - 423 - - - - 1,692 2,937
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - - - - - - - 200
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - - - - - - 600 800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 10 - - - - - - 10
DSM, Class 1 Total - - - - - - - - - - - - - - 10 - - - - - - 10
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 56 54 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 484 742
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 51 39 42 39 38 37 35 33 32 31 30 567 922
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 59 158 112 242 83 68 61 90 34 46 163 181 280 40 61 167 101 106
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - - (74) - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 20 19 19 22 22 22 22 22 22 23 275 489
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 103
DSM, Class 2 Total 45 49 41 41 38 33 29 26 24 26 25 24 24 27 27 26 26 26 26 27 352 610
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 297 297 297 297 210 297 297 297 297 297 295 297 252 270
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 55 87 100 100 97
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (1,279) (205) (816) (74) (220) (268) - - - - (328) - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 187 821 1,455 532 937 91 957 492 283 490 308 90 501 76 810 74 74
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,231 1,330 1,284 1,414 1,255 1,240 1,233 1,262 1,119 1,218 1,335 1,353 1,452 1,167 1,218 1,339
Total Annual Additions 791 1,485 1,339 1,534 2,052 2,785 1,816 2,351 1,346 2,197 1,725 1,545 1,609 1,526 1,425 1,854 1,528 1,977 1,292 1,413
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-09
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

172

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - - - - - - - - - - 423 - - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - 181 - - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - 9 - - - 1 - 9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 7 81 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 11 - 4 - 15
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 10 - - - 2 - 12
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 2 0 - 2
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 8 100 - 11 2 11 - 130
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 56 126
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 30 581 938
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.7 0.9 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 169 263 142 107 213 293 300 51 144 192 300 65 133
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - - - 0 - 8
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - 3 - 46
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 1 1 - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 16 45 1 - - - 3 - 64
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 19 22 22 22 22 22 22 23 23 284 504
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 106
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 24 27 28 28 26 26 26 27 27 361 628
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 105 99 95 96 98 84 264 743 98 134 914 499 746 77 88
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,341 1,435 1,314 1,279 1,385 1,465 1,472 1,223 1,316 1,364 1,472
Total Annual Additions 790 1,485 966 1,101 1,218 1,318 1,430 1,523 1,295 1,439 1,519 1,578 2,022 1,483 1,599 2,386 1,722 2,062 1,441 1,560
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-10
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
173

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - - - - - - - 200
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - - - - - - 600 800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - 9 - - - - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - 1 - - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 7 74 4 4 - - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 22 - - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - 0 - - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - 13 - 10 - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 4 - - - - - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - 0 - 0.1 - - - - - - - - 0
DSM, Class 1 Total - - - - - - 1 - - - 0 9 0 20 95 17 4 - - - 1 146
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 2 2 2 30 56
DSM, Class 2, UT 67 61 54 51 50 51 48 43 42 40 30 33 30 28 27 25 23 21 21 20 507 765
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 7 56 125
DSM, Class 2 Total 73 67 61 59 58 61 58 52 52 51 39 42 39 38 37 35 33 30 30 29 593 946
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.7 0.9 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 30 143 238 10 147 241 253 217 251 288 221 300 61 115 241 57 138
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - 15 - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 - 1 - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - 11 - 45 - 1 15 - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 26 24 23 20 23 23 22 22 22 22 22 22 18 18 18 289 500
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 69 106
DSM, Class 2 Total 45 49 41 41 38 34 32 30 27 30 28 27 27 28 28 26 26 22 22 22 367 624
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 103 223 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 205 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 188 162 139 119 97 95 538 84 306 743 374 177 1,013 95 1,153 68 68
Annual Additions, Short Term Resources 646 705 840 978 1,098 1,202 1,315 1,410 1,182 1,319 1,413 1,425 1,389 1,423 1,460 1,393 1,472 1,233 1,287 1,413
Total Annual Additions 791 1,482 961 1,166 1,260 1,341 1,434 1,507 1,277 1,857 1,497 1,731 2,132 1,797 1,637 2,406 1,567 2,386 1,355 1,481
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-11
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

174

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - - - - - - - 661
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 846 - - - 1,692
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - - 9 - 9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - - 41 43 - 84
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 19 - - 2 - 21
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - 0 - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - - 19 - 41 59 - 119
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 56 54 51 50 48 48 43 42 40 30 33 30 28 27 25 24 22 21 20 495 755
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 56 127
DSM, Class 2 Total 69 63 61 59 59 57 57 52 52 51 39 42 39 38 37 35 34 32 32 31 581 941
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 42 157 253 25 168 263 - 40 40 172 223 300 280 286 300 65 127
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - - 46 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - - 1 - - - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - 1 - - - 47 - 48
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 22 22 22 23 23 26 25 26 26 285 522
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 112
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 28 28 28 29 28 30 29 30 30 365 653
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 134 251 267 297 297 297 297 297 297 297 22 177 297 297 297 297 297 297 297 257 257
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 311 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 318
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 121 118 116 106 104 95 96 95 84 748 83 83 83 927 100 924 119 183
Annual Additions, Short Term Resources 650 713 849 988 1,108 1,214 1,329 1,425 1,197 1,340 1,435 897 1,092 1,212 1,344 1,395 1,472 1,452 1,458 1,472
Total Annual Additions 791 1,485 970 1,106 1,224 1,320 1,433 1,520 1,293 1,435 1,519 1,645 1,175 1,295 1,427 2,322 1,572 2,376 1,577 1,655
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-12
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
175

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - - - 661 - - - 661
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - - - - - 423 - - 423 - - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - - - - - - - 200
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - - - - - - 600 800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - 37 4 - - 40
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 37 4 - - 40
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 2 2 3 2 3 3 3 2 27 50
DSM, Class 2, UT 63 56 54 51 50 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 492 751
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 56 125
DSM, Class 2 Total 69 63 61 59 58 56 54 52 51 50 39 41 38 36 36 34 33 32 32 29 574 925
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 158 256 28 169 263 - 149 249 40 143 242 300 300 265 65 130
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - 8 - - - 8
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - 44 - - 44
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 8 44 - - 51
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 19 19 22 22 22 22 23 26 22 285 505
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 111
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 25 25 27 27 27 26 27 30 26 365 634
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 133 250 271 297 297 297 297 297 297 297 248 297 297 293 297 297 297 297 297 257 274
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 216 309 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 121 188 162 136 113 94 95 534 84 706 79 308 503 814 76 781 125 253
Annual Additions, Short Term Resources 650 712 848 987 1,106 1,213 1,330 1,428 1,200 1,341 1,435 1,123 1,321 1,421 1,208 1,315 1,414 1,472 1,472 1,437
Total Annual Additions 791 1,484 969 1,175 1,268 1,349 1,443 1,522 1,295 1,875 1,519 1,829 1,400 1,729 1,711 2,129 1,490 2,253 1,597 1,690
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-13
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

176

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - (416) - - - - - - - - - - - (416) (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - (269) - - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - - - - - (459) - - - - - - - (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - - (450) - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - (205) - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - - - 661 - - - 661
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 368 - 368
CCCT GH 2x1 - - - - - - - - 736 - - - 736 - - - - - - - 736 1,472
CCCT J 1x1 - - - - - - 423 1,269 - - 423 411 - - - 846 - - - - 1,692 3,372
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - 3 - - - - - 203
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - 3 - - - - 600 803
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 6 6 6 3 3 3 3 3 1 1 1 2 1 1 1 1 1 1 46 59
DSM, Class 2, UT 84 76 75 73 73 50 47 41 41 39 14 13 11 11 10 13 11 9 8 7 599 707
DSM, Class 2, WY 24 24 24 24 25 3 3 3 3 2 2 2 1 2 2 2 2 1 1 1 136 153
DSM, Class 2 Total 114 106 105 103 104 56 54 47 47 45 17 17 13 14 13 17 14 12 11 10 781 919
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.2 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 53 159 - 102 - 68 61 173 40 53 80 150 267 69 138 61 38 74
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - (363) - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - - 362 - - - - - - - - - 719 1,081
Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 1 1 0 0 15 20
DSM, Class 2, OR 37 41 34 33 31 28 24 23 21 21 21 20 21 20 20 20 21 20 20 20 293 498
DSM, Class 2, WA 13 12 13 14 14 6 6 6 6 6 2 2 2 2 2 2 2 1 1 1 97 114
DSM, Class 2 Total 52 55 49 49 47 35 31 30 28 28 23 22 23 23 23 23 23 22 22 22 405 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - 54 23 77 297 297 292 297 220 297 297 297 6 174 297 297 297 297 297 206 185 216
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 107 75 200 236 375 375 309 375 375 375 375 375 375 375 375 375 375 375 375 375 280 328
Existing Plant Retirements/Conversions - - (164) 8 (378) - - (1,258) (779) - (261) (450) - (459) - (760) - (338) (74) -
Annual Additions, Long Term Resources 193 822 173 240 216 137 535 1,360 827 529 480 667 789 704 53 906 54 712 50 416
Annual Additions, Short Term Resources 607 629 723 813 1,225 1,331 1,101 1,274 1,095 1,240 1,233 1,345 921 1,102 1,252 1,322 1,439 1,241 1,310 1,142
Total Annual Additions 800 1,451 896 1,053 1,441 1,468 1,636 2,634 1,922 1,769 1,713 2,012 1,710 1,806 1,305 2,228 1,493 1,953 1,360 1,558
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-14
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
177

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero WYAE - - - - - - - - - - - - - - - 182 - - - - - 182
IC Aero WYNE - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame UT - - - - - - - - - - - - - - 181 362 - 362 - - - 905
SCCT Frame ID - - - - - - 181 - - - - - - - - - - - - - 181 181
SCCT Frame WYAE - - - - - - - - - - - - - - - 181 - - - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - 181 - - - - - 181
SCCT Frame WYSW - - - - - - - - - - - - 172 - - - 172 - 172 - - 516
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - 3 - - - - - 203
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - 3 - - - - 600 803
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - 9 - - - - - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - 7 41 37 - - - - 4 - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - 7 - - - - - - 14 - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - 19 - - - - - 3 - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.1 0.1 - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - 25 60 37 - - - - 21 - - - 142
DSM, Class 2, ID 6 6 6 6 6 2 2 1 3 3 1 1 1 1 1 1 1 1 1 1 40 52
DSM, Class 2, UT 81 74 68 65 69 45 43 37 39 37 12 11 9 10 9 11 10 9 7 6 558 652
DSM, Class 2, WY 23 23 23 24 24 2 2 2 2 2 2 2 1 2 1 2 2 1 1 1 129 145
DSM, Class 2 Total 111 103 97 95 98 49 46 41 44 42 16 14 12 12 12 14 13 11 10 9 726 849
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.1 1.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 95 208 176 263 45 198 263 263 300 267 265 246 215 300 257 257 99 181
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - 197 - - - - - - - 197
SCCT Frame OR - - - - - - - - - - - - - - - - - 362 - - - 362
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, OR-Curtail - - - - - - - 21 - - 22 - - - - - - - - - 21 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1 Total - - - - - - - 21 - - 25 - - - - - - - - - 21 47
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 0 0 0 0 0 0 0 13 15
DSM, Class 2, OR 36 41 33 32 29 26 22 19 17 17 18 17 17 17 17 17 17 17 17 17 274 443
DSM, Class 2, WA 13 12 12 12 12 5 5 5 5 5 2 1 1 1 1 1 1 1 1 1 86 96
DSM, Class 2 Total 51 55 47 46 43 32 28 24 23 23 20 19 19 18 18 18 18 18 18 18 373 554
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - - 297 297 297 297 297 297 297 297 297 297 297 297 297 262 229 297 178 232
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 135 160 262 400 400 400 400 400 400 400 400 400 400 387 400 397 400 400 400 400 336 367
FOT MidColumbia Q3 - 2 375 375 375 345 375 375 375 375 375 375 375 375 375 375 368 375 375 375 375 375 372 373
Existing Plant Retirements/Conversions - - (164) - (387) - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 188 818 163 228 207 126 284 101 83 522 102 310 256 471 227 958 219 791 216 134
Annual Additions, Short Term Resources 610 635 737 845 1,267 1,380 1,348 1,435 1,217 1,370 1,435 1,435 1,472 1,426 1,430 1,415 1,387 1,437 1,361 1,429
Total Annual Additions 798 1,453 900 1,073 1,474 1,506 1,632 1,536 1,300 1,892 1,537 1,745 1,728 1,897 1,657 2,373 1,606 2,228 1,577 1,563
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-15
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

178

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - 181 - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - - - 115 - - - - - - - 115
Wind, GO, 29 - - - - 19 9 56 50 - 466 - - - - - - - - - - 600 600
Total Wind - - - - 19 9 56 50 - 466 - - - - - - - - - - 600 600
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 77 4 - - - 3 - 84
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 15 7 - - 4 - 26
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 22 - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - 2 2 - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 0 - - 77 41 8 2 - 11 - 140
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 29 57
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 56 54 52 52 51 39 42 39 38 37 35 33 32 31 30 579 936
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.7 0.9 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 18 136 233 5 143 237 263 228 243 253 266 198 142 192 300 54 143
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - 25 - - - - - - - - - 5 - - - - - - 25 30
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - 3 - 46
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 8 - - 46 - - - - 3 - 57
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 22 22 22 23 23 284 507
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 106
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 27 28 26 26 26 27 27 361 631
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 87 208 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 178 238
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 142 132 114 154 145 95 563 84 95 743 201 204 965 265 918 75 88
Annual Additions, Short Term Resources 650 709 845 962 1,083 1,190 1,308 1,405 1,177 1,315 1,409 1,435 1,400 1,415 1,425 1,438 1,370 1,314 1,364 1,472
Total Annual Additions 790 1,485 966 1,104 1,215 1,304 1,462 1,550 1,272 1,878 1,493 1,530 2,143 1,616 1,629 2,403 1,635 2,232 1,439 1,560
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-16
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
179

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - - - - - - - 423 - - 423 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 440 - - - - - - - - - - 600 600
Wind, UT, 29 - - - - - - - - - - - 200 - - - 3 - - - - - 203
Total Wind - - - 70 47 30 13 - - 440 - 200 - - - 3 - - - - 600 803
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - 9 - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - 4 4 84 - 91
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 9 10 - 2 - 21
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 4 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - 0 - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 1 0 - 9 22 7 87 - 128
DSM, Class 2, ID 3 3 3 4 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 61
DSM, Class 2, UT 68 61 57 55 53 51 48 44 44 42 31 34 31 29 28 27 25 23 22 21 523 793
DSM, Class 2, WY 4 4 5 5 6 7 7 7 7 8 7 7 7 7 8 7 7 7 8 8 60 133
DSM, Class 2 Total 74 68 64 64 63 62 59 55 55 53 41 43 40 40 39 37 35 33 32 32 616 987
Utility Solar - PV - - - - - - - - - - - - - 227 - - - - - - - 227
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 70 - - 44 92 279 53 145 246 53 273 273 300 7 91
West Expansion Resources
CCCT GH 1x1 - - - - 420 - - - - - - - - - - - - - - - 420 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, WV, 29 - - - - - - - - - - - - - - - - - - - 42 - 42
Total Wind - - - - - - - - - - - - - - - - - - - 42 - 42
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - 44 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - - - - 3 - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - 2 - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 9 44 3 - 55
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 21
DSM, Class 2, OR 37 41 34 34 33 31 28 24 24 26 26 26 26 26 26 26 26 26 26 26 312 568
DSM, Class 2, WA 8 8 8 8 8 7 7 7 7 7 5 5 5 5 5 4 4 3 3 3 74 118
DSM, Class 2 Total 46 50 43 43 42 39 36 32 32 34 32 32 31 32 32 30 30 30 30 30 397 707
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 163 125 239 292 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 260 279
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 383 400 400 400 331 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 391 396
FOT MidColumbia Q3 - 2 - 79 97 177 - 30 141 165 3 137 183 163 168 141 177 180 112 186 181 183 83 125
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 146 778 125 195 591 145 122 101 103 544 90 292 88 739 87 823 514 534 130 210
Annual Additions, Short Term Resources 646 704 836 969 728 827 938 1,032 800 934 1,024 1,052 1,244 991 1,119 1,223 962 1,256 1,251 1,280
Total Annual Additions 792 1,482 961 1,164 1,319 972 1,060 1,133 903 1,478 1,114 1,344 1,332 1,730 1,206 2,046 1,476 1,790 1,381 1,490
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-1 Case C-17
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

180

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - - - - - - (416) - - - - - - - (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - (269) - - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - - - - - - (479) - - - - - - - - (479)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - - - - - - (205) - - - - - - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - - - (268) - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT J 1x1 - - - - - - - 423 - - - - - - - 846 423 423 - - 423 2,115
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Nuclear - - - - - - - - - - - - 2,236 - - - - - - - - 2,236
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - 105 - - - - - - - - - 105
Wind, GO, 29 - - - - - - - - - 211 212 63 65 49 - - - - - - 211 600
Wind, UT, 29 - - - - - - - - - - 200 - - - - - - - - - - 200
Total Wind - - - - - - - - - 211 412 63 65 49 - - - - - - 211 800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - - 2 - 2
DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 2 - 2
DSM, Class 2, ID 6 6 8 8 7 3 3 3 3 3 1 1 1 2 2 2 1 1 1 1 51 65
DSM, Class 2, UT 88 81 77 81 80 51 49 43 42 40 14 13 11 12 10 14 11 10 9 8 633 744
DSM, Class 2, WY 25 25 25 26 26 3 3 3 3 3 3 2 2 2 2 2 2 2 1 1 141 159
DSM, Class 2 Total 120 112 109 115 114 58 55 48 48 46 18 17 13 15 14 17 15 13 12 10 824 967
Utility Solar - PV - - - - - - - - - - - - - 450 - - - - - - - 450
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.4 13.4 13.4 131 263
Micro Solar - Water Heating - - - 0.4 0.3 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - - - - 41 - - 53 82 212 53 53 77 217 - 39
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
Colstrip3 (Early Retirement/Conversion)- - - - - - - - - - - - (74) - - - - - - - - (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - - - - - - - - - (74) - - - - - (74)
Coal Ret_Bridger -Gas RePower - - - - - - - - - - 362 - - - - - - - - - - 362
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - - - - - - - - - 30 - - - - - - - - - 30
Wind, WV, 29 - - - - - - - - - - - - - - - 300 - - - - - 300
Total Wind - - - - - - - - - - - - - - - 300 - - - - - 300
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 1 0 0 1 1 1 1 1 1 0 16 22
DSM, Class 2, OR 41 44 40 38 34 31 28 25 23 23 22 21 21 21 21 21 21 21 21 21 327 536
DSM, Class 2, WA 14 14 14 14 14 7 7 6 6 6 2 2 2 3 3 3 2 2 2 2 104 126
DSM, Class 2 Total 57 60 56 55 51 38 36 33 30 30 25 24 24 24 24 24 24 23 23 23 447 684
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 99 33 - 83 113 201 297 83 - 5 297 274 - 174 297 297 226 253 297 297 91 166
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 - 81 201 206 240 255 271 375 233 375 375 375 210 375 375 375 375 375 375 375 224 291
Existing Plant Retirements/Conversions - - (164) - - - - (158) - - (261) - (1,413) (416) - (834) - (338) (74) -
Annual Additions, Long Term Resources 203 832 183 187 183 111 106 519 95 304 471 255 2,355 555 54 1,204 478 476 52 53
Annual Additions, Short Term Resources 599 614 701 789 853 956 1,068 958 733 880 1,213 1,149 710 1,102 1,254 1,384 1,154 1,181 1,249 1,389
Total Annual Additions 802 1,446 884 976 1,036 1,067 1,174 1,477 828 1,184 1,684 1,404 3,065 1,657 1,308 2,588 1,632 1,657 1,301 1,442
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-1 Case C-18 Capacity (MW)Resource Totals 1/
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
181

Table K.8 – Energy Gateway Scenario 2 – Case C-01 to C-19

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Total Wind - - - - - - - - - - - - - - - - - - - 22 - 22
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 3.6 7.6
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - 9 - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 44 - - 4 - - 43 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - - 26 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 22 - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 0 - - 46 - - 35 - - 76 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 31 581 937
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 169 263 67 262 282 68 242 298 245 295 300 65 149
West Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - 423 - - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - 8 - - 8 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 11 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - - 14 - 14
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 2 - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 57 - - 8 - - 37 - 101
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 22 22 22 22 26 284 509
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 106
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 27 26 26 26 26 30 361 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 100 95 96 97 84 747 82 184 504 739 118 916 74 213
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,341 1,435 1,239 1,434 1,454 1,240 1,414 1,470 1,417 1,467 1,472
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,431 1,523 1,295 1,438 1,519 1,986 1,516 1,638 1,744 2,153 1,588 2,333 1,541 1,685
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-01
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

182

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - 91 - - - 91
SCCT Frame UT - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 46 29 13 - - 44 - - - - - - - - - - 202 202
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - - 544 - - - - - - - - 544
Total Wind - - - 70 46 29 13 - - 44 - - 544 - - - - - - 22 202 768
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - 9 - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 7 - 81 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 19 - - 3 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 22 - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 4 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 9 - 131 - - 7 11 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 30 581 938
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 157 254 26 169 263 67 258 300 256 299 240 266 299 242 65 157
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - - - - - - - - - 203 - 181 - - - - 384
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - 6 6 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 - 1 - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 71 - 1 - - 7 9 - 88
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 21 23 22 22 22 22 22 22 22 26 26 281 510
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 106
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 27 28 27 27 28 28 26 26 26 30 30 359 634
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 187 159 133 113 95 96 139 84 747 626 162 284 870 256 826 91 299
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,211 1,329 1,426 1,198 1,341 1,435 1,239 1,430 1,472 1,428 1,471 1,412 1,438 1,471 1,414
Total Annual Additions 790 1,485 966 1,171 1,263 1,344 1,442 1,521 1,294 1,480 1,519 1,986 2,056 1,634 1,712 2,341 1,668 2,264 1,562 1,713
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-02
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
183

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - 661 - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - 181 - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - 9 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 37 - - - - - 54 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - - 26 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 22 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 1 - - 37 - - - - 31 87 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 47 45 43 42 40 30 33 30 28 27 25 23 22 21 20 494 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 55 55 52 52 51 39 42 39 38 37 35 33 32 31 30 580 936
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 40 158 255 27 170 263 64 258 300 278 105 204 300 297 179 65 145
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - - - - - - - 197 - 197
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - 8 - 0 - 16
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 21 - - - - 22 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 2 - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 42 - - - 8 22 3 - 75
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 20 23 22 22 22 19 22 22 22 22 26 280 502
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 26 27 28 27 27 28 24 26 26 26 26 30 358 625
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 375 400 399
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 147 136 114 95 95 140 90 1,115 364 161 258 1,161 75 743 127 386
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,212 1,330 1,427 1,199 1,342 1,435 1,236 1,430 1,472 1,450 1,277 1,376 1,472 1,469 1,326
Total Annual Additions 790 1,485 966 1,174 1,251 1,348 1,444 1,522 1,294 1,482 1,525 2,351 1,794 1,633 1,708 2,438 1,451 2,215 1,596 1,712
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-03
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

184

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - (450) - - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 - 661 661 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - 736 - - - - - - - 736
CCCT J 1x1 - - - - - - - 423 - 846 411 - - - - 423 - 423 - - 1,269 2,526
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 2 2 2 2 2 27 47
DSM, Class 2, UT 63 55 50 47 45 43 41 36 36 35 27 26 29 27 26 25 23 22 21 20 452 698
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 6 7 7 7 7 7 7 54 121
DSM, Class 2 Total 68 62 58 55 54 52 49 45 45 45 35 34 37 36 35 33 32 31 30 29 533 865
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 187 76 189 - 131 149 203 17 63 255 38 40 40 91 104 157 282 105 107
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - - - 423 - - - - - - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 35 38 33 32 29 26 22 19 17 17 17 17 17 18 18 18 18 18 19 19 268 449
DSM, Class 2, WA 7 7 7 7 7 5 6 6 6 6 4 4 4 4 4 3 3 3 3 3 62 98
DSM, Class 2 Total 43 46 40 40 37 32 28 25 24 24 22 22 22 23 23 22 22 22 22 22 340 564
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 38 66 342 297 297 297 284 297 297 297 297 292 297 - 206 245 297 297 297 297 251 252
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 23 100 100 100 100 100 100 96
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 152 272 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 346
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (269) (682) (442) - - - - (434) - (338) (74) -
Annual Additions, Long Term Resources 138 768 116 112 770 98 753 1,171 86 931 908 72 75 812 75 495 71 492 69 68
Annual Additions, Short Term Resources 652 718 1,226 1,359 1,248 1,361 1,159 1,303 1,321 1,375 1,189 1,230 1,427 913 1,044 1,160 1,263 1,276 1,329 1,454
Total Annual Additions 790 1,486 1,342 1,471 2,018 1,459 1,912 2,474 1,407 2,306 2,097 1,302 1,502 1,725 1,119 1,655 1,334 1,768 1,398 1,522
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-04
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
185

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - (450) - - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 - 661 661 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
CCCT J 1x1 - - - - - - - 423 - 846 822 - - - - 423 - - - - 1,269 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 14 - - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 14 - - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 2 2 2 2 2 27 47
DSM, Class 2, UT 63 55 50 47 45 43 41 36 36 35 26 26 23 27 26 25 23 22 21 20 452 691
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 6 7 7 7 7 7 7 54 121
DSM, Class 2 Total 68 62 58 55 54 52 49 45 45 45 34 34 31 36 35 33 31 30 30 29 533 858
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 186 75 188 - 130 147 202 25 63 40 43 175 40 45 114 167 293 104 102
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 35 38 33 32 29 26 22 19 17 17 17 17 17 16 18 18 18 18 19 19 268 447
DSM, Class 2, WA 7 7 7 7 7 5 6 6 6 6 4 4 4 4 4 3 3 3 3 3 62 98
DSM, Class 2 Total 43 46 40 40 37 32 28 25 24 24 22 22 22 21 23 22 22 22 22 22 340 561
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 38 66 342 297 297 297 283 297 297 297 297 297 174 297 297 - 7 297 297 297 251 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 8 100 100 100 100 100 95
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 152 272 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 346
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (269) (682) (442) - - - - (434) - (338) (74) -
Annual Additions, Long Term Resources 138 768 116 185 805 132 767 1,171 86 977 901 504 710 74 75 1,231 70 69 69 68
Annual Additions, Short Term Resources 652 718 1,226 1,358 1,247 1,360 1,158 1,302 1,319 1,374 1,197 1,235 1,089 1,215 1,347 823 927 1,286 1,339 1,465
Total Annual Additions 790 1,486 1,342 1,543 2,052 1,492 1,925 2,473 1,405 2,351 2,098 1,739 1,799 1,289 1,422 2,054 997 1,355 1,408 1,533
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-05
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

186

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - - - - - - - 661
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 834 - - - 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - 9 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - 1 - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - - 44 47 - 91
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - 0 - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 10 2 - 12
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - 1 - - - - - 63 50 - 114
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 31 59
DSM, Class 2, UT 67 61 54 52 50 48 48 43 42 40 30 33 30 28 27 26 24 22 21 20 505 765
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 8 56 128
DSM, Class 2 Total 73 67 61 60 59 57 58 53 52 51 39 43 39 38 37 36 34 32 32 31 592 953
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 33 147 243 13 154 249 - 40 40 155 204 300 292 276 299 59 122
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - - 46 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - - 3 - - - - - 3
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - 3 - - - 47 - 49
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 23 23 23 22 23 23 23 23 26 23 26 26 291 529
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 113
DSM, Class 2 Total 45 49 42 41 38 35 32 28 30 30 29 28 29 29 29 28 30 27 30 30 372 660
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 243 258 297 297 297 297 297 297 297 7 160 280 297 297 297 297 297 297 254 253
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 302 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 116 107 105 96 99 98 85 748 86 84 83 929 80 910 141 174
Annual Additions, Short Term Resources 646 705 841 979 1,099 1,205 1,319 1,415 1,185 1,326 1,421 882 1,075 1,195 1,327 1,376 1,472 1,464 1,448 1,471
Total Annual Additions 791 1,482 962 1,098 1,215 1,312 1,424 1,511 1,284 1,424 1,506 1,630 1,161 1,279 1,410 2,305 1,552 2,374 1,589 1,645
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-06
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
187

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - - - - 423 - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - - - - - - 181 - 181
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 14 - - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 14 - - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - 9 - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 11 77 - - - - - 88
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 22 - - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 12 108 - - - - - 121
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 31 59
DSM, Class 2, UT 63 61 54 52 50 48 48 43 42 40 30 33 30 28 27 25 24 22 21 20 500 759
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 7 56 126
DSM, Class 2 Total 69 67 61 60 59 57 58 52 52 51 39 42 39 38 37 35 34 32 31 30 587 944
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 36 150 246 18 159 253 - 131 252 299 204 300 59 109 74 61 115
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - 15 - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 72 - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 23 23 22 22 23 23 26 26 19 22 22 288 516
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 112
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 30 28 28 28 29 29 30 30 23 26 26 368 646
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 130 247 268 297 297 297 297 297 297 297 235 297 297 297 297 297 297 297 297 256 273
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 214 305 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 777 121 191 151 140 118 95 96 144 90 942 301 84 168 1,032 80 1,155 73 254
Annual Additions, Short Term Resources 650 709 845 982 1,102 1,208 1,322 1,418 1,190 1,331 1,425 1,110 1,303 1,424 1,471 1,376 1,472 1,231 1,281 1,246
Total Annual Additions 791 1,486 966 1,173 1,253 1,348 1,440 1,513 1,286 1,475 1,515 2,052 1,604 1,508 1,639 2,408 1,552 2,386 1,354 1,500
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-07
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

188

Preferred Portfolio Capacity (MW)Resource Totals 1/
(EG-2 Case-07a)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - - - - 423 - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - - - - - - 181 - 181
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - - - - - - - - - 432 218 - - - - - - - - 650
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - 88 - - - - 88
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 3 19 - - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 14 19 88 - - - - 121
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 31 59
DSM, Class 2, UT 63 61 54 52 50 48 48 43 42 40 30 33 30 28 27 26 24 22 21 20 500 760
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 7 56 127
DSM, Class 2 Total 69 67 61 60 59 57 58 52 52 51 39 42 39 38 37 36 34 32 31 30 587 946
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 37 151 248 19 161 255 - 132 253 297 292 300 59 109 74 62 119
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - 15 - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 72 - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 23 23 22 22 23 26 26 24 19 22 22 288 517
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 112
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 30 28 28 28 29 32 30 29 23 26 26 368 647
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 130 247 262 297 297 297 297 297 297 297 237 297 297 297 297 297 297 297 297 255 273
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 305 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 777 121 119 116 106 104 95 96 98 84 942 302 84 171 944 167 1,155 73 254
Annual Additions, Short Term Resources 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
Total Annual Additions 791 1,486 966 1,102 1,218 1,315 1,427 1,515 1,287 1,431 1,511 2,054 1,606 1,509 1,640 2,408 1,639 2,386 1,354 1,500
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
189

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT F 2x1 - - - - - - - - - - - - - 634 - - - - - - - 634
CCCT FD 2x1 - - - - 661 1,322 - - - - - - - - - - - - - - 1,983 1,983
CCCT J 1x1 - - - - - - 423 846 411 411 - - - - - 423 - 423 - - 2,091 2,937
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 56 54 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 484 742
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 51 39 42 39 38 37 35 33 32 31 30 567 922
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 60 65 85 215 - - - 13 207 34 33 40 119 127 177 299 71 88
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 20 19 20 19 19 19 22 22 22 22 22 23 277 488
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 103
DSM, Class 2 Total 45 49 41 41 38 33 29 26 26 26 25 24 24 24 27 26 26 26 26 27 354 609
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 144 48 278 297 297 145 272 297 297 297 297 297 212 245
FOT NOB Q3 100 100 100 100 100 100 100 100 100 - 100 100 100 - - 80 100 100 100 100 90 84
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (1,173) (279) (816) (220) - (268) - - - - (434) - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 117 774 1,425 519 937 504 505 81 83 79 712 80 501 76 497 74 74
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,232 1,237 1,257 1,387 1,019 823 1,153 1,185 1,379 954 1,080 1,192 1,291 1,299 1,349 1,471
Total Annual Additions 791 1,485 1,339 1,464 2,006 2,662 1,776 2,324 1,523 1,328 1,234 1,268 1,458 1,666 1,160 1,693 1,367 1,796 1,423 1,545
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-08
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

190

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - (459) - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_UT - Gas RePower - - - - - - 468 - - - - - - - - - - - - - 468 468
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 661 661 - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
CCCT J 1x1 - - - - - - - 834 411 - 423 - 423 - - 423 - - - - 1,245 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 14 - - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 14 - - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 56 54 51 49 47 44 40 40 39 30 33 30 28 27 25 23 22 21 20 482 741
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 50 39 42 39 38 37 35 33 32 31 30 566 921
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 60 231 17 157 80 221 205 234 79 40 40 40 45 40 61 61 105 95
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 18 19 20 19 19 19 22 19 22 22 22 23 276 483
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 103
DSM, Class 2 Total 45 49 41 41 38 33 29 26 24 26 25 24 24 24 27 23 26 26 26 27 352 604
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 297 297 297 297 297 114 240 64 158 - - 29 252 201
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 - 7 100 100 90
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 354 375 375 316 344
Existing Plant Retirements/Conversions - - (582) 8 (378) (714) (270) (816) (548) - (268) - - - - (106) - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 190 809 798 771 925 502 139 509 515 720 501 80 497 76 810 74 74
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,232 1,403 1,189 1,329 1,252 1,393 1,377 1,406 1,251 1,029 1,155 979 1,078 794 843 965
Total Annual Additions 791 1,485 1,339 1,537 2,041 2,201 1,960 2,254 1,754 1,532 1,886 1,921 1,971 1,530 1,235 1,476 1,154 1,604 917 1,039
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-09
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
191

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 368 - 368
CCCT J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
ICE - - - - - - - - - - - - - - - - 103 - - - - 103
IC Aero UT - - - - - - - - - - - - - 91 - - - - - - - 91
SCCT Frame UT - - - - - - - - - - - - - - - - - 181 - - - 181
SCCT Frame ID - - - - - - - - - - - - - - 181 - - - - - - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 172 - - - - - 172
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.7 0.4 0.4 0.7 2.6 0.7 0.4 3.6 10.3
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 4 - - - - - - - - 4
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 85 - - - - 4 - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 19 - - - 3 - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 13 10 - - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - 4 - - - - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 102 32 - - - 7 - 10 - 152
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 3 3 3 3 3 3 3 2 31 58
DSM, Class 2, UT 67 61 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 504 763
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 7 7 8 7 7 7 7 8 56 128
DSM, Class 2 Total 73 67 61 59 58 57 58 52 52 51 40 43 39 38 37 35 33 32 31 30 591 950
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 34 148 244 14 155 249 263 296 298 273 298 298 232 279 300 60 169
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Other - - - - - - - - - - - - - - - - - 0.3 - - - 0.3
DSM, Class 1, WA-Curtail - - - - - - - - - - - 8 8 - - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - 6 - - 6 - - - - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 44 - - - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - 1 - - - - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - 2 - - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 19 53 7 - - 6 - - 3 - 87
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 26 24 22 23 23 23 22 24 26 22 22 26 26 26 26 290 532
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 5 5 4 3 4 3 3 3 69 109
DSM, Class 2 Total 45 49 41 41 38 34 31 29 30 30 28 27 30 32 28 26 30 30 30 30 368 659
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 104 224 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 205 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 118 115 105 105 96 99 98 85 107 664 217 263 911 189 930 78 457
Annual Additions, Short Term Resources 646 705 840 979 1,099 1,206 1,320 1,416 1,186 1,327 1,421 1,435 1,468 1,470 1,445 1,470 1,470 1,404 1,451 1,472
Total Annual Additions 791 1,482 961 1,097 1,214 1,311 1,425 1,512 1,285 1,425 1,506 1,542 2,132 1,687 1,708 2,381 1,659 2,334 1,529 1,929
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-10
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

192

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - 661 661 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - - - - - 181 - - 181
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 14 - - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 14 - - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - 9 - - - - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 4 74 - - - - - - - 77
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - 10 - - - - - - - - - 10
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 20 4 74 - - - - - - - 97
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 2 2 2 3 2 2 30 54
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 26 25 23 22 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 55 123
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 35 34 32 32 30 29 581 930
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 157 254 26 168 261 263 296 300 40 42 144 251 147 273 64 133
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 1 1 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1 Total - - - - - - - - - - 1 10 - 44 - - - - - - - 55
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 17
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 21 23 22 22 22 18 18 19 19 18 18 282 483
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 104
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 28 28 27 27 28 23 22 23 23 22 22 359 604
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 122 297 297 297 297 297 182 231
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 148 138 114 95 96 142 91 548 485 199 736 733 71 732 249 68
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,211 1,329 1,426 1,198 1,340 1,433 1,435 1,468 1,472 1,037 1,214 1,316 1,423 1,319 1,445
Total Annual Additions 790 1,485 966 1,174 1,252 1,349 1,443 1,521 1,294 1,482 1,524 1,983 1,953 1,671 1,773 1,947 1,387 2,155 1,568 1,513
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-11
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
193

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - - - - - - - 661
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 834 - - - 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - 9 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - - 37 47 - 84
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 19 2 - 21
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - - - - - 65 50 - 116
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 31 59
DSM, Class 2, UT 67 61 54 52 50 48 48 43 42 40 30 33 30 28 27 26 24 22 21 20 505 765
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 8 56 128
DSM, Class 2 Total 73 67 61 60 59 57 58 53 52 51 39 43 39 38 37 36 34 32 32 31 592 953
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 33 147 243 13 154 249 - 40 40 155 204 300 292 274 297 59 122
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - - 46 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - - 3 - - - - - 3
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - 3 - - - 47 - 49
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 23 23 23 22 23 23 23 23 26 23 26 26 291 529
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 113
DSM, Class 2 Total 45 49 42 41 38 35 32 28 30 30 29 28 29 29 29 28 30 27 30 30 372 660
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 243 258 297 297 297 297 297 297 297 6 160 280 297 297 297 297 297 297 254 253
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 302 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 116 107 105 96 99 98 85 749 85 84 83 929 80 910 143 174
Annual Additions, Short Term Resources 646 705 841 979 1,099 1,205 1,319 1,415 1,185 1,326 1,421 881 1,075 1,195 1,327 1,376 1,472 1,464 1,446 1,469
Total Annual Additions 791 1,482 962 1,098 1,215 1,312 1,424 1,511 1,284 1,424 1,506 1,630 1,160 1,279 1,410 2,305 1,552 2,374 1,589 1,643
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-12
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

194

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame WYNE - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 14 - - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 14 - - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - 9 - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - 11 4 - - 15
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 22 - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 22 - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - 0 - - - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - - - - 42 25 - - 69
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 32 60
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 28 27 25 23 22 22 20 508 768
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 6 7 8 7 7 7 8 7 56 127
DSM, Class 2 Total 73 67 61 60 59 61 58 53 52 51 40 43 39 38 37 35 33 32 32 30 597 956
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 25 139 234 4 145 238 263 40 40 137 190 288 300 300 265 55 130
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - 15 - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 2 - - - - - 2 - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - 22 21 - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - 2 - - - 2
DSM, Class 1 Total - - - - - - - - - - - 5 - - - - - 46 21 - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 22 22 22 22 23 24 26 26 22 295 526
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 4 4 3 3 3 71 113
DSM, Class 2 Total 45 49 42 41 40 35 32 31 30 30 29 28 28 28 28 28 28 30 30 26 376 659
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 242 263 297 297 297 297 297 297 297 297 141 263 297 297 297 297 297 297 254 266
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 97 214 298 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 258 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 192 153 145 119 98 99 144 91 526 962 82 82 925 78 828 125 254
Annual Additions, Short Term Resources 646 705 839 977 1,095 1,197 1,311 1,406 1,176 1,317 1,410 1,435 1,056 1,178 1,309 1,362 1,460 1,472 1,472 1,437
Total Annual Additions 791 1,482 960 1,169 1,248 1,342 1,430 1,504 1,275 1,461 1,501 1,961 2,018 1,260 1,391 2,287 1,538 2,300 1,597 1,691
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-13
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
195

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - (416) - - - - - - - - - - - (416) (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - (269) - - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - - - - - (459) - - - - - - - (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - - (450) - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - (205) - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - 661 - 661 - 661 - - - 1,983
CCCT GH 2x1 - - - - - - - - - - - 736 - - - - - - - - - 736
CCCT J 1x1 - - - - - - 423 1,257 423 423 411 - - - 423 - - - - - 2,526 3,360
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 6 6 7 3 3 3 3 3 1 1 1 2 1 1 1 1 1 1 47 60
DSM, Class 2, UT 84 76 75 73 79 50 47 41 41 39 14 13 11 11 10 13 11 9 8 7 605 713
DSM, Class 2, WY 24 24 24 25 25 3 3 3 3 2 2 2 1 2 2 2 2 1 1 1 137 154
DSM, Class 2 Total 114 106 105 104 111 57 54 47 47 45 17 17 13 14 13 16 14 12 11 10 789 928
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.2 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 47 152 - 104 219 20 23 - 47 40 40 40 136 40 40 149 54 55
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - (363) - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - - 362 - - - - - - - - - 719 1,081
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 1 1 0 0 15 20
DSM, Class 2, OR 37 41 34 33 31 28 24 23 21 21 21 20 20 20 20 20 20 20 20 21 293 497
DSM, Class 2, WA 13 13 13 14 14 6 6 6 6 6 2 2 2 2 2 2 2 2 2 2 97 115
DSM, Class 2 Total 52 55 49 49 47 35 31 30 28 28 23 22 22 23 23 23 23 23 23 23 405 633
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - 54 23 77 297 297 285 297 297 297 297 130 297 282 85 277 297 195 264 297 192 217
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 107 75 200 236 375 375 309 375 375 375 375 375 375 375 375 375 375 375 375 375 280 328
Existing Plant Retirements/Conversions - - (164) 8 (378) - - (1,258) (779) - (261) (450) - (459) - (760) - (338) (74) -
Annual Additions, Long Term Resources 193 822 173 243 211 140 537 1,348 514 557 473 1,160 334 715 475 717 54 713 50 71
Annual Additions, Short Term Resources 607 629 723 813 1,219 1,324 1,094 1,276 1,391 1,192 1,195 1,005 1,219 1,197 1,000 1,192 1,308 1,110 1,179 1,321
Total Annual Additions 800 1,451 896 1,056 1,430 1,464 1,631 2,624 1,905 1,749 1,668 2,165 1,553 1,912 1,475 1,909 1,362 1,823 1,229 1,392
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-14
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

196

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame UT - - - - - - - - - - - - - - 181 362 - 362 - - - 905
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - - 181 181 - - 362
SCCT Frame WYSW - - - - - - - - - - - - - - - 343 172 - - - - 515
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 2.7 2.7 2.7 0.4 0.4 3.6 14.7
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 4 - - - - - - - - 4
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 85 - - 4 - - - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 19 3 - - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 3 19 - - - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1 Total - - - - - - - - - - 1 - 92 37 3 4 - 4 - - - 142
DSM, Class 2, ID 6 6 6 6 6 2 2 2 2 3 1 1 1 2 1 1 1 1 1 1 39 52
DSM, Class 2, UT 81 74 68 65 63 39 37 37 37 37 12 11 9 10 9 12 11 9 7 6 537 634
DSM, Class 2, WY 23 23 23 23 24 2 2 2 2 2 2 2 1 2 2 2 2 1 1 1 128 144
DSM, Class 2 Total 111 103 97 94 92 43 41 41 41 42 16 14 11 13 12 15 14 12 10 9 704 830
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - 6 115 - 56 170 230 184 294 292 269 237 300 215 283 18 133
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - - - 197 - - - - - 197
SCCT Frame OR - - - - - - - - - - - - - - - - - 181 - - - 181
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 15 - - - - - - - - 15
DSM, Class 1, CA-Curtail - - - - - - - - - - - - 1 - - - - - - - - 1
DSM, Class 1 Total - - - - - - - - - - - - 16 - - - - - - - - 16
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 0 0 0 0 12 16
DSM, Class 2, OR 36 41 33 32 29 26 22 19 17 17 18 17 18 17 17 19 19 19 17 17 274 451
DSM, Class 2, WA 12 12 12 12 12 5 5 5 5 5 2 1 1 1 1 2 1 1 1 1 86 98
DSM, Class 2 Total 51 55 47 46 43 32 28 24 23 23 20 19 19 19 19 21 21 20 18 18 372 566
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - - 56 175 297 297 197 297 297 297 297 297 297 297 297 297 297 297 132 214
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 135 160 262 371 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 333 366
FOT MidColumbia Q3 - 2 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 188 818 163 231 188 122 98 80 80 126 58 418 619 86 233 961 225 779 225 156
Annual Additions, Short Term Resources 610 635 737 846 931 1,050 1,178 1,287 1,072 1,228 1,342 1,402 1,356 1,466 1,464 1,441 1,409 1,472 1,387 1,455
Total Annual Additions 798 1,453 900 1,077 1,119 1,172 1,276 1,367 1,152 1,354 1,400 1,820 1,975 1,552 1,697 2,402 1,634 2,251 1,612 1,611
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-15
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
197

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - - - 115 - - - - - - - 115
Wind, GO, 29 - - - - 63 - - - - 63 - - - - - - - - - - 126 126
Wind, Wyoming, 40 - - - - - - - - - - - - 446 - - - - - - - - 446
Total Wind - - - - 63 - - - - 63 - - 446 - - - - - - - 126 572
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, UT-Curtail - - - - - - - - - - - 4 - - 81 - - - - - - 85
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.2 - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 4 0 - 89 - - - - - - 93
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 3 3 3 2 2 2 2 2 31 55
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 56 124
DSM, Class 2 Total 69 67 61 59 57 57 55 52 52 51 39 42 39 38 37 33 31 30 30 29 582 932
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 16 135 232 3 144 236 263 293 300 300 40 40 116 170 296 53 129
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - 25 - - - - - - - - - 5 - - - - - - 25 30
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - - - - - 8
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - 4 - - - - - - - - 4
DSM, Class 1 Total - - - - - - - - - - 3 4 4 8 44 - - - - - - 63
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 18 18 18 18 18 283 487
DSM, Class 2, WA 8 7 7 7 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 22 22 22 22 22 361 610
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 87 207 297 297 297 297 297 297 297 297 297 297 163 266 297 297 297 178 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 142 177 105 100 95 96 161 87 94 714 210 214 1,394 70 730 68 68
Annual Additions, Short Term Resources 650 709 845 962 1,082 1,188 1,307 1,404 1,175 1,316 1,408 1,435 1,465 1,472 1,472 1,078 1,181 1,288 1,342 1,468
Total Annual Additions 790 1,485 966 1,104 1,259 1,293 1,407 1,499 1,271 1,477 1,495 1,529 2,179 1,682 1,686 2,472 1,251 2,018 1,410 1,536
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-16
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

198

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - - - 1,322 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - 423 - 846 - - - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 4 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 62
DSM, Class 2, UT 68 61 57 55 53 51 48 44 44 42 31 34 30 29 27 26 24 22 21 20 523 788
DSM, Class 2, WY 4 4 5 5 6 6 7 7 7 8 7 7 7 7 8 7 7 7 7 8 59 132
DSM, Class 2 Total 74 68 64 64 63 61 59 55 55 53 41 43 40 39 38 36 34 32 32 31 615 981
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 70 - - 53 103 288 54 180 228 300 53 53 53 7 72
West Expansion Resources
CCCT GH 1x1 - - - - 420 - - - - - - - - - - - - - - - 420 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 20
DSM, Class 2, OR 37 41 34 34 33 31 27 24 24 24 24 23 25 26 26 26 26 23 26 26 308 558
DSM, Class 2, WA 8 8 8 8 8 7 7 7 7 7 5 5 5 5 5 4 4 3 3 3 74 118
DSM, Class 2 Total 46 50 43 43 42 39 35 32 32 32 30 29 31 32 32 30 30 28 30 30 393 695
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 163 125 239 291 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 260 279
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 383 400 400 400 331 400 400 400 400 400 400 400 400 400 400 400 400 379 400 400 391 395
FOT MidColumbia Q3 - 2 - 79 97 178 - 31 143 166 4 143 183 163 168 174 177 180 202 - 26 145 84 113
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 146 778 125 198 578 147 122 101 103 147 92 457 369 510 86 929 81 1,399 78 99
Annual Additions, Short Term Resources 646 704 836 969 728 828 940 1,033 801 940 1,033 1,063 1,253 1,025 1,154 1,205 1,299 829 876 995
Total Annual Additions 792 1,482 961 1,167 1,306 975 1,062 1,134 904 1,087 1,125 1,520 1,622 1,535 1,240 2,134 1,380 2,228 954 1,094
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-2 Case C-17
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
199

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - - - - - - (416) - - - - - - - (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - - (269) - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - - - - - - (479) - - - - - - - - (479)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - - - (268) - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
WY IGCC CCS - - - - - - - - - - - - - - - - - - - 456 - 456
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 846 411 - - 2,103
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Nuclear - - - - - - - - - - - - 2,236 - - - - - - - - 2,236
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - 105 - - - - - - - - - 105
Wind, GO, 29 - - - - - - - - - - 393 63 84 59 - - - - - - - 599
Wind, UT, 29 - - - - - - - - - - 200 - - - - - - - - - - 200
Wind, Wyoming, 40 - - - - - - - 650 - - - - - - - - - - - - 650 650
Total Wind - - - - - - - 650 - - 593 63 84 59 - - - - - - 650 1,449
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 8 8 7 3 3 3 3 3 1 1 1 2 2 2 1 1 1 1 51 65
DSM, Class 2, UT 88 81 77 81 80 51 49 43 42 40 14 13 11 12 10 14 11 10 9 8 633 743
DSM, Class 2, WY 25 25 25 26 26 3 3 3 3 3 3 2 2 2 2 2 2 2 1 1 141 159
DSM, Class 2 Total 120 112 109 115 114 58 55 48 48 46 18 17 13 15 14 17 15 13 12 10 824 967
Utility Solar - PV - - - - - - - - - - - - - 450 - - - - - - - 450
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.4 13.4 13.4 131 263
Micro Solar - Water Heating - - - 0.4 0.3 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - - - - 6 180 - 53 103 168 284 285 82 53 - 61
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
Colstrip3 (Early Retirement/Conversion)- - - - - - - - - - - - (74) - - - - - - - - (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - - - - - - - - - - - - (74) - - (74)
Coal Ret_Bridger -Gas RePower - - - - - - - - - - 362 - - - - - - - - - - 362
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - - - - - - - - - 30 - - - - - - - - - 30
Wind, WV, 29 - - - - - - - - - - - - - - - 300 - - - - - 300
Total Wind - - - - - - - - - - - - - - - 300 - - - - - 300
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 1 0 0 1 1 1 1 1 1 0 16 22
DSM, Class 2, OR 41 44 40 38 34 31 28 25 23 23 22 21 21 21 21 21 21 21 21 21 327 535
DSM, Class 2, WA 14 14 14 14 14 7 7 6 6 6 2 2 2 3 3 3 2 2 2 2 104 127
DSM, Class 2 Total 57 60 56 55 51 38 36 33 30 30 25 24 24 24 24 24 24 23 23 23 447 684
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 99 33 - 83 113 201 297 286 60 210 297 297 - 195 297 297 297 297 297 65 138 186
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 - 81 201 206 240 255 271 375 375 375 375 375 210 375 375 375 375 375 375 375 238 298
Existing Plant Retirements/Conversions - - (164) - - - - - - - 8 (269) (1,208) (416) - (760) - (701) (148) -
Annual Additions, Long Term Resources 203 832 183 187 183 111 106 746 95 93 652 255 2,374 565 54 1,204 55 899 462 506
Annual Additions, Short Term Resources 599 614 701 789 853 956 1,068 1,161 935 1,085 1,178 1,352 710 1,123 1,275 1,340 1,456 1,457 1,254 993
Total Annual Additions 802 1,446 884 976 1,036 1,067 1,174 1,907 1,030 1,178 1,830 1,607 3,084 1,688 1,329 2,544 1,511 2,356 1,716 1,499
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-2 Case C-18 Capacity (MW)Resource Totals 1/
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

200

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - - - - - 736
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - 181 181 - - - 362
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - 16 - - - - 22 - 38
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - 16 - - - - 22 199 892
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - 1 - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 7 77 - - - - 3 - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 3 - - - - 4 - 8
DSM, Class 1, UT-Irrigate - - - - - - - 0 - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - 10 - 3 9 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1, WY-Irrigate - - - - - - - - - - 0 - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - 1 - - 0 10 - 11 99 - - - - 11 1 131
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 32 60
DSM, Class 2, UT 67 61 54 51 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 507 766
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 56 126
DSM, Class 2 Total 73 67 61 59 59 61 58 52 52 51 39 42 39 38 37 35 33 32 31 30 595 952
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.1 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 29 143 237 8 149 241 255 217 268 300 253 196 142 192 300 57 147
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 1 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - 3 8 - 60 1 - - - - 3 - 75
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 26 24 23 20 23 23 22 22 22 22 19 20 22 22 23 289 506
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 69 106
DSM, Class 2 Total 45 49 41 41 38 34 32 30 27 30 28 27 27 28 28 23 24 26 26 27 367 630
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 103 223 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 205 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 191 149 143 118 99 96 143 92 472 1,025 153 197 991 254 916 74 110
Annual Additions, Short Term Resources 646 705 840 978 1,098 1,201 1,315 1,409 1,180 1,321 1,413 1,427 1,389 1,440 1,472 1,425 1,368 1,314 1,364 1,472
Total Annual Additions 791 1,482 961 1,169 1,247 1,344 1,433 1,508 1,276 1,464 1,505 1,899 2,414 1,593 1,669 2,416 1,622 2,230 1,438 1,582
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-2 Case C-19 Capacity (MW)Resource Totals 1/
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
201

Table K.9 – Energy Gateway Scenario 3 – Case C-01 to C-19

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - 91 - - - - - - - 91
SCCT Frame ID - - - - - - - - - - - - - - 181 - - - - - - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 172 - - - - - 172
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - 7.9 7.9 7.9 7.9 7.9 - 39.5
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.8 2.7 2.7 2.7 2.7 2.7 2.7 3.7 3.7 3.6 28.4
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 9 - - - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 85 - - - 4 - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 3 - - 15 3 - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 13 10 - - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - 4 - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.2 - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 106 13 - - 23 3 1 11 - 158
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 61
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 29 28 27 25 23 23 21 508 777
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 8 7 7 7 7 8 7 7 8 8 8 57 131
DSM, Class 2 Total 73 67 61 61 59 61 58 53 52 52 40 43 40 39 38 37 35 34 33 32 597 969
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 27 140 235 4 145 239 263 298 300 269 279 300 300 300 300 55 170
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
IC Aero WW - - - - - - - - - - - - - - - - - 99 - 99 - 198
Wind, HM, 29 - - - - - - - - - - - - - - - - - - - 78 - 78
Total Wind - - - - - - - - - - - - - - - - - - - 78 - 78
Utility Biomass - - - - - - - - - - - - - - - - - - 35 5 - 40
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - 2.3 2.3 2.3 2.3 2.3 - 11.6
CHP - Other - - - - - - - - - - - - 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 - 2.7
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 15 - - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - 11 - - 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 2 2 - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 22 21 - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - 27 - - 2 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 1 1 - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 2 2 - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - 1 - - 1 - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - 1 - - - - - 1 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 6 44 22 - - 39 - 1 5 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 20
DSM, Class 2, OR 37 41 33 32 29 28 27 23 23 23 23 26 26 26 26 26 26 26 26 26 296 549
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 5 5 5 5 4 4 4 4 3 69 112
DSM, Class 2 Total 46 49 41 41 38 35 34 30 30 30 28 32 31 32 32 31 30 30 31 30 375 682
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 102 222 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 204 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 115 111 108 98 99 98 85 98 664 217 270 930 156 857 132 290
Annual Additions, Short Term Resources 646 704 840 977 1,097 1,199 1,312 1,407 1,176 1,317 1,411 1,435 1,470 1,472 1,441 1,451 1,472 1,472 1,472 1,472
Total Annual Additions 791 1,481 961 1,096 1,212 1,310 1,420 1,505 1,275 1,415 1,496 1,533 2,134 1,689 1,711 2,381 1,628 2,329 1,604 1,762
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-01
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

202

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - - (387) - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - 661 - 661 - 661 - - - 1,983
CCCT GH 1x1 - - - - - - - - - - - - - - - 368 - - - - - 368
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 22 15 - - 48 - - - - - - - - - - 202 202
Wind, Wyoming, 40 - - - - - - - - - - - - 540 - - - - - - - - 540
Total Wind - - - 70 47 22 15 - - 48 - - 540 - - - - - - - 202 742
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - 4 4 - - - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 85 - - - - - - - - 85
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 22 - - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 22 - - - - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 6 111 - 24 - - - - - - 141
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 2 2 2 2 2 30 53
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 21 21 20 495 752
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 55 123
DSM, Class 2 Total 69 67 61 59 57 56 54 52 52 51 39 42 39 38 37 33 31 30 30 29 580 928
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 158 255 27 168 262 263 300 191 300 172 273 40 61 167 65 134
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, HM, 29 - - - - - - - - - - - - - - - - - - - 78 - 78
Total Wind - - - - - - - - - - - - - - - - - - - 78 - 78
Utility Biomass - - - - - - - - - - - - - - - - - - 35 5 - 40
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 44 - - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - 2 - - - - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - 28 44 - - - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 17
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 22 22 22 18 18 18 18 18 283 486
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 104
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 29 28 27 26 27 27 22 22 22 22 22 361 608
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 297 297 290 297 297 182 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - (387) - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 187 160 126 114 95 96 145 84 120 777 742 104 1,101 70 1,153 103 151
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,211 1,330 1,427 1,199 1,340 1,434 1,435 1,472 1,363 1,472 1,344 1,445 1,205 1,233 1,339
Total Annual Additions 790 1,485 966 1,171 1,264 1,337 1,444 1,522 1,295 1,485 1,518 1,555 2,249 2,105 1,576 2,445 1,515 2,358 1,336 1,490
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-02
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
203

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - 1,322 - - - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 74 35 33 12 - - 44 4 - - - - - - - - - 198 202
Wind, Wyoming, 40 - - - - - - - - - - - 398 236 - - - - - - - - 634
Total Wind - - - 74 35 33 12 - - 44 4 398 236 - - - - - - - 198 836
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - 9 - - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 8 77 - - - - 7 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 22 - - - - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - 10 - - 13 - - - - 2 - 25
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 11 - 16 111 - - - - 14 - 153
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 2 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 34 33 32 31 30 581 935
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 157 254 26 168 262 263 226 300 300 40 40 181 200 300 64 138
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, HM, 29 - - - - - - - - - - - - - 14 - - - - - 78 - 92
Total Wind - - - - - - - - - - - - - 14 - - - - - 78 - 92
Utility Biomass - - - - - - - - - - - - - - - - - - 35 5 - 40
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 8 - 8 - - - - - 0 - 16
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 22 21 - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - 1 - 1 - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 20 - 31 21 - - - - 3 - 75
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 22 22 22 18 19 19 22 22 283 494
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 29 28 27 27 28 28 22 22 23 26 26 361 617
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 162 264 297 297 297 182 231
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 191 148 137 112 95 96 141 88 515 979 143 214 1,395 72 675 108 173
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,211 1,329 1,426 1,198 1,340 1,434 1,435 1,398 1,472 1,472 1,077 1,179 1,353 1,372 1,472
Total Annual Additions 790 1,485 966 1,175 1,252 1,348 1,441 1,521 1,294 1,481 1,522 1,950 2,377 1,615 1,686 2,472 1,251 2,028 1,480 1,645
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-03
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

204

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - (450) - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 - - 1,322 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - 736 - - - - - - - - - - 736 - - 736 1,472
CCCT J 1x1 - - - - - - - - 846 834 - - - 423 - - - - - - 1,680 2,103
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 4 - - - - - - - - 4
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 37 4 - - - - - 41
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 3 - - - - - - - - 3
DSM, Class 1 Total - - - - - - - - - - - - 8 - 40 4 - - - - - 52
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 2 2 2 29 54
DSM, Class 2, UT 63 55 51 48 49 47 44 40 41 40 30 33 30 28 27 26 25 22 21 20 477 739
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 55 123
DSM, Class 2 Total 68 62 58 56 57 55 53 49 51 51 39 42 39 38 37 36 34 31 30 29 561 916
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 182 68 177 - - - - 67 97 281 54 137 205 300 40 73 199 54 100
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 2 - - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - 2 - - - - - - - 2
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 20 20 23 22 22 22 26 26 26 18 19 19 277 500
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 66 103
DSM, Class 2 Total 45 48 41 40 38 33 29 26 26 27 28 27 27 27 31 30 30 22 23 22 353 620
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 202 116 122 273 297 297 297 297 297 297 297 277 297 297 205 250
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (1,047) (788) 8 - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 117 113 774 103 832 1,413 940 928 84 86 90 507 124 86 81 805 69 68
Annual Additions, Short Term Resources 651 714 1,222 1,354 1,240 1,349 1,077 991 997 1,148 1,239 1,269 1,453 1,226 1,309 1,377 1,472 1,192 1,245 1,371
Total Annual Additions 791 1,485 1,339 1,467 2,014 1,452 1,909 2,404 1,937 2,076 1,323 1,355 1,543 1,733 1,433 1,463 1,553 1,997 1,314 1,439
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-04
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
205

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - (450) - - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - (106) - - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - 661 1,322 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - 736 - - - - - - - - - - - - 736 - - 736 1,472
CCCT J 1x1 - - - - - - - - - 846 822 - 423 - - - - - - - 846 2,091
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, UT-Curtail - - - - - - - - - - - 4 - - - 4 - - - - - 7
DSM, Class 1, UT-DLC-RES - - - - - - - - - - 4 - - - 3 - - - - - - 7
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 3 - - - - - - - - 3
DSM, Class 1 Total - - - - - - - - - - 4 8 3 - 3 4 - - - - - 22
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 55 54 51 49 47 45 43 42 40 30 33 30 28 28 28 25 22 21 20 489 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 61 59 57 55 54 52 52 51 39 42 39 38 38 37 35 32 31 30 574 935
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 - 102 - - 199 244 55 74 40 40 141 206 300 61 71 196 83 101
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - - - - - 8
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 2 2 - - - - - 4
DSM, Class 1 Total - - - - - - - - - - - - - 8 2 2 - - - - - 12
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 19
DSM, Class 2, OR 36 40 33 32 29 26 22 21 20 23 23 22 23 26 26 26 26 18 19 19 283 510
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 5 5 4 4 3 3 3 67 107
DSM, Class 2 Total 45 49 41 41 38 33 29 28 27 30 28 27 28 32 32 31 30 22 23 22 359 635
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 291 297 192 102 297 297 297 297 170 281 297 297 297 255 297 297 222 250
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (703) (682) (442) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 190 884 137 772 1,419 96 989 916 526 727 94 92 90 82 806 70 70
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,166 1,274 1,067 977 1,371 1,416 1,227 1,246 1,085 1,196 1,313 1,378 1,472 1,191 1,243 1,368
Total Annual Additions 791 1,485 1,339 1,537 2,050 1,411 1,839 2,396 1,467 2,405 2,143 1,772 1,812 1,290 1,405 1,468 1,554 1,997 1,313 1,438
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-05
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

206

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 2 3 3 3 3 3 3 3 32 59
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 508 767
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 6 7 7 7 7 7 7 7 56 126
DSM, Class 2 Total 73 67 61 60 59 61 58 53 52 51 40 43 38 38 37 35 33 32 31 30 596 952
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 28 142 237 6 148 241 263 40 40 147 201 300 59 109 232 56 110
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1 Total - - - - - - - - - - - 11 - - - - - - - - - 11
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 22 19 19 19 22 22 19 22 22 295 504
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 3 3 3 3 3 71 110
DSM, Class 2 Total 45 49 42 41 40 35 32 31 30 30 29 28 25 24 24 26 26 23 26 26 376 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 243 258 297 297 297 297 297 297 297 297 145 269 297 297 297 297 297 297 254 266
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 220 300 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 117 111 105 98 99 98 85 100 740 79 78 923 76 1,155 73 73
Annual Additions, Short Term Resources 646 705 841 978 1,097 1,200 1,314 1,409 1,178 1,320 1,413 1,435 1,060 1,184 1,319 1,373 1,472 1,231 1,281 1,404
Total Annual Additions 791 1,482 962 1,097 1,214 1,311 1,419 1,507 1,277 1,418 1,498 1,535 1,800 1,263 1,397 2,296 1,548 2,386 1,354 1,477
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-06
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
207

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - - - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - - - - 423 - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - 14 - - 664
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - 14 - 202 872
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - - 4 - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 11 - - - 40 - - 51
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 3 - - 3
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 22 - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 17 - - 27 44 - - 87
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 61 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 499 759
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 7 56 127
DSM, Class 2 Total 69 67 61 59 59 57 57 52 52 51 39 42 39 38 37 35 33 32 32 30 586 945
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 36 151 248 19 162 257 - 134 255 298 40 40 297 300 277 62 126
West Expansion Resources
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 420 - 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - 15 - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 72 - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 22 22 22 23 22 23 26 26 22 285 516
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 112
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 28 28 28 29 27 28 30 30 26 365 646
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 130 247 268 297 297 297 297 297 297 297 238 297 297 297 156 254 297 297 297 256 264
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 215 305 375 375 375 375 375 375 375 375 375 375 375 375 375 375 166 259 307
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 777 121 191 151 140 117 96 96 141 90 942 302 83 172 1,400 77 528 136 493
Annual Additions, Short Term Resources 650 709 845 983 1,102 1,208 1,323 1,420 1,191 1,334 1,429 1,113 1,306 1,427 1,470 1,071 1,169 1,469 1,472 1,240
Total Annual Additions 791 1,486 966 1,174 1,253 1,348 1,440 1,516 1,287 1,475 1,519 2,055 1,608 1,510 1,642 2,471 1,246 1,997 1,608 1,733
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-07
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

208

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - (450) - - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - (106) - - - - - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 1,322 661 - - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - 736 - - - - - - 736 - - - 1,472
CCCT J 1x1 - - - - - - 423 846 411 - - - - - 411 - - - - - 1,680 2,091
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 3 3 3 3 3 3 3 3 27 54
DSM, Class 2, UT 63 55 50 48 45 43 41 38 39 39 30 32 30 28 27 25 23 22 21 20 462 719
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 123
DSM, Class 2 Total 68 62 58 56 54 52 49 47 49 49 38 41 38 38 37 35 33 32 31 30 543 896
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 185 - 176 18 150 75 219 - - 142 265 57 132 231 129 178 300 94 118
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 35 40 33 32 29 26 22 19 17 17 17 19 19 19 19 22 22 22 22 23 271 475
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 63 100
DSM, Class 2 Total 43 48 40 40 37 33 29 25 24 24 22 24 24 24 24 26 26 26 26 27 343 592
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 38 65 342 297 196 297 297 297 297 297 211 245 297 297 297 297 297 297 297 297 242 263
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 151 270 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 346
Existing Plant Retirements/Conversions - - (582) 8 (828) (829) (74) (816) (548) - (268) - - - - - - (543) (74) -
Annual Additions, Long Term Resources 138 770 116 113 1,431 760 516 934 500 90 813 81 79 78 488 78 76 810 74 74
Annual Additions, Short Term Resources 652 716 1,224 1,357 1,071 1,348 1,190 1,322 1,247 1,391 1,086 1,120 1,314 1,437 1,229 1,304 1,403 1,301 1,350 1,472
Total Annual Additions 790 1,486 1,340 1,470 2,502 2,108 1,706 2,256 1,747 1,481 1,899 1,201 1,393 1,515 1,717 1,382 1,479 2,111 1,424 1,546
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-08
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
209

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - (459) - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_UT - Gas RePower - - - - - - 468 - - - - - - - - - - - - - 468 468
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT F 2x1 - - - - - - 634 - - - - - - - - - - - - - 634 634
CCCT FD 2x1 - - - - 661 661 - - - - - - - - - - - - - - 1,322 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - - 736 - - - - 736
CCCT J 1x1 - - - - - - - 846 423 411 411 - 423 - - - - - - - 1,680 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 56 54 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 484 742
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 51 39 42 39 38 37 35 33 32 31 30 567 922
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 60 231 41 171 85 - - 4 40 40 102 177 40 40 61 164 87 77
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 19 19 19 19 19 22 22 22 22 22 275 481
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 66 103
DSM, Class 2 Total 45 49 41 41 38 33 29 25 24 26 25 24 24 24 24 26 26 26 26 26 351 602
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 297 279 273 297 107 231 297 297 - 249 278 297 250 242
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 - 100 100 100 100 95
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 369 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (714) (270) (816) (548) (106) (268) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 190 809 798 743 938 514 551 497 515 720 78 77 78 812 74 74 73
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,232 1,403 1,213 1,343 1,257 1,154 1,148 1,176 1,022 1,146 1,274 1,349 809 1,164 1,214 1,336
Total Annual Additions 791 1,485 1,339 1,537 2,041 2,201 1,956 2,281 1,771 1,705 1,645 1,691 1,742 1,224 1,351 1,427 1,621 1,238 1,288 1,409
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-09
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

210

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - - - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - 181 - - - - - - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 172 - - - - - 172
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - 9 - - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 4 - - 77 - - - - 81
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 22 - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - 1 - - 13 - - 99 - - - - 113
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 2 2 2 30 56
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 21 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 55 124
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 30 30 29 581 933
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 170 263 67 262 300 276 300 299 40 47 174 65 134
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, HM, 29 - - - - - - - - - - - - - 8 - - - - - - - 8
Total Wind - - - - - - - - - - - - - 8 - - - - - - - 8
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 - 1 - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - 71 - 1 - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 21 23 22 22 22 22 22 22 18 18 18 282 493
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 28 28 27 27 28 27 26 26 22 22 22 359 615
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 251 297 297 182 237
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 100 95 96 96 85 747 82 174 262 912 175 1,228 68 68
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,342 1,435 1,239 1,434 1,472 1,448 1,472 1,471 1,166 1,219 1,346
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,431 1,523 1,295 1,438 1,520 1,986 1,516 1,646 1,710 2,384 1,646 2,394 1,287 1,414
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-10
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
211

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - - (387) - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - 661 - 661 - 661 - - - 1,983
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 368 - 368
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - - - - 181 - - - 181
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 33 13 - - 45 5 - - - - - - - - - 199 204
Wind, Wyoming, 40 - - - - - - - - - - - - 684 - - - - - - - - 684
Total Wind - - - 73 35 33 13 - - 45 5 - 684 - - - - - - - 199 888
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - 4 4 - - - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - 1 - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - 4 81 - - 4 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - 7 11 - - 3 - - - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - 0 - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 22 - - - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 4 - - - - - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.2 - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 16 120 - - 11 - - - 10 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 8 55 126
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 30 581 938
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 157 254 26 167 261 258 300 190 294 300 241 203 258 208 64 158
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - - - - 197 - - - - 197
Wind, HM, 29 - - - - - - - - - - - - - 8 - - - - - - - 8
Total Wind - - - - - - - - - - - - - 8 - - - - - - - 8
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - 6 - - - - - - 6
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 22 - 21 - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - 3 - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 2 2 - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - 1 1 - - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 22 28 - 28 - - - - 3 - 82
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 22 19 22 22 23 284 503
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 106
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 26 23 26 26 27 361 627
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 369 400 398
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 364 348 343 375 333 350
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - (387) - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 148 137 113 95 96 142 89 124 915 751 110 931 269 916 73 455
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,211 1,329 1,426 1,198 1,339 1,433 1,430 1,472 1,362 1,466 1,472 1,402 1,348 1,398 1,349
Total Annual Additions 790 1,485 966 1,174 1,252 1,348 1,442 1,521 1,294 1,481 1,522 1,554 2,387 2,113 1,576 2,403 1,671 2,264 1,471 1,804
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-11
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

212

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 2 3 3 3 3 3 3 3 32 59
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 508 767
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 6 7 7 7 7 7 7 7 56 126
DSM, Class 2 Total 73 67 61 60 59 61 58 53 52 51 40 43 38 38 37 35 33 32 31 30 596 952
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 28 142 237 6 148 241 263 40 40 147 201 300 59 109 232 56 110
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1 Total - - - - - - - - - - - 11 - - - - - - - - - 11
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 22 19 19 19 22 22 19 22 22 295 504
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 3 3 3 3 3 71 110
DSM, Class 2 Total 45 49 42 41 40 35 32 31 30 30 29 28 25 24 24 26 26 23 26 26 376 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 243 258 297 297 297 297 297 297 297 297 145 269 297 297 297 297 297 297 254 266
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 220 300 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 117 111 105 98 99 98 85 100 740 79 78 923 76 1,155 73 73
Annual Additions, Short Term Resources 646 705 841 978 1,097 1,200 1,314 1,409 1,178 1,320 1,413 1,435 1,060 1,184 1,319 1,373 1,472 1,231 1,281 1,404
Total Annual Additions 791 1,482 962 1,097 1,214 1,311 1,419 1,507 1,277 1,418 1,498 1,535 1,800 1,263 1,397 2,296 1,548 2,386 1,354 1,477
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-12
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
213

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - - - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - - - - 423 - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - - 4 - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 11 - - - 40 - - 51
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4 - - 4
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 22 - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 17 - - 27 44 - - 88
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 61 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 499 759
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 7 56 127
DSM, Class 2 Total 69 67 61 59 59 57 57 52 52 51 39 42 39 38 37 35 33 32 32 30 586 945
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 36 151 248 19 162 257 - 134 255 298 40 40 297 300 277 62 126
West Expansion Resources
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 420 - 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - 15 - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 72 - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 22 22 22 23 22 23 26 26 22 285 516
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 112
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 28 28 28 29 27 28 30 30 26 365 646
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 130 247 268 297 297 297 297 297 297 297 238 297 297 297 156 254 297 297 297 256 264
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 215 305 375 375 375 375 375 375 375 375 375 375 375 375 375 375 166 259 307
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 777 121 191 151 140 117 96 96 141 90 942 302 83 172 1,400 77 528 122 493
Annual Additions, Short Term Resources 650 709 845 983 1,102 1,208 1,323 1,420 1,191 1,334 1,429 1,113 1,306 1,427 1,470 1,071 1,169 1,469 1,472 1,240
Total Annual Additions 791 1,486 966 1,174 1,253 1,348 1,440 1,516 1,287 1,475 1,519 2,055 1,608 1,510 1,642 2,471 1,246 1,997 1,594 1,733
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-13
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

214

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - (416) - - - - - - - - - - - (416) (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - (269) - - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - - - - - (459) - - - - - - - (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - - (450) - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - (205) - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - - - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - 736 - 736 - - - - - 736 - 2,208
CCCT J 1x1 - - - - - - 411 1,269 834 - 423 - - - - - - - - - 2,514 2,937
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 74 35 33 12 - - 44 4 - - - - - - - - - 198 202
Wind, Wyoming, 40 - - - - - - - - 566 - - 398 236 - - - - - - - 566 1,200
Total Wind - - - 74 35 33 12 - 566 44 4 398 236 - - - - - - - 764 1,402
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 6 6 6 2 3 3 3 3 1 1 1 2 1 1 1 1 1 1 45 58
DSM, Class 2, UT 84 76 70 73 71 44 42 41 41 39 13 13 10 11 10 13 11 9 8 7 580 687
DSM, Class 2, WY 24 24 24 24 25 3 3 2 3 2 2 2 1 2 2 2 2 1 1 1 136 153
DSM, Class 2 Total 114 106 101 103 102 50 48 47 46 44 17 16 13 14 13 16 14 12 11 10 761 898
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.2 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 60 171 - 131 - 56 49 - 73 53 136 40 40 249 287 72 42 71
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - (363) - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - - 362 - - - - - - - - - 719 1,081
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, HM, 29 - - - - - - - - - - - - - - - - - - - 78 - 78
Total Wind - - - - - - - - - - - - - - - - - - - 78 - 78
Utility Biomass - - - - - - - - - - - - - - - - - - 35 5 - 40
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 1 0 0 0 15 19
DSM, Class 2, OR 37 41 34 33 30 28 24 21 19 19 21 20 20 20 20 20 20 20 20 20 285 484
DSM, Class 2, WA 13 12 13 14 14 6 6 6 6 6 2 2 2 2 2 2 2 1 1 1 96 112
DSM, Class 2 Total 52 55 49 49 46 35 31 28 26 26 23 22 22 22 22 22 22 21 22 22 395 615
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - 54 28 82 297 297 297 297 203 297 297 156 297 229 297 13 131 297 297 10 185 194
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 107 75 200 236 375 375 331 375 375 375 375 375 375 375 375 375 375 375 375 375 282 329
Existing Plant Retirements/Conversions - - (164) 8 (378) - - (1,258) (779) - (261) (450) - (459) - (760) - (338) (74) -
Annual Additions, Long Term Resources 192 822 167 244 201 133 516 1,358 1,488 131 484 1,189 288 789 52 1,377 52 50 85 867
Annual Additions, Short Term Resources 607 629 728 818 1,232 1,343 1,128 1,303 1,078 1,228 1,221 1,031 1,245 1,157 1,308 928 1,046 1,421 1,459 957
Total Annual Additions 799 1,451 895 1,062 1,433 1,476 1,644 2,661 2,566 1,359 1,705 2,220 1,533 1,946 1,360 2,305 1,098 1,471 1,544 1,824
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-14
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
215

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - 181 362 - 362 - - - 905
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
SCCT Frame WYAE - - - - - - - - - - - - - - - - - - - 181 - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 515 - - - - - 515
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 74 35 33 12 - - 44 4 - - - - - - - - - 198 202
Wind, Wyoming, 40 - - - - - - - - - - - 398 236 - - - - - - - - 634
Total Wind - - - 74 35 33 12 - - 44 4 398 236 - - - - - - - 198 836
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.8 2.7 2.7 2.7 0.4 3.6 14.8
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - 9 - - - - - - - 9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 37 40 - 4 - - - - - 81
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 19 3 - - - - - - 22
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - 22 - - - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.2 - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - 37 90 3 4 - 4 - - - 138
DSM, Class 2, ID 6 6 6 6 6 2 2 2 2 3 1 1 1 2 1 1 1 1 1 1 39 52
DSM, Class 2, UT 81 74 68 65 63 39 37 37 37 37 12 11 9 10 9 12 10 9 8 6 537 634
DSM, Class 2, WY 23 23 23 23 24 2 2 2 2 2 2 2 1 2 2 2 2 1 1 1 128 144
DSM, Class 2 Total 111 103 97 94 92 43 41 41 41 42 16 14 11 13 12 15 13 12 11 9 704 831
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - 6 115 - 56 171 231 215 272 269 270 230 272 300 283 18 135
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - - - - - - - - - - - 181 384 - - - 565
Wind, HM, 29 - - - - - - - - - - - - - - - - - - - 78 - 78
Total Wind - - - - - - - - - - - - - - - - - - - 78 - 78
Utility Biomass - - - - - - - - - - - - - - - - - - 45 5 - 50
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Other - - - - - - - - - - - - - - - - - 0.3 0.3 - - 0.5
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 15 - - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - 2 - - - - - - - - 2
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 22 - - - - - - - - 22
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - 2 - - - - - - - - 2
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - 1 - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1 Total - - - - - - - - - - - - 42 1 - - - 1 - - - 44
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 0 0 0 0 13 17
DSM, Class 2, OR 36 41 33 32 29 26 22 19 17 17 18 17 18 17 19 19 19 19 19 17 274 455
DSM, Class 2, WA 12 12 12 12 12 5 5 5 5 5 2 1 1 1 1 2 1 1 1 1 86 99
DSM, Class 2 Total 51 55 47 46 43 32 28 24 23 23 20 19 19 19 20 21 21 21 21 18 373 571
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - - 56 174 297 297 196 297 297 297 297 297 297 297 297 297 297 297 132 214
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 135 160 262 370 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 333 366
FOT MidColumbia Q3 - 2 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 188 818 163 232 189 122 96 80 80 126 56 448 543 140 234 934 234 803 95 307
Annual Additions, Short Term Resources 610 635 737 845 931 1,049 1,178 1,287 1,071 1,228 1,343 1,403 1,387 1,444 1,441 1,442 1,402 1,444 1,472 1,455
Total Annual Additions 798 1,453 900 1,077 1,120 1,171 1,274 1,367 1,151 1,354 1,399 1,851 1,930 1,584 1,675 2,376 1,636 2,247 1,567 1,762
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-15
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

216

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - - - 115 - - - - - - - 115
Wind, GO, 29 - - - - 63 - - - - 63 - - - - - - - - - - 126 126
Wind, Wyoming, 40 - - - - - - - - - - - - 446 - - - - - - - - 446
Total Wind - - - - 63 - - - - 63 - - 446 - - - - - - - 126 572
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 85 - - - - - - 85
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 13 - - - - - - 13
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 0 - - 102 - - - - - - 102
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 2 2 2 2 2 30 54
DSM, Class 2, UT 63 59 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 493 751
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 55 123
DSM, Class 2 Total 69 65 61 59 57 56 54 52 52 51 39 42 39 38 37 33 31 30 30 29 578 927
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 20 138 235 7 150 244 263 298 291 300 40 40 116 170 296 55 130
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - 25 - - - - - - - - - 5 - - - - - - 25 30
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 8 - - - - - - - - - 8
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 22 21 - - - - - - 44
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1 Total - - - - - - - - - - - 16 - 22 22 - - - - - - 61
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 17
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 20 23 22 22 22 22 18 18 18 18 18 280 484
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 104
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 27 28 27 27 27 28 22 22 22 22 22 358 605
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 89 209 297 297 297 297 297 297 297 297 297 297 163 266 297 297 297 178 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 211 347 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 354
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 774 121 142 176 104 99 95 95 157 84 102 709 224 205 1,394 70 730 68 68
Annual Additions, Short Term Resources 650 711 847 964 1,084 1,192 1,310 1,407 1,179 1,322 1,416 1,435 1,470 1,463 1,472 1,078 1,181 1,288 1,342 1,468
Total Annual Additions 790 1,485 968 1,106 1,260 1,296 1,409 1,502 1,274 1,479 1,500 1,537 2,179 1,687 1,677 2,472 1,251 2,018 1,410 1,536
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-16
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
217

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - 661 - - - - - - - 661
CCCT J 1x1 - - - - - - - - - - - - - - - 423 - 846 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 74 35 33 12 - - 44 4 - - - - - - - - - 198 202
Wind, Wyoming, 40 - - - - - - - - - - - 398 236 566 - - - - - - - 1,200
Total Wind - - - 74 35 33 12 - - 44 4 398 236 566 - - - - - - 198 1,402
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - 37 37 - - - 74
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 13 - - - - 13
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - 0 - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - 1 - 0 50 37 - - - 88
DSM, Class 2, ID 3 3 3 4 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 34 62
DSM, Class 2, UT 68 61 57 55 53 51 48 44 44 42 31 34 31 29 28 27 25 22 21 20 523 791
DSM, Class 2, WY 4 4 5 5 6 7 7 7 7 8 7 7 7 7 8 7 7 7 8 8 60 133
DSM, Class 2 Total 74 68 65 64 63 62 59 55 55 53 41 44 40 40 39 37 35 32 32 31 616 987
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 49 - - 46 94 278 53 53 300 300 259 298 253 5 99
West Expansion Resources
CCCT GH 1x1 - - - - 420 - - - - - - - - - - - - - - - 420 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, HM, 29 - - - - - - - - - - - - - - - 60 9 - - 78 - 147
Total Wind - - - - - - - - - - - - - - - 60 9 - - 78 - 147
Utility Biomass - - - - - - - - - - - - - - - - - - 35 5 - 40
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - 22 21 - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - 4 - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - 1 - - - - 1
DSM, Class 1 Total - - - - - - - - - - - - - - 3 27 22 - - - - 52
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 21
DSM, Class 2, OR 37 41 34 36 33 31 28 24 24 26 26 26 26 26 26 26 26 26 26 26 314 570
DSM, Class 2, WA 8 8 8 8 8 7 7 7 7 7 5 5 5 5 5 4 4 3 3 3 74 118
DSM, Class 2 Total 46 50 43 45 42 39 36 32 32 34 32 32 31 32 32 30 30 30 30 30 399 709
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 163 125 238 289 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 260 278
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 383 400 400 400 329 400 400 400 400 400 400 400 400 333 400 400 400 400 400 400 391 392
FOT MidColumbia Q3 - 2 - 79 97 179 - 29 139 184 - 138 183 163 168 - 59 180 202 186 164 165 85 116
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 146 778 126 201 579 148 121 102 103 148 94 490 324 1,316 90 594 163 962 113 341
Annual Additions, Short Term Resources 646 704 835 968 726 826 936 1,030 797 935 1,026 1,054 1,243 783 909 1,277 1,299 1,242 1,259 1,215
Total Annual Additions 792 1,482 961 1,169 1,305 974 1,057 1,132 900 1,083 1,120 1,544 1,567 2,099 999 1,871 1,462 2,204 1,372 1,556
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-3 Case C-17
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

218

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - - - - - - (416) - - - - - - - (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - - (269) - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - - - - - - (479) - - - - - - - - (479)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - - - (268) - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
WY IGCC CCS - - - - - - - - - - - - - - - - - - - 456 - 456
CCCT J 1x1 - - - - - - - - - - 423 - - - - 423 834 411 - - - 2,091
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Nuclear - - - - - - - - - - - - 2,236 - - - - - - - - 2,236
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - 105 - - - - - - - - - 105
Wind, GO, 29 - - - - - - - - - 346 47 63 76 68 - - - - - - 346 600
Wind, UT, 29 - - - - - - - - - - 200 - - - - - - - - - - 200
Wind, Wyoming, 40 - - - - - - - 1,200 - - - - - - - - - - - - 1,200 1,200
Total Wind - - - - - - - 1,200 - 346 247 63 76 68 - - - - - - 1,546 2,000
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 8 8 7 3 3 3 3 3 1 1 1 2 2 2 1 1 1 1 51 65
DSM, Class 2, UT 88 81 83 81 80 51 49 43 42 40 14 13 11 12 11 14 11 10 9 8 639 750
DSM, Class 2, WY 25 25 25 26 26 3 3 3 3 3 3 2 2 2 2 2 2 2 1 1 141 159
DSM, Class 2 Total 120 112 115 115 114 58 55 48 48 46 18 17 13 15 14 17 15 13 11 10 830 973
Utility Solar - PV - - - - - - - - - - - - - 450 - - - - - - - 450
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.4 13.4 13.4 131 263
Micro Solar - Water Heating - - - 0.4 0.3 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 118 - 40 - - - 53 53 293 53 53 78 53 16 40
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
Colstrip3 (Early Retirement/Conversion)- - - - - - - - - - - - (74) - - - - - - - - (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - - - - - - - - - - - - (74) - - (74)
Coal Ret_Bridger -Gas RePower - - - - - - - - - 360 362 - - - - - - - - - 360 722
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - - - - - - - - - 30 - - - - - - - - - 30
Wind, HM, 29 - - - - - - - - - - 360 240 - - - - - - - - - 600
Total Wind - - - - - - - - - - 360 240 - - - - - - - - - 600
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 1 0 0 1 1 1 1 1 1 0 16 22
DSM, Class 2, OR 41 44 40 38 34 31 28 25 23 23 22 21 21 21 21 21 21 21 21 21 327 535
DSM, Class 2, WA 14 14 14 14 14 7 7 6 6 6 2 2 2 3 3 3 2 2 2 2 104 127
DSM, Class 2 Total 57 60 56 55 51 38 36 33 30 30 25 24 24 24 24 24 24 23 23 23 447 684
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 99 33 - 78 108 196 297 297 190 297 81 250 - - 120 297 - 188 297 61 160 144
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 - 81 196 206 240 255 266 375 375 375 375 375 4 343 375 375 345 375 375 375 237 284
Existing Plant Retirements/Conversions - - (164) - - - - (158) - (3) 8 (269) (1,208) (416) - (760) - (543) (148) -
Annual Additions, Long Term Resources 203 832 189 187 183 111 106 1,296 95 439 1,089 495 2,366 574 54 481 889 464 51 506
Annual Additions, Short Term Resources 599 614 696 784 848 951 1,063 1,290 1,065 1,212 956 1,125 504 896 1,048 1,465 898 1,116 1,250 989
Total Annual Additions 802 1,446 885 971 1,031 1,062 1,169 2,586 1,160 1,651 2,045 1,620 2,870 1,470 1,102 1,946 1,787 1,580 1,301 1,495
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-3 Case C-18 Capacity (MW)Resource Totals 1/
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
219

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - 181 - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 74 35 33 12 - - 44 4 - - - - - - - - - 198 202
Wind, Wyoming, 40 - - - - - - - - - - - 398 236 - - - - - - - - 634
Total Wind - - - 74 35 33 12 - - 44 4 398 236 - - - - - - - 198 836
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - 4 4 77 - - - - - - - 85
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 22 - - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 13 - 9 - - - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.2 - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 5 17 77 40 - - - - - - 139
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 2 3 2 2 2 30 55
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 21 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 7 55 123
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 34 33 30 30 29 581 932
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 157 254 26 167 261 262 207 49 142 199 300 250 273 265 64 143
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - - - - - - - 197 - 197
Wind, HM, 29 - - - - - - - - - - - - - - - - - - - 78 - 78
Total Wind - - - - - - - - - - - - - - - - - - - 78 - 78
Utility Biomass - - - - - - - - - - - - - - - - - - 35 5 - 40
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - 1 1 - - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - 26 1 45 - - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 17
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 18 19 18 18 18 283 487
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 22 23 22 22 22 361 610
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 108 229 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 333 333 352
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 191 148 137 112 95 96 141 88 515 997 385 121 919 72 911 103 348
Annual Additions, Short Term Resources 650 709 845 983 1,104 1,211 1,329 1,426 1,198 1,339 1,433 1,434 1,379 1,221 1,314 1,371 1,472 1,422 1,445 1,395
Total Annual Additions 790 1,485 966 1,174 1,252 1,348 1,441 1,521 1,294 1,480 1,521 1,949 2,376 1,606 1,435 2,290 1,544 2,333 1,548 1,743
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-3 Case C-19 Capacity (MW)Resource Totals 1/
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

220

Table K.10 – Energy Gateway Scenario 4 – Case C-01 to C-19

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
IC Aero WYAE - - - - - - - - - - - - - - - - 91 - - - - 91
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - - - 13
Total Wind - - - - - - - - - - - - - - - - - 13 - - - 13
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 3.6 7.6
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - 9 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 44 - - - 41 4 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 22 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 22 - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 0 - - 45 - - - 63 34 14 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 56 125
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 31 581 938
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 169 263 67 262 300 88 262 283 300 299 300 65 154
West Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - 423 - - - - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - - - 8 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 11 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 22 - - - 21 - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 13 2 - 15
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 2 - - - 2 - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - 1 1 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 39 - - - 24 14 26 - 103
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 19 22 22 22 26 26 283 509
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 24 26 26 26 30 30 361 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 378 389
FOT MidColumbia Q3 - 2 375 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 355 365
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 100 95 96 98 84 747 82 166 500 738 167 835 126 209
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,341 1,435 1,239 1,434 1,472 1,260 1,434 1,455 1,472 1,471 1,472
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,431 1,523 1,295 1,439 1,519 1,986 1,516 1,638 1,760 2,172 1,622 2,307 1,597 1,681
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-01
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
221

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - - - (387) - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - 661 661 661 - - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - 181 - - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 46 29 13 - - 44 - - - - - - - - - - 202 202
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - - - 13
Wind, Wyoming, 40 - - - - - - - - - - - - 544 - - - - - - - - 544
Total Wind - - - 70 46 29 13 - - 44 - - 544 - - - - 13 - - 202 759
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - 4 - 4 - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - 1 - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 48 - 41 - - - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - 8 7 - 7 - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - 0 - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 10 13 - - - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 2 - - - - - 2
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - 0.1 - - 0 - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - 19 72 - 54 - - - - - 144
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 2 2 2 2 30 55
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 21 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 55 124
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 31 30 30 29 581 931
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 39 157 254 26 169 263 140 300 300 202 300 40 164 218 208 65 139
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - - - - - - - 197 - 197
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 8 - - 8 - - - - - 15
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - 11 - - - - - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - 2 2 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - 1 1 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 2 - 2 - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - 1 - - - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - 2 - - - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - 13 49 - 22 - - - - - 84
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 21 23 22 22 22 22 22 18 18 18 18 282 489
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 28 28 27 27 27 28 26 22 22 22 22 359 611
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 297 87 297 297 297 182 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 370 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 365 358 377
FOT MidColumbia Q3 - 2 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - (387) (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 187 159 133 113 95 96 140 84 267 658 203 742 815 731 505 68 265
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,211 1,329 1,426 1,198 1,341 1,435 1,312 1,472 1,472 1,374 1,472 1,002 1,336 1,390 1,345
Total Annual Additions 790 1,485 966 1,171 1,263 1,344 1,442 1,521 1,294 1,481 1,519 1,579 2,130 1,675 2,116 2,287 1,733 1,841 1,458 1,610
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-02
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

222

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT F 2x1 - - - - - - - - - - - - - - - - 634 - - - - 634
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - - - - - 661
CCCT GH 2x1 - - - - - - - - - - - - 713 - - - - - - - - 713
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 34 13 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - 12 - 25
Wind, Wyoming, 40 - - - - - - - - - - - - 684 - - - - - - - - 684
Total Wind - - - 73 34 34 13 - - 45 5 - 684 - - - - 13 - 12 199 913
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - - - - 5 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 85 4 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 3 - - - 23 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 13 10 - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - 102 17 - - - 37 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 47 45 43 42 40 30 33 30 28 27 25 23 22 21 20 494 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 67 61 59 57 55 55 52 52 51 39 42 39 38 37 35 33 32 31 30 580 935
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 40 158 255 27 169 263 255 168 290 298 298 40 182 232 300 65 149
West Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 8 - - - - - - - 8 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 6 - 6
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - 22 - - 21 - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 41 - - 23 - - - - 16 - 80
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 22 22 22 22 19 19 22 24 282 499
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 26 29 28 27 27 27 28 26 23 23 26 28 360 622
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 297 108 297 297 297 182 230
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 370 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 358 379
FOT MidColumbia Q3 - 2 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 147 137 113 95 95 141 89 129 1,479 81 206 936 706 507 73 140
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,212 1,330 1,427 1,199 1,341 1,435 1,427 1,340 1,462 1,470 1,470 1,023 1,354 1,404 1,472
Total Annual Additions 790 1,485 966 1,174 1,251 1,349 1,443 1,522 1,294 1,482 1,524 1,556 2,819 1,543 1,676 2,406 1,729 1,861 1,477 1,612
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-03
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
223

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - (450) - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 - - 661 - - - - - - - - - - - - 1,322 1,322
CCCT GH 2x1 - - - - - - 736 - - 736 - - - - - - - 736 - - 1,472 2,208
CCCT J 1x1 - - - - - - - - 846 423 - 411 - - 423 - - - - - 1,269 2,103
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 2 2 2 2 2 27 47
DSM, Class 2, UT 63 55 51 48 49 47 44 40 40 35 27 32 29 27 26 25 23 22 21 20 471 723
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 6 7 7 7 7 7 7 55 122
DSM, Class 2 Total 68 62 58 56 57 55 53 49 50 45 35 40 37 36 35 33 32 31 30 29 553 892
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 182 68 177 - 253 261 117 216 - 112 238 40 101 204 62 116 241 117 125
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 17 17 17 17 18 18 18 18 19 19 19 273 454
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 65 101
DSM, Class 2 Total 45 48 41 40 38 33 29 25 24 24 22 22 22 23 23 22 22 23 22 22 347 572
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 202 297 297 297 297 212 297 297 297 297 297 297 297 297 243 266
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 82 100 100 100 100 100 100 99
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 269 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (927) (1,047) (788) 8 - - - - - - (495) (74) -
Annual Additions, Long Term Resources 140 770 117 113 774 103 832 752 937 1,244 74 490 75 76 498 72 71 806 69 68
Annual Additions, Short Term Resources 651 714 1,223 1,354 1,240 1,349 1,077 1,425 1,433 1,289 1,388 1,087 1,284 1,410 1,194 1,273 1,376 1,234 1,288 1,413
Total Annual Additions 791 1,484 1,340 1,467 2,014 1,452 1,909 2,177 2,370 2,533 1,462 1,577 1,359 1,486 1,692 1,345 1,447 2,040 1,357 1,481
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-04
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

224

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - (269) - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - (459) - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - (450) - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - - (220) - - - - - - - - - - (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - 661 661 661 - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - 736 - - - - - - - - 736 - - - - - - 736 1,472
CCCT J 1x1 - - - - - - - 411 423 423 411 - - - - - - 423 - - 1,257 2,091
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 2 2 2 2 2 2 2 28 50
DSM, Class 2, UT 63 55 51 48 49 47 44 40 40 40 30 33 30 27 26 25 23 22 21 20 477 734
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 6 7 7 7 7 7 7 55 122
DSM, Class 2 Total 68 62 58 56 57 55 53 49 50 51 39 42 39 36 35 33 32 30 30 29 560 906
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 181 - 108 140 225 175 128 79 108 300 34 40 40 99 112 165 291 107 117
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - - - (74) - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 20 19 19 18 18 18 18 18 19 19 275 463
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 66 102
DSM, Class 2 Total 45 49 41 40 38 33 29 26 24 26 25 24 24 23 23 22 22 22 22 22 350 582
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 297 297 297 297 297 83 275 254 297 297 297 297 252 261
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 67 - 100 100 100 100 100 100 93
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (548) (1,010) (1,237) (183) (212) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 117 187 884 137 770 1,164 1,175 563 498 515 297 812 75 72 71 492 69 68
Annual Additions, Short Term Resources 651 714 1,222 1,353 1,172 1,280 1,312 1,397 1,347 1,300 1,251 1,280 1,472 959 1,090 1,169 1,271 1,284 1,337 1,463
Total Annual Additions 791 1,485 1,339 1,540 2,056 1,417 2,082 2,561 2,522 1,863 1,749 1,795 1,769 1,771 1,165 1,241 1,342 1,776 1,406 1,531
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-05
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
225

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 2 3 3 3 3 3 3 3 32 59
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 508 767
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 6 7 7 7 7 7 7 7 56 126
DSM, Class 2 Total 73 67 61 60 59 61 58 53 52 51 40 43 38 38 37 35 33 32 31 30 596 952
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 28 142 237 6 148 241 263 40 40 147 201 300 57 107 230 56 109
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1 Total - - - - - - - - - - - 11 - - - - - - - - - 11
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 22 19 19 19 22 22 22 22 22 295 507
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 3 3 3 3 3 71 110
DSM, Class 2 Total 45 49 42 41 40 35 32 31 30 30 29 28 25 24 24 26 26 26 26 26 376 635
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 243 258 297 297 297 297 297 297 297 297 145 269 297 297 297 297 297 297 254 266
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 220 300 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 117 111 105 98 99 98 85 100 740 79 78 923 75 1,158 73 73
Annual Additions, Short Term Resources 646 705 841 978 1,097 1,200 1,314 1,409 1,178 1,320 1,413 1,435 1,060 1,184 1,319 1,373 1,472 1,229 1,279 1,402
Total Annual Additions 791 1,482 962 1,097 1,214 1,311 1,419 1,507 1,277 1,418 1,498 1,535 1,800 1,263 1,397 2,296 1,547 2,387 1,352 1,475
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-06
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

226

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - - - - - 661
CCCT J 1x1 - - - - - - - - - - - - - - - 423 - 846 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 436 218 - - - - - - - - 654
Total Wind - - - 73 35 34 13 1 - 46 6 436 218 - - - - - - - 202 862
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 81 - - - - - - - 81
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 2 - - 2
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - 81 - - - - 2 0 - 84
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 32 61
DSM, Class 2, UT 67 61 55 52 50 51 48 43 42 40 30 33 30 28 27 25 24 22 22 20 510 770
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 7 7 8 7 7 7 8 8 56 129
DSM, Class 2 Total 73 67 62 60 60 61 58 53 52 51 40 43 39 38 37 35 34 32 32 31 598 960
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 24 138 233 3 144 237 263 298 291 266 90 176 156 205 166 54 135
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - - 197 - - - - - - 197
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - 1 - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1 Total - - - - - - - - - - - 3 - 45 - - - 4 1 - - 53
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 23 23 26 22 23 23 26 26 26 295 536
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 4 4 3 3 3 71 114
DSM, Class 2 Total 45 49 42 41 40 36 32 31 30 30 29 29 29 32 28 28 28 30 30 29 377 668
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 242 263 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 254 276
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 97 214 297 375 375 375 375 375 375 375 375 375 361 364 375 370 365 366 258 314
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 122 192 153 145 118 99 99 144 91 529 484 212 279 1,163 78 929 81 258
Annual Additions, Short Term Resources 646 705 839 977 1,094 1,196 1,310 1,405 1,175 1,316 1,409 1,435 1,470 1,463 1,424 1,251 1,348 1,323 1,367 1,329
Total Annual Additions 791 1,482 961 1,169 1,247 1,341 1,428 1,504 1,274 1,460 1,500 1,964 1,954 1,675 1,703 2,414 1,426 2,252 1,448 1,587
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-07
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
227

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - (106) - - - - - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 1,322 - - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - 736 - - - - - - 736 - - - - - - 736 1,472
CCCT J 1x1 - - - - - - - 846 423 - 411 - - - - - - 411 423 - 1,269 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 55 54 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 483 742
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 51 39 42 39 38 37 35 33 32 31 30 567 922
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 176 61 160 - 16 - 71 64 96 290 34 33 40 75 93 61 61 59 72
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 19 19 19 19 22 22 22 22 22 22 275 485
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 103
DSM, Class 2 Total 45 49 41 41 38 33 29 26 24 26 25 24 24 24 27 26 26 26 26 26 352 606
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 184 297 227 297 297 297 297 138 265 297 297 297 32 155 234 236
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 - - 36 100 100 100 100 100 87
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (1,279) (279) (816) (548) - (268) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 117 774 1,425 832 937 514 94 491 83 79 814 80 78 76 485 497 73
Annual Additions, Short Term Resources 651 714 1,219 1,348 1,233 1,332 1,059 1,188 1,102 1,243 1,236 1,268 1,462 947 1,073 1,148 1,247 1,265 968 1,091
Total Annual Additions 791 1,485 1,339 1,465 2,007 2,757 1,891 2,125 1,616 1,337 1,727 1,351 1,541 1,761 1,153 1,226 1,323 1,750 1,465 1,164
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-08
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

228

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - (459) - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_UT - Gas RePower - - - - - - 468 - - - - - - - - - - - - - 468 468
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 661 661 - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
CCCT J 1x1 - - - - - - - 846 423 411 411 - - - 423 - - - - - 1,680 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, UT, 29 - - - - - - - - - - - - - 83 - - - - - - - 83
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 83 - - - - - - 202 941
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 27 55
DSM, Class 2, UT 63 55 51 51 49 47 44 40 40 39 30 33 30 28 27 25 23 22 21 20 479 737
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 58 59 57 55 53 49 50 49 39 42 39 38 37 35 33 32 31 30 561 917
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 178 64 235 21 150 64 - - - 177 300 82 159 258 40 61 145 82 102
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 19 19 19 19 19 19 22 22 22 23 275 479
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 66 103
DSM, Class 2 Total 45 49 41 40 38 33 29 26 24 26 25 24 24 24 24 23 26 26 26 27 351 599
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 297 260 254 283 297 297 297 297 297 231 260 297 249 265
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (714) (270) (816) (548) (106) (268) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 117 190 809 798 770 938 514 549 497 515 297 161 500 74 75 810 74 74
Annual Additions, Short Term Resources 651 714 1,222 1,350 1,236 1,407 1,193 1,322 1,236 1,135 1,129 1,158 1,349 1,472 1,254 1,331 1,430 1,146 1,196 1,317
Total Annual Additions 791 1,485 1,339 1,540 2,045 2,205 1,963 2,260 1,750 1,684 1,626 1,673 1,646 1,633 1,754 1,405 1,505 1,956 1,270 1,391
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-09
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
229

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - 661 - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - 411 - - - - - - 411
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - 9 - - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 4 - - 48 - 37 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 11 15 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - 3 - - 19 - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - - 4 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - 0 - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 1 - - 16 - - 67 0 48 25 - 157
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 31 30 581 937
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 170 263 67 262 298 94 268 299 299 299 300 65 155
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
ICE - - - - - - - - - - - - - - - - - 117 - - - 117
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 11 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - 1 1 - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 70 - - 1 1 - 16 - 88
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 22 22 22 22 22 22 25 26 282 511
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 106
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 29 28 27 27 28 27 26 26 26 30 30 360 635
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 378 389
FOT MidColumbia Q3 - 2 375 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 355 365
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 100 95 96 96 85 747 82 168 492 739 144 853 125 208
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,342 1,435 1,239 1,434 1,470 1,266 1,440 1,471 1,471 1,471 1,472
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,431 1,523 1,295 1,438 1,520 1,986 1,516 1,638 1,758 2,179 1,615 2,324 1,596 1,680
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-10
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

230

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - 91 - - - - 91
SCCT Frame UT - - - - - - - - - - - - - - - 181 - - - - - 181
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - 7.9 6.6 6.6 7.9 7.9 7.9 - 44.8
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 2.7 2.7 2.7 2.7 2.7 2.7 3.7 3.7 3.6 28.3
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 0 1 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 44 40 4 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 22 - - - - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - 4 - - - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - 45 97 4 - - 0 11 - 158
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 61
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 29 28 27 24 23 22 22 508 776
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 8 7 7 7 7 8 7 7 7 8 8 57 131
DSM, Class 2 Total 73 67 61 61 59 61 58 53 52 52 40 43 39 39 39 37 34 33 33 33 597 967
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 26 138 233 3 143 237 263 294 293 300 300 295 298 300 300 54 171
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
IC Aero WW - - - - - - - - - - - - - - - - - 99 - 99 - 198
Utility Biomass - - - - - - - - - - - - - - - - - - 20 5 - 25
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - 2.3 1.1 0.9 2.3 2.3 2.3 - 11.3
CHP - Other - - - - - - - - - - - - 0.3 0.3 0.4 0.3 0.3 0.4 0.4 0.4 - 2.7
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - 11 - - - - 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - 14 - 13 2 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - 1 - - - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 1 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 71 13 - 14 - 13 5 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 20
DSM, Class 2, OR 37 41 33 32 29 28 27 23 23 23 23 26 26 26 26 26 26 26 26 26 296 550
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 5 5 5 5 4 4 4 4 4 69 112
DSM, Class 2 Total 46 49 41 41 38 35 34 30 30 30 29 32 31 32 32 31 30 30 30 31 375 683
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 102 221 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 171 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 377 389
FOT MidColumbia Q3 - 2 375 204 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 354 365
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 192 150 144 121 99 99 144 91 525 489 206 210 940 196 853 128 214
Annual Additions, Short Term Resources 646 704 840 977 1,096 1,198 1,310 1,405 1,175 1,315 1,409 1,435 1,466 1,465 1,472 1,472 1,467 1,470 1,472 1,472
Total Annual Additions 791 1,481 961 1,169 1,246 1,342 1,431 1,504 1,274 1,459 1,500 1,960 1,955 1,671 1,682 2,412 1,663 2,323 1,600 1,686
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-11
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
231

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - 423 - 423 - - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 2 2 3 3 3 3 3 3 3 30 57
DSM, Class 2, UT 63 56 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 494 752
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 56 125
DSM, Class 2 Total 69 63 61 59 59 57 57 52 52 51 39 42 38 38 37 35 33 32 31 30 580 934
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 42 157 254 25 169 263 - 152 276 64 240 40 98 149 271 65 110
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 19 19 19 19 19 19 22 22 22 285 488
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 3 3 3 3 3 71 109
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 25 24 24 24 23 23 26 26 26 365 615
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 134 251 267 297 297 297 297 297 297 297 251 297 297 297 297 252 297 297 297 257 272
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 311 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 318
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 121 118 116 106 103 95 96 95 84 506 79 79 501 735 495 735 73 73
Annual Additions, Short Term Resources 650 713 849 988 1,108 1,214 1,329 1,426 1,197 1,341 1,435 1,126 1,324 1,448 1,236 1,412 1,167 1,270 1,321 1,443
Total Annual Additions 791 1,485 970 1,106 1,224 1,320 1,432 1,521 1,293 1,436 1,519 1,632 1,403 1,527 1,737 2,147 1,662 2,005 1,394 1,516
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-12
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

232

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - 43 - - - - - 693
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - 43 - - - - 202 901
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 2.7 0.4 0.5 2.7 0.4 3.6 12.5
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - 9 - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - 88 - - - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 22 - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 22 - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 4 - - - - - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - 0 - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 1 145 - - - - - 146
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 32 61
DSM, Class 2, UT 67 61 55 52 53 51 48 43 42 40 30 33 30 29 28 27 24 22 22 20 513 777
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 8 7 7 7 7 8 7 7 7 8 7 57 130
DSM, Class 2 Total 73 67 62 60 63 61 58 53 52 52 40 43 39 39 39 37 34 33 32 31 602 968
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 22 135 230 - 140 234 262 106 224 300 300 240 256 300 295 53 152
West Expansion Resources
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 420 - 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
IC Aero SO-CAL - - - - - - - - - - - - - - - - 182 - - - - 182
IC Aero WW - - - - - - - - - - - - - - - - - 99 - - - 99
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Other - - - - - - - - - - - - - - - - - - 0.3 - - 0.3
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - 15 - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - 4 - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - 1 - - - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 1 1 - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 51 22 - - - - - 73
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 20
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 26 26 26 26 26 26 26 26 22 295 545
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 4 4 3 3 3 71 114
DSM, Class 2 Total 45 50 42 41 40 36 32 31 30 30 29 32 31 32 32 31 30 30 30 26 377 679
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 242 262 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 254 275
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 97 214 294 375 375 375 375 375 375 375 375 375 375 375 375 375 375 147 258 305
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 122 192 156 145 118 99 99 145 91 523 728 87 140 958 262 839 82 493
Annual Additions, Short Term Resources 646 705 839 976 1,091 1,194 1,307 1,402 1,172 1,312 1,406 1,434 1,278 1,396 1,472 1,472 1,412 1,428 1,472 1,239
Total Annual Additions 791 1,482 961 1,168 1,247 1,339 1,425 1,501 1,271 1,457 1,497 1,957 2,006 1,483 1,612 2,430 1,674 2,267 1,554 1,732
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-13
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
233

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - (416) - - - - - - - - - - - - (416) (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - (269) - - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - - - - - (459) - - - - - - - (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - - (450) - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - (205) - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT F 2x1 - - - - - - - - - - - 634 - - - - - - - - - 634
CCCT FD 2x1 - - - - - - - - - - - - - 661 - 1,322 - - - - - 1,983
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
CCCT J 1x1 - - - - - - 423 1,680 - 423 411 - - - - - - - - - 2,526 2,937
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 34 13 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - - - 13
Wind, Wyoming, 40 - - - - - - - - 316 - - - 684 - - - - - - - 316 1,000
Total Wind - - - 73 34 34 13 - 316 45 5 - 684 - - - - 13 - - 515 1,217
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 6 6 6 2 3 3 3 3 1 1 1 2 1 1 1 1 1 1 45 58
DSM, Class 2, UT 84 76 70 73 71 44 42 35 41 39 13 13 10 11 10 13 11 9 8 7 575 681
DSM, Class 2, WY 24 24 24 24 25 3 3 2 3 2 2 2 1 2 2 2 2 1 1 1 136 153
DSM, Class 2 Total 114 106 101 103 102 50 48 41 46 44 17 16 13 14 13 16 14 12 11 10 755 891
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.2 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 60 171 - 157 249 52 55 - 169 148 299 40 40 2 53 61 69 78
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - (363) - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - - 362 - - - - - - - - - 719 1,081
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 1 1 0 0 15 19
DSM, Class 2, OR 37 41 34 33 30 28 24 21 19 20 21 20 20 20 20 20 20 20 20 20 285 485
DSM, Class 2, WA 13 12 13 14 14 6 6 6 6 6 2 2 2 2 2 2 2 1 1 1 96 112
DSM, Class 2 Total 52 55 49 49 46 35 31 28 26 26 23 22 22 22 22 22 22 21 22 22 396 616
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - 54 28 82 297 297 297 297 297 297 297 256 297 297 297 176 294 68 86 221 195 212
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 107 75 200 236 375 375 321 375 375 375 375 375 375 375 375 375 375 375 375 375 281 328
Existing Plant Retirements/Conversions - - (164) 8 (378) - - (1,674) (363) - (261) (450) - (459) - (760) - (338) (74) -
Annual Additions, Long Term Resources 192 822 167 243 200 134 529 1,763 404 555 473 689 736 714 51 1,376 52 799 50 48
Annual Additions, Short Term Resources 607 629 728 818 1,232 1,343 1,118 1,329 1,421 1,224 1,227 1,131 1,341 1,320 1,471 1,091 1,209 945 1,014 1,157
Total Annual Additions 799 1,451 895 1,061 1,432 1,477 1,647 3,092 1,825 1,779 1,700 1,820 2,077 2,034 1,522 2,467 1,261 1,744 1,064 1,205
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-14
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

234

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame UT - - - - - - - - - - - - - - 181 362 - 362 - - - 905
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
SCCT Frame WYAE - - - - - - - - - - - - - - - - - 181 - - - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - - - 181 - - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 515 - - - - - 515
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 34 13 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - - - 13
Wind, Wyoming, 40 - - - - - - - - - - - - 684 - - - - - - - - 684
Total Wind - - - 73 34 34 13 - - 45 5 - 684 - - - - 13 - - 199 901
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 2.7 2.7 2.7 0.4 0.4 3.6 14.4
DSM, Class 1, ID-Curtail - - - - - - - - - - - - 9 - - - - - - - - 9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 85 - - 4 - - - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 19 3 - - - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 3 19 - - - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1 Total - - - - - - - - - - 0 - 97 37 3 4 - 4 - - - 145
DSM, Class 2, ID 6 6 6 6 6 2 2 2 2 3 1 1 1 2 1 1 1 1 1 1 39 52
DSM, Class 2, UT 81 74 68 65 63 39 37 37 37 37 12 11 9 10 9 12 11 9 7 6 537 634
DSM, Class 2, WY 23 23 23 23 23 2 2 2 2 2 2 2 1 2 2 2 2 1 1 1 128 144
DSM, Class 2 Total 111 103 97 94 92 43 41 41 41 42 16 14 11 13 12 15 14 12 10 9 704 830
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - 7 115 - 56 171 235 190 300 298 297 257 300 215 284 18 136
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - - - - - - - - - - - 181 203 - - - 384
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 8 - - - - - - - - 8
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - 1 - - - 1
DSM, Class 1 Total - - - - - - - - - - - - 8 - - - - 1 - - - 8
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 0 0 0 0 12 16
DSM, Class 2, OR 36 41 33 32 29 26 22 19 17 17 18 17 18 17 17 19 19 19 17 17 274 451
DSM, Class 2, WA 12 12 12 12 12 5 5 5 5 5 2 1 1 1 1 2 1 1 1 1 86 98
DSM, Class 2 Total 51 55 47 46 43 32 28 24 23 23 20 19 19 19 19 21 21 20 18 18 372 565
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - - 57 175 297 297 197 297 297 297 297 297 297 297 297 297 297 297 132 215
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 135 160 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 350 375
FOT MidColumbia Q3 - 2 375 375 237 346 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 358 367
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 188 818 163 231 187 123 97 80 80 126 57 50 1,016 86 232 936 234 815 225 134
Annual Additions, Short Term Resources 610 635 737 846 932 1,050 1,179 1,287 1,072 1,228 1,343 1,407 1,362 1,472 1,470 1,469 1,429 1,472 1,387 1,456
Total Annual Additions 798 1,453 900 1,077 1,119 1,173 1,276 1,367 1,152 1,354 1,400 1,457 2,378 1,558 1,702 2,405 1,663 2,287 1,612 1,590
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-15
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
235

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - - - 115 - - - - - - - 115
Wind, GO, 29 - - - - 63 - - - - 63 - - - - - - - - - - 126 126
Wind, Wyoming, 40 - - - - - - - - - - - - 446 - - - - - - - - 446
Total Wind - - - - 63 - - - - 63 - - 446 - - - - - - - 126 572
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - - - 9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 85 - - - - - - 85
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 0 - - 116 - - - - - - 116
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 2 2 2 2 2 30 54
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 56 123
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 33 31 30 30 29 581 930
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 18 136 233 4 145 237 263 298 284 300 40 40 116 170 296 54 129
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - 25 - - - - - - - - - 5 - - - - - - 25 30
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - - - - - 8
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 21 - - - - - - - 21
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1 Total - - - - - - - - - - 3 8 - 29 1 - - - - - - 41
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 17
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 18 18 18 18 18 284 487
DSM, Class 2, WA 8 7 7 7 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 104
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 27 28 22 22 22 22 22 361 609
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 87 207 297 297 297 297 297 297 297 297 297 297 163 266 297 297 297 178 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 370 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 358 379
FOT MidColumbia Q3 - 2 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 142 176 104 100 95 96 161 87 95 709 231 198 1,394 70 730 68 68
Annual Additions, Short Term Resources 650 709 845 962 1,082 1,190 1,308 1,405 1,176 1,317 1,409 1,435 1,470 1,456 1,472 1,078 1,181 1,288 1,342 1,468
Total Annual Additions 790 1,485 966 1,104 1,258 1,294 1,408 1,500 1,272 1,478 1,496 1,530 2,179 1,687 1,670 2,472 1,251 2,018 1,410 1,536
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-16
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

236

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - - - 661 - - - 661
CCCT J 1x1 - - - - - - - - - - - - - 423 - 846 - - - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - - - 181 - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 34 13 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - - - 13
Wind, Wyoming, 40 - - - - - - - - - - - - 684 316 - - - - - - - 1,000
Total Wind - - - 73 34 34 13 - - 45 5 - 684 316 - - - 13 - - 199 1,217
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - 9 - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - 7 81 - - - 88
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 3 10 - - - - 13
DSM, Class 1 Total - - - - - - - - - - - - - 1 - 3 17 90 - - - 111
DSM, Class 2, ID 3 3 3 4 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 34 62
DSM, Class 2, UT 68 61 57 55 53 51 48 44 44 42 31 34 30 29 28 27 25 23 22 20 523 792
DSM, Class 2, WY 4 4 5 5 6 6 7 7 7 8 7 7 7 7 8 7 7 7 8 8 59 132
DSM, Class 2 Total 74 68 65 64 63 61 59 55 55 53 41 43 40 40 39 37 35 33 32 31 616 987
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 70 - - 50 102 283 53 170 189 245 249 300 261 7 99
West Expansion Resources
CCCT GH 1x1 - - - - 420 - - - - - - - - - - - - - - - 420 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - 22 - 21 - - - 44
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - 2 - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - - 24 - 21 - - - 46
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 21
DSM, Class 2, OR 37 41 34 34 33 31 27 24 24 24 26 26 26 26 26 26 26 26 26 26 308 565
DSM, Class 2, WA 8 8 8 8 8 7 7 7 7 7 5 5 5 5 5 4 4 3 3 3 74 118
DSM, Class 2 Total 46 50 43 43 42 39 35 32 32 32 32 32 31 32 32 30 30 30 30 30 393 703
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 163 125 239 291 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 260 279
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 383 400 400 400 330 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 391 396
FOT MidColumbia Q3 - 2 - 79 97 178 - 31 142 166 3 143 183 163 168 166 177 180 202 186 181 183 84 131
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 146 778 125 198 578 148 121 101 103 147 94 92 772 828 87 957 99 865 79 258
Annual Additions, Short Term Resources 646 704 836 969 727 828 939 1,033 800 940 1,030 1,062 1,248 1,016 1,144 1,166 1,244 1,232 1,278 1,241
Total Annual Additions 792 1,482 961 1,167 1,305 976 1,060 1,134 903 1,087 1,124 1,154 2,020 1,844 1,231 2,123 1,343 2,097 1,357 1,499
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-4 Case C-17
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
237

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - - - - - - (416) - - - - - - - (416)
Hunter3 (Early Retirement/Conversion)- - - - - - - - - - - - (479) - - - - - - - - (479)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - - - (268) - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
WY IGCC CCS - - - - - - - - - - - - - - - - - - - 456 - 456
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 834 - - - 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Nuclear - - - - - - - - - - - - 2,236 - - - - - - - - 2,236
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - 105 - - - - - - - - - 105
Wind, GO, 29 - - - - - - - - - - 373 62 60 105 - - - - - - - 600
Wind, UT, 29 - - - - - - - - - - 200 - - - - - - - - - - 200
Wind, Wyoming, 40 - - - - - - - 650 350 - - - - - - - - - - - 1,000 1,000
Total Wind - - - - - - - 650 350 - 573 62 60 105 - - - - - - 1,000 1,800
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 8 8 7 3 3 3 3 3 1 1 1 2 2 2 1 1 1 1 51 65
DSM, Class 2, UT 88 81 77 81 80 51 49 43 42 40 14 13 11 12 10 14 11 10 9 8 633 743
DSM, Class 2, WY 25 25 25 26 26 3 3 3 3 3 3 2 2 2 2 2 2 2 1 1 141 159
DSM, Class 2 Total 120 112 109 115 114 58 55 48 48 46 18 17 13 15 14 17 15 13 12 10 824 967
Utility Solar - PV - - - - - - - - - - - - - 450 - - - - - - - 450
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.4 13.4 13.4 131 263
Micro Solar - Water Heating - - - 0.4 0.3 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 128 - 49 143 80 - 53 53 134 250 122 190 53 18 63
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
Colstrip3 (Early Retirement/Conversion)- - - - - - - - - - - - (74) - - - - - - - - (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - - - - - - - - - (74) - - - - - (74)
Coal Ret_Bridger -Gas RePower - - - - - - - - - - 362 - - - - - - - - - - 362
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - - - - - - - - - 30 - - - - - - - - - 30
Wind, WV, 29 - - - - - - - - - - - - - - - 300 - - - - - 300
Total Wind - - - - - - - - - - - - - - - 300 - - - - - 300
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 1 0 0 1 1 1 1 1 1 0 16 22
DSM, Class 2, OR 41 44 40 38 34 31 28 25 23 23 22 21 21 21 21 21 21 21 21 21 327 535
DSM, Class 2, WA 14 14 14 14 14 7 7 6 6 6 2 2 2 3 3 3 2 2 2 2 104 126
DSM, Class 2 Total 57 60 56 55 51 38 36 33 30 30 25 24 24 24 24 24 24 23 23 23 447 684
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 99 33 - 83 113 201 297 297 197 297 297 297 - 95 248 297 297 297 297 173 162 196
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 - 81 201 206 240 255 271 375 375 375 375 375 210 375 375 375 375 375 375 375 238 298
Existing Plant Retirements/Conversions - - (164) - - - - (158) - - 8 - (1,208) (416) - (834) - (543) (74) -
Annual Additions, Long Term Resources 203 832 183 187 183 111 106 746 445 93 632 254 2,350 611 54 1,204 55 887 51 506
Annual Additions, Short Term Resources 599 614 701 789 853 956 1,068 1,300 1,072 1,221 1,315 1,252 710 1,023 1,176 1,306 1,422 1,294 1,362 1,101
Total Annual Additions 802 1,446 884 976 1,036 1,067 1,174 2,046 1,517 1,314 1,947 1,506 3,060 1,634 1,230 2,510 1,477 2,181 1,413 1,607
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-4 Case C-18 Capacity (MW)Resource Totals 1/
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

238

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - 736 - - - - - - - - 736
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 34 13 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - 10 - - - - - - 13 - - - 23
Wind, Wyoming, 40 - - - - - - - - - - - - 684 - - - - - - - - 684
Total Wind - - - 73 34 34 13 - - 45 15 - 684 - - - - 13 - - 199 911
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 3.6 7.6
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 41 4 - - - 47 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 3 7 - - - 15 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - 0 - - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - 4 - - - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 0 1 - - 79 11 - - - 65 - 157
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 60 54 51 49 47 45 43 42 40 30 33 30 28 27 25 23 22 21 20 494 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 55 55 52 52 51 39 42 39 38 37 35 33 32 31 31 580 936
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 169 263 263 156 277 300 300 244 196 251 300 65 160
West Expansion Resources
CCCT GH 1x1 - - - - - - - - - - - - - - - - - 420 - - - 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - - - - - - - - - - - 181 - - - - 181
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 8 - - - 8 - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 2 - - 2 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - 22 - - 21 - - - - 3 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 2 - - 2 - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - 1 - - - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 1 - - - - 1 - 2
DSM, Class 1 Total - - - - - - - - - - - 34 - - 31 8 - - - 3 - 76
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 22 22 22 20 19 22 22 26 283 502
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 104
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 29 28 27 27 27 27 24 22 26 26 29 360 624
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 192 400 378 378
FOT MidColumbia Q3 - 2 375 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 171 375 168 355 345
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 147 137 113 95 96 141 99 121 1,502 81 191 936 253 1,168 74 146
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,341 1,435 1,435 1,328 1,449 1,472 1,472 1,416 1,164 1,215 1,265
Total Annual Additions 790 1,485 966 1,174 1,252 1,350 1,444 1,523 1,295 1,482 1,534 1,556 2,830 1,530 1,663 2,408 1,669 2,332 1,289 1,411
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-4 Case C-19 Capacity (MW)Resource Totals 1/
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
239

Table K.11 – Energy Gateway Scenario 5 – Case C-01 to C-19

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - 661 - 661 - - - 1,983
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 368 - 368
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 343 - - - - - 343
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 37 - 48 4 - - - - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 19 - - - - - - - 19
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 1 37 19 79 4 - - - - - 139
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 2 2 2 31 56
DSM, Class 2, UT 66 61 54 51 49 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 502 761
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 7 56 126
DSM, Class 2 Total 72 67 61 59 57 57 58 52 52 51 39 43 39 38 37 35 33 31 30 29 588 943
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 37 152 249 21 162 257 263 168 270 299 172 270 220 273 237 62 153
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 22 - 21 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - 26 22 1 23 - - - - - - 73
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 22 22 19 19 18 284 495
DSM, Class 2, WA 8 7 7 7 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 26 26 23 23 22 361 619
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 106 227 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 172 231 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 360 380
FOT MidColumbia Q3 - 2 375 375 342 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 372 373
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 144 776 121 117 113 104 103 95 96 98 84 114 803 102 184 1,086 76 912 69 436
Annual Additions, Short Term Resources 647 706 842 981 1,102 1,209 1,324 1,421 1,193 1,334 1,429 1,435 1,340 1,442 1,471 1,344 1,442 1,392 1,445 1,409
Total Annual Additions 791 1,482 963 1,098 1,215 1,313 1,427 1,516 1,289 1,432 1,513 1,549 2,143 1,544 1,655 2,430 1,518 2,304 1,514 1,845
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-01
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

240

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - 846 - - - - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
ICE - - - - - - - - - - - - - - - - - 103 - - - 103
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 70 47 30 13 - - 44 - - - - - - - - - - 204 204
Wind, Wyoming, 40 - - - - - - - - - - - - 546 - - - - - - - - 546
Total Wind - - - 70 47 30 13 - - 44 - - 546 - - - - - - - 204 750
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 6.6 7.9 - 14.5
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.8 2.7 2.7 3.6 12.5
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - 4 - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - 4 - - 7 - 77 - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - 4 11 7 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 13 10 - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 4 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 5 - - 12 13 95 11 11 12 - 158
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 31 59
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 22 21 495 756
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 8 8 56 127
DSM, Class 2 Total 69 67 61 59 57 57 55 52 52 51 39 42 39 38 37 35 33 33 32 32 581 942
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 38 156 253 25 166 260 262 101 223 299 300 300 299 299 299 64 164
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Wind, HM, 29 - - - - - - - - - - - - - - - 55 22 - - - - 77
Total Wind - - - - - - - - - - - - - - - 55 22 - - - - 77
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 1.4 1.8 - 3.2
CHP - Other - - - - - - - - - - - - - - - - - - 0.4 0.4 - 0.8
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - 11 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 14 15 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - 2 - - - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 28 - - 44 - - - 26 18 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 26 26 26 26 26 284 523
DSM, Class 2, WA 8 7 7 7 8 7 6 6 6 6 4 4 4 4 4 4 4 3 3 3 68 108
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 30 30 30 30 30 361 649
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 108 229 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 361 380
FOT MidColumbia Q3 - 2 375 375 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 372 374
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 187 160 134 113 95 96 142 84 120 1,474 82 137 992 197 854 127 212
Annual Additions, Short Term Resources 650 709 845 983 1,104 1,210 1,328 1,425 1,197 1,338 1,432 1,434 1,273 1,395 1,471 1,472 1,472 1,471 1,471 1,471
Total Annual Additions 790 1,485 966 1,170 1,264 1,344 1,441 1,520 1,293 1,480 1,516 1,554 2,747 1,477 1,608 2,464 1,669 2,325 1,598 1,683
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-02
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
241

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - - (387) - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - 661 - 1,322 - - - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 3.6 7.3
DSM, Class 1, ID-Curtail - - - - - - - - - - - 4 4 - - - - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - 1 - - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 85 - - - - - - 7 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - 4 - - 18 - - - - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - 22 - - - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - 2 - - - - 2 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - 1 8 111 - 20 - - - - 16 - 157
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 61 54 51 49 47 45 42 42 40 30 33 30 28 27 25 23 22 21 20 494 752
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 55 125
DSM, Class 2 Total 69 67 61 59 57 55 54 52 52 51 39 42 39 38 37 35 33 32 31 30 579 935
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 40 159 256 28 170 263 263 299 190 300 40 40 178 228 300 65 138
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 11 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 44 - - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - - 15 - 15
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 1 - - 1 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 2 2 - - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - 1 - - 1 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 24 46 - 2 - - - - 31 - 103
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 22 22 22 18 19 22 22 26 282 500
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 26 29 28 27 27 27 28 22 23 26 26 30 359 623
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 229 297 297 297 297 297 297 297 297 297 297 161 262 297 297 297 182 231
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 361 380
FOT MidColumbia Q3 - 2 375 375 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 372 374
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - (387) - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 148 137 112 95 95 142 91 550 457 743 104 1,396 72 678 73 124
Annual Additions, Short Term Resources 650 709 845 984 1,104 1,212 1,331 1,428 1,200 1,342 1,435 1,435 1,471 1,362 1,472 1,076 1,177 1,350 1,400 1,472
Total Annual Additions 790 1,485 966 1,174 1,252 1,349 1,443 1,523 1,295 1,484 1,526 1,985 1,928 2,105 1,576 2,472 1,249 2,028 1,473 1,596
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-03
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

242

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - (450) - - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - - (220) - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT F 2x1 - - - - - - - - - - 634 - - - - - - - - - - 634
CCCT FD 2x1 - - - - 661 - - 1,322 - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - - - 736 - - - - 736 - - - - - 736 1,472
CCCT J 1x1 - - - - - - 423 - 423 423 - - - - - - - - - 411 1,269 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 3 2 2 3 3 3 3 3 3 3 2 27 53
DSM, Class 2, UT 63 55 50 48 45 43 41 39 39 39 30 33 30 28 27 25 23 22 21 20 463 721
DSM, Class 2, WY 3 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 54 123
DSM, Class 2 Total 68 62 58 56 54 52 49 48 49 49 38 41 38 38 37 35 33 32 31 29 545 897
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 112 185 74 186 209 125 83 - - - 109 232 33 40 40 250 300 88 97 103
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 35 40 33 32 29 26 22 19 17 17 17 19 19 19 20 22 22 22 22 19 270 471
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 64 101
DSM, Class 2 Total 43 48 41 40 37 33 29 25 24 24 22 24 24 24 25 26 26 26 26 22 344 589
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 38 65 342 297 297 297 297 297 297 233 179 212 297 297 99 153 211 297 297 297 246 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 - - 41 100 100 100 100 87
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 151 270 375 375 375 375 375 375 375 375 375 375 375 361 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) - (279) (1,084) (597) (788) (442) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 138 770 116 113 770 99 516 1,412 512 1,249 711 82 79 78 814 78 76 74 74 479
Annual Additions, Short Term Resources 652 716 1,224 1,357 1,246 1,358 1,381 1,297 1,255 1,108 1,054 1,087 1,281 1,404 893 968 1,067 1,422 1,472 1,260
Total Annual Additions 790 1,486 1,340 1,470 2,016 1,457 1,897 2,709 1,767 2,357 1,765 1,169 1,360 1,482 1,707 1,046 1,143 1,496 1,546 1,739
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-04
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
243

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - (416) - - - - - - - - - - - (416) (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - (269) - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - (459) - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - (450) - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - (158) - - - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - 661 661 - - - - - - - - - - - 1,322 1,322
CCCT GH 2x1 - - - - - - - - - 736 - - - - - - - - - - 736 736
CCCT J 1x1 - - - - - 423 423 423 - 423 - - - - - 411 - 411 - - 1,692 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - 15 - - - - 665
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - 15 - - - 202 873
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - 7.5 7.9 7.9 7.9 7.9 - 39.1
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 2.7 2.7 2.7 2.7 2.7 2.7 2.7 3.7 3.6 27.3
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 37 15 37 - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - 19 3 - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - 4 - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 1 68 15 59 3 1 11 - 158
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 56 54 51 49 47 45 43 42 40 30 33 30 28 27 26 25 23 22 21 490 756
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 8 8 55 128
DSM, Class 2 Total 69 63 61 59 57 55 54 52 52 51 39 43 39 38 38 36 35 33 33 32 575 942
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 263 164 248 181 232 - - - 187 299 282 282 300 300 300 299 109 167
Capacity (MW)Resource Totals 1/EG-5 Case C-05
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

244

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
CCCT J 1x1 - - - - - - - - 423 - - - - - - - - - - - 423 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Fly Wheel - - - - - - - - - - - - - - - - - - - 10 - 10
Utility Biomass - - - - - - - - - - - - - - - - - - - 5 - 5
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - 0.2 2.3 2.3 2.3 2.3 - 9.4
CHP - Other - - - - - - - - - - - - 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 - 2.7
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - 15 - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - 6 - 6 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 27 2 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - 1 - 1 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 3 69 - 6 - 33 5 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 19
DSM, Class 2, OR 36 40 33 32 29 26 22 19 20 23 23 22 22 26 26 26 26 26 26 26 281 527
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 5 5 4 4 3 3 3 67 108
DSM, Class 2 Total 45 49 41 41 38 33 29 26 27 30 28 27 27 32 32 31 30 30 30 30 358 655
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 143 124 297 297 297 297 297 181 272 297 297 297 297 297 297 297 297 297 203 249
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 149 207 353 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 307 341
Existing Plant Retirements/Conversions - - (164) 8 (378) (158) (353) (853) (1,355) (568) 8 - - - - (328) - (338) (74) -
Annual Additions, Long Term Resources 140 772 120 190 148 560 534 1,180 1,180 1,302 90 519 303 93 226 520 175 507 127 214
Annual Additions, Short Term Resources 651 713 850 977 1,435 1,336 1,420 1,353 1,404 1,056 1,147 1,172 1,359 1,471 1,454 1,454 1,472 1,472 1,472 1,471
Total Annual Additions 791 1,485 970 1,167 1,583 1,896 1,954 2,533 2,584 2,358 1,237 1,691 1,662 1,564 1,680 1,974 1,647 1,979 1,599 1,685
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-5 Case C-05, cont.Capacity (MW)Resource Totals 1/
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
245

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 2 3 3 3 3 3 3 3 32 59
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 508 767
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 6 7 7 7 7 7 7 7 56 126
DSM, Class 2 Total 73 67 61 60 59 61 58 53 52 51 40 43 38 38 37 35 33 32 31 30 596 952
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 28 142 237 6 148 241 263 40 40 147 201 300 59 109 232 56 110
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1 Total - - - - - - - - - - - 11 - - - - - - - - - 11
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 31 28 24 23 23 23 23 22 19 19 19 22 22 19 22 22 295 504
DSM, Class 2, WA 8 8 8 8 8 7 7 6 7 7 5 5 5 5 5 3 3 3 3 3 71 110
DSM, Class 2 Total 45 49 42 41 40 35 32 31 30 30 29 28 25 24 24 26 26 23 26 26 376 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 127 126 243 258 297 297 297 297 297 297 297 297 145 269 297 297 297 297 297 297 254 266
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 220 300 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 119 117 111 105 98 99 98 85 100 740 79 78 923 76 1,155 73 73
Annual Additions, Short Term Resources 646 705 841 978 1,097 1,200 1,314 1,409 1,178 1,320 1,413 1,435 1,060 1,184 1,319 1,373 1,472 1,231 1,281 1,404
Total Annual Additions 791 1,482 962 1,097 1,214 1,311 1,419 1,507 1,277 1,418 1,498 1,535 1,800 1,263 1,397 2,296 1,548 2,386 1,354 1,477
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-06
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

246

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - - - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - - - - 423 - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - 3 - - 653
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - 3 - 202 861
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 4 - - 4 - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 11 - - - 40 - - 51
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 3 - - 3
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 22 - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 17 - - 27 44 - - 87
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 61 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 499 759
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 7 7 56 127
DSM, Class 2 Total 69 67 61 59 59 57 57 52 52 51 39 42 39 38 37 35 33 32 32 30 586 945
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 36 151 248 19 162 257 - 134 255 298 40 40 297 300 277 62 126
West Expansion Resources
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 420 - 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - 15 - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 44 - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 72 - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 22 22 22 23 22 23 26 26 22 285 516
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 112
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 28 28 28 29 27 28 30 30 26 365 646
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 130 247 268 297 297 297 297 297 297 297 238 297 297 297 156 254 297 297 297 256 264
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 215 305 375 375 375 375 375 375 375 375 375 375 375 375 375 375 166 259 307
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 777 121 191 151 140 117 96 96 141 90 942 302 83 172 1,400 77 528 125 493
Annual Additions, Short Term Resources 650 709 845 983 1,102 1,208 1,323 1,420 1,191 1,334 1,429 1,113 1,306 1,427 1,470 1,071 1,169 1,469 1,472 1,240
Total Annual Additions 791 1,486 966 1,174 1,253 1,348 1,440 1,516 1,287 1,475 1,519 2,055 1,608 1,510 1,642 2,471 1,246 1,997 1,597 1,733
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-07
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
247

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - (106) - - - - - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - (205) - - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - 1,322 661 - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - 736 - - 736 - - - - - - - 736 - - - - 1,472 2,208
CCCT J 1x1 - - - - - - - - 423 - 423 - 423 - - - - - - - 423 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, Wyoming, 40 - - - - - - - - - - - - - - - - - - - 509 - 509
Total Wind - - - - - - - - - - - - - - - - - - - 509 - 509
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 3 3 3 3 3 3 3 3 28 56
DSM, Class 2, UT 63 56 54 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 484 742
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 51 39 42 39 38 37 35 33 32 31 30 567 922
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 - 93 - 70 - 124 108 140 40 111 240 40 40 129 179 300 57 95
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 17
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 19 19 19 19 19 22 22 22 22 19 275 478
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 103
DSM, Class 2 Total 45 49 41 41 38 33 29 26 24 26 25 24 24 24 24 26 26 26 26 22 352 599
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 291 297 184 297 281 297 297 297 245 297 297 33 123 297 297 297 239 243
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 - 9 100 100 100 100 90
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (1,279) (279) (816) (548) - (268) - - - - - - (338) (74) -
Annual Additions, Long Term Resources 140 771 120 117 849 1,425 757 827 514 94 503 83 502 78 77 814 76 74 74 578
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,166 1,265 1,059 1,242 1,156 1,296 1,280 1,312 1,160 1,283 1,412 848 947 1,301 1,351 1,472
Total Annual Additions 791 1,485 1,339 1,464 2,015 2,690 1,816 2,069 1,670 1,390 1,783 1,395 1,662 1,361 1,489 1,662 1,023 1,375 1,425 2,050
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-08
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

248

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - (418) - - - - - - - - - - - - - - - - - (418) (418)
Hunter2 (Early Retirement/Conversion)- - - - - (269) - - - - - - - - - - - - - - (269) (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - (459) - - - - - - - - - - - - - - (459) (459)
Huntington2 (Early Retirement/Conversion)- - - - - (450) - - - - - - - - - - - - - - (450) (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 (Early Retirement/Conversion)- - - - - - - (106) - - - - - - - - - - - - (106) (106)
Johnston2 (Early Retirement/Conversion)- - - - - - - - - (106) - - - - - - - - - - (106) (106)
Johnston3 (Early Retirement/Conversion)- - - - - - - - (220) - - - - - - - - - - - (220) (220)
Johnston4 (Early Retirement/Conversion)- - - - - - - - (328) - - - - - - - - - - - (328) (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - (268) - - - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - 661 1,322 - - - - - - - - - - - - - - 1,983 1,983
CCCT GH 2x1 - - - - - - - 736 - - - - 736 - - - - 736 - - 736 2,208
CCCT J 1x1 - - - - - - - 423 423 - 423 - - - - - - - - - 846 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 33 14 - - 49 - - - - - - - - - - 204 204
Wind, Wyoming, 40 - - - - - - - - - 42 - 439 - - - - - - - 509 42 990
Total Wind - - - 73 35 33 14 - - 91 - 439 - - - - - - - 509 246 1,194
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 3 4 3 3 2 3 3 3 3 3 3 3 28 55
DSM, Class 2, UT 63 56 54 51 49 47 44 40 40 40 30 33 30 28 27 25 23 22 21 20 484 742
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 6 7 7 7 7 7 8 55 124
DSM, Class 2 Total 69 62 61 59 57 55 53 49 50 51 39 42 38 37 37 35 33 32 31 30 567 921
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - - 2.2 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 109 175 60 64 249 86 - 233 217 246 40 40 54 129 228 125 175 293 98 126
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - (354) - - - - - - - - - - - - - - (354) (354)
JBridger2 (Early Retirement/Conversion)- - - - - (363) - - - - - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - (74) - - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 722 - - - - - - - - - - - - - - 1,441 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 18
DSM, Class 2, OR 36 40 33 32 29 26 22 19 17 19 19 19 19 19 19 22 22 22 22 23 275 482
DSM, Class 2, WA 7 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 103
DSM, Class 2 Total 45 49 41 41 38 33 29 26 24 26 25 24 24 24 24 26 26 26 26 27 352 603
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 37 64 342 297 297 297 297 297 297 297 297 297 59 183 297 297 297 297 297 297 252 257
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 114 150 268 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 316 345
Existing Plant Retirements/Conversions - - (582) 8 (378) (1,173) (74) (816) (548) (106) (268) - - - - - - (543) (74) -
Annual Additions, Long Term Resources 140 771 120 190 809 1,458 110 1,250 514 185 503 522 814 78 77 78 76 810 74 583
Annual Additions, Short Term Resources 651 714 1,219 1,347 1,232 1,236 1,421 1,258 1,172 1,405 1,389 1,418 974 1,098 1,226 1,301 1,400 1,297 1,347 1,465
Total Annual Additions 791 1,485 1,339 1,537 2,041 2,694 1,531 2,508 1,686 1,590 1,892 1,940 1,788 1,176 1,303 1,379 1,476 2,107 1,421 2,048
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-09
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
249

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - - - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - 181 - - - - - - 181
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 7.9 7.9 - 15.8
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 2.7 0.8 2.7 2.7 3.6 14.7
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - 9 - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 37 - - 15 - - 40 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - 11 - 11 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 22 - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 2 2 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 38 - - 57 - 13 51 - 158
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 24 22 22 21 495 757
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 8 8 56 128
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 34 32 32 32 581 943
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 256 27 169 263 67 262 297 272 286 298 278 300 298 65 164
West Expansion Resources
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Utility Biomass - - - - - - - - - - - - - - - - - - - 15 - 15
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 2.3 2.3 - 4.6
CHP - Other - - - - - - - - - - - - - - - - - - 0.4 0.4 - 0.8
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 11 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 21 - - 22 - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - - 29 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 1 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - 2 - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 48 - - 24 - - 44 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 26 26 26 26 26 284 523
DSM, Class 2, WA 8 7 7 7 8 6 6 6 6 6 4 4 4 4 4 4 4 3 3 3 68 107
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 30 30 30 30 30 361 649
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 361 380
FOT MidColumbia Q3 - 2 375 375 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 372 374
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 100 95 96 98 84 747 83 168 263 924 164 925 104 202
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,428 1,199 1,341 1,435 1,239 1,434 1,469 1,444 1,458 1,470 1,450 1,472 1,470
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,431 1,523 1,295 1,439 1,519 1,986 1,517 1,637 1,707 2,382 1,634 2,375 1,576 1,672
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-10
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

250

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame UT - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - 0.4 7.9 7.9 - 16.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.8 0.8 0.8 2.7 2.7 2.7 3.6 15.7
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 85 4 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 11 3 - 7 - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 4 - - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 1 127 11 - 7 1 11 - 158
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 31 60
DSM, Class 2, UT 65 61 54 51 49 48 45 43 42 40 30 33 30 28 27 26 24 23 22 21 497 762
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 7 7 8 7 7 7 8 8 56 128
DSM, Class 2 Total 71 67 61 59 57 57 55 52 52 51 39 43 39 38 38 36 34 33 33 32 584 950
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 36 154 251 23 164 258 58 251 298 299 300 217 300 300 300 63 160
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - - - - - - - - - - - 203 - - - - 203
Wind, HM, 29 - - - - - - - - - - - - - - - - - - 6 11 - 17
Total Wind - - - - - - - - - - - - - - - - - - 6 11 - 17
Utility Biomass - - - - - - - - - - - - - - - - - - - 15 - 15
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - 1.4 2.3 2.3 - 6.1
CHP - Other - - - - - - - - - - - - - - - - 0.3 0.4 0.4 0.4 - 1.5
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - 6 6 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 27 2 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - 1 - - 1 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 70 2 1 - 6 33 5 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 26 26 26 26 26 26 26 284 530
DSM, Class 2, WA 8 7 7 7 8 7 6 6 6 6 4 4 4 5 5 4 4 4 3 3 68 109
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 32 32 31 30 30 30 30 362 659
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 106 227 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 173 232 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 361 380
FOT MidColumbia Q3 - 2 375 375 343 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 372 373
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 142 776 121 190 148 139 113 96 96 144 90 1,180 301 158 215 937 285 759 133 225
Annual Additions, Short Term Resources 648 707 843 981 1,102 1,208 1,326 1,423 1,195 1,336 1,430 1,230 1,423 1,470 1,471 1,472 1,389 1,472 1,472 1,472
Total Annual Additions 790 1,483 964 1,171 1,250 1,347 1,439 1,519 1,291 1,480 1,520 2,410 1,724 1,628 1,686 2,409 1,674 2,231 1,605 1,697
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-11
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
251

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - - - - - 661
CCCT J 1x1 - - - - - - - - - - - 411 - - 423 - 423 423 - - - 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, Wyoming, 40 - - - - - - - - - - - - - - - - - - 93 - - 93
Total Wind - - - - - - - - - - - - - - - - - - 93 - - 93
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - 1 - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - - - 88 - 88
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - 0 - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 13 12 - 25
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - 0 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 1 13 100 - 114
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 56 54 51 50 48 48 43 42 40 30 33 30 28 27 25 23 22 21 20 494 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 8 56 126
DSM, Class 2 Total 69 63 61 59 59 57 57 52 52 51 39 42 39 38 37 35 33 32 32 31 581 938
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 42 157 254 25 169 263 - 158 280 66 240 40 299 300 294 65 129
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - - 8 8 0 - 16
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - 21 25 - 46
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - - - - 3 - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - - - - 2 2 - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - 2 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - - - - - 17 33 25 - 75
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 24 21 20 20 23 19 22 22 22 22 23 26 26 26 285 515
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 7 5 5 5 5 5 4 4 3 3 3 71 111
DSM, Class 2 Total 45 49 42 41 38 35 32 28 27 27 28 25 28 28 28 27 28 30 30 30 365 645
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 134 251 267 297 297 297 297 297 297 297 260 297 297 297 297 248 297 297 297 257 272
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 221 311 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 260 318
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 121 118 116 106 103 95 96 95 84 495 83 82 504 739 500 520 217 202
Annual Additions, Short Term Resources 650 713 849 988 1,108 1,214 1,329 1,426 1,197 1,341 1,435 1,135 1,330 1,452 1,238 1,412 1,163 1,471 1,472 1,466
Total Annual Additions 791 1,485 970 1,106 1,224 1,320 1,432 1,521 1,293 1,436 1,519 1,630 1,413 1,534 1,742 2,151 1,663 1,991 1,689 1,668
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-12
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

252

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - 423 - - 423 - - 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 36 33 12 - - 45 4 - - - - - - - - - 199 203
Wind, UT, 29 - - - - - - - - - - - - - - - - - 13 - - - 13
Wind, Wyoming, 40 - - - - - - - - - - - 379 234 - - - - - 93 - - 706
Total Wind - - - 73 36 33 12 - - 45 4 379 234 - - - - 13 93 - 199 922
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 3 3 3 3 4 4 3 3 3 3 3 3 3 3 3 3 30 58
DSM, Class 2, UT 63 58 54 51 50 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 494 752
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 56 124
DSM, Class 2 Total 69 65 61 59 59 57 54 52 52 51 39 42 39 38 37 35 33 32 31 30 580 935
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 40 157 254 26 169 263 - 146 269 57 231 300 59 110 233 65 116
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - - - - 8 - - - - 8
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - 22 - - - - 22
DSM, Class 1 Total - - - - - - - - - - - - - - - - 30 - - - - 30
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 26 24 21 20 20 23 19 19 19 20 22 22 19 19 22 283 487
DSM, Class 2, WA 8 7 8 8 8 7 7 6 6 6 5 5 5 5 5 3 4 3 3 3 70 110
DSM, Class 2 Total 45 49 42 41 38 34 32 28 27 27 28 25 25 24 26 26 26 23 23 26 363 614
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 131 132 249 270 297 297 297 297 297 297 297 247 297 297 297 297 297 297 297 297 256 274
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 19 79 98 215 308 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 259 317
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 774 121 191 152 138 112 95 96 140 88 885 314 79 502 739 106 1,168 163 72
Annual Additions, Short Term Resources 650 711 847 985 1,105 1,212 1,329 1,426 1,198 1,341 1,435 1,122 1,318 1,441 1,229 1,403 1,472 1,231 1,282 1,405
Total Annual Additions 791 1,485 968 1,176 1,257 1,350 1,441 1,521 1,294 1,481 1,523 2,007 1,632 1,520 1,731 2,142 1,578 2,399 1,445 1,477
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-13
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
253

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - (416) - - - - - - - - - - - - (416) (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - (269) - - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - (479) - - - - - - - - - - - - (479) (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - - - - - (459) - - - - - - - (459)
Huntington2 (Early Retirement/Conversion)- - - - - - - - - - - (450) - - - - - - - - - (450)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 (Early Retirement/Conversion)- - - - - - - (205) - - - - - - - - - - - - (205) (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - (268) - - - - - - - - - - - - (268) (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - 661 661 - 661 - - - 1,983
CCCT GH 2x1 - - - - - - - - - - - - 736 - - - - - - - - 736
CCCT J 1x1 - - - - - - 423 1,680 - 423 - 411 - - - - - - - - 2,526 2,937
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - 850 - - 432 218 - - - - - - - 850 1,500
Total Wind - - - 73 35 34 13 1 850 46 6 432 218 - - - - - - - 1,052 1,708
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 6 6 7 3 3 3 3 3 1 1 1 2 1 1 1 1 1 1 47 60
DSM, Class 2, UT 84 76 75 73 73 50 47 41 41 39 14 13 11 11 10 13 11 10 8 7 599 707
DSM, Class 2, WY 24 24 24 25 25 3 3 3 3 2 2 2 1 2 2 2 2 1 1 1 137 154
DSM, Class 2 Total 114 106 105 104 105 56 54 47 47 45 17 17 13 14 13 17 14 12 11 10 783 922
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.2 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 52 157 - 131 - - 50 162 40 288 40 56 173 40 44 186 34 71
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
JBridger3 (Early Retirement/Conversion)- - - (349) - - - - - - - - - - - - - - - - (349) (349)
JBridger4 (Early Retirement/Conversion)- - - - (353) - - - - - - - - - - - - - - - (353) (353)
Colstrip3 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Colstrip4 (Early Retirement/Conversion)- - - - - - - (74) - - - - - - - - - - - - (74) (74)
Coal Ret_Bridger -Gas RePower - - - 357 362 - - - - 360 362 - - - - - - - - - 1,079 1,441
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 1 1 0 0 15 20
DSM, Class 2, OR 37 41 34 33 31 28 24 23 21 21 21 20 20 20 20 20 20 20 21 21 293 498
DSM, Class 2, WA 13 13 13 14 14 6 6 6 6 6 2 2 2 2 2 2 2 2 2 2 97 114
DSM, Class 2 Total 52 55 49 49 47 35 31 30 28 28 23 22 22 23 23 23 23 23 23 23 405 632
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - 54 23 77 297 297 291 297 199 - 297 297 - 297 122 297 297 232 297 297 154 198
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 107 75 200 236 375 375 309 375 375 375 375 375 369 375 375 375 375 375 375 375 280 327
Existing Plant Retirements/Conversions - - (164) 8 (378) - - (1,674) - (3) (261) (450) - (459) - (760) - (338) (74) -
Annual Additions, Long Term Resources 193 822 173 243 206 141 535 1,772 941 558 63 898 1,006 54 713 717 53 712 50 49
Annual Additions, Short Term Resources 607 629 723 813 1,224 1,329 1,100 1,303 1,074 875 1,222 1,334 909 1,460 1,037 1,228 1,345 1,147 1,216 1,358
Total Annual Additions 800 1,451 896 1,056 1,430 1,470 1,635 3,075 2,015 1,433 1,285 2,232 1,915 1,514 1,750 1,945 1,398 1,859 1,266 1,407
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-14
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

254

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - 181 362 - 362 - - - 905
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
SCCT Frame WYAE - - - - - - - - - - - - - - - - - - - 181 - 181
SCCT Frame WYNE - - - - - - - - - - - - - - - - - - 181 - - 181
SCCT Frame WYSW - - - - - - - - - - - - - - - 515 - - - - - 515
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.8 2.7 2.7 0.4 0.4 3.6 12.5
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, UT-Curtail - - - - - - - - - - - - 74 - - 4 - - - - - 77
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - 19 3 - - - - - - 22
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - 22 - - - - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - 4 - - - 4
DSM, Class 1 Total - - - - - - - - - - - - 74 45 3 4 - 4 - - - 129
DSM, Class 2, ID 6 6 6 6 6 2 2 2 2 3 1 1 1 2 1 1 1 1 1 1 39 52
DSM, Class 2, UT 81 74 68 65 63 39 37 37 37 37 12 11 9 10 9 12 10 9 7 6 537 634
DSM, Class 2, WY 23 23 23 23 24 2 2 2 2 2 2 2 1 2 2 2 2 1 1 1 128 144
DSM, Class 2 Total 111 103 97 94 92 43 41 41 41 42 16 14 12 13 12 15 13 12 10 9 704 830
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - 6 114 - 55 171 230 198 300 297 298 258 300 215 204 18 132
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - - - - - - - - - - - 181 384 - - - 565
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Other - - - - - - - - - - - - - - - - - 0.3 - - - 0.3
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 21 - - - - - - - - 21
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - 1 - - - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - 1 - - - - - - - - 1
DSM, Class 1 Total - - - - - - - - - - - - 22 - - - - 1 - - - 24
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 0 0 0 1 1 1 0 0 0 0 13 16
DSM, Class 2, OR 36 41 33 32 29 26 22 19 17 17 18 17 18 17 19 19 19 19 17 17 274 453
DSM, Class 2, WA 12 12 12 12 12 5 5 5 5 5 2 1 1 1 1 2 1 1 1 1 86 98
DSM, Class 2 Total 51 55 47 46 43 32 28 24 23 23 20 19 19 19 20 21 21 21 18 18 373 568
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - - 56 174 297 297 196 297 297 297 297 297 297 297 297 297 297 297 132 214
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 135 160 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 350 375
FOT MidColumbia Q3 - 2 375 375 237 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 358 367
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 188 818 163 231 189 123 97 81 80 128 58 482 542 94 234 934 234 803 225 224
Annual Additions, Short Term Resources 610 635 737 845 931 1,049 1,178 1,286 1,071 1,227 1,343 1,402 1,370 1,472 1,469 1,470 1,430 1,472 1,387 1,376
Total Annual Additions 798 1,453 900 1,076 1,120 1,172 1,275 1,367 1,151 1,355 1,401 1,884 1,912 1,566 1,703 2,404 1,664 2,275 1,612 1,600
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-15
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
255

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 1,322 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - - - 115 - - - - - - - 115
Wind, GO, 29 - - - - 63 - - - - 63 - - - - - - - - - - 126 126
Wind, Wyoming, 40 - - - - - - - - - - - - 446 - - - - - - - - 446
Total Wind - - - - 63 - - - - 63 - - 446 - - - - - - - 126 572
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - - - 9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 85 - - - - - - 85
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 13 - - - - - - 13
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 0 - - 106 - - - - - - 106
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 2 2 2 2 2 30 54
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 753
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 7 56 124
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 33 31 30 30 29 581 931
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 17 136 233 4 145 237 263 290 297 300 40 40 116 170 296 54 129
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - 25 - - - - - - - - - 5 - - - - - - 25 30
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 8 8 - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 21 - - - - - - 21
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - 3 8 8 8 23 - - - - - - 50
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 18 18 18 18 18 284 487
DSM, Class 2, WA 8 7 7 7 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 105
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 30 28 27 27 28 28 22 22 22 22 22 361 610
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 87 207 297 297 297 297 297 297 297 297 297 297 163 266 297 297 297 178 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 175 234 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 361 380
FOT MidColumbia Q3 - 2 375 375 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 372 374
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 142 176 104 100 95 96 161 87 95 717 210 211 1,394 70 730 68 68
Annual Additions, Short Term Resources 650 709 845 962 1,082 1,189 1,308 1,405 1,176 1,317 1,409 1,435 1,462 1,469 1,472 1,078 1,181 1,288 1,342 1,468
Total Annual Additions 790 1,485 966 1,104 1,258 1,293 1,408 1,500 1,272 1,478 1,496 1,530 2,179 1,679 1,683 2,472 1,251 2,018 1,410 1,536
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-16
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

256

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - - - - - 661
CCCT J 1x1 - - - - - - - - - - - - - 423 - 423 - 423 - - - 1,269
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - - - - 181 - - - 181
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 686 - - - 164 - - - 1,500
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 686 - - - 164 - - 202 1,708
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - 9 - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - 41 44 - - 3 - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 22 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 22 - - - 2 - 25
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 1 - 63 53 - 22 10 - 149
DSM, Class 2, ID 3 3 3 4 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 34 62
DSM, Class 2, UT 68 61 57 55 53 51 48 44 44 42 31 34 30 29 28 27 25 23 22 21 523 793
DSM, Class 2, WY 4 4 5 5 6 6 7 7 7 8 7 7 7 7 8 7 7 7 8 8 59 132
DSM, Class 2 Total 74 68 65 64 63 61 59 55 55 53 41 43 40 40 39 37 35 33 32 32 616 987
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - 0.8 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 52 - - 52 100 285 53 169 53 53 129 159 264 5 68
West Expansion Resources
CCCT GH 1x1 - - - - 420 - - - - - - - - - - - - - - - 420 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - - - - 3 - 3
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 3 - 3
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 21
DSM, Class 2, OR 37 41 34 34 33 31 27 24 24 24 24 26 26 26 26 26 26 26 26 26 308 563
DSM, Class 2, WA 8 8 8 8 8 7 7 7 7 7 5 5 5 5 5 4 4 3 3 3 75 119
DSM, Class 2 Total 46 50 43 43 42 39 35 32 32 32 30 32 31 32 32 30 30 30 30 30 395 702
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 163 125 239 291 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 260 279
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 383 400 400 400 330 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 391 396
FOT MidColumbia Q3 - 2 - 79 97 178 - 31 142 183 3 142 183 163 168 164 177 54 95 186 181 182 86 120
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 146 778 126 198 579 148 122 103 103 148 93 524 306 1,198 87 1,231 135 848 101 91
Annual Additions, Short Term Resources 646 704 836 969 727 828 939 1,032 800 939 1,032 1,060 1,250 1,014 1,143 904 945 1,112 1,137 1,243
Total Annual Additions 792 1,482 962 1,167 1,306 976 1,061 1,135 903 1,087 1,125 1,584 1,556 2,212 1,230 2,135 1,080 1,960 1,238 1,334
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Capacity (MW)Resource Totals 1/EG-5 Case C-17
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
257

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Hunter1 (Early Retirement/Conversion)- - - - - - - - - - - - - (416) - - - - - - - (416)
Hunter2 (Early Retirement/Conversion)- - - - - - - - - - - (269) - - - - - - - - - (269)
Hunter3 (Early Retirement/Conversion)- - - - - - - - - - - - (479) - - - - - - - - (479)
Huntington1 (Early Retirement/Conversion)- - - - - - - - - - - - - - (459) - - - - - - (459)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 (Early Retirement/Conversion)- - - - - - - (158) - - - - - - - - - - - - (158) (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Wyodak1 (Early Retirement/Conversion)- - - - - - - - - - - - (268) - - - - - - - - (268)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
WY IGCC CCS - - - - - - - - - - - - - - - - - - - 456 - 456
CCCT J 1x1 - - - - - - - - - - 423 - - - - 1,245 - 846 - - - 2,514
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Nuclear - - - - - - - - - - - - 2,236 - - - - - - - - 2,236
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Geothermal, Greenfield - - - - - - - - - - - 105 - - - - - - - - - 105
Wind, GO, 29 - - - - - - - - - 263 122 50 11 154 - - - - - - 263 600
Wind, UT, 29 - - - - - - - - - - 200 - - - - - - - - - - 200
Wind, Wyoming, 40 - - - - - - - 650 850 - - - - - - - - - - - 1,500 1,500
Total Wind - - - - - - - 650 850 263 322 50 11 154 - - - - - - 1,763 2,300
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 6 6 8 8 7 3 3 3 3 3 1 1 1 2 2 2 1 1 1 1 51 65
DSM, Class 2, UT 88 81 83 81 80 52 49 43 42 40 14 13 11 12 11 14 11 10 9 8 640 751
DSM, Class 2, WY 25 25 25 26 26 3 3 3 3 3 3 2 2 2 2 2 2 2 1 1 141 159
DSM, Class 2 Total 120 112 115 115 114 58 55 49 48 46 18 17 13 15 14 17 15 13 12 10 831 974
Utility Solar - PV - - - - - - - - - - - - - 450 - - - - - - - 450
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.4 13.4 13.4 131 263
Micro Solar - Water Heating - - - 0.4 0.3 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - - - 122 - 38 - - - 53 276 53 135 53 65 53 16 42
West Existing Plant Retirements/Conversions
JBridger1 (Early Retirement/Conversion)- - - - - - - - - - (354) - - - - - - - - - - (354)
JBridger2 (Early Retirement/Conversion)- - - - - - - - - (363) - - - - - - - - - - (363) (363)
Colstrip3 (Early Retirement/Conversion)- - - - - - - - - - - - - (74) - - - - - - - (74)
Coal Ret_Bridger -Gas RePower - - - - - - - - - 360 362 - - - - - - - - - 360 722
Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Geothermal, Greenfield - - - - - - - - - - - 30 - - - - - - - - - 30
Wind, HM, 29 - - - - - - - - - - - 600 - - - - - - - - - 600
Total Wind - - - - - - - - - - - 600 - - - - - - - - - 600
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 2 2 2 2 2 1 1 1 1 1 1 0 0 1 1 1 1 1 1 0 16 22
DSM, Class 2, OR 41 44 40 38 34 31 28 25 23 23 22 21 21 21 21 21 21 21 21 21 327 535
DSM, Class 2, WA 14 14 14 14 14 7 7 6 6 6 2 2 2 3 3 3 2 2 2 2 104 127
DSM, Class 2 Total 57 60 56 55 51 38 36 33 30 30 25 24 24 24 24 24 24 23 23 23 447 684
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 99 33 - 78 108 196 297 297 187 297 84 248 - - 297 263 297 241 297 49 159 168
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 - 81 196 206 240 255 265 375 375 375 375 375 4 340 375 375 375 375 375 375 237 286
Existing Plant Retirements/Conversions - - (164) - - - - (158) - (3) 8 (269) (1,134) (490) (459) (760) - (543) (74) -
Annual Additions, Long Term Resources 203 832 189 187 183 111 106 746 945 356 804 842 2,301 660 54 1,303 55 899 51 506
Annual Additions, Short Term Resources 599 614 696 784 848 951 1,062 1,294 1,062 1,210 959 1,123 504 893 1,448 1,191 1,307 1,169 1,237 977
Total Annual Additions 802 1,446 885 971 1,031 1,062 1,168 2,040 2,007 1,566 1,763 1,965 2,805 1,553 1,502 2,494 1,362 2,068 1,288 1,483
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-5 Case C-18 Resource Totals 1/Capacity (MW)
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

258

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - - - - - - - 661
CCCT GH 1x1 - - - - - - - - - - - - - - - 368 - - - - - 368
CCCT GH 2x1 - - - - - - - - - - - - - - - 736 - 736 - - - 1,472
CCCT J 1x1 - - - - - - - - - - - - - - - - - - - 423 - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 2 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 35 34 13 1 - 46 6 - - - - - - - - - 202 208
Wind, Wyoming, 40 - - - - - - - - - - - 432 218 - - - - - - - - 650
Total Wind - - - 73 35 34 13 1 - 46 6 432 218 - - - - - - - 202 858
CHP - Biomass 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - 1 - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 7 77 - - - - - - 85
DSM, Class 1, UT-DLC-RES - - - - - - - - - - 4 - - - - - - - - - - 4
DSM, Class 1, UT-Irrigate - - - - - - - 0 - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - - - 22
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - 1 - - 4 0 - 7 108 - - - - - 1 121
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 3 3 3 2 2 2 2 2 31 55
DSM, Class 2, UT 67 61 54 51 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 507 766
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 7 56 125
DSM, Class 2 Total 73 67 61 59 59 61 58 52 52 51 39 42 39 38 37 34 32 31 30 29 595 946
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 1.1 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 29 143 237 9 150 237 245 208 277 300 106 206 244 300 65 57 138
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - 15 - - - - - - - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - 3 - - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 1 1 - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - 3 24 - 45 1 - - - - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 26 24 23 20 23 23 22 22 22 22 18 19 20 22 18 289 498
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 69 106
DSM, Class 2 Total 45 49 41 41 38 34 32 30 27 30 28 27 27 28 28 22 23 24 26 22 367 622
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 103 223 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 171 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 377 389
FOT MidColumbia Q3 - 2 375 205 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 355 365
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 191 150 144 117 100 96 144 97 542 961 134 191 1,177 71 807 72 491
Annual Additions, Short Term Resources 646 705 840 978 1,098 1,201 1,315 1,409 1,181 1,322 1,409 1,417 1,380 1,449 1,472 1,278 1,378 1,416 1,472 1,237
Total Annual Additions 791 1,482 961 1,169 1,248 1,345 1,432 1,509 1,277 1,466 1,506 1,959 2,341 1,583 1,663 2,455 1,449 2,223 1,544 1,728
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
EG-5 Case C-19 Capacity (MW)Resource Totals 1/
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
259

Table K.12 – Sensitivity Cases under Energy Gateway Scenario 2, excluding S-04 and S-X that are included in Confidential
Volume III

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - (387) - - - - - - - - - - - - - - - (387) (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame UT - - - - - - - - - - - - - - 181 - 181 - - - - 362
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 0.4 2.7 2.7 2.7 3.6 14.7
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - 9 - - - 1 - 9
DSM, Class 1, ID-Irrigate - - - - - - 1 - - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - - 74 - - - - - - - 15 - - - 3 74 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 19 - 3 - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - 0 - - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Curtail - - - - - - 10 9 - - - - - - - 3 - - - 2 19 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 4 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - 0 - - - - - - - - - - - - 0 0 0
DSM, Class 1 Total - - - - - - 11 83 - - - - - - - 45 - 3 4 11 94 157
DSM, Class 2, ID 3 3 3 4 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 61
DSM, Class 2, UT 67 61 54 52 53 51 48 43 42 40 30 33 30 28 27 26 23 23 22 21 512 774
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 8 8 56 128
DSM, Class 2 Total 73 67 62 61 63 61 58 52 52 51 39 43 39 38 37 36 33 33 32 32 601 964
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.1 1.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - 140 228 256 255 21 158 243 263 291 226 188 300 222 300 300 300 106 185
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - 197 - - - - - - - 197
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 0.9 0.9 - 1.8
CHP - Other - - - - - - - - - - - - - - - - - 0.3 0.4 0.3 - 0.9
DSM, Class 1, WA-Curtail - - - - - - 15 - - - - - - - - - - - - 0 15 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - 6 6 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - 4 - - - - - - - - - - - - - 4 4
DSM, Class 1, OR-Curtail - - - - - - 44 - - - - - - - - - - - - 3 44 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 14 15 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - 3 - - - - - - - - - - - - - 3 3
DSM, Class 1, CA-DLC-IRR - - - - - - 4 - - - - - - - - - - - - - 4 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - 1 - - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - 2 - - - 0 - 2
DSM, Class 1 Total - - - - - - 70 - - - - - - - - 3 - 6 19 18 70 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 37 41 33 32 29 28 27 21 20 23 23 22 22 22 24 26 23 26 26 26 291 530
DSM, Class 2, WA 8 7 8 8 8 7 6 6 6 6 4 4 4 4 5 4 4 3 3 3 69 109
DSM, Class 2 Total 46 49 42 41 38 36 34 28 27 30 28 27 27 28 30 30 28 30 30 30 370 658
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - - 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 178 238
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 109 141 400 386 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 344 372
FOT MidColumbia Q3 - 2 375 375 237 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 361 368
Existing Plant Retirements/Conversions - - (164) - (387) - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 122 192 153 144 203 178 96 143 89 455 545 279 265 793 259 752 106 224
Annual Additions, Short Term Resources 584 616 737 861 1,312 1,400 1,428 1,427 1,193 1,330 1,415 1,435 1,463 1,398 1,360 1,472 1,394 1,472 1,472 1,472
Total Annual Additions 729 1,393 859 1,053 1,465 1,544 1,631 1,605 1,289 1,473 1,504 1,890 2,008 1,677 1,625 2,265 1,653 2,224 1,578 1,696
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-01 Capacity (MW)
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

260

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - 661 - 661 - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - 423 - - - - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - - - - 181 181 - - 362
SCCT Frame ID - - - - - - - - - - 181 - - - - - - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 0.4 0.4 0.4 3.6 7.6
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - 9 - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - 1 - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - - 37 - - - - - 37 - 11 4 - - 3 37 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - 22 - - - - 22
DSM, Class 1, UT-Irrigate - - - - - - - 0 - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 22 - - - - 22
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 2 2 - - - - 4
DSM, Class 1, WY-Irrigate - - - - - - - 0 - - - - - - - - 0 - - 0 0 0
DSM, Class 1 Total - - - - - - - 38 - - - - - 37 - 13 58 - - 3 38 149
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 32 60
DSM, Class 2, UT 67 61 54 51 50 51 48 43 42 40 30 33 30 28 27 25 23 22 21 20 507 766
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 7 8 56 126
DSM, Class 2 Total 73 67 61 59 59 61 58 52 52 51 39 42 39 38 37 35 33 32 31 30 595 952
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.4 1.2 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - 37 143 263 214 257 46 203 162 217 187 289 84 254 298 256 159 298 116 168
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame OR - - - - - - 203 - - - - - - - - - - - - - 203 203
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - - - - - - - 2 - 2
DSM, Class 1, OR-Curtail - - - - 21 - - 22 - - - - - - - - - - - 3 44 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - 14 - - - - 14
DSM, Class 1, OR-DLC-IRR - - - - - - - 3 - - - - - - - - - - - - 3 3
DSM, Class 1, CA-DLC-IRR - - - - - - - 4 - - - - - - - - - - - - 4 4
DSM, Class 1 Total - - - - 21 - - 30 - - - - - - - - 14 - - 4 51 69
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 18
DSM, Class 2, OR 37 41 33 32 29 26 24 23 20 19 20 19 22 22 22 22 22 19 22 22 285 498
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 4 4 4 3 3 3 3 3 69 105
DSM, Class 2 Total 45 49 41 41 38 34 32 30 26 26 25 24 27 27 27 26 26 23 26 26 364 621
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - 7 190 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 228 262
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 270 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 365 370
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 191 171 142 322 165 95 139 267 451 1,025 119 504 752 148 913 254 102
Annual Additions, Short Term Resources 770 882 1,065 1,209 1,315 1,435 1,386 1,429 1,218 1,375 1,334 1,389 1,359 1,461 1,256 1,426 1,470 1,428 1,331 1,470
Total Annual Additions 915 1,659 1,186 1,400 1,486 1,577 1,708 1,594 1,313 1,514 1,601 1,840 2,384 1,580 1,760 2,178 1,618 2,341 1,585 1,572
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-02 Capacity (MW)
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
261

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - 661 - 661 - - - 1,983
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame UT - - - - - - - - - - - - - - - 362 - 181 - - - 543
SCCT Frame ID - - - - - - - 181 - - - - - - - - - - - - 181 181
SCCT Frame WYSW - - - - - - - - - - - - - - 172 - - - - 172 - 344
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - 9 - - - - - - - - - - - - - - 9 9
DSM, Class 1, ID-Irrigate - - - - - - 1 - - - - - - - - - - - - - 1 1
DSM, Class 1, UT-Curtail - - - - - - 37 - - - - - - 48 - - - - - - 37 85
DSM, Class 1, UT-Irrigate - - - - - - 0 - - - - - - - - - - - - - 0 0
DSM, Class 1, WY-Irrigate - - - - - - 0 - - - - - - - - - - - - - 0 0
DSM, Class 1 Total - - - - - 9 38 - - - - - - 48 - - - - - - 47 95
DSM, Class 2, ID 3 3 3 3 4 4 4 3 3 4 3 3 3 3 2 2 2 2 3 2 32 56
DSM, Class 2, UT 67 61 54 52 50 51 48 40 40 40 30 33 30 28 26 25 23 22 21 20 504 761
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 6 6 7 7 7 7 7 7 7 56 123
DSM, Class 2 Total 73 67 61 61 59 61 58 49 50 51 39 42 39 38 35 33 32 31 31 29 591 940
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - 10 154 261 207 249 200 - 127 227 261 231 300 292 159 270 216 271 251 121 184
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - 197 - - - - - - - - - - - - - - 197 197
Utility Biomass - - - - 5 - - - - - - - - - - - - - - - 5 5
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - 8 - - - - - - 8 - - - - - - 8 15
DSM, Class 1, WA-DLC-IRR - - - - - - 4 - - - - - - - - - - - - - 4 4
DSM, Class 1, OR-Curtail - - - 44 - - - - - - - - - - - - - - - - 44 44
DSM, Class 1, OR-DLC-RES - - - - 13 - - - - - - - - - - - - - - - 13 13
DSM, Class 1, OR-DLC-IRR - - - - - - 3 - - - - - - - - - - - - - 3 3
DSM, Class 1, CA-DLC-IRR - - - - - - 4 - - - - - - - - - - - - - 4 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 2 - - - - - - - 2
DSM, Class 1 Total - - - 44 13 - 19 - - - - - - 9 - - - - - - 76 85
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 9 16
DSM, Class 2, OR 33 37 30 29 27 26 22 17 20 20 20 22 22 22 19 19 19 19 17 19 260 457
DSM, Class 2, WA 7 7 7 7 7 6 6 5 5 5 4 4 4 4 4 3 3 3 3 3 63 94
DSM, Class 2 Total 42 45 38 37 35 32 29 23 26 26 24 27 26 26 23 22 22 22 21 22 332 567
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 142 210 342 297 297 297 297 297 276 297 297 297 297 297 297 297 297 297 297 297 275 286
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 375 375 375 375 375 360 375 375 375 375 375 375 375 375 375 375 375 375 375 375 374 374
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 141 772 118 232 164 346 174 268 93 138 85 453 1,024 138 247 1,095 70 911 68 262
Annual Additions, Short Term Resources 1,017 1,085 1,227 1,326 1,433 1,364 1,421 1,372 1,151 1,299 1,399 1,433 1,403 1,472 1,464 1,331 1,442 1,388 1,443 1,423
Total Annual Additions 1,158 1,857 1,345 1,558 1,597 1,710 1,595 1,640 1,244 1,437 1,484 1,886 2,427 1,610 1,711 2,426 1,512 2,299 1,511 1,685
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-03 Capacity (MW)
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

262

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - 661 - - 1,322 - - - - - 1,983
CCCT J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
SCCT Frame ID - - - - - - - - - - - - - - 181 - - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, Wyoming, 40 - - - - - - 144 - - - - - - - - - - - - - 144 144
Total Wind - - - - - - 144 - - - - - - - - - - - - - 144 144
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 1, ID-Curtail - - - - - - - - - - - 9 - - - - - - - - - 9
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - 11 - - - - - 4 74 - - 88
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 3 - - - 3
DSM, Class 1, WY-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1 Total - - - - - - - - - - - 25 - - - - - 7 74 - - 106
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 2 2 30 57
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 21 20 495 754
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 7 7 7 7 7 7 55 124
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 33 32 30 29 581 934
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - 0.2 1.4 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 158 255 26 169 263 260 226 297 275 40 40 292 272 251 65 143
West Expansion Resources
CCCT GH 1x1 - - - - - - - - - - - - - - - - - - - 420 - 420
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 - - - 8 - - - 15
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - - - 44
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - 4 - - - - - - - - - 4
DSM, Class 1, CA-Curtail - - - - - - - - - - - 2 - - - - - - - - - 2
DSM, Class 1 Total - - - - - - - - - - - 13 - 51 - - - 8 - - - 72
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 17
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 22 23 22 19 22 19 19 22 22 18 18 282 487
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 68 104
DSM, Class 2 Total 45 49 41 41 38 34 29 28 27 29 28 27 24 27 24 23 26 26 22 22 360 609
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 136 234 297 297 297 182 229
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 167 333 344
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 117 113 104 244 95 96 96 84 124 740 133 258 1,396 75 512 142 488
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,330 1,427 1,198 1,341 1,435 1,432 1,398 1,469 1,447 1,051 1,149 1,464 1,444 1,215
Total Annual Additions 790 1,485 966 1,101 1,218 1,317 1,574 1,522 1,294 1,437 1,519 1,556 2,138 1,602 1,705 2,447 1,224 1,976 1,586 1,703
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-05 Capacity (MW)
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
263

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - - - 661 - - - 661
CCCT J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - 91 - - - - 91
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 69 51 45 109 - - - - - - - - - - - - - 274 274
Wind, UT, 29 - - - - - - - - - - - - 21 - - - - - - 31 - 52
Wind, Wyoming, 40 - - - - - - 400 - - - - 250 - - - - - - - - 400 650
Total Wind - - - 69 51 45 509 - - - - 250 21 - - - - - - 31 674 976
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - 7.9 7.9 7.9 7.9 7.9 7.9 7.9 - 55.3
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 2.7 2.7 2.7 2.7 2.7 2.7 3.7 3.7 3.6 28.3
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - 1 - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 37 48 4 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 22 - - - - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - 0 - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - 4 - - - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - 0 - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - 38 105 4 - - 1 11 - 158
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 61
DSM, Class 2, UT 67 61 54 52 50 51 48 43 42 40 30 33 30 29 28 27 25 23 23 22 508 778
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 8 7 7 7 7 8 7 7 8 8 8 57 131
DSM, Class 2 Total 73 67 61 60 59 61 58 53 52 52 40 43 40 39 39 37 35 34 33 33 597 970
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 26 134 229 - 140 232 261 292 300 300 300 300 285 300 300 53 170
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
ICE - - - - - - - - - - - - - - - - - 117 - - - 117
IC Aero WW - - - - - - - - - - - - - - - - - - - 99 - 99
Utility Biomass - - - - - - - - - - - - - - - - - - 20 5 - 25
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - 2.3 2.3 2.3 2.3 2.3 2.3 2.3 - 16.2
CHP - Other - - - - - - - - - - - 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 - 3.3
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 8 8 - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - 6 6 - - 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - 27 - - - 2 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - 3 - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 2 2 - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - 1 1 - - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 2 - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - 60 12 33 6 - - 5 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 21
DSM, Class 2, OR 37 41 33 32 29 28 27 23 23 23 25 26 26 26 26 26 26 26 26 26 296 552
DSM, Class 2, WA 8 7 8 8 8 7 6 6 6 6 4 5 5 5 5 4 4 4 4 4 69 112
DSM, Class 2 Total 46 49 42 41 38 35 34 30 30 30 30 32 32 32 32 31 30 30 30 31 375 685
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 102 221 297 297 297 296 297 297 297 297 297 297 297 297 297 297 297 181 239
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 204 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 188 166 155 617 98 99 98 87 342 293 199 218 981 191 871 115 245
Annual Additions, Short Term Resources 646 704 840 977 1,096 1,198 1,306 1,401 1,171 1,312 1,404 1,433 1,464 1,472 1,472 1,472 1,472 1,457 1,472 1,472
Total Annual Additions 791 1,481 961 1,165 1,262 1,353 1,923 1,499 1,270 1,410 1,491 1,775 1,757 1,671 1,690 2,453 1,663 2,328 1,587 1,717
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-06 Capacity (MW)
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

264

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - 91 - - - - 91
SCCT Frame UT - - - - - - - - - - - - - - - 181 - - - - - 181
SCCT Frame ID - - - - - - - - - - - - 181 - - - - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, UT, 29 - - - - 18 12 - - - - - 16 - 74 - - - - 7 72 30 199
Wind, Wyoming, 40 - - - - - - 1 74 - - - - - 539 26 - - 9 - - 75 649
Total Wind - - - - 18 12 1 74 - - - 16 - 613 26 - - 9 7 72 105 848
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - 7.9 7.9 7.9 7.9 - 31.6
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.8 2.7 2.7 2.7 2.7 2.7 2.7 3.6 21.7
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - 1 - - - - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - 7 77 4 - - - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - 18 4 - - - 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - 0.2 - - - - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - 22 - - - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - 4 - - - 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - 0 - - - - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - 1 - 8 126 11 - - 1 11 - 158
DSM, Class 2, ID 3 3 3 3 3 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 32 60
DSM, Class 2, UT 67 61 54 51 50 48 48 43 42 40 30 33 30 28 28 26 25 23 22 21 504 770
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 7 7 7 7 8 7 7 7 8 8 56 129
DSM, Class 2 Total 73 67 61 59 59 57 58 52 52 51 40 43 39 38 38 36 35 33 33 32 591 960
Utility Solar - PV - - - 100 - - - - - - - - - 100 - - - 100 - - 100 300
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 23 137 232 - 143 236 263 299 300 300 299 298 298 299 300 54 171
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
IC Aero SO-CAL - - - - - - - - - - - - - - - - - 91 - - - 91
IC Aero WW - - - - - - - - - - - - - - - - - - - 99 - 99
Geothermal, Greenfield - - - - - - - - - - - - - 30 - - - - - - - 30
Utility Biomass - - - - - - - - - - - - - - - - - - - 5 - 5
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - 2.3 2.3 2.3 2.3 - 9.3
CHP - Other - - - - - - - - - - - - - - 0.3 0.3 0.3 0.4 0.4 0.4 - 2.0
DSM, Class 1, WA-Curtail - - - - - - - - - - - - - 15 - - - - - 0 - 16
DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - 6 - 6 0 - 11
DSM, Class 1, WA-DLC-IRR - - - - - - - - - - - 2 - 2 - - - - - - - 4
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - 44 - - - - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 27 2 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - 3 - - - - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - 4 - - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - 1 - - 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - 2 - - - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - 5 - 67 - - 7 - 33 5 - 116
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 20
DSM, Class 2, OR 37 41 33 32 29 26 24 23 23 23 23 24 24 26 26 26 26 26 26 26 292 542
DSM, Class 2, WA 8 7 7 8 8 7 6 6 6 6 4 4 4 5 5 4 4 4 3 3 69 110
DSM, Class 2 Total 45 49 41 41 38 34 31 30 30 30 28 29 30 32 32 31 30 30 30 30 370 671
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 94 213 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 179 238
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 146 205 340 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 332 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 145 777 121 218 133 117 106 172 99 98 85 110 266 905 242 940 193 954 133 284
Annual Additions, Short Term Resources 646 705 840 969 1,088 1,195 1,309 1,404 1,172 1,315 1,408 1,435 1,471 1,472 1,472 1,471 1,470 1,470 1,471 1,472
Total Annual Additions 791 1,482 961 1,187 1,221 1,312 1,415 1,576 1,271 1,413 1,493 1,545 1,737 2,377 1,714 2,411 1,663 2,424 1,604 1,756
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-07 Capacity (MW)
PACIFICORP - 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS
265

EG 2 - Case S09 Capacity (MW)Resource Totals 1/
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - - (387) - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - - - - - 661 - 661 - - - 1,322
CCCT J 1x1 - - - - - - - - - - - - 846 - 423 - - 411 - - - 1,680
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 69 51 45 109 - - - - - - - - - - - - - 274 274
Wind, UT, 29 - - - - - - - - - - - - 21 - - - - - - 31 - 52
Wind, Wyoming, 40 - - - - - - 400 - - - - 250 - - - - - - - - 400 650
Total Wind - - - 69 51 45 509 - - - - 250 21 - - - - - - 31 674 976
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 3.6 7.2
DSM, Class 2, ID 3 3 3 3 4 4 4 3 4 4 3 3 3 3 3 3 3 3 3 3 33 61
DSM, Class 2, UT 68 61 57 55 53 53 50 44 44 42 31 34 31 29 28 27 25 23 22 21 526 796
DSM, Class 2, WY 4 4 5 5 6 6 7 7 7 8 7 7 7 7 8 7 7 8 8 8 59 133
DSM, Class 2 Total 74 68 64 63 63 62 60 55 55 54 41 44 40 40 39 37 35 33 32 32 618 991
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - 0.4 0.3 0.4 0.5 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 12 118 212 - 117 208 236 76 194 53 146 240 53 53 163 46 94
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
Utility Biomass - - - - - - - - - - - - - - - - - - - 5 - 5
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 21
DSM, Class 2, OR 37 41 34 34 31 32 28 24 24 26 26 26 26 26 26 26 26 26 26 26 311 568
DSM, Class 2, WA 8 8 8 8 8 7 7 7 7 7 5 5 5 5 5 4 4 4 4 4 76 120
DSM, Class 2 Total 46 50 43 43 40 40 36 33 32 34 33 32 32 32 32 31 30 30 30 30 398 710
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 95 210 297 297 297 277 297 297 297 297 297 220 297 297 247 293 297 177 230
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 170 229 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 360 380
FOT MidColumbia Q3 - 2 375 375 337 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 371 373
Existing Plant Retirements/Conversions - - (164) - - - - - - - - - (387) - - (760) - (701) (74) -
Annual Additions, Long Term Resources 146 778 125 193 173 162 620 102 103 105 90 342 956 88 510 745 82 1,152 79 115
Annual Additions, Short Term Resources 645 704 837 970 1,085 1,184 1,290 1,384 1,152 1,289 1,380 1,408 1,248 1,366 1,148 1,318 1,412 1,175 1,221 1,335
Total Annual Additions 791 1,482 962 1,163 1,258 1,346 1,910 1,486 1,255 1,394 1,470 1,750 2,204 1,454 1,658 2,063 1,494 2,327 1,300 1,450
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
PACIFICORP – 2013 IRP APPENDIX K – DETAILED CAPACITY EXPANSION RESULTS

266

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden1 - - - - - - - - - - - - - - - - - - (43) - - (43)
Hayden2 - - - - - - - - - - - - - - - - - - (30) - - (30)
Carbon1 (Early Retirement/Conversion)- - (67) - - - - - - - - - - - - - - - - - (67) (67)
Carbon2 (Early Retirement/Conversion)- - (105) - - - - - - - - - - - - - - - - - (105) (105)
Cholla1 (Early Retirement/Conversion)- - - - - - - - - - - (387) - - - - - - - - - (387)
Johnston1 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston2 - - - - - - - - - - - - - - - (106) - - - - - (106)
Johnston3 - - - - - - - - - - - - - - - (220) - - - - - (220)
Johnston4 - - - - - - - - - - - - - - - (328) - - - - - (328)
Naughton1 - - - - - - - - - - - - - - - - - (158) - - - (158)
Naughton2 - - - - - - - - - - - - - - - - - (205) - - - (205)
Naughton3 (Early Retirement/Conversion)- - (330) - - - - - - - - - - - - - - - - - (330) (330)
Coal Ret_WY - Gas RePower - - 338 - - - - - - - - - - - - - - (338) - - 338 -
Expansion Resources
CCCT FD 2x1 - - - - - - - - - - - 661 - - - 661 - - - - - 1,322
CCCT GH 2x1 - - - - - - - - - - - - - - - - - 736 - - - 736
Lake Side II - 645 - - - - - - - - - - - - - - - - - - 645 645
IC Aero UT - - - - - - - - - - - - - - - - - - - 91 - 91
SCCT Frame ID - - - - - - - - - - - - - - - 181 - - - - - 181
Coal Plant Turbine Upgrades 1.8 - - - - - - - - - - - - - - - - - - - 2 2
Wind, GO, 29 - - - 73 34 33 14 - - 45 5 - - - - - - - - - 199 204
Wind, UT, 29 - - - - - - - - - - - - - - - - - - - 22 - 22
Wind, Wyoming, 40 - - - - - - - - - - - 368 282 - - - - - - - - 650
Total Wind - - - 73 34 33 14 - - 45 5 368 282 - - - - - - 22 199 876
CHP - Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.6 3.2
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 7.0 6.6 - 13.6
CHP - Other 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.7 2.4 2.7 2.7 2.7 3.6 16.6
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - 9 - - - - 1 - 9
DSM, Class 1, ID-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - 1 - - - - - - 1
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - 7 - 44 37 - 3 - 91
DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - 7 - 14 4 - 26
DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - 0 - - - - - - 0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - 10 13 - - 2 - 25
DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 4 0 - 4
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - 0 - 0 - - 0 - 0
DSM, Class 1 Total - - - - - - - - - - - - - - 18 10 64 37 19 11 - 158
DSM, Class 2, ID 3 3 3 3 3 3 4 3 4 4 3 3 3 3 3 3 3 3 3 3 30 59
DSM, Class 2, UT 63 61 54 51 49 48 45 43 42 40 30 33 30 28 27 25 23 22 22 21 495 756
DSM, Class 2, WY 4 4 5 5 6 6 6 6 7 7 6 7 6 7 8 7 7 7 8 8 55 127
DSM, Class 2 Total 69 67 61 59 57 56 55 52 52 51 39 42 39 38 37 35 34 32 32 32 581 942
DSM, Class 3, UT Res TOU - - - - - - - - - - - - - - - - - - 3 3 - 6
DSM, Class 3, WY IRR TOU - - - - - - - - - - - - - - - - - - 0 0 - 0
DSM, Class 3 Total - - - - - - - - - - - - - - - - - - 3 3 - 6
Micro Solar - PV 7.11 11.0 14.2 16.4 17.0 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 131 262
Micro Solar - Water Heating - - - - - - 1.6 0.6 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 7.0 30.6
FOT Mona Q3 - - - - - 41 159 257 28 169 263 64 258 220 300 300 300 295 300 300 65 163
West Expansion Resources
Coal Plant Turbine Upgrades 12 - - - - - - - - - - - - - - - - - - - 12 12
SCCT Frame WW - - - - - - - - - - - - - 197 - - - - - - - 197
CHP - Biomass 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.5 11.0
CHP - Reciprocating Engine - - - - - - - - - - - - - - - - - - 1.4 0.2 - 1.6
CHP - Other - - - - - - - - - - - - - - - - - - 0.3 0.3 - 0.5
DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - 21 - 22 - - 3 - 46
DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 14 15 - 29
DSM, Class 1, OR-DLC-IRR - - - - - - - - - - - - - - 3 - - - - - - 3
DSM, Class 1, CA-DLC-IRR - - - - - - - - - - - - - - 4 - - - - - - 4
DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - 1 0 - 1
DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - 1 1 - - - 0 - 2
DSM, Class 1 Total - - - - - - - - - - - - - - 30 1 22 - 15 18 - 86
DSM, Class 2, CA 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 19
DSM, Class 2, OR 36 41 33 32 29 26 22 21 20 23 23 22 22 22 22 26 26 26 26 26 284 523
DSM, Class 2, WA 8 7 7 7 7 6 6 6 6 6 4 4 4 4 4 3 3 3 3 3 67 104
DSM, Class 2 Total 45 49 41 41 38 33 29 28 27 30 28 27 27 27 27 30 30 30 30 30 360 646
DSM, Class 3, CA IRR TOU - - - - - - - - - - 1 - - - 1 - - - - - - 1
DSM, Class 3, OR IRR TOU - - - - - - - - - - - - - - 1 1 - - - - - 2
DSM, Class 3 Total - - - - - - - - - - 1 - - - 2 1 - - - - - 4
OR Solar (Util Cap Standard & Cust Incentive Prgm)4.45 3 3 - - - - - - - - - - - - - - - - - 10 10
FOT COB Q3 - - - 109 230 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 182 240
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 387 400 393 400 400 400 397 400 399
FOT MidColumbia Q3 - 2 150 209 345 375 375 375 375 375 375 375 375 375 375 375 366 375 375 375 371 375 333 353
Existing Plant Retirements/Conversions - - (164) - - - - - - - - (387) - - - (760) - (701) (74) -
Annual Additions, Long Term Resources 140 776 121 190 147 137 114 95 96 143 90 1,115 364 279 132 937 169 853 130 235
Annual Additions, Short Term Resources 650 709 845 984 1,105 1,213 1,331 1,429 1,200 1,341 1,435 1,236 1,430 1,379 1,463 1,465 1,472 1,467 1,468 1,469
Total Annual Additions 790 1,485 966 1,174 1,252 1,350 1,445 1,524 1,296 1,484 1,525 2,351 1,794 1,658 1,595 2,402 1,641 2,320 1,598 1,704
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average.
Resource Totals 1/EG-2 Case S-10 Capacity (MW)
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

267
APPENDIX L – STOCHASTIC PRODUCTION COST
SIMULATION RESULTS
This appendix reports additional results for the Monte Carlo production cost simulations
conducted with PacifiCorp’s Planning and Risk (PaR) model, including Energy Gateway
scenarios 1 and 2 for all core cases. These results supplement the data presented in Chapter 8 of
the main IRP document. The results presented include the following:
 Stochastic mean present value of revenue requirements (PVRR) versus upper-tail mean less
stochastic mean PVRR scatter-plot diagrams that include all carbon dioxide (CO2) hard
cap portfolios
 The full complement of stochastic risk and other portfolio performance measures for the
portfolios simulated using PaR.
 Stochastic mean PVRR component cost details for the portfolios.
 EG2 - Case C07a is the preferred portfolio.
Core Case Study Stochastic Results
Mean versus Upper-tail Mean PVRR Scatter-plot Charts
The following set of scatter plot charts (Figures L.1 through L.6) incorporates all core cases for
zero, medium, and high, CO2 tax scenarios and for Energy Gateway (EG) scenarios 1 and 2 as
applicable64.
Stochastic Risk and Other Portfolio Performance Measures
The following set of tables (Tables L.1 through L.8) show the stochastic risk and other portfolio
performance measures as follows:

 Table L.1 - Stochastic Mean PVRR by CO2 Tax Level, Core Case Portfolios
 Table L.2 - Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios
 Table L.3 - Stochastic Risk Adjusted PVRR by CO2 Tax Level, Core Case Portfolios
 Table L.4 - Carbon Dioxide Emissions by CO2 Tax Level, Core Case Portfolios
 Table L.5 - 10-Year Average Incremental Customer Rate Impact, Final Screen Portfolios
 Table L.6 - Average Annual Energy Not served (2013 – 2032), Medium CO2 Initial
Screen Portfolios
 Table L.7 - Loss of Load Probability for Major (25,000 MWh) July Event
 Table L.8 - Average Loss of Load Probability during Summer Peak

Tables L.9 through L.11 report the breakdown of each portfolio’s stochastic mean PVRR by
variable and fixed cost components. These costs reflect the medium, zero, and high ton CO2 cost
scenario.

64 Core case 19 is not applicable to Energy Gateway scenario 1.
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

269
Figure L.1 – Stochastic Risk Profile, Zero CO2 Scenario, Energy Gateway Scenario 1

PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

270
Figure L.2 – Stochastic Risk Profile, Medium CO2 Scenario, Energy Gateway Scenario 1

PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

271
Figure L.3 – Stochastic Risk Profile, High CO2 Scenario, Energy Gateway Scenario 1

PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

272
Figure L.4 – Stochastic Risk Profile, Zero CO2 Scenario, Energy Gateway Scenario 2
Figure L.5 – Stochastic Risk Profile, Medium CO2 Scenario, Energy Gateway Scenario 2
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

273

PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

274
Figure L.6 – Stochastic Risk Profile, High CO2 Scenario, Energy Gateway Scenario 2

$4
$5
$6
$7
$8
$9
$10
$11
$12
$13
$14
$15
$16
$17
$18
$37 $38 $39 $40 $41 $42 $43 $44
Up
p
e
r

T
a
i
l

M
e
a
n

P
V
R
R

l
e
s
s

S
t
o
c
h
a
s
t
i
c

M
e
a
n

P
V
R
R
($

b
i
l
l
i
o
n
)
Stochastic Mean PVRR($ billion)
EG-2 High CO2: Updated
C01 C02 C03 C04 C05 C06 C07 C08 C09 C10
C11 C12 C13 C14 C15 C16 C17 C18
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

275
Table L.1– Stochastic Mean PVRR by CO2 Tax Level, Core Case Portfolios

C01 27,004 30,964 37,337 31,768
C02 27,586 31,397 37,534 32,172
C03 27,766 31,557 37,668 32,330
C04 30,071 33,507 38,860 34,146
C05 30,754 34,035 39,155 34,648
C06 27,132 31,159 37,593 31,961
C07 27,935 31,789 37,953 32,559
C08 30,810 34,378 39,613 34,934
C09 31,570 35,009 40,046 35,542
C10 27,461 31,425 37,803 32,230
C11 28,190 31,966 38,027 32,728
C12 27,603 31,615 38,046 32,421
C13 28,439 32,293 38,460 33,064
C14 30,203 33,401 38,461 34,022
C15 27,457 31,308 37,483 32,083
C16 27,748 31,556 37,677 32,327
C17 28,186 32,036 38,184 32,802
C18 33,984 37,390 42,774 38,049
C01 27,202 31,138 37,468 31,936
C02 27,593 31,432 37,571 32,199
C03 27,770 31,596 37,722 32,363
C04 30,162 33,554 38,858 34,191
C05 30,640 33,898 38,968 34,502
C06 27,359 31,376 37,816 32,184
C07 27,708 31,556 37,677 32,314
C07a 27,466 31,357 37,546 32,123
C08 30,965 34,548 39,822 35,112
C09 31,554 34,944 39,877 35,458
C10 27,559 31,501 37,849 32,303
C11 28,132 31,986 38,146 32,755
C12 27,855 31,874 38,315 32,681
C13 28,333 32,202 38,373 32,969
C14 30,142 33,384 38,520 34,015
C15 27,588 31,480 37,716 32,261
C16 27,729 31,607 37,817 32,384
C17 28,118 31,985 38,132 32,745
C18 34,509 37,836 43,058 38,468
C19 27,715 31,528 37,630 32,291
EG1 CO2 tax level
Million Dollars (2013$)
Case Zero High AverageMedium
EG2 CO2 tax level
Million Dollars (2013$)
Case Zero High AverageMedium
PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

276

Table L.2 – Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios

Case Standard
Deviation
5th
percentile
95th
percentile
Upper Tail (mean of
5 Highest)
C01 1,567 24,589 29,880 31,038
C02 1,446 25,322 30,146 31,270
C03 1,462 25,611 30,307 31,508
C04 4,211 24,301 38,116 41,336
C05 3,963 25,458 38,431 41,326
C06 1,518 24,793 29,839 30,946
C07 1,416 25,697 30,485 31,424
C08 4,617 24,521 39,449 43,124
C09 4,412 25,624 39,789 43,323
C10 1,568 25,029 30,197 31,481
C11 1,430 25,970 30,697 31,833
C12 1,512 25,262 30,294 31,407
C13 1,397 26,290 30,898 31,928
C14 3,493 25,360 36,960 39,557
C15 1,477 25,182 30,021 31,364
C16 1,449 25,538 30,285 31,451
C17 1,372 26,122 30,812 31,561
C18 1,852 31,113 37,170 38,863
Case Standard
Deviation
5th
percentile
95th
percentile
Upper Tail (mean of
5 Highest)
C01 1,559 24,792 29,910 31,255
C02 1,453 25,367 30,162 31,328
C03 1,470 25,498 30,356 31,516
C04 4,155 24,420 38,070 41,313
C05 3,972 25,108 38,247 41,255
C06 1,503 25,041 30,018 31,153
C07 1,357 25,577 30,159 31,060
C07a 1,387 25,282 29,991 30,913
C08 4,544 24,781 39,379 43,102
C09 4,473 25,384 39,770 43,469
C10 1,507 25,222 30,253 31,447
C11 1,353 26,035 30,614 31,496
C12 1,502 25,550 30,557 31,647
C13 1,380 26,182 30,780 31,770
C14 3,499 25,313 36,956 39,472
C15 1,292 25,571 29,902 30,937
C16 1,352 25,609 30,198 31,101
C17 1,371 26,050 30,785 31,485
C18 1,616 32,156 37,444 38,786
C19 1,420 25,516 30,228 31,311
EG1 CO2 tax level: Zero
Million Dollars (2013$)
EG2 CO2 tax level: Zero
Million Dollars (2013$)
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

277

Table L.2 – Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios (Continued)

Case Standard
Deviation
5th
percentile
95th
percentile
Upper Tail (mean of
5 Highest)
C01 1,901 28,000 34,234 35,666
C02 1,774 28,654 34,284 35,714
C03 1,788 28,787 34,439 35,937
C04 4,758 27,007 42,624 46,307
C05 4,481 27,979 42,725 46,056
C06 1,867 28,211 34,301 35,648
C07 1,768 29,012 34,644 35,937
C08 5,225 27,268 44,142 48,397
C09 4,992 28,290 44,318 48,382
C10 1,902 28,465 34,569 36,108
C11 1,762 29,253 34,840 36,237
C12 1,858 28,692 34,688 36,096
C13 1,749 29,537 35,105 36,444
C14 3,951 27,921 41,046 44,056
C15 1,793 28,480 34,160 35,883
C16 1,774 28,805 34,417 35,885
C17 1,698 29,135 34,973 36,001
C18 2,067 34,007 40,788 42,609
Case Standard
Deviation
5th
percentile
95th
percentile
Upper Tail (mean of
5 Highest)
C01 1,882 28,213 34,172 35,876
C02 1,778 28,697 34,303 35,817
C03 1,802 28,830 34,518 35,999
C04 4,697 27,082 42,534 46,234
C05 4,489 27,676 42,521 45,965
C06 1,848 28,484 34,467 35,856
C07 1,693 28,925 34,363 35,552
C07a 1,723 28,646 34,208 35,452
C08 5,145 27,579 44,113 48,357
C09 5,055 27,995 44,226 48,502
C10 1,822 28,658 34,480 36,044
C11 1,686 29,350 34,774 35,988
C12 1,844 28,978 34,912 36,352
C13 1,718 29,513 35,048 36,287
C14 3,968 27,898 41,145 44,013
C15 1,602 28,945 34,077 35,460
C16 1,672 28,990 34,399 35,598
C17 1,691 29,119 34,961 35,960
C18 1,822 34,875 41,003 42,433
C19 1,745 28,822 34,374 35,766
EG1 CO2 tax level: Medium
Million Dollars (2013$)
EG2 CO2 tax level: Medium
Million Dollars (2013$)
PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

278
Table L.2 – Stochastic Risk Results by CO2 Tax Level, Core Case Portfolios

Case Standard
Deviation
5th
percentile
95th
percentile
Upper Tail (mean of
5 Highest)
C01 2,536 33,038 41,380 43,283
C02 2,395 33,440 41,234 43,034
C03 2,415 33,497 41,370 43,236
C04 5,574 31,116 49,612 53,982
C05 5,251 31,847 49,331 53,383
C06 2,495 33,323 41,547 43,281
C07 2,396 33,794 41,757 43,258
C08 6,028 31,282 51,008 55,959
C09 5,744 32,107 50,881 55,590
C10 2,536 33,521 41,777 43,722
C11 2,388 33,916 41,745 43,489
C12 2,485 33,848 41,924 43,718
C13 2,373 34,416 42,156 43,767
C14 4,681 31,997 47,553 51,186
C15 2,405 33,371 41,144 43,271
C16 2,391 33,537 41,360 43,180
C17 2,287 34,167 41,832 43,196
C18 2,421 38,585 46,646 48,335
Case Standard
Deviation
5th
percentile
95th
percentile
Upper Tail (mean of
5 Highest)
C01 2,494 33,153 41,348 43,454
C02 2,391 33,436 41,277 43,136
C03 2,423 33,614 41,468 43,314
C04 5,509 31,249 49,342 53,868
C05 5,254 31,712 49,030 53,226
C06 2,462 33,582 41,692 43,471
C07 2,291 33,660 41,316 42,769
C07a 2,321 33,521 41,244 42,744
C08 5,943 31,775 51,014 55,919
C09 5,815 31,862 50,747 55,625
C10 2,430 33,753 41,629 43,582
C11 2,285 34,181 41,782 43,257
C12 2,460 34,091 42,146 43,973
C13 2,314 34,368 42,039 43,575
C14 4,715 32,045 47,750 51,243
C15 2,205 33,865 41,187 42,852
C16 2,253 33,897 41,392 42,888
C17 2,262 34,147 41,776 43,123
C18 2,171 39,278 46,455 48,006
C19 2,356 33,570 41,308 43,024
EG1 CO2 tax level: High
Million Dollars (2013$)
EG2 CO2 tax level: High
Million Dollars (2013$)
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

279
Table L.3– Stochastic Risk Adjusted PVRR by CO2 Tax Level

Risk-adjusted PVRR [Mean + .05 * 95th]
CO2 Tax Scenario $/Ton
EG
Scenario Case Zero Medium High Average
EG1 C01 27,997 32,175 38,905 33,026
EG1 C02 28,542 32,560 39,044 33,382
EG1 C03 28,719 32,717 39,175 33,537
EG1 C04 31,485 35,146 40,848 35,826
EG1 C05 32,122 35,618 41,068 36,269
EG1 C06 28,119 32,368 39,165 33,217
EG1 C07 28,894 32,956 39,476 33,775
EG1 C08 32,285 36,088 41,666 36,680
EG1 C09 33,002 36,668 42,033 37,234
EG1 C10 28,446 32,628 39,366 33,480
EG1 C11 29,140 33,123 39,529 33,931
EG1 C12 28,588 32,820 39,612 33,673
EG1 C13 29,393 33,458 39,978 34,277
EG1 C14 31,500 34,902 40,288 35,563
EG1 C15 28,413 32,471 38,996 33,293
EG1 C16 28,703 32,718 39,186 33,536
EG1 C17 29,146 33,203 39,694 34,014
EG1 C18 35,026 38,613 44,290 39,310
Risk-adjusted PVRR [Mean + .05 * 95th]
CO2 Tax Scenario $/Ton
EG
Scenario Case Zero Medium High Average
EG2 C01 28,151 32,300 38,989 33,147
EG2 C02 28,517 32,563 39,050 33,376
EG2 C03 28,695 32,729 39,203 33,542
EG2 C04 31,529 35,145 40,789 35,821
EG2 C05 31,967 35,439 40,835 36,080
EG2 C06 28,310 32,549 39,350 33,403
EG2 C07 28,621 32,679 39,149 33,483
EG2 C07a 28,639 32,663 39,116 33,473
EG2 C08 32,389 36,208 41,827 36,808
EG2 C09 32,957 36,571 41,830 37,119
EG2 C10 28,505 32,658 39,363 33,508
EG2 C11 29,045 33,108 39,618 33,924
EG2 C12 28,808 33,045 39,847 33,900
EG2 C13 29,253 33,334 39,856 34,148
EG2 C14 31,407 34,859 40,325 35,530
EG2 C15 28,494 32,595 39,186 33,425
EG2 C16 28,646 32,735 39,295 33,558
EG2 C17 29,044 33,120 39,607 33,924
EG2 C18 35,477 38,982 44,476 39,645
EG2 C19 28,633 32,654 39,102 33,463
PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

280
Table L.4 – Carbon Dioxide Emissions

EG1
Case Zero
Cost
Spread
Relative to
Lowest
Case Rank Medium
Cost
Spread
Relative to
Lowest
Case Rank High
Cost
Spread
Relative to
Lowest
Case Rank Average
Cost
Spread
Relative to
Lowest
Case Rank
C01 887,205 293,696 14 851,682 272,976 14 820,408 249,166 14 853,098 271,946 14
C02 874,178 280,669 11 837,578 258,873 11 805,381 234,139 11 839,046 257,894 11
C03 871,984 278,475 9 836,154 257,448 9 803,958 232,717 9 837,365 256,213 9
C04 634,787 41,278 4 620,712 42,006 4 610,174 38,932 4 621,891 40,739 4
C05 628,979 35,470 3 615,020 36,315 3 604,101 32,859 3 616,033 34,881 3
C06 898,540 305,031 18 860,125 281,419 17 828,295 257,054 17 862,320 281,168 17
C07 884,725 291,216 13 845,061 266,356 12 811,879 240,638 12 847,222 266,070 12
C08 604,917 11,408 2 589,900 11,194 2 582,215 10,973 2 592,344 11,192 2
C09 593,509 0 1 578,705 0 1 571,242 0 1 581,152 0 1
C10 887,337 293,828 15 851,922 273,216 15 820,869 249,628 15 853,376 272,224 15
C11 871,047 277,538 8 833,753 255,048 8 801,042 229,800 7 835,280 254,128 8
C12 898,486 304,977 17 860,758 282,053 18 829,118 257,876 18 862,787 281,635 18
C13 884,686 291,177 12 845,088 266,382 13 811,937 240,695 13 847,237 266,085 13
C14 656,665 63,156 5 642,532 63,827 5 630,718 59,476 5 643,305 62,153 5
C15 862,764 269,254 7 831,381 252,676 7 802,982 231,740 8 832,375 251,223 7
C16 873,506 279,997 10 836,778 258,073 10 804,491 233,249 10 838,258 257,106 10
C17 896,136 302,627 16 857,056 278,350 16 824,668 253,426 16 859,286 278,134 16
C18 784,248 190,739 6 757,244 178,539 6 727,457 156,216 6 756,317 175,164 6
Cummulative Carbon Dioxide Emissions for 2013 - 2032 (Short Tons)
CO2 tax level
EG2
Case Zero
Cost
Spread
Relative to
Lowest
Case Rank Medium
Cost
Spread
Relative to
Lowest
Case Rank High
Cost
Spread
Relative to
Lowest
Case Rank Average
Cost
Spread
Relative to
Lowest
Case Rank
C01 889,148 296,180 15 855,657 276,602 17 825,416 253,892 17 856,740 275,558 17
C02 876,193 283,225 9 841,021 261,966 9 809,731 238,207 9 842,315 261,133 9
C03 873,964 280,996 7 837,300 258,245 8 804,480 232,956 7 838,581 257,399 7
C04 642,874 49,907 4 629,200 50,145 4 618,391 46,867 4 630,155 48,973 4
C05 632,540 39,573 3 619,210 40,155 3 608,417 36,893 3 620,056 38,874 3
C06 899,552 306,584 20 862,337 283,281 19 830,971 259,447 19 864,286 283,104 19
C07 884,841 291,873 10 845,998 266,942 10 813,184 241,660 10 848,008 266,825 10
C07a 889,291 296,324 16 851,000 271,945 13 818,735 247,211 13 853,009 271,827 13
C08 608,294 15,327 2 593,165 14,110 2 584,787 13,263 2 595,416 14,233 2
C09 592,968 0 1 579,055 0 1 571,524 0 1 581,182 0 1
C10 887,424 294,456 13 854,002 274,947 15 823,761 252,237 15 855,062 273,880 15
C11 886,356 293,389 12 848,108 269,053 12 815,771 244,247 12 850,079 268,896 12
C12 899,509 306,541 19 862,425 283,370 20 830,975 259,450 20 864,303 283,120 20
C13 886,118 293,150 11 847,343 268,288 11 814,289 242,765 11 849,250 268,068 11
C14 655,509 62,542 5 639,325 60,270 5 625,810 54,285 5 640,215 59,032 5
C15 889,384 296,417 17 855,418 276,363 16 824,930 253,406 16 856,578 275,395 16
C16 888,635 295,667 14 851,427 272,372 14 820,124 248,600 14 853,395 272,213 14
C17 897,356 304,388 18 858,353 279,298 18 825,533 254,009 18 860,414 279,232 18
C18 785,096 192,128 6 755,983 176,928 6 724,551 153,026 6 755,210 174,028 6
C19 874,360 281,392 8 837,127 258,072 7 804,536 233,011 8 838,674 257,492 8
Cummulative Carbon Dioxide Emissions for 2013 - 2032 (Short Tons)
CO2 tax level
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

281

Table L.5 –10-year Average Incremental Customer Rate Impact, Final Screen Portfolios

Table L.6 – Average Annual Energy Not Served (2013 – 2032), Medium CO2 Initial Screen
Portfolios

10-year Average Incremental Customer Rate Impact (2013 - 2022)
Zero Medium High
Difference
from C07 Rank
Difference
from C07 Rank
Difference
from C07 Rank Total Average
Difference
from C07 Rank
EG1
C03 0.0 3 0.2 3 0.2 3 0.3 0.1 0.1 3
C07 0.0 2 0.0 2 0.0 2 0.0 0.0 0.0 2
C15 (7.3)1 (9.4)1 (10.1)1 (26.9)(9.0)(9.0)1
C16 2.9 4 2.7 4 2.4 4 8.0 2.7 2.7 4
C17 5.8 5 5.2 5 4.6 5 15.7 5.2 5.2 5
Difference
from C07a Rank
Difference
from C07a Rank
Difference
from C07a Rank Total Average
Difference
from C07a Rank
EG2
C03 5.4 4 4.9 4 4.3 4 14.6 4.9 4.9 4
C07 5.5 5 4.7 3 4.2 3 14.4 4.8 4.8 3
C07a 0.0 1 0.0 1 0.0 2 0.0 0.0 0.0 1
C15 1.8 2 0.1 2 (1.6)1 0.3 0.1 0.1 2
C16 5.4 3 4.9 5 4.6 5 14.9 5.0 5.0 5
C17 10.8 6 9.6 6 8.4 6 28.8 9.6 9.6 6
$ Millions
EG1
Preferred
Case
Average Annual
Energy Not Served,
2013-2032 (GWh)
Cost Spread
Relative to
Lowest Case Rank
Upper Tail Mean Energy Not Served
Cumulative Total,
2013-2032
Cost Spread
Relative to
Lowest Case Rank
C01 52.6 17.6 7 90.0 33.9 11
C02 41.7 6.7 2 65.6 9.5 2
C03 46.0 11.1 6 70.9 14.8 3
C04 54.2 19.3 9 83.0 26.9 7
C05 56.9 22.0 12 87.3 31.3 10
C06 57.0 22.0 13 117.9 61.9 18
C07 58.8 23.8 14 104.2 48.2 15
C08 53.7 18.7 8 85.8 29.7 9
C09 59.4 24.4 15 91.9 35.8 12
C10 45.7 10.7 5 77.4 21.3 6
C11 42.3 7.3 3 73.0 17.0 4
C12 54.9 19.9 10 100.8 44.8 13
C13 61.1 26.2 16 103.8 47.8 14
C14 56.6 21.6 11 85.1 29.0 8
C15 35.0 0.0 1 56.1 0.0 1
C16 44.3 9.3 4 77.3 21.2 5
C17 63.6 28.6 17 105.1 49.0 16
C18 65.1 30.1 18 116.3 60.3 17
Averaged Annual Energy Not Served (GWh)
CO2 tax level: Medium
PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

282

Table L.6 – Average Annual Energy Not Served (2013 – 2032), Medium CO2 Initial Screen
Portfolios (Continued)
Table L.7 – Loss of Load Probability for a Major (> 25,000 MWh) July Event

EG2
Preferred
Case
Average Annual
Energy Not Served,
2013-2032 (GWh)
Cost Spread
Relative to
Lowest Case Rank
Upper Tail Mean Energy Not Served
Cumulative Total,
2013-2032
Cost Spread
Relative to
Lowest Case Rank
C01 44.5 5.8 5 83.2 17.1 11
C02 38.8 0.0 1 79.4 13.4 10
C03 45.6 6.9 7 75.4 9.3 8
C04 49.6 10.9 14 71.8 5.8 5
C05 48.3 9.6 13 66.2 0.2 2
C06 53.3 14.5 16 98.4 32.4 17
C07 46.6 7.8 8 89.3 23.3 15
C07a 46.8 8.1 9 89.0 23.0 14
C08 47.5 8.7 11 67.9 1.9 3
C09 48.3 9.6 12 70.8 4.8 4
C10 41.2 2.5 2 73.8 7.8 6
C11 43.3 4.5 4 74.5 8.5 7
C12 54.3 15.6 19 103.0 37.0 19
C13 50.5 11.7 15 91.3 25.3 16
C14 46.9 8.1 10 66.0 0.0 1
C15 53.6 14.9 17 86.3 20.3 13
C16 45.6 6.9 6 84.3 18.3 12
C17 55.8 17.1 20 99.2 33.2 18
C18 54.0 15.2 18 104.7 38.7 20
C19 42.0 3.2 3 75.9 9.9 9
Averaged Annual Energy Not Served (GWh)
CO2 tax level: Medium
EG1
Year C03 C07 C11 C15 C16 C17
2013 1%1%1%1%1%1%
2014 0%0%1%0%0%0%
2015 1%1%1%2%1%1%
2016 2%3%2%2%3%2%
2017 5%5%5%5%5%5%
2018 37%37%37%37%37%37%
2019 19%19%20%19%19%20%
2020 5%5%6%5%5%6%
2021 2%2%3%2%3%4%
2022 11%11%12%6%11%10%
2023 11%13%12%6%12%12%
2024 17%17%21%7%22%20%
2025 3%4%3%2%2%7%
2026 2%6%2%4%6%4%
2027 3%3%3%4%3%6%
2028 3%10%7%3%4%11%
2029 10%18%11%6%8%19%
2030 13%25%8%10%10%21%
2031 3%12%0%5%2%13%
2032 5%9%4%8%5%13%
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

283

Table L.8 – Average Loss of Load Probability during Summer Peak

EG2
Year C03 C07 C07a C11 C15 C16 C17
2013 1%1%1%1%1%1%1%
2014 0%0%0%0%0%0%0%
2015 1%2%1%1%1%1%1%
2016 2%3%2%3%2%2%2%
2017 5%5%6%5%4%5%5%
2018 37%37%37%37%35%38%38%
2019 19%19%21%19%18%19%19%
2020 5%5%5%5%5%6%5%
2021 2%2%3%2%3%3%2%
2022 11%11%12%11%10%12%11%
2023 11%14%12%12%12%14%13%
2024 17%17%20%22%22%25%20%
2025 3%4%4%6%6%8%10%
2026 5%8%10%6%9%9%8%
2027 5%10%13%3%13%14%14%
2028 2%3%3%2%7%2%7%
2029 11%7%11%5%13%5%18%
2030 14%12%12%14%19%11%18%
2031 2%5%4%4%11%6%4%
2032 5%5%3%4%7%4%6%
EG1
Event Size
(MWh)C03 C07 C11 C15 C16 C17
> 0 92%92%92%91%92%92%
> 1,000 75%75%75%71%75%74%
> 10,000 25%25%25%21%24%25%
> 25,000 8%8%9%8%9%9%
> 50,000 1%1%1%1%1%1%
> 100,000 0%0%0%0%0%0%
> 500,000 0%0%0%0%0%0%
> 1,000,000 0%0%0%0%0%0%
Event Size
(MWh)C03 C07 C11 C15 C16 C17
> 0 91%92%90%90%90%93%
> 1,000 74%78%72%69%73%78%
> 10,000 23%28%22%18%23%29%
> 25,000 8%10%8%7%8%11%
> 50,000 1%3%2%1%2%4%
> 100,000 0%1%0%0%0%1%
> 500,000 0%0%0%0%0%0%
> 1,000,000 0%0%0%0%0%0%
Average for operating years 2013 through 2022
Average for operating years 2013 through 2032
PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

284

EG2
Event Size
(MWh)C03 C07 C07a C11 C15 C16 C17
> 0 92%92%92%92%92%92%92%
> 1,000 75%75%75%75%74%75%74%
> 10,000 24%24%24%25%24%25%25%
> 25,000 8%9%9%8%8%9%8%
> 50,000 1%1%1%1%1%1%1%
> 100,000 0%0%0%0%0%0%0%
> 500,000 0%0%0%0%0%0%0%
> 1,000,000 0%0%0%0%0%0%0%
Event Size
(MWh)C03 C07 C07a C11 C15 C16 C17
> 0 90%91%91%90%93%91%94%
> 1,000 73%74%74%73%78%73%78%
> 10,000 24%24%24%23%28%24%29%
> 25,000 8%9%9%8%10%9%10%
> 50,000 2%2%2%2%3%2%3%
> 100,000 0%1%1%1%1%1%1%
> 500,000 0%0%0%0%0%0%0%
> 1,000,000 0%0%0%0%0%0%0%
Average for operating years 2013 through 2022
Average for operating years 2013 through 2032
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

285
Table L.9 – Core Cases 1 through 19, Portfolio PVRR Cost Components (Zero CO2 Tax Level)

Stochastic PVRR ($ millions)
EG Scenario Study ID
Thermal
Fuel
Variable
O&M
inlcudes
FOT
Emission
Cost
Long
Term
Contracts Renewables DSM
System
Balancing
(System
Sales)
System
Balancing
(System
Purchases)
Transmission
Wheeling SBT
Capital
and
Fixed
O&M
Cost
Total
PVRR
EG1 C01 13,263 1,989 0 1,376 1,273 616 (3,703) 2,165 11 - 10,015 27,004
EG1 C02 12,961 1,988 0 1,375 1,302 645 (3,750) 2,021 11 - 11,031 27,586
EG1 C03 12,939 1,991 0 1,376 1,304 588 (3,734) 2,053 11 - 11,237 27,766
EG1 C04 15,261 2,286 0 1,378 1,272 548 (3,193) 2,665 11 - 9,844 30,071
EG1 C05 14,871 2,226 0 1,378 1,304 559 (3,270) 2,601 11 - 11,075 30,754
EG1 C06 13,390 1,999 0 1,376 1,273 630 (3,808) 2,157 11 - 10,104 27,132
EG1 C07 13,106 1,976 0 1,376 1,303 621 (3,860) 2,100 11 - 11,303 27,935
EG1 C08 15,686 2,395 0 1,378 1,272 482 (3,121) 2,760 10 - 9,947 30,810
EG1 C09 15,280 2,353 0 1,378 1,304 566 (3,202) 2,739 11 - 11,140 31,570
EG1 C10 13,249 1,994 0 1,376 1,272 617 (3,696) 2,133 11 - 10,505 27,461
EG1 C11 12,910 1,974 0 1,376 1,304 656 (3,761) 2,019 11 - 11,701 28,190
EG1 C12 13,381 1,971 0 1,376 1,272 644 (3,804) 2,157 11 - 10,594 27,603
EG1 C13 13,105 1,978 0 1,376 1,304 613 (3,862) 2,111 11 - 11,803 28,439
EG1 C14 14,385 2,120 0 1,377 1,304 979 (3,402) 2,406 11 - 11,023 30,203
EG1 C15 12,599 1,985 0 1,374 1,303 645 (3,451) 2,090 11 - 10,900 27,457
EG1 C16 12,946 1,975 0 1,376 1,347 615 (3,745) 2,050 11 - 11,174 27,748
EG1 C17 13,426 1,757 0 1,377 1,304 751 (4,036) 1,972 11 - 11,623 28,186
EG1 C18 12,994 1,743 0 1,378 1,349 1,278 (3,527) 2,432 11 - 16,327 33,984
EG1 C19
Stochastic PVRR ($ millions)
EG Scenario Study ID
Thermal
Fuel
Variable
O&M
inlcudes
FOT
Emission
Cost
Long
Term
Contracts Renewables DSM
System
Balancing
(System
Sales)
System
Balancing
(System
Purchases)
Transmission
Wheeling SBT
Capital
and
Fixed
O&M
Cost
Total
PVRR
EG2 C01 13,267 2,002 0 1,376 1,273 618 (3,693) 2,085 11 (655) 10,919 27,202
EG2 C02 12,970 1,992 0 1,376 1,306 617 (3,724) 2,005 11 (655) 11,697 27,593
EG2 C03 12,973 1,985 0 1,376 1,312 609 (3,740) 2,042 11 (655) 11,856 27,770
EG2 C04 15,319 2,293 0 1,378 1,272 462 (3,214) 2,564 11 (655) 10,732 30,162
EG2 C05 14,965 2,260 0 1,378 1,313 456 (3,274) 2,481 11 (655) 11,704 30,640
EG2 C06 13,377 1,960 0 1,376 1,272 677 (3,810) 2,139 11 (655) 11,010 27,359
EG2 C07 13,002 1,951 0 1,376 1,313 658 (3,857) 2,014 11 (655) 11,894 27,708
EG2 C07a 13,094 1,961 0 1,376 1,302 661 (3,839) 2,042 11 (654) 11,512 27,466
EG2 C08 15,644 2,319 0 1,378 1,272 568 (3,159) 2,670 11 (655) 10,916 30,965
EG2 C09 15,440 2,275 0 1,377 1,313 560 (3,135) 2,670 10 (655) 11,698 31,554
EG2 C10 13,136 2,013 0 1,376 1,272 670 (3,695) 2,084 11 (655) 11,348 27,559
EG2 C11 12,993 1,958 0 1,375 1,313 606 (3,844) 2,022 11 (655) 12,353 28,132
EG2 C12 13,377 1,960 0 1,376 1,272 677 (3,809) 2,143 11 (655) 11,502 27,855
EG2 C13 13,056 1,957 0 1,376 1,313 693 (3,855) 2,041 11 (655) 12,397 28,333
EG2 C14 14,385 2,105 0 1,377 1,312 992 (3,384) 2,334 11 (655) 11,664 30,142
EG2 C15 12,856 1,899 0 1,377 1,312 626 (3,779) 2,154 11 (655) 11,786 27,588
EG2 C16 13,018 1,950 0 1,376 1,349 615 (3,835) 2,047 11 (655) 11,853 27,729
EG2 C17 13,425 1,757 0 1,377 1,312 763 (4,042) 1,905 11 (655) 12,264 28,118
EG2 C18 12,587 1,753 0 1,377 1,397 1,278 (3,591) 2,257 11 (655) 18,095 34,509
EG2 C19 12,908 1,980 0 1,376 1,313 661 (3,755) 2,009 11 (655) 11,868 27,715
PACIFICORP – 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

286
Table L.10 – Core Cases 1 through 19, Portfolio PVRR Cost Components (Medium CO2 Tax Level)

Stochastic PVRR ($ millions)
EG
Scenario
Study
ID
Thermal
Fuel
Variable
O&M
inlcudes
FOT
Emission
Cost
Long
Term
Contracts Renewables DSM
System
Balancing
(System
Sales)
System
Balancing
(System
Purchases)
Transmission
Wheeling SBT
Capital
and
Fixed
O&M
Cost
Total
PVRR
EG1 C01 13,620 2,148 3,236 1,392 1,273 616 (4,071) 2,726 10 - 10,015 30,964
EG1 C02 13,282 2,154 3,137 1,391 1,302 645 (4,123) 2,567 10 - 11,031 31,397
EG1 C03 13,261 2,156 3,125 1,392 1,304 588 (4,109) 2,592 10 - 11,237 31,557
EG1 C04 16,441 2,424 1,883 1,394 1,272 548 (3,506) 3,198 10 - 9,844 33,507
EG1 C05 16,003 2,359 1,834 1,394 1,304 559 (3,609) 3,106 10 - 11,075 34,035
EG1 C06 13,731 2,164 3,297 1,392 1,273 630 (4,178) 2,736 10 - 10,104 31,159
EG1 C07 13,407 2,140 3,192 1,392 1,303 621 (4,237) 2,658 10 - 11,303 31,789
EG1 C08 16,997 2,544 1,843 1,394 1,272 482 (3,418) 3,307 10 - 9,947 34,378
EG1 C09 16,536 2,499 1,807 1,394 1,304 566 (3,521) 3,274 10 - 11,140 35,009
EG1 C10 13,604 2,156 3,237 1,392 1,272 617 (4,062) 2,694 10 - 10,505 31,425
EG1 C11 13,227 2,137 3,111 1,391 1,304 656 (4,134) 2,563 10 - 11,701 31,966
EG1 C12 13,711 2,130 3,302 1,392 1,272 644 (4,174) 2,733 10 - 10,594 31,615
EG1 C13 13,408 2,142 3,192 1,392 1,304 613 (4,240) 2,669 10 - 11,803 32,293
EG1 C14 15,419 2,257 1,935 1,393 1,304 979 (3,778) 2,857 11 - 11,023 33,401
EG1 C15 12,904 2,174 3,135 1,390 1,303 645 (3,795) 2,643 10 - 10,900 31,308
EG1 C16 13,268 2,138 3,131 1,391 1,347 615 (4,116) 2,598 10 - 11,174 31,556
EG1 C17 13,763 1,883 3,258 1,394 1,304 751 (4,442) 2,491 10 - 11,623 32,036
EG1 C18 13,594 1,869 2,579 1,394 1,349 1,278 (3,943) 2,932 10 - 16,327 37,390
EG1 C19
Stochastic PVRR ($ millions)
EG
Scenario
Study
ID
Thermal
Fuel
Variable
O&M
inlcudes
FOT
Emission
Cost
Long
Term
Contracts Renewables DSM
System
Balancing
(System
Sales)
System
Balancing
(System
Purchases)
Transmission
Wheeling SBT
Capital
and
Fixed
O&M
Cost
Total
PVRR
EG2 C01 13,652 2,166 3,214 1,392 1,273 618 (4,072) 2,621 10 (655) 10,919 31,138
EG2 C02 13,316 2,162 3,142 1,392 1,306 617 (4,102) 2,548 10 (655) 11,697 31,432
EG2 C03 13,313 2,149 3,132 1,392 1,312 609 (4,116) 2,592 10 (655) 11,856 31,596
EG2 C04 16,509 2,435 1,870 1,394 1,272 462 (3,540) 3,064 10 (655) 10,732 33,554
EG2 C05 16,123 2,398 1,821 1,394 1,313 456 (3,621) 2,955 10 (655) 11,704 33,898
EG2 C06 13,704 2,118 3,311 1,392 1,272 677 (4,182) 2,718 10 (655) 11,010 31,376
EG2 C07 13,289 2,114 3,196 1,392 1,313 658 (4,236) 2,581 10 (655) 11,894 31,556
EG2 C07a 13,387 2,125 3,226 1,392 1,302 661 (4,216) 2,612 10 (654) 11,512 31,357
EG2 C08 16,934 2,454 1,906 1,394 1,273 568 (3,467) 3,215 10 (655) 10,916 34,548
EG2 C09 16,720 2,406 1,733 1,393 1,313 560 (3,436) 3,202 10 (655) 11,698 34,944
EG2 C10 13,468 2,185 3,238 1,391 1,272 670 (4,066) 2,639 10 (655) 11,348 31,501
EG2 C11 13,269 2,118 3,209 1,391 1,313 606 (4,218) 2,590 10 (655) 12,353 31,986
EG2 C12 13,704 2,117 3,312 1,392 1,272 677 (4,183) 2,724 10 (655) 11,502 31,874
EG2 C13 13,351 2,120 3,208 1,391 1,313 693 (4,234) 2,608 10 (655) 12,397 32,202
EG2 C14 15,408 2,237 1,965 1,393 1,312 992 (3,745) 2,803 11 (655) 11,664 33,384
EG2 C15 13,118 2,079 3,243 1,392 1,312 626 (4,152) 2,720 10 (655) 11,786 31,480
EG2 C16 13,290 2,108 3,237 1,391 1,350 615 (4,208) 2,617 10 (655) 11,853 31,607
EG2 C17 13,767 1,881 3,267 1,394 1,312 763 (4,452) 2,434 10 (655) 12,264 31,985
EG2 C18 13,104 1,892 2,577 1,394 1,397 1,278 (4,012) 2,755 10 (655) 18,095 37,836
EG2 C19 13,228 2,145 3,132 1,391 1,313 661 (4,128) 2,564 10 (655) 11,868 31,528
PACIFICORP - 2013 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS

287
Table L.11 – Core Cases 1 through 19, Portfolio PVRR Cost Components (High CO2 Tax Level)
Stochastic PVRR ($ millions)
EG
Scenario
Study
ID
Thermal
Fuel
Variable
O&M
inlcudes
FOT
Emission
Cost
Long
Term
Contracts Renewables DSM
System
Balancing
(System
Sales)
System
Balancing
(System
Purchases)
Transmission
Wheeling SBT
Capital
and
Fixed
O&M
Cost
Total
PVRR
EG1 C01 14,471 2,449 8,255 1,405 1,273 616 (4,698) 3,541 10 - 10,015 37,337
EG1 C02 14,075 2,466 7,992 1,404 1,302 645 (4,758) 3,365 10 - 11,031 37,534
EG1 C03 14,055 2,470 7,964 1,405 1,304 588 (4,746) 3,382 10 - 11,237 37,668
EG1 C04 18,264 2,686 5,045 1,407 1,273 548 (4,127) 3,911 10 - 9,844 38,860
EG1 C05 17,758 2,616 4,921 1,407 1,304 559 (4,267) 3,772 10 - 11,075 39,155
EG1 C06 14,577 2,461 8,414 1,405 1,273 630 (4,843) 3,561 10 - 10,104 37,593
EG1 C07 14,203 2,436 8,120 1,405 1,303 621 (4,913) 3,466 10 - 11,303 37,953
EG1 C08 18,824 2,818 4,873 1,407 1,273 482 (4,032) 4,012 9 - 9,947 39,613
EG1 C09 18,277 2,767 4,794 1,407 1,304 566 (4,176) 3,958 10 - 11,140 40,046
EG1 C10 14,453 2,461 8,264 1,405 1,273 617 (4,690) 3,505 10 - 10,505 37,803
EG1 C11 14,021 2,444 7,907 1,404 1,304 656 (4,775) 3,355 10 - 11,701 38,027
EG1 C12 14,547 2,421 8,431 1,405 1,273 644 (4,838) 3,560 10 - 10,594 38,046
EG1 C13 14,201 2,439 8,121 1,405 1,304 613 (4,914) 3,478 10 - 11,803 38,460
EG1 C14 17,117 2,522 5,130 1,406 1,304 979 (4,489) 3,459 10 - 11,023 38,461
EG1 C15 13,708 2,518 7,969 1,403 1,303 645 (4,420) 3,447 10 - 10,900 37,483
EG1 C16 14,061 2,448 7,970 1,404 1,347 615 (4,752) 3,400 10 - 11,174 37,677
EG1 C17 14,614 2,122 8,316 1,407 1,304 751 (5,175) 3,212 10 - 11,623 38,184
EG1 C18 14,844 2,128 6,561 1,407 1,349 1,278 (4,695) 3,565 10 - 16,327 42,774
EG1 C19
Stochastic PVRR ($ millions)
EG
Scenario
Study
ID
Thermal
Fuel
Variable
O&M
inlcudes
FOT
Emission
Cost
Long
Term
Contracts Renewables DSM
System
Balancing
(System
Sales)
System
Balancing
(System
Purchases)
Transmission
Wheeling SBT
Capital
and
Fixed
O&M
Cost
Total
PVRR
EG2 C01 14,520 2,476 8,219 1,405 1,273 618 (4,714) 3,397 10 (655) 10,919 37,468
EG2 C02 14,149 2,482 7,976 1,405 1,306 617 (4,747) 3,332 10 (655) 11,697 37,571
EG2 C03 14,122 2,458 7,963 1,405 1,312 609 (4,755) 3,397 10 (655) 11,856 37,722
EG2 C04 18,354 2,702 5,014 1,407 1,273 462 (4,176) 3,736 10 (655) 10,732 38,858
EG2 C05 17,905 2,657 4,876 1,407 1,313 456 (4,289) 3,585 10 (655) 11,704 38,968
EG2 C06 14,531 2,406 8,463 1,405 1,273 677 (4,853) 3,549 10 (655) 11,010 37,816
EG2 C07 14,045 2,407 8,125 1,405 1,313 658 (4,917) 3,392 10 (655) 11,894 37,677
EG2 C07a 14,150 2,419 8,212 1,405 1,302 661 (4,893) 3,422 10 (654) 11,512 37,546
EG2 C08 18,744 2,710 5,026 1,407 1,273 568 (4,095) 3,919 10 (655) 10,916 39,822
EG2 C09 18,503 2,638 4,588 1,406 1,313 560 (4,063) 3,881 9 (655) 11,698 39,877
EG2 C10 14,278 2,510 8,267 1,404 1,273 670 (4,701) 3,445 10 (655) 11,348 37,849
EG2 C11 14,014 2,422 8,162 1,404 1,313 606 (4,892) 3,408 10 (655) 12,353 38,146
EG2 C12 14,532 2,406 8,464 1,405 1,273 677 (4,853) 3,553 10 (655) 11,502 38,315
EG2 C13 14,122 2,415 8,157 1,404 1,313 693 (4,913) 3,430 10 (655) 12,397 38,373
EG2 C14 17,098 2,494 5,194 1,406 1,312 992 (4,435) 3,439 10 (655) 11,664 38,520
EG2 C15 13,860 2,417 8,233 1,406 1,312 626 (4,815) 3,536 10 (655) 11,786 37,716
EG2 C16 14,018 2,408 8,264 1,405 1,350 615 (4,881) 3,432 10 (655) 11,853 37,817
EG2 C17 14,622 2,116 8,321 1,407 1,312 763 (5,193) 3,165 10 (655) 12,264 38,132
EG2 C18 14,221 2,165 6,516 1,407 1,398 1,278 (4,765) 3,388 10 (655) 18,095 43,058
EG2 C19 14,007 2,456 7,963 1,404 1,313 661 (4,766) 3,369 10 (655) 11,868 37,630
PACIFICORP – 2013 IRP APPENDIX M – CASE FACT SHEETS
289

APPENDIX M – CASE STUDY FACT SHEETS
Introduction

This appendix documents the 2013 Integrated Resource Plan modeling assumptions used for the
Core Case studies and the Sensitivity Case studies in a 2-page format handout given to
participants to identify key assumptions used. These aided in the discussion during the public
process and gave details beyond the high level summary tables. The Core Case Fact sheets were
provided to the public on December 19, 2012 and the Sensitivity Case Fact Sheets were provided
on February 27, 2013.
PACIFICORP – 2013 IRP APPENDIX M – CASE FACT SHEETS

290

Case Fact Sheets Summary Tables
Table M.1 – 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

PACIFICORP – 2013 IRP APPENDIX M – CASE FACT SHEETS
291

Table M.2 – 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 3) Base Medium Medium
State & Federal
(RPS Floor) 2012/2016
Hypothetical
Regional Haze

S-X
(Volume 3) 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.

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 to this report.

PACIFICORP – 2013 IRP APPENDIX M – CASE FACT SHEETS

292

Core Case Fact Sheets

Core Case Fact Sheets – C-01 to C-19
Theme: Reference
Case: C-1 (Base, No RPS)
December 19, 2012 - 293 - Case C-1
Description
Case C-1 is one of three core cases in the “Reference” theme
(Cases C-1 through C-3). These cases are characterized by
base/medium assumptions and varying degrees of RPS
assumptions. This structure will enable reporting on how RPS
requirements, whether state or federal, influence resource
portfolios, costs and stochastic risk.

Forward Price Curve
Case C-1 gas and power prices will utilize medium natural gas
and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-1 includes medium CO2 prices starting 2022 at $16/ton
rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-1 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Reference
Case: C-1 (Base, No RPS)
December 19, 2012 - 294 - Case C-1
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-1 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-1 does not include any federal RPS requirements.

State RPS
Case C-1 does not include any state RPS requirements.

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Reference
Case: C-2 (Base, State RPS)
December 19, 2012 - 295 - Case C-2
Description
Case C-2 is one of three core cases in the “Reference” theme
(Cases C-1 through C-3). These cases are characterized by
base/medium assumptions and varying degrees of RPS
assumptions. This structure will enable reporting on how RPS
requirements, whether state or federal, influence resource
portfolios, costs and stochastic risk.

Forward Price Curve
Case C-2 gas and power prices will utilize medium natural gas
and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-2 includes medium CO2 prices starting 2022 at $16/ton
rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-2 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Reference
Case: C-2 (Base, State RPS)
December 19, 2012 - 296 - Case C-2
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-2 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-2 does not include any federal RPS requirements.

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Reference
Case: C-3 (Base, State & Federal RPS)
December 19, 2012 - 297 - Case C-3
Description
Case C-3 is one of three core cases in the “Reference” theme
(Cases C-1 through C-3). These cases are characterized by
base/medium assumptions and varying degrees of RPS
assumptions. This structure will enable reporting on how RPS
requirements, whether state or federal, influence resource
portfolios, costs and stochastic risk.

Forward Price Curve
Case C-3 gas and power prices will utilize medium natural gas
and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-3 includes medium CO2 prices starting 2022 at $16/ton
rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-3 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Reference
Case: C-3 (Base, State & Federal RPS)
December 19, 2012 - 298 - Case C-3
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-3 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-3 will include the following federal RPS assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-4 (Base Regional Haze, Low Gas, High CO2 & Coal, No RPS)
December 19, 2012 - 299 - Case C-4
Description
Case C-4 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-4 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC High CO2 Low Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC High CO2 Low Gas
Coal Fuel Costs
Case C-4 high coal costs are shown alongside the medium
coal costs in the figure below.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium High
Federal CO2 Policy/Price Signal
Case C-4 includes high CO2 prices starting 2020 at
approximately $14/ton rising to approximately $75/ton by
2032. These high CO2 prices are shown alongside the medium
CO2 price assumptions in the figure below.
$-
$10
$20
$30
$40
$50
$60
$70
$80
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium High
Regional Haze
Case C-4 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Environmental Policy
Case: C-4 (Base Regional Haze, Low Gas, High CO2 & Coal, No RPS)
December 19, 2012 - 300 - Case C-4
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-4 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-4 does not include any federal RPS requirements.

State RPS
Case C-4 does not include any state RPS requirements.

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-5 (Base Regional Haze, Low Gas, High CO2 & Coal, With RPS)
December 19, 2012 - 301 - Case C-5
Description
Case C-5 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-5 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC High CO2 Low Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC High CO2 Low Gas
Coal Fuel Costs
Case C-5 high coal costs are shown alongside the medium
coal costs in the figure below.

$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium High
Federal CO2 Policy/Price Signal
Case C-5 includes high CO2 prices starting 2020 at
approximately $14/ton rising to approximately $75/ton by
2032. These high CO2 prices are shown alongside the medium
CO2 price assumptions in the figure below.
$-
$10
$20
$30
$40
$50
$60
$70
$80
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium High
Regional Haze
Case C-5 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Environmental Policy
Case: C-5 (Base Regional Haze, Low Gas, High CO2 & Coal, With RPS)
December 19, 2012 - 302 - Case C-5
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-5 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-5 will include the following federal RPS assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-6 (Base Regional Haze, High Gas, No CO2, Low Coal, No RPS)
December 19, 2012 - 303 - Case C-6
Description
Case C-6 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-6 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$2
$4
$6
$8
$10
$12
$14
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC No CO2 High Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC No CO2 High Gas
Coal Fuel Costs
Case C-6 low coal costs are shown alongside the medium coal
costs in the figure below.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Low
Federal CO2 Policy/Price Signal
Case C-6 does not have a federal CO2 price assumption.

Regional Haze
Case C-6 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-6 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-6 does not include any federal RPS requirements.

Theme: Environmental Policy
Case: C-6 (Base Regional Haze, High Gas, No CO2, Low Coal, No RPS)
December 19, 2012 - 304 - Case C-6
State RPS
Case C-6 does not include any state RPS requirements.

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.

Theme: Environmental Policy
Case: C-7 (Base Regional Haze, High Gas, No CO2, Low Coal, With RPS)
December 19, 2012 - 305 - Case C-7
Description
Case C-7 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-7 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$2
$4
$6
$8
$10
$12
$14
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC No CO2 High Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC No CO2 High Gas
Coal Fuel Costs
Case C-7 low coal costs are shown alongside the medium coal
costs in the figure below.

$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Low
Federal CO2 Policy/Price Signal
Case C-7 does not have a federal CO2 price assumption.

Regional Haze
Case C-7 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-7 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-7 will include the following federal RPS assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
Theme: Environmental Policy
Case: C-7 (Base Regional Haze, High Gas, No CO2, Low Coal, With RPS)
December 19, 2012 - 306 - Case C-7
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-8 (Stringent Regional Haze, Low Gas, High CO2 & Coal, No RPS)
December 19, 2012 - 307 - Case C-8
Description
Case C-8 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-8 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC High CO2 Low Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC High CO2 Low Gas
Coal Fuel Costs
Case C-8 high coal costs are shown alongside the medium
coal costs in the figure below.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium High
Federal CO2 Policy/Price Signal
Case C-8 includes high CO2 prices starting 2020 at
approximately $14/ton rising to approximately $75/ton by
2032. These high CO2 prices are shown alongside the medium
CO2 price assumptions in the figure below.
$-
$10
$20
$30
$40
$50
$60
$70
$80
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium High
Regional Haze
Case C-8 will apply stringent case Regional Haze investments
patterned after prospective federal implementation plan
requirements and potential long-term requirements.
Theme: Environmental Policy
Case: C-8 (Stringent Regional Haze, Low Gas, High CO2 & Coal, No RPS)
December 19, 2012 - 308 - Case C-8
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-8 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-8 does not include any federal RPS requirements.

State RPS
Case C-8 does not include any state RPS requirements.

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-9 (Stringent Regional Haze, Low Gas, High CO2 & Coal, With RPS)
December 19, 2012 - 309 - Case C-9
Description
Case C-9 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-9 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC High CO2 Low Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC High CO2 Low Gas
Coal Fuel Costs
Case C-9 high coal costs are shown alongside the medium
coal costs in the figure below.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium High
Federal CO2 Policy/Price Signal
Case C-9 includes high CO2 prices starting 2020 at
approximately $14/ton rising to approximately $75/ton by
2032. These high CO2 prices are shown alongside the medium
CO2 price assumptions in the figure below.
$-
$10
$20
$30
$40
$50
$60
$70
$80
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium High
Regional Haze
Case C-9 will apply stringent case Regional Haze investments
patterned after prospective federal implementation plan
requirements and potential long-term requirements.
Theme: Environmental Policy
Case: C-9 (Stringent Regional Haze, Low Gas, High CO2 & Coal, With RPS)
December 19, 2012 - 310 - Case C-9
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-9 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-9 will include the following federal RPS assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-10 (Stringent Regional Haze, Med Gas, Med CO2 & Coal, No RPS)
December 19, 2012 - 311 - Case C-10
Description
Case C-10 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-10 gas and power prices will utilize medium natural
gas and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Case C-10 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium
Regional Haze
Case C-10 will apply stringent case Regional Haze
investments patterned after prospective federal
implementation plan requirements and potential long-term
requirements.
Theme: Environmental Policy
Case: C-10 (Stringent Regional Haze, Med Gas, Med CO2 & Coal, No RPS)
December 19, 2012 - 312 - Case C-10
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-10 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-10 does not include any federal RPS requirements.

State RPS
Case C-10 does not include any state RPS requirements.

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-11 (Stringent Regional Haze, Med Gas, Med CO2 & Coal, With RPS)
December 19, 2012 - 313 - Case C-11
Description
Case C-11 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-11 gas and power prices will utilize medium natural
gas and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Case C-11 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium
Regional Haze
Case C-11 will apply stringent case Regional Haze
investments patterned after prospective federal
implementation plan requirements and potential long-term
requirements.
Theme: Environmental Policy
Case: C-11 (Stringent Regional Haze, Med Gas, Med CO2 & Coal, With RPS)
December 19, 2012 - 314 - Case C-11
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-11 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-11 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-12 (Stringent Regional Haze, High Gas, No CO2, Low Coal, No RPS)
December 19, 2012 - 315 - Case C-12
Description
Case C-12 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-12 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$2
$4
$6
$8
$10
$12
$14
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC No CO2 High Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC No CO2 High Gas
Coal Fuel Costs
Case C-12 low coal costs are shown alongside the medium
coal costs in the figure below.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Low
Federal CO2 Policy/Price Signal
Case C-12 does not have a federal CO2 price assumption.

Regional Haze
Case C-12 will apply stringent case Regional Haze
investments patterned after prospective federal
implementation plan requirements and potential long-term
requirements.
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-12 will include estimated costs to achieve compliance
with the following:
Theme: Environmental Policy
Case: C-12 (Stringent Regional Haze, High Gas, No CO2, Low Coal, No RPS)
December 19, 2012 - 316 - Case C-12
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-12 does not include any federal RPS requirements.

State RPS
Case C-12 does not include any state RPS requirements.

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-13 (Stringent Regional Haze, High Gas, No CO2, Low Coal, With RPS)
December 19, 2012 - 317 - Case C-13
Description
Case C-13 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-13 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$2
$4
$6
$8
$10
$12
$14
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC No CO2 High Gas
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC No CO2 High Gas
Coal Fuel Costs
Case C-13 low coal costs are shown alongside the medium
coal costs in the figure below.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Low
Federal CO2 Policy/Price Signal
Case C-13 does not have a federal CO2 price assumption.

Regional Haze
Case C-13 will apply stringent case Regional Haze
investments patterned after prospective federal
implementation plan requirements and potential long-term
requirements.
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-13 will include estimated costs to achieve compliance
with the following:
Theme: Environmental Policy
Case: C-13 (Stringent Regional Haze, High Gas, No CO2, Low Coal, With RPS)
December 19, 2012 - 318 - Case C-13
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-13 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Environmental Policy
Case: C-14 (Base Regional Haze, Med Gas, U.S. Hard Cap, Med Coal, With RPS)
December 19, 2012 - 319 - Case C-14
Description
Case C-14 is one of eleven core cases in the “Environmental
Policy” theme (Cases C-4 through C-14). These cases are
characterized by varying combinations of commodity market
prices, CO2 costs, RPS requirements, and Regional Haze
requirements. This structure will enable reporting on the
conditions that might require early retirement and resource
replacement or conversion to natural gas for existing coal-
fueled resources.

Forward Price Curve
Case C-14 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$2
$4
$6
$8
$10
$12
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC US Hard Cap Med Gas
$-
$20
$40
$60
$80
$100
$120
$140
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC US Hard Cap Med Gas
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-14 includes CO2 prices required for the U.S. power
sector to achieve an 80% reduction in emissions by 2050.
Prices start in 2020 at approximately $47/ton rising to
approximately $109/ton by 2032. These U.S. hard cap CO2
prices are shown alongside the medium CO2 price
assumptions in the figure below.
$-
$20
$40
$60
$80
$100
$120
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium U.S. Hard Cap
Regional Haze
Case C-14 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Environmental Policy
Case: C-14 (Base Regional Haze, Med Gas, U.S. Hard Cap, Med Coal, With RPS)
December 19, 2012 - 320 - Case C-14
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-14 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-14 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Supply curves will be adjusted from the base assumptions by
accelerating ramp rates with resource selection up to the
achievable potential identified in the 2012 potential study.
Measure and market ramp rates are adjusted from the base
case assumptions to allow selection of up to 2% of 2011 actual
sales in each state. After discretionary resources are
exhausted, annual opportunities decrease significantly, with
remaining resources from equipment upgrades and new
construction. Class 2 resources that are not selected in any
given year are not available for selection in future years.

Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Targeted Resources
Case: C-15 (No Thermal Base Load)
December 19, 2012 - 321 - Case C-15
Description
Case C-15 is one of five core cases in the “Targeted
Resources” theme (Cases C-15 through C-18). These cases
are characterized by alternative assumptions for specific
resource types to understand how those assumptions influence
resource portfolios, costs and stochastic risk.

Forward Price Curve
Case C-15 gas and power prices will utilize medium natural
gas and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-15 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-15 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Targeted Resources
Case: C-15 (No Thermal Base Load)
December 19, 2012 - 322 - Case C-15
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-15 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-15 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Supply curves will be adjusted from the base assumptions by
accelerating ramp rates with resource selection up to the
achievable potential identified in the 2012 potential study.
Measure and market ramp rates are adjusted from the base
case assumptions to allow selection of up to 2% of 2011 actual
sales in each state. After discretionary resources are
exhausted, annual opportunities decrease significantly, with
remaining resources from equipment upgrades and new
construction. Class 2 resources that are not selected in any
given year are not available for selection in future years.

Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
All base load thermal resources (gas-fired CCCTs) will be
excluded as potential resource alternatives.
Theme: Targeted Resources
Case: C-16 (Geothermal RPS Strategy)
December 19, 2012 - 323 - Case C-16
Description
Case C-16 is one of five core cases in the “Targeted
Resources” theme (Cases C-15 through C-18). These cases
are characterized by alternative assumptions for specific
resource types to understand how those assumptions influence
resource portfolios, costs and stochastic risk.

Forward Price Curve
Case C-16 gas and power prices will utilize medium natural
gas and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-16 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-16 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Targeted Resources
Case: C-16 (Geothermal RPS Strategy)
December 19, 2012 - 324 - Case C-16
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-16 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-16 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
State and federal RPS assumptions will be met with
geothermal resources at five sites identified in the 2011
Geothermal Information Request report prepared by Black &
Veatch (B&V Report). Costs will reflect PPA pricing
consistent with recent RFP activity. The total geothermal
capacity available is 145 MW. Any RPS compliance shortfall
that cannot be met with geothermal resource generation will
be met with other renewable resource alternatives.
Theme: Targeted Resources
Case: C-17 (Market Price Spike)
December 19, 2012 - 325 - Case C-17
Description
Case C-17 is one of five core cases in the “Targeted
Resources” theme (Cases C-15 through C-18). These cases
are characterized by alternative assumptions for specific
resource types to understand how those assumptions influence
resource portfolios, costs and stochastic risk.

Forward Price Curve
Case C-17 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$- $1 $2 $3 $4 $5 $6 $7 $8 $9 $10 $11 $12 $13 $14
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC Market Price Spike
$-
$20
$40
$60
$80
$100
$120
$140
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC Market Price Spike
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-17 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-17 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Targeted Resources
Case: C-17 (Market Price Spike)
December 19, 2012 - 326 - Case C-17
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-17 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-17 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
Forward price curves applied in the case reflect high gas price
assumptions and an incremental power price increase over the
period 2017 – 2022 at 50% on-peak and 30% off-peak.
Theme: Targeted Resources
Case: C-18 (Clean Energy Bookend)
December 19, 2012 - 327 - Case C-18

Description
Case C-18 is one of five core cases in the “Targeted
Resources” theme (Cases C-15 through C-18). These cases
are characterized by alternative assumptions for specific
resource types to understand how those assumptions influence
resource portfolios, costs and stochastic risk.

Forward Price Curve
Case C-18 gas and power prices are summarized alongside the
medium case September 2012 forward price curve in the
figures below.
$-
$2
$4
$6
$8
$10
$12
$14
$16
$18
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC US Hard Cap High Gas
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC US Hard Cap High Gas
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-18 includes CO2 prices required for the U.S. power
sector to achieve an 80% reduction in emissions by 2050.
Prices start in 2020 at approximately $57/ton rising to
approximately $132/ton by 2032. These U.S. hard cap CO2
prices are shown alongside the medium CO2 price
assumptions in the figure below.
$-
$20
$40
$60
$80
$100
$120
$140
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium U.S. Hard Cap High Gas
Regional Haze
Case C-18 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Targeted Resources
Case: C-18 (Clean Energy Bookend)
December 19, 2012 - 328 - Case C-18
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-18 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-18 does not include any federal RPS requirements.

State RPS
Case C-18 does not include any state RPS requirements.

Federal Tax Incentives
PTCs are extended through 2019
ITCs are extended through 2019

Energy Efficiency (Class 2 DSM)
Supply curves will be adjusted from the base assumptions by
accelerating ramp rates with resource selection up to the
achievable potential identified in the 2012 potential study.
Measure and market ramp rates are adjusted from the base
case assumptions to allow selection of up to 2% of 2011 actual
sales in each state. After discretionary resources are
exhausted, annual opportunities decrease significantly, with
remaining resources from equipment upgrades and new
construction. Class 2 resources that are not selected in any
given year are not available for selection in future years.

Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Transmission
Case: C-19 (Energy Gateway Segment D Alternative)
December 19, 2012 - 329 - Case C-19
Description
Case C-19 represents an incremental Energy Gateway core
case that will be implemented among all Energy Gateway
Scenarios but for the Reference Case, which does not include
segment D. This case evaluates an assumed third party
transmission can be purchased from a newly built line
connecting Wyoming with the Populous substation in Idaho.

Forward Price Curve
Case C-19 gas and power prices will utilize medium natural
gas and CO2 price assumptions consistent with the Company’s
September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Case C-19 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Case C-19 will apply base case Regional Haze investments
patterned after known state implementation plan requirements
and potential long-term requirements.
Theme: Transmission
Case: C-19 (Energy Gateway Segment D Alternative)
December 19, 2012 - 330 - Case C-19
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Case C-19 will include estimated costs to achieve compliance
with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Case C-19 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Segment D Transmission Alternative
Wheeling costs applied to this case total $14.15/kW-mo for
900 MW and reflect the following assumptions:
Costs are patterned after the only know project proposed
that generally fits the targeted scenario, which is the
proposed Zephyr DC project from Wyoming to Las
Vegas.
Total transfer capability is 3,000 MW, and 2,100 MW is
paid for by other parties (wheeling costs are proportionate
to the assumed 900 MW of firm transmission purchased).

PACIFICORP – 2013 IRP APPENDIX M – CASE FACT SHEETS

331

Sensitivity Case Fact Sheets

Sensitivity Case Fact Sheets – S-1 to S-10, S-X
Theme: Load Sensitivities
Sensitivity: S-1 (Low Load Forecast)
February 27, 2013 - 332 - Sens. S-1
Description
Sensitivity S-1 will be completed assuming a low load
forecast. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-1 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Sensitivity S-1 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-1 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Load Sensitivities
Sensitivity: S-1 (Low Load Forecast)
February 27, 2013 - 333 - Sens. S-1
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-1 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-1 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
A low load forecast derived using low economic driver
assumptions will be used. The figure below shows the change
in system coincident peak as compared to the medium (base)
load forecast before accounting for any potential contribution
from DSM or distributed generation resources.
-400
-300
-200
-100
0
100
200
300
400
500
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Change in Coincident System Peak Load
Low
Resource Specific
There are no other specific resource constraints that apply to
this sensitivity.
Theme: Load Sensitivities
Sensitivity: S-2 (High Load Forecast)
February 27, 2013 - 334 - Sens. S-2
Description
Sensitivity S-2 will be completed assuming a high load
forecast. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-2 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Sensitivity S-2 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-2 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Load Sensitivities
Sensitivity: S-2 (High Load Forecast)
February 27, 2013 - 335 - Sens. S-2
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-2 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-2 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
A high load forecast derived using high economic drivers and
high industrial load growth will be used. The figure below
shows the change in system coincident peak as compared to
the medium (base) load forecast before accounting for any
potential contribution from DSM or distributed generation
resources.
-400
-300
-200
-100
0
100
200
300
400
500
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Change in Coincident System Peak Load
High
Resource Specific
There are no other specific resource constraints that apply to
this sensitivity.
Theme: Load Sensitivities
Sensitivity: S-3 (1 in 20 Load)
February 27, 2013 - 336 - Sens. S-3
Description
Sensitivity S-3 will be completed assuming a 1 in 20 load
forecast. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-3 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Sensitivity S-3 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-3 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Load Sensitivities
Sensitivity: S-3 (1 in 20 Load)
February 27, 2013 - 337 - Sens. S-3
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-3 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-3 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
A 1 in 20 load forecast reflecting the top peak producing
weather over the past 20 years will be used. The figure below
shows the change in system coincident peak as compared to
the medium (base) load forecast before accounting for any
potential contribution from DSM or distributed generation
resources.
-400
-300
-200
-100
0
100
200
300
400
500
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Change in Coincident System Peak Load
1 in 20
Resource Specific
There are no other specific resource constraints that apply to
this sensitivity.
Theme: Environmental Policy Sensitivities
Sensitivity: S-4 (Hypothetical Regional Haze Compliance Alternative)
February 27, 2013 - 338 - Sens. S-4
Description
Sensitivity S-4 will explore hypothetical compliance
alternatives to near-term Regional Haze-based emissions
control investments. For this sensitivity, it is assumed that
near-term SCR investments currently required at Jim Bridger
Units 3&4 and at Cholla Unit 4 can be avoided if a
commitment is made to retire those coal units early. The
selection of hypothetical retirement dates in this sensitivity is
informed by an evaluation of the cost per ton of pollutant
removed; much the same as such information would be
factored into a BART analysis. This sensitivity is a variant of
Core Case C-03 assuming Energy Gateway Scenario EG-2.
The results of Sensitivity S-4 will be presented in Confidential
Volume 3 of the 2013 IRP.

Forward Price Curve
Sensitivity S-4 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Sensitivity S-4 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
For those units that are not being analyzed as part of this
sensitivity, base case Regional Haze investments patterned
after known state implementation plan requirements and
potential long-term requirements will be applied.
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse
Theme: Environmental Policy Sensitivities
Sensitivity: S-4 (Hypothetical Regional Haze Compliance Alternative)
February 27, 2013 - 339 - Sens. S-4
Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-4 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-4 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
The Jim Bridger Unit 3 and Unit 4 S-4 Sensitivity will assume
that if Units 3 and 4 are retired at the end of 2020 and 2021,
respectively, SCR investments currently required in 2015 and
2016 can be avoided. The selection of the hypothetical
retirement dates of 2020 and 2021 in this sensitivity is
informed by an evaluation of the cost per ton of pollutant
removed. In the case of Jim Bridger Units 3 and 4, the cost per
ton of pollutant removed does not exceed a value that would
likely be deemed excessive by EPA until the outer most years
of unit operation. As such, a second criterion limiting the
hypothetically negotiable compliance delay window to 5-years
beyond the current compliance deadline is applied.

The Cholla 4 S-4 Sensitivity will assume that the unit is retired
at the end of 2023 and that the SCR investment required in
2017 can be avoided. Again, the selection of the hypothetical
retirement date of 2023 in this sensitivity is informed by an
evaluation of the cost per ton of pollutant removed. In this
case, the cost per ton of pollutant removed begins an upward
trend in 2023 that that hypothetically could be deemed
excessive by EPA. As such, a second criterion limiting the
hypothetically negotiable compliance delay window to 5-years
beyond the current compliance deadline is not applied.

Theme: Environmental Policy Sensitivities
Sensitivity: S-X (Emissions Control PVRR(d) Analysis)
February 27, 2013 - 340 - Sens. S-X
Description
Sensitivity S-X will be used to report the present value
revenue requirement differential (PVRR(d)) associated with
near-term emissions control investments. The PVRR(d)
sensitivities will focus on near-term emissions control
investments required at Hunter 1 (baghouse & low NOX
burners), Jim Bridger Units 3&4 (SCRs) and at Cholla Unit 4
(SCR). This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2. The results of
Sensitivity S-X will be presented in Confidential Volume 3 of
the 2013 IRP.

Forward Price Curve
Sensitivity S-X gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC

Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Sensitivity S-X includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-X will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Environmental Policy Sensitivities
Sensitivity: S-X (Emissions Control PVRR(d) Analysis)
February 27, 2013 - 341 - Sens. S-X
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-X will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-X will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
This sensitivity will be used to analyze the PVRR(d) of
emissions control investments required at Hunter 1, Jim
Bridger Units 3&4, and Cholla 4. To arrive at the PVRR(d)
results, these units will be required to cease coal-fueled
operation as an alternative to the required investments. The
System Optimizer model will endogenously establish the
prospective alternative – gas conversion or early retirement.
Theme: Targeted Resource Sensitivities
Sensitivity: S-5 (PTC/ITC Extension, No RPS)
February 27, 2013 - 342 - Sens. S-5
Description
Sensitivity S-5 will assume that federal tax incentives for
renewable resources will be extended through 2019 and will
not include any state or Federal RPS assumptions. This
sensitivity is a variant of Core Case C-01 assuming Energy
Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-5 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC

Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium
Federal CO2 Policy/Price Signal
Sensitivity S-5 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-5 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Targeted Resource Sensitivities
Sensitivity: S-5 (PTC/ITC Extension, No RPS)
February 27, 2013 - 343 - Sens. S-5
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-5 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-5 does not include any federal RPS requirements.

State RPS
Sensitivity S-5 does not include any state RPS requirements.

Federal Tax Incentives
PTCs extended through 2019
ITCs extended through 2019

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this sensitivity.

Theme: Targeted Resource Sensitivities
Sensitivity: S-6 (PTC/ITC Extension, With RPS)
February 27, 2013 - 344 - Sens. S-6
Description
Sensitivity S-6 will assume that federal tax incentives for
renewable resources will be extended through 2019 and will
include known state and prospective Federal RPS
assumptions. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-6 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Sensitivity S-6 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium
Regional Haze
Sensitivity S-6 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Targeted Resource Sensitivities
Sensitivity: S-6 (PTC/ITC Extension, With RPS)
February 27, 2013 - 345 - Sens. S-6
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-6 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-6 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs extended through 2019
ITCs extended through 2019

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this sensitivity.
Theme: Targeted Resource Sensitivities
Sensitivity: S-7 (Endogenous RPS Compliance)
February 27, 2013 - 346 - Sens. S-7
Description
Sensitivity S-7 will be completed using the RPS compliance
logic built into the System Optimizer model. System level
RPS requirements will be used as inputs and renewable
resources will be added endogenously by the System
Optimizer model. This sensitivity is a variant of Core Case C-
03 assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-7 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Sensitivity S-7 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-7 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Targeted Resource Sensitivities
Sensitivity: S-7 (Endogenous RPS Compliance)
February 27, 2013 - 347 - Sens. S-7
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-7 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-7 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
Theme: Targeted Resource Sensitivities
Sensitivity: S-8 (2013 Business Plan)
February 27, 2013 - 348 - Sens. S-8
Description
Sensitivity S-8 will be completed with the resource portfolio
from the Company’s 2013 business plan and DSM resources
re-optimized. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-8 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Sensitivity S-8 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-8 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Targeted Resource Sensitivities
Sensitivity: S-8 (2013 Business Plan)
February 27, 2013 - 349 - Sens. S-8
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-8 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-8 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
The resource expansion plan included in the 2013 Business
Plan will be forced and DSM resources re-optimized.
Theme: Targeted Resource Sensitivities
Sensitivity: S-9 (Targeted Renewable Resources)
February 27, 2013 - 350 - Sens. S-9
Description
Sensitivity S-9 will include market price assumptions (high
gas, high CO2) and federal tax incentive assumptions
(extension of PTCs/ITCs) favorable to renewable resource
additions. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-9 gas and power prices are summarized
alongside the medium case September 2012 forward price
curve in the figures below.
$-
$2
$4
$6
$8
$10
$12
$14
$16
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC High CO2 High Gas
$-
$20
$40
$60
$80
$100
$120
$140
$160
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC High CO2 High Gas
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Sensitivity S-9 includes high CO2 prices starting 2020 at
approximately $14/ton rising to approximately $75/ton by
2032. The high CO2 prices are shown alongside the medium
CO2 price assumptions in the figure below.
$-
$10
$20
$30
$40
$50
$60
$70
$80
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium High Regional Haze
Sensitivity S-9 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Targeted Resource Sensitivities
Sensitivity: S-9 (Targeted Renewable Resources)
February 27, 2013 - 351 - Sens. S-9
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-9 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-9 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs extended through 2019
ITCs extended through 2019

Energy Efficiency (Class 2 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable potential by state and
year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA
Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.

Theme: Targeted Resource Sensitivities
Sensitivity: S-10 (Class 3 DSM)
February 27, 2013 - 352 - Sens. S-10
Description
Sensitivity S-10 will include Class 3 DSM resource
alternatives. This sensitivity is a variant of Core Case C-03
assuming Energy Gateway Scenario EG-2.

Forward Price Curve
Sensitivity S-10 gas and power prices will utilize medium
natural gas and CO2 price assumptions consistent with the
Company’s September 28, 2012 official forward price curve.
$-
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Nominal Average Annual Henry Hub Gas Prices
9/28/2012 FPC
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
W
h
Nominal Average Annual Power Prices (Flat)
9/28/2012 FPC
Coal Fuel Costs
Medium coal prices will be used. The figure below shows the
medium fleet-wide average coal costs.
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
M
M
B
t
u
Fleet-wide Average Coal Fuel Cost
Medium Federal CO2 Policy/Price Signal
Sensitivity S-10 includes medium CO2 prices starting 2022 at
$16/ton rising to approximately $26/ton by 2032.
$-
$5
$10
$15
$20
$25
$30
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
$/
t
o
n
Nominal Federal CO2 Prices
Medium Regional Haze
Sensitivity S-10 will apply base case Regional Haze
investments patterned after known state implementation plan
requirements and potential long-term requirements.
Theme: Targeted Resource Sensitivities
Sensitivity: S-10 (Class 3 DSM)
February 27, 2013 - 353 - Sens. S-10
*SNCR = selective non-catalytic reduction; SCR = selective
catalytic reduction; LNB = low NOx burner; BH = baghouse

Other Non-CO2 Environmental Policy Assumptions
Sensitivity S-10 will include estimated costs to achieve
compliance with the following:
Mercury and Air Toxics (MATS)
Coal Combustion Residuals (CCR) under subtitle D of
RCRA
Cooling water intake structures under §316(b) of the
Clean Water Act

Federal RPS
Sensitivity S-10 will include the following federal RPS
assumptions:
Targets applied to retail sales (adjusted for non-qualifying
hydro)
4.5% in 2018
7.1% in 2019 – 2020
9.8% in 2021 – 2022
12.4% in 2023 – 2024
15% by 2025

State RPS
Known state RPS requirements with targets as a percentage of
retail sales (by year-end but for WA, which is Jan 1st):
CA: 20% through 2013, 25% by 2016, 33% by 2020
OR: 5% by 2011; 15% by 2015; 20% by 2020, 25% by
2025
WA: 3% by 2012; 9% by 2016; 15% by 2020
UT: 20% of adjusted retail sales by 2025

Federal Tax Incentives
PTCs expire end of 2012
ITCs expire end of 2016

Energy Efficiency (Class 2 and Class 3 DSM)
Base case supply curves and ramp rates with resource
selections up to the achievable potential. Class 2 resources
that are not selected in any given year are not available for
selection in future years. Achievable Class 2 DSM potential
by state and year are summarized below.
0
500
1,000
1,500
2,000
2,500
3,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Class 2 DSM Cumulative Achievable Potential
UT OR WA WY ID CA For this sensitivity, Class 3 DSM resources, which are
generally considered non-firm due to the voluntary nature of
customer response to price signals, will be considered firm
resources. Only incremental potential is included in this
sensitivity. To avoid overstating the capacity contribution of
Class 3 DSM resources in this sensitivity, the potential for
each Class 3 DSM product was adjusted for expected
interactions among competing Class 1 and 3 DSM resource
alternatives.

Load Forecast
The medium load forecast will be used. The figure below
shows the system coincident peak load forecast before
accounting for any potential contribution from DSM or
distributed generation resources.
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
MW
Coincident System Peak Load
Medium
Resource Specific
There are no other specific resource constraints that will be
applied to this case.
PACIFICORP – 2013 IRP APPENDIX N – DSM DECREMENT ANALYSIS

355

APPENDIX N – CLASS 2 DSM DECREMENT STUDY
This section presents the methodology and results of the energy efficiency (Class 2 demand-side
management (DSM)) decrement study. For this analysis, the 2013 IRP preferred portfolio (Case
C-07a under Energy Gateway scenario 2) was used to calculate the decrement value (“avoided
cost”) of various types of Class 2 DSM resources. To minimize the impacts of IRP specific
assumptions when evaluating long-term resources, such as Class 2 DSM, PacifiCorp will use the
20-year levelized Class 2 DSM avoided costs shown in Table N.1 when evaluating the cost-
effectiveness of current programs and potential new programs between IRP cycles.

To align with the resource costs applied for resource portfolio development using the System
Optimizer capacity expansion model, cost credits were applied to the Class 2 DSM avoided cost
values reflecting (1) a transmission and distribution (T&D) investment deferral benefit, (2) a
generation capacity investment deferral benefit, and (3) a stochastic risk reduction benefit
associated with clean, no-fuel resources.
Modeling Approach
To determine the Class 2 DSM avoided cost values, PacifiCorp defined 17 shaped Class 2 DSM
resources, each at 100 megawatts maximum capacity, and available starting in 2013 and for the
duration of the 20-year IRP study period.

Consistent with prior valuation studies, PacifiCorp first determined the system production cost
with and without each Class 2 DSM resources using the Planning and Risk production cost
model in Monte Carlo stochastic mode. The difference in production cost (stochastic mean
present value revenue requirement (PVRR)) for the two runs indicates the system value
attributable to the DSM resource through lower spot market transaction activity and resource re-
optimization with the DSM resource in the portfolio. The cost credits mentioned above are then
added separately outside of the model, thereby increasing Class 2 DSM avoided cost values. The
Planning and Risk avoided cost values were determined for the medium CO2 tax scenario
(starting at $16/ton in 2022 and escalating to $26/ton by 2032).
Generation Resource Capacity Deferral Benefit Methodology
PacifiCorp used the System Optimizer model to determine the generation resource capacity
deferral benefit. The approach is similar to the stochastic production cost difference method,
except that only the fixed cost benefit of a 100-megawatt Class 2 DSM resource is calculated.
This is accomplished by running System Optimizer model with a base resource portfolio, and
then comparing the fixed portfolio costs against the cost of the same portfolio derived by System
Optimizer that removes 100-megawatt of DSM program. The simulation period is 20 years. As a
simplifying assumption, PacifiCorp applied the East “system” load shape for the generic DSM
program, which has a capacity planning contribution of 94 percent and a capacity factor of 70
percent. The resource deferral fixed cost benefit is comprised of the deferred capital recovery
and fixed operation and maintenance costs of a “next best alternative” resource—a combined-
cycle combustion turbine (CCCT). The difference in the portfolio fixed cost represents the
resource deferral benefit of the DSM program. (Note that System Optimizer’s production cost
PACIFICORP – 2013 IRP APPENDIX N – DSM DECREMENT ANALYSIS

356

benefits were not taken into account to avoid double-counting the benefit extracted from
stochastic Planning and Risk model results.)

Since a 100-megawatt Class 2 DSM is not sufficiently large enough to defer a whole CCCT unit,
System Optimizer was configured to allow fractional CCCT unit sizes for both the base portfolio
and the Class 2 DSM resource portfolio. Deferral of CCCT capacity can begin starting in 2017.
Note that each Class 2 DSM resource can also defer front office transactions (a market resource
representing a range of forward firm market purchase products).

The resource capacity deferral benefit is calculated in two steps:

1. Fixed Cost Deferral Benefit Determination
Fixed cost benefits are obtained by calculating the differences in annual fixed and capital
recovery costs (millions of 2012 dollars) between the base portfolio and the portfolio
with the Class 2 DSM program removed. The stream of annual benefits is then converted
into a net present value (NPV) using the 2013 IRP discount rate (6.882 percent).
2. Levelized Value Calculation
The fixed cost resource deferral benefit value obtained from step 1 is divided by the Class
2 DSM program energy in megawatt-hours (also converted to a NPV) to yield a value in
dollars per megawatt-hour-year ($/MWh-year).

This value, along with the T&D investment deferral credit and stochastic risk reduction credit,
are added to the Planning and Risk model decrement values to yield the final adjusted values.
Class 2 DSM Decrement Value Results

Table N.1 reports the NPV levelized avoided costs by DSM resource and CO2 tax scenario for
2013 through 2032, along with a breakdown of the three cost credits (capacity deferral, T&D
investment deferral, and stochastic risk reduction). Tables N.1 and N.2 report the levelized
Avoided Cost and the annual nominal-dollar avoided costs, in $/MWh.

Consistent with the results for the 2011 IRP, the residential air conditioning decrements produce
the highest value for both the east and west locations. The water heating, plug loads, and system
load shapes provide the lowest avoided costs. Much of their end use shapes reduce loads during a
greater percentage of off-peak hours than the other shapes and during all seasons, not just the
summer.

PACIFICORP – 2013 IRP APPENDIX N – DSM DECREMENT ANALYSIS

357

Table N.1 – Levelized Class 2 DSM Avoided costs, 20-Year Net Present Value (2013-2032)

Residential Cooling East 10% 18.49 64.61 2.10 85.20 146.13
Residential Lighting East 48% 18.49 12.85 2.52 33.87 80.86
Residential Whole House East 35% 18.49 17.71 2.40 38.61 87.28
Commercial Cooling East 20% 18.49 10.45 2.67 31.62 107.94
Commercial Lighting East 48% 18.49 10.80 2.52 31.81 84.05
Water Heating East 57% 18.49 31.95 2.44 52.87 79.18
Plug Loads East 59% 18.49 12.76 2.74 33.99 77.48
System Load Shape East 70% 18.49 8.88 2.62 29.99 75.75

Residential Cooling West 7% 18.49 90.98 1.39 110.86 161.83
Residential Heating West 25% 18.49 26.17 2.27 46.93 88.87
Residential Lighting West 48% 18.49 12.85 2.81 34.15 77.85
Commercial Cooling West 16% 18.49 12.93 2.81 34.23 106.58
Residential Whole House West 49% 18.49 10.45 2.90 31.85 77.89
Commercial Lighting West 48% 18.49 10.89 2.77 32.14 79.67
Water Heating West 56% 18.49 37.75 2.24 58.48 75.70
Plug Loads West 59% 18.49 12.76 2.72 33.98 74.88
System Load Shape West 71% 18.49 8.61 2.85 29.96 73.03

PACIFICORP – 2013 IRP APPENDIX N – DSM DECREMENT ANALYSIS
358

Table N.2 – Annual Nominal Class 2 DSM Avoided Costs, 2013-2032

Decrement Name
Actual
Load
Factor 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
EAST
Residential Cooling 10% 118.51 118.95 123.98 131.72 153.60 121.70 144.87 140.44 128.53 171.08
Residential Lighting 48% 61.07 61.94 65.21 67.69 73.25 68.16 74.44 75.95 76.10 97.40
Residential Whole House 35% 66.21 67.40 71.01 73.51 80.03 73.14 81.81 82.80 80.60 106.52
Commercial Cooling 20% 82.92 84.76 88.64 92.74 104.68 89.66 103.14 103.01 97.71 132.00
Commercial Lighting 48% 61.66 63.53 66.62 69.31 74.53 70.43 77.96 77.89 78.63 103.10
Water Heating 57% 58.52 59.86 63.02 65.23 69.54 66.59 72.44 73.62 75.12 95.20
Plug Loads 59% 57.95 58.83 61.99 64.36 68.90 65.49 70.43 72.99 73.85 93.66
System Load Shape 70% 56.24 57.43 60.14 62.72 66.07 64.43 68.76 70.74 72.87 91.36
WEST
Residential Cooling 7% 144.28 145.27 146.33 157.79 183.68 138.01 158.82 158.57 138.83 179.04
Residential Heating 25% 71.93 73.72 74.07 79.70 86.16 75.95 82.91 84.86 80.77 105.58
Residential Lighting 48% 60.57 61.87 63.50 66.90 71.78 66.74 71.48 73.44 73.51 91.95
Commercial Cooling 16% 88.92 89.67 91.53 97.59 109.02 90.80 101.81 102.90 96.11 120.75
Residential Whole House 49% 60.48 61.94 63.69 66.68 70.90 66.83 71.45 73.67 73.65 91.98
Commercial Lighting 48% 61.52 62.74 65.23 68.30 72.70 68.05 73.29 74.71 75.66 93.80
Water Heating 56% 58.20 59.55 61.46 64.49 68.32 64.84 69.31 71.20 72.46 88.33
Plug Loads 59% 57.77 59.19 60.56 63.71 67.36 63.87 67.89 70.46 71.35 88.84
System Load Shape 71% 55.97 57.38 58.93 61.86 64.57 62.29 65.87 68.35 70.12 86.38

PACIFICORP – 2013 IRP APPENDIX N – DSM DECREMENT ANALYSIS

359

Table N.2 – Annual Nominal Class 2 DSM Avoided Costs, 2013-2032 (Continued)

Decrement Name 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
EAST
Residential Cooling 167.70 168.33 135.41 190.10 252.77 122.82 136.44 138.04 214.18 194.54
Residential Lighting 95.45 95.07 90.75 100.99 118.72 94.52 96.75 97.63 115.94 114.01
Residential Whole House 104.14 103.88 93.86 110.84 132.59 96.77 100.67 101.57 122.92 122.04
Commercial Cooling 124.62 125.67 113.18 135.87 176.68 107.72 119.99 116.78 157.09 145.85
Commercial Lighting 101.32 99.45 95.76 107.06 126.40 99.50 103.68 104.19 118.12 117.59
Water Heating 96.07 93.27 91.24 100.01 117.34 93.01 98.55 98.78 112.99 112.25
Plug Loads 93.13 90.17 86.05 97.27 114.19 93.20 93.08 95.05 112.32 109.66
System Load Shape 92.27 87.28 86.73 94.23 108.78 92.30 95.02 94.67 108.43 107.77
WEST
Residential Cooling 153.86 183.13 143.24 199.23 264.43 109.03 131.61 142.59 240.98 220.96
Residential Heating 95.03 102.49 90.99 113.32 133.74 88.00 91.54 96.49 130.63 126.66
Residential Lighting 86.31 89.69 85.36 97.05 108.04 87.41 92.77 95.81 114.49 110.90
Commercial Cooling 110.18 122.28 106.86 129.57 162.76 94.22 109.41 114.91 156.95 148.11
Residential Whole House 86.20 90.12 85.75 97.66 108.08 88.08 93.75 96.10 113.21 110.81
Commercial Lighting 87.97 92.45 88.70 99.85 110.92 89.26 97.45 100.19 114.85 113.08
Water Heating 84.52 87.63 84.54 95.26 103.60 87.26 93.52 95.84 109.64 108.07
Plug Loads 84.09 87.33 82.89 94.45 102.92 85.96 91.92 93.43 109.16 106.98
System Load Shape 82.20 84.77 82.83 92.30 98.72 86.28 92.28 92.93 105.22 104.44
PACIFICORP – 2013 IRP APPENDIX O – WIND AND SOLAR PEAK CONTRIBUTION
361

APPENDIX O – WIND AND SOLAR PEAK
CONTRIBUTION
Overview

The amount of capacity provided by a resource at the time of system peak is known as its peak
capacity contribution, which is stated as a percentage of its nameplate capacity. The Company
calculated wind peak contribution by analyzing the historical generation over the Company’s 100
summer peak load hours in each of four historical years and assuming a 90 percent probability
that the resource will produce at least that same level of power during peak hours in the future.
The solar peak contribution was determined based on third party information due to lack of
historical data from the Company’s system. The peak contributions of the resources using
historic data are presented in Table O.1.

Table O.1 – Wind and Solar Peak Contribution (% of nameplate capacity)
Wind 4.2%
Solar 13.6%
Methodology

For both the wind and solar resources, the peak contributions are based on historical generation,
if available, provided by a particular resource type in the top 100 summer peak load hours
assuming a 90 percent probability that it will produce the same level of power during peak hours
in the future. The historical data are from a four year period from 2007 to 2010. The average of
the four annual values represents the peak contribution for that resource type. The period of
measure is restricted to summer load hours since the Company’s system peak occurs in the
summer months. Detailed steps of the calculations are:

● Compile the aggregate energy output from all resources of the resource type in each hour
of the year;
● Calculate the aggregate nameplate capacity from all resources of each type in each hour
of the year;
● Divide the aggregate energy output by the aggregate nameplate capacity to arrive at the
aggregate capacity factor for each hour of the year;
● Using actual hourly system load data for 2007-2010 to determine the top 100 load hours
that occurred in each year between the months of June and September. The resulting
hours are the top 100 summer peak load hours for each year 2007-2010;
● Align the hourly aggregate generation of the resource set to the top 100 summer peak
load hours in each year; and
● Calculate the capacity contribution based on a 90 percent probability from the level of
generation of the resource set during those peak hours.
PACIFICORP – 2013 IRP APPENDIX O – WIND AND SOLAR PEAK CONTRIBUTION

362

Wind
The Company determined that the historic wind generation had a peak contribution of 4.2
percent. This value is comparable to the five percent wind capacity contribution assumption used
by the Northwest Power and Conservation Council.65 Hourly generation logs were used to
develop the capacity contribution for the Company’s system wind resources. The analysis
included owned resources and non-owned wind resources where the Company acquired the
output under a power purchase agreement. Figure O.1 shows the result of the study, and Table
O.2 lists the wind generation resources that were included in the study.

Figure O.1 – Wind Peak Contribution, in top 100 summer load hours

65 Sixth Northwest Conservation and Electric Power Plan, N.W.P.C.C. Chapter 12, 4,
http://www.nwcouncil.org/energy/powerplan/6/final/SixthPowerPlan_Ch12.pdf .
Wind Peak Contribution
Top 100 Summer Load Hours
3.9%3.4%3.4%
5.9%
4.2%
0.0%
2.0%
4.0%
6.0%
8.0%
2007 2008 2009 2010 Peak
Contribution
(Average)
PACIFICORP – 2013 IRP APPENDIX O – WIND AND SOLAR PEAK CONTRIBUTION
363

Table O.2 – Resources Included in the Wind Analysis

Solar
The Company did not have sufficient historical data from operating solar resources during 2007
– 2010 from which it could develop the capacity contribution value for a solar QF. In the absence
of actual system data, the Company relied on a simulated hourly solar profile developed by the
National Renewable Energy Laboratory (NREL). The identical simulated hourly data is
compared against the top 100 summer load hours in each year 2007 – 2010. Unlike wind, where
the levels of generation change in each year depending on the output of the resource set, the
simulated solar output remains constant in each year and is compared to changes in the top 100
peak summer load hours from year to year.

In developing the solar generation profile the Company used an NREL tool, called PVWatts, in
order to simulate hourly solar generation levels based on historic meteorological solar radiation
data. The PVWatts tool develops a solar profile based on input parameters such as the location,
size, array type, tilt angle, and azimuth angle of the solar resource.

Wind Resource COD Type Nameplate Capacity
----------------------------------------------------------------------------------------------------------------------------------------------------------
Chevron Wind QF 12/1/2009 PPA 16.5
Combine Hills 12/22/2003 PPA 41.0
Dunlap I Wind 10/1/2010 Owned 111.0
Foote Creek Generation 7/21/1997 Owned 32.1
Glenrock III Wind 1/17/2009 Owned 39.0
Glenrock Wind 12/31/2008 Owned 99.0
Goodnoe Wind 5/31/2008 Owned 94.0
High Plains Wind 9/13/2009 Owned 99.0
Leaning Juniper 1 9/14/2006 Owned 100.5
Marengo 1 & 2 8/3/2007 Owned 210.6
McFadden Ridge Wind 9/29/2009 Owned 28.5
Mountain Wind 1 & 2 QF 7/2/2008 PPA 140.7
Oregon Wind Farm QF 3/31/2009 PPA 64.6
Rock River I 11/7/2001 PPA 50.0
Rolling Hills Wind 1/17/2009 Owned 99.0
Seven Mile II Wind 12/31/2008 Owned 19.5
Seven Mile Wind 12/31/2008 Owned 99.0
Spanish Fork Wind 2 QF 7/31/2008 PPA 18.9
Three Buttes Wind 12/1/2009 PPA 99.0
Threemile Canyon Wind QF p500139 9/1/2009 PPA 9.9
Top of the World Wind p522807 10/1/2010 PPA 200.2
Wolverine Creek 2/12/2006 PPA 64.5
---------------------------------
Total Wind December 31, 2010:1,736.5
================
PACIFICORP – 2013 IRP APPENDIX O – WIND AND SOLAR PEAK CONTRIBUTION

364

The peak contribution calculation was based on a simulated group of solar resources located
throughout the Company’s service territory. It was developed using the combined simulated
profiles from five locations: Pocatello, ID; Yakima, WA; Pendleton, OR; Lander, WY; and Salt
Lake City, UT. The analysis was performed twice, first with all of the resources configured to
peak and second with all of the resourced configured to energy, as detailed above. Figure O.2
shows the result of the study

Figure O.2 – Solar Resource Peak Contribution, in top 100 summer load hours

Solar Peak Contribution
Top 100 Summer Load Hours
13.0%18.7%
4.2%
18.4%13.6%
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
2007 2008 2009 2010 Peak
Contribution
(Average)