20160331PAC IRP Update .pdf

ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
RTC E IVE D
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1407 W . North Temple, Suite 310
Salt Lake City, Utah 84116
March 31,2016
YIA OWRNIGHT DELIWRY
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise, ID 83702
RE: Case No. PAC-E-15-04
IN THE MATTER OF THE APPLICATION OF ROCKY MOTINTAIN POWER
FOR APPROVAL OF THE 2Ol5INTEGRATED RESOURCE PLAN
Dear Ms. Jewell:
Please find enclosed an original and nine (9) copies of PacifiCorp's 2015 Integrated Resource
Plan ("IRP") Update. A copy of the report is also available electronically on PacifiCorp's
website, at www.pacificom.com. PacifiCorp is also providing data disks with this filing that
support and provide additional details for analysis described in the document. Disk 1 is public,
and Disk 2 contains confidential information. Confidential information in the 2015 IRP Update
will be provided to parties who have signed a non-disclosure agreement in the referenced case.
Rocky Mountain Power requests that interested parties contact the state manager listed below for
a copy of the non-disclosure agreement that must be executed and submitted prior to obtaining a
copy of the confidential information.
The 2015 IRP Update summarizes updates since the 2015 IRP was filed. Highlights are as
follows.l) Updates to the planning environment, which include release of the U.S. Environmental
Protection Agency's final rule for the Clean Power Plan, changes to renewable portfolio
standards in the states of Califomia and Oregon, and activities to explore the potential
formation of a regional ISO.
2) Updates to the load and resource balance, reflecting an updated load forecast and updated
resource assumptions, including current assumptions for coal unit retirements.
3) Updates to the resource portfolio, which continues to show that PacifiCorp's first year of
a major resource addition is planned to occur in 2028, consistent with the 2015 IRP
Preferred Portfolio.
4) Confidential Appendix B contains updated economic analysis of regional haze
compliance alternatives for Naughton Unit 3.
Idaho Public Utilities Commission
March 31,2016
Page2
All formal correspondence and regarding this filing should be addressed to:
Ted Weston Yvonne Hogle
Rocky Mountain Power Rocky Mountain Power
1407 W. North Temple, Suite 330 1407 W. North Temple, Suite 320
Salt Lake city, Utah 84116 Salt Lake City, Utah 84116
Telephone: [phone] Telephone: [phone]
Fax [phone] Fax: [phone]
Email: [e-mail] Email: wonne.hogle@f'acificorp.com
Communications regarding discovery matters, including data requests issued to Rocky Mountain
Power, should be addressed to the following:
By E-mail (prefened): [e-mail]
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR97232
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
Very Truly Yours,
}r,tt"{- L Ju^^,,.,- I cn^t
Jeffrej K. Larsen
Vice President, Regulation
Enclosures
cc: Jim Yost, Idaho Govemor's Office (without enclosures)
Benjamin J. Otto, Idaho Conservation League (without enclosures)
Mark Stokes, Idaho Power Company (without enclosures)
Terrie Carlock, Idaho Public Utilities Commission (without enclosures)
Rick Sterling, Idaho Public Utilities Commission (without enclosures)
Matt Elam, Idaho Public Utilities Commission (without enclosures)
Randall Budge, Racine, Olson, Nye, Budge & Bailey (without enclosures)
Nancy Kelly, Western Resource Advocates (without enclosures)

This 2015 Integrated Resource Plan Update 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):
Wind Turbine: Marengo II
Solar: Residential Solar Install
Transmission: Populus to Terminal Tower Construction
Demand-Side Management: Wattsmart Flower
Thermal-Gas: Lake Side 1

PACIFICORP – 2015 IRP UPDATE TABLE OF CONTENTS

i
TABLE OF CONTENTS
TABLE OF CONTENTS .............................................................................................................. I
INDEX OF TABLES .................................................................................................................. III
INDEX OF FIGURES ................................................................................................................ IV
EXECUTIVE SUMMARY ...........................................................................................................1
2015 IRP UPDATE HIGHLIGHTS ................................................................................................................ 1
LOAD AND RESOURCE BALANCE UPDATE ............................................................................................... 3
RESOURCE PORTFOLIO UPDATE ............................................................................................................... 4
IRP ACTION PLAN .................................................................................................................................... 6
CHAPTER 1 – INTRODUCTION ...............................................................................................9
CHAPTER 2 – PLANNING ENVIRONMENT ........................................................................11
BUSINESS PLAN DEVELOPMENT ............................................................................................................. 11
FEDERAL POLICY UPDATE ...................................................................................................................... 11
New Source Performance Standards for Carbon Emissions – Clean Air Act § 111(b) ..................... 11
Carbon Emission Guidelines for Existing Sources – Clean Air Act § 111(d) .................................... 11
Clean Air Act Criteria Pollutants – National Ambient Air Quality Standards .................................. 12
Regional Haze .................................................................................................................................... 13
Mercury and Hazardous Air Pollutants ............................................................................................. 14
Coal Combustion Residuals ............................................................................................................... 15
Water Quality Standards .................................................................................................................... 15
2015 Tax Extender Legislation .......................................................................................................... 16
STATE POLICY UPDATE .......................................................................................................................... 17
California ........................................................................................................................................... 17
Oregon ................................................................................................................................................ 17
Washington ......................................................................................................................................... 18
Utah .................................................................................................................................................... 18
Greenhouse Gas Emission Performance Standards .......................................................................... 19
ENERGY GATEWAY TRANSMISSION PROGRAM PLANNING .................................................................... 19
Energy Gateway Transmission Project Updates ................................................................................ 20
Regional Markets ............................................................................................................................... 22
CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE...........................................25
INTRODUCTION ....................................................................................................................................... 25
LOAD FORECAST ..................................................................................................................................... 25
RESOURCE UPDATES ............................................................................................................................... 26
Existing and Firm Resources ............................................................................................................. 26
Changes Made between the 2015 IRP and the Business Plan ....................................................................... 26
Changes Made between the Business Plan and the 2015 IRP Update ........................................................... 27
UPDATED CAPACITY LOAD AND RESOURCE BALANCE.......................................................................... 29
PacifiCorp West ................................................................................................................................. 38
PacifiCorp East .................................................................................................................................. 38
CHAPTER 4 – MODELING ASSUMPTIONS UPDATE .......................................................39
GENERAL ASSUMPTIONS ........................................................................................................................ 39
NATURAL GAS AND POWER MARKET PRICE UPDATES .......................................................................... 39
Natural Gas Market Prices ................................................................................................................ 39
PACIFICORP – 2015 IRP UPDATE TABLE OF CONTENTS

ii
Power Market Prices .......................................................................................................................... 40
CARBON DIOXIDE EMISSION POLICY ..................................................................................................... 42
TRANSMISSION TOPOLOGY ..................................................................................................................... 42
SUPPLY-SIDE RESOURCES ....................................................................................................................... 42
CHAPTER 5 – PORTFOLIO DEVELOPMENT .....................................................................47
INTRODUCTION ....................................................................................................................................... 47
2015 IRP UPDATE RESOURCE PORTFOLIO ............................................................................................. 47
BUSINESS PLAN RESOURCE PORTFOLIO ................................................................................................. 51
RENEWABLE PORTFOLIO STANDARD COMPLIANCE ............................................................................... 53
Oregon ................................................................................................................................................ 53
Washington ......................................................................................................................................... 56
California ........................................................................................................................................... 58
Utah .................................................................................................................................................... 59
CARBON DIOXIDE EMISSIONS ................................................................................................................. 59
SENSITIVITY STUDIES AND RESPONSES TO COMMISSION REQUESTS ..................................................... 61
Clean Power Plan and Allocation of Renewable Energy Attributes .................................................. 61
Historical Cooling Degree Days ........................................................................................................ 63
Interaction of FERC Order 1000 and Energy Gateway ..................................................................... 63
Accelerated Class 2 DSM ................................................................................................................... 63
CHAPTER 6 – ACTION PLAN STATUS UPDATE ...............................................................67
APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS ...........................................75

PACIFICORP – 2015 IRP UPDATE INDEX OF TABLES

iii
INDEX OF TABLES
Table ES.1 – Comparison of 2015 IRP Update with 2015 IRP Preferred Portfolio (Megawatts) ................................. 5
Table ES.2 – 2015 IRP Update Action Plan .................................................................................................................. 6
Table 2.1 – Energy Gateway Segment In-Service Dates ............................................................................................. 21
Table 3.1 – New Qualifying Facility Wind Contracts Online 2015-2017 ................................................................... 27
Table 3.2 – New Qualifying Facility Solar Contracts Online 2015-2017 .................................................................... 28
Table 3.3 – System Capacity Load and Resource Balance without Resource Additions, 2015 IRP Update
(Megawatts) ....................................................................................................................................................... 31
Table 3.4 – System Capacity Load and Resource Balance without Resource Additions, Business Plan (Megawatts)
........................................................................................................................................................................... 32
Table 3.5 – System Capacity Load and Resource Balance without Resource Additions, 2015 IRP (Megawatts) ...... 33
Table 3.6 – System Capacity Load and Resource Balance without Resource Additions, 2015 IRP Update less 2015
IRP (Megawatts) ................................................................................................................................................ 34
Table 3.7 – System Capacity Load and Resource Balance without Resource Additions, Business Plan less 2015 IRP
(Megawatts) ....................................................................................................................................................... 35
Table 4.1 – Updated Cost of Solar Resources, 2014$ - (50 MWAC Single Axis Tracking) ......................................... 43
Table 4.2 – Updated Cost of Wind Resources, 2014$ ................................................................................................. 43
Table 4.3 – Updated Cost of Energy Storage, 2014$................................................................................................... 44
Table 4.4 – Updated Supply Side Resource Table, 2014$ ........................................................................................... 45
Table 5.1 – Comparison of 2015 IRP Update with 2015 IRP Preferred Portfolio (Megawatts) .................................. 48
Table 5.2 – 2015 IRP Update Capacity Load and Resource Balance (Megawatts) ..................................................... 49
Table 5.3 – 2015 IRP Update, Detailed Portfolio (Megawatts) ................................................................................... 50
Table 5.4 – 2015 Fall Business Plan Capacity Load and Resource Balance (Megawatts) .......................................... 52
Table 5.5 –Business Plan, Detailed Portfolio (Megawatts) ......................................................................................... 53
Table 5.6 – Oregon RPS Targets ................................................................................................................................. 53
Table 5.7 – California RPS Targets ............................................................................................................................. 58
Table 5.8 – Portfolio Comparison of Accelerated DSM Study and 2015 IRP Update (Megawatts) ........................... 65
Table 6.1 – 2015 IRP Action Plan Status Update ........................................................................................................ 68
Table A.1 – October 2015 (2015 IRP Update): Forecasted Annual Load Growth, 2016 through 2025 (Megawatt-
hours) ................................................................................................................................................................. 75
Table A.2 – October 2015 (2015 IRP Update): Forecasted Annual Coincident Peak Load (Megawatts) ................... 75
Table A.3 – September 2014 (2015 IRP): Forecasted Annual Load Growth, 2016 through 2025 (Megawatt-hours) 76
Table A.4 – September 2014 (2015 IRP): Forecasted Annual Coincident Peak Load (Megawatts) ........................... 76
Table A.5 – Annual Load Growth Change: October 2015 (2015 IRP Update) Forecast less September 2014 (2015
IRP) Forecast (Megawatt-hours) ........................................................................................................................ 77
Table A.6 – Annual Coincidental Peak Growth Change: October 2015 (2015 IRP Update) Forecast less September
2014 (2015 IRP) Forecast (Megawatts) ............................................................................................................. 77

PACIFICORP – 2015 IRP UPDATE INDEX OF FIGURES

iv
INDEX OF FIGURES
Figure ES.1 – System Coincident Peak Load ................................................................................................................ 1
Figure ES.2 – Power and Natural Gas Price Comparisons (Nominal)........................................................................... 2
Figure ES.3 – Capacity Position Comparison................................................................................................................ 4
Figure 2.1 – Energy Gateway Map .............................................................................................................................. 20
Figure 3.1 – Forecasted Annual Load Growth............................................................................................................. 25
Figure 3.2 – Forecasted Annual Coincident Peak Load............................................................................................... 26
Figure 3.3 – Capacity Position Comparison ................................................................................................................ 30
Figure 3.4 – 2015 IRP Update, System Capacity Position Trend ................................................................................ 36
Figure 3.5 – 2015 IRP Update, West Capacity Position Trend ................................................................................... 37
Figure 3.6 – 2015 IRP Update, East Capacity Position Trend ..................................................................................... 37
Figure 4.1 – Henry Hub Natural Gas Prices (Nominal) ............................................................................................... 40
Figure 4.2 – Average Annual Flat Palo Verde Electricity Prices (Nominal) ............................................................... 40
Figure 4.3 – Average Annual Heavy Load Hour Palo Verde Electricity Prices (Nominal) ........................................ 41
Figure 4.4 – Average Annual Flat Mid-Columbia Electricity Prices (Nominal) ......................................................... 41
Figure 4.5 – Average Annual Heavy Load Hour Mid-Columbia Electricity Prices (Nominal) ................................... 42
Figure 5.1 – Baseline Oregon RPS Compliance Position ............................................................................................ 54
Figure 5.2 – Oregon RPS Compliance Position with REC Purchases ......................................................................... 55
Figure 5.3 – Baseline Washington RPS Compliance Position ..................................................................................... 57
Figure 5.4 – Washington RPS Compliance Position with REC Purchases .................................................................. 57
Figure 5.5 – Baseline California RPS Compliance Position ........................................................................................ 58
Figure 5.6 – California RPS Compliance Position with REC Purchases ..................................................................... 59
Figure 5.7 – Total CO2 Emissions ............................................................................................................................... 60
Figure 5.8 – Total Thermal Generation ....................................................................................................................... 60
Figure 5.9 – Mass-Cap and Emissions from Affected Units ....................................................................................... 61
Figure 5.10 – Oregon Share of CO2 Emission from Coal-fueled Resources ............................................................... 61

PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

1
EXECUTIVE SUMMARY
PacifiCorp submitted its 2015 Integrated Resource Plan (2015 IRP) to state regulatory
commissions in March 2015. That plan provides a framework for future actions that PacifiCorp
will take to provide reliable, reasonable-cost service with manageable risks for customers. This
2015 IRP Update describes resource planning and procurement activities that occurred since the
2015 IRP was filed, presents an updated load and resource balance, presents an updated resource
portfolio consistent with changes in the planning environment, presents an updated action plan,
and provides a status update on the action plan filed with the 2015 IRP. In presenting the updated
load and resource balance and updated resource portfolio, PacifiCorp shows changes relative to
the 2015 IRP and relative to its fall 2015 ten-year business plan (Business Plan), which covers
the 2016 to 2025 planning horizon. In this update PacifiCorp also addresses recommendations
and requirements identified by its state regulatory commissions during the 2015 IRP
acknowledgement process.
2015 IRP Update Highlights

PacifiCorp’s long-term planning process involves balanced consideration of cost, risk,
uncertainty, supply reliability/delivery, and long-run public policy goals. The following
summarizes the key highlights of PacifiCorp’s 2015 IRP Update:

 As shown in Figure ES.1 PacifiCorp’s most recent coincident system peak load forecast,
used for the Business Plan and the 2015 IRP Update, is down relative to the 2015 IRP. On
average, across the front ten years of the planning period, the coincident system peak is down
by about 54 MW relative to the 2015 IRP.

Figure ES.1 – System Coincident Peak Load

10,000
10,200
10,400
10,600
10,800
11,000
11,200
11,400
MW
2015 IRP Update and Business Plan 2015 IRP
PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

2
 Figure ES.2 shows that forecasted natural gas and energy prices have declined from those
assumed in the 2015 IRP. Domestic gas price forecasts continue to be driven down by growth
in unconventional shale gas plays. This in turn (combined with lower forecast regional loads)
impacts forward market power prices.

Figure ES.2 – Power and Natural Gas Price Comparisons (Nominal)

 PacifiCorp’s updated resource portfolio continues to show that customer loads over the front
ten years of the planning horizon will be met with front office transactions (firm market
purchases) and energy efficiency. Over the front ten years of the planning period (2016
through 2025), accumulated acquisition of incremental energy efficiency resources meets
87% of projected load growth.

 PacifiCorp refreshed its analysis of Regional Haze compliance alternatives for Naughton
Unit 3, which was assumed to convert to a natural gas-fired facility by mid-2018 in the 2015
IRP. With reduced load, lower market prices, and increased costs for gas conversion, the
refreshed analysis shows that retiring Naughton Unit 3 at the end of 2017 is a lower cost
alternative than the assessed gas conversion approach. As such, the capacity of the converted
Unit 3 is no longer included in the 2015 IRP Update resource portfolio after year-end 2017.
However, recognizing that Naughton Unit 3 is an important generation resource to the state
of Wyoming and PacifiCorp’s customers, PacifiCorp will continue to review emerging
technologies, re-assess traditional gas conversion technologies and costs, and consider other
potential alternatives that could be applied to Naughton Unit 3 to allow continued operation
beyond year-end 2017.

 The state of Arizona issued a regional haze state implementation plan (SIP) requiring, among
other things, the installation of SO2, NOX and particulate matter controls on Cholla Unit 4,
which is owned by PacifiCorp but operated by Arizona Public Service. The U.S.
Environmental Protection Agency (EPA) approved in part, and disapproved in part, the
Arizona SIP and issued a federal implementation plan (FIP) requiring the installation of
selective catalytic reduction (SCR) equipment on Cholla Unit 4. PacifiCorp filed an appeal
regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of
Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP
as it relates to their interests. With respect to the Cholla FIP requirements, the court has
placed the appeals in abeyance while parties attempt to agree on an alternative compliance
approach. In October 2015, EPA acknowledged receipt of the state of Arizona’s re-assessed
regional haze SIP that commits to ceasing operation of Cholla Unit 4 as a coal fueled
20.00
30.00
40.00
50.00
60.00
70.00
80.00
$/
M
W
h
Average Mid-C/Palo Verde Flat Electricity Prices
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
$/
M
M
B
t
u
Henry Hub Natural Gas Prices
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

3
resource in April 2025, in lieu of installation of SCR. EPA is currently expected to propose
its final action on the Arizona SIP in mid-2016 and commence the public comment process.
Similar to Naughton Unit 3, with reduced load, lower market prices, and expected costs for
gas conversion, PacifiCorp has assumed Cholla Unit 4 will cease operation at the end of 2024
for capacity planning purposes in the 2015 IRP Update.

 After PacifiCorp filed its 2015 IRP, EPA issued its final rule for the Clean Power Plan (CPP).
On February 9, 2016, the U.S. Supreme Court issued a stay of the CPP suspending
implementation of the rule pending the outcome of the merits of litigation before the D.C.
Circuit Court of Appeals. If parties petition for a writ of certiorari before the U.S. Supreme
Court, the stay will remain in effect until the U.S. Supreme Court takes action to either deny
the petition, or, if the U.S. Supreme Court hears the case, the stay remains in effect until the
court enters its judgment. Oral argument on the CPP litigation is scheduled for June 2, 2016
before the D.C. Circuit Court of Appeals. In the 2015 IRP Update, PacifiCorp assumes a
mass-based emission target to limit CO2 emission from its affected generation facilities
covered by the CPP.

 On March 8, 2016, Oregon Senate Bill 1547-B (SB 1547-B), the Clean Electricity and Coal
Transition Plan, was signed into law, which, among other things, doubles the Oregon
renewable portfolio standard (RPS) target to 50% by 2040. In October 2015, California
Senate Bill No. 350 (SB 350) was signed into law, which among other things, expands
California’s RPS targets to 50% by 2030. Considering these updated RPS targets, renewable
energy credit (REC) banking provisions and the market potential for RECs, PacifiCorp can
meet its state RPS obligations through the planning horizon with REC purchases. However,
PacifiCorp has identified the potential for a near-term, time-sensitive opportunity that may
reduce state RPS compliance costs over time through the acquisition of renewable resources
that can take full advantage of federal income tax deductions and credits passed in December
2015. PacifiCorp has updated its action plan to issue requests for proposals (RFPs) seeking
both REC purchase and resource procurement alternatives.
Load and Resource Balance Update

Figure ES.3 summarizes the 2015 IRP Update capacity load and resource balance, prior to
acquiring any new resources and making firm market purchases, alongside the load and resource
balance from the 2015 IRP and the Business Plan. The load and resource balance has decreased
by an average of 209 MW, relative to the 2015 IRP, in 2016 and 2017 reflecting to changes in
the load forecast, hydro generation and qualifying facility contracts. The projected load and
resource balance position is shorter beginning in 2018, relative to the 2015 IRP, primarily due to
the assumed early retirement of Naughton Unit 3 at the end of 2017 and Cholla Unit 4 at the end
of 2024. This is partially offset by the addition of new wind and solar qualifying facility
contracts. The 2015 IRP Update load and resource balance shows is shorter by 128 MW in 2018
rising to 720 MW by 2025.

PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

4
Figure ES.3 – Capacity Position Comparison

Resource Portfolio Update

Table ES.1 reports the 2015 IRP Update resource portfolio and differences relative to the 2015
IRP Preferred Portfolio.1 The table shows the resource mix targeted to achieve a 13% planning
reserve margin in each reported year. As compared to the 2015 IRP Preferred Portfolio, changes
in the resource mix for the 2016-2025 planning period reflect those needed to meet capacity
needs associated with the assumed early retirement of Naughton Unit 3 and Cholla Unit 4. As
was the case in the 2015 IRP Preferred Portfolio, PacifiCorp continues to plan to meet its
customers’ needs largely through the acquisition of cost-effective energy efficiency (Class 2
Demand Side Management) resources and FOTs over the next ten years.

1 A comparison of the portfolio changes relative to the Business Plan is presented in Chapter 5.
PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

5
Table ES.1 – Comparison of 2015 IRP Update with 2015 IRP Preferred Portfolio
(Megawatts)

2015 IRP Update
Capacity (MW)10- year Total
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2016-2025
Expansion Options
Gas - CCCT - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - -
DSM - Energy Efficiency 143 128 138 146 158 142 149 155 161 162 135 1,476
DSM - Load Control - - - - - - - - - - 39 39
Renewable - Wind - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - - -
Renewable - Biomass - - - - - - - - - - - -
Front Office Transactions *764 903 748 1,094 1,246 1,203 970 1,060 965 993 1,440 1,062
Existing Unit Changes
Coal Early Retirement/Conversions (222)- - (280) - - - - - - (387) (667)
Thermal Plant End-of-life Retirements - - - - - - - - - - - -
Coal Plant Gas Conversion Additions - - - - - - - - - - - -
Total 685 1,031 886 960 1,403 1,345 1,120 1,215 1,126 1,155 1,227
FOT in resource total are 10-year averages
2015 IRP Update less 2015 IRP Preferred Portfolio
Capacity (MW)10- year Total
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2016-2025
Expansion Options
Gas - CCCT - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - -
DSM - Energy Efficiency 10 (11) (8) (0) 5 8 12 11 15 14 12 58
DSM - Load Control - - - - - - - (5) (11) - 39 23
Renewable - Wind - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - - -
Renewable - Biomass - - - - - - - - - - - -
Front Office Transactions *37 (34) (157) 224 311 224 202 269 205 239 670 215
Existing Unit Changes
Coal Early Retirement/Conversions - - - - - - - - - - - -
Thermal Plant End-of-life Retirements - - - - - - - - - - - -
Coal Plant Gas Conversion Additions - - - (337) - - - - - - (387) (724)
Total 47 (45) (164) (113) 315 232 214 275 209 252 333
FOT in resource total are 10-year averages
PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

6
IRP Action Plan

PacifiCorp has updated its action plan to reflect changes in the planning environment since the IRP was filed in March 2015. Specifically,
PacifiCorp updated action item 1a (Renewable Portfolio Standard Compliance) to issue RFPs for REC and near-term resource
procurement opportunities that can be used to meet RPS requirements in Oregon, Washington, and California. The updated action plan
also removes action item 1c (Oregon Solar Capacity Standard), which was eliminated when SB 1547-B was signed into law. As it relates
to coal resource actions, action item 4a (Naughton Unit 3) has been updated consistent with PacifiCorp’s most recent analysis summarized
in Confidential Appendix B. Table ES.2 presents the updated action plan. Chapter 6 of the 2015 IRP Update provides a status update of
PacifiCorp’s 2015 IRP action plan action items.

Table ES.2 – 2015 IRP Update Action Plan

 Issue a request for proposals (RFP) in spring 2016 seeking bids for new renewable resources that qualify for the
Oregon, Washington, and/or California RPS and that can take full advantage of federal income tax deductions and
credits renewed or extended in December 2015.
 Issue a RFP in 2016 for current year and forward vintage RECs that qualify for the Oregon, Washington, and/or
California RPS.
 Complete the concurrent evaluation, selection, and contracting process for both the renewable resource RFP and REC
RFP by fall 2016.

 On a quarterly basis, and through calendar year 2016, issue reverse RFPs to sell 2016 vintage or older RECs that are
not required to meet state RPS compliance obligations.

– Acquire economic short-term firm market purchases for on-peak summer deliveries from 2016 through 2017
consistent with the Risk Management Policy and Commercial and Trading Front Office Procedures and Practices.
These short-term firm market purchases will be acquired through multiple means:
– Balance of month and day-ahead brokered transactions in which the broker provides the service of providing a
PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

7
–
–
Action
Item 3. Demand Side Management (DSM) Actions
3a
Class 1 DSM
–
3b
Class 2 DSM

selections from the preferred portfolio as summarized in the following table. PacifiCorp’s implementation plan to
Year Annual Incremental Energy (GWh) Annual Incremental Capacity* (MW)
2016 584 139
2017 616 146
2018 634 146
*Class 2 DSM capacity figures reflect projected maximum annual hourly energy savings, which is similar to a nameplate rating for a supply side
resource.
Action
Item 4. Coal Resource Actions
4a
Naughton Unit 3

4b
Dave Johnston Unit 3
 The portion of EPA’s final Regional Haze Federal Implementation Plan (FIP) requiring the installation of sele
 If following appeal, EPA’s final FI
PACIFICORP – 2015 IRP UPDATE EXECUTIVE SUMMARY

8
 If following appeal, EPA’s final FIP as it pertains to Dave Johnston Unit 3 is or will be modified, PacifiCorp will
4c
Wyodak
 Continue to pursue the Company’s appeal of the portion of EPA’s final Regional Haze FIP
 If following appeal, EPA’s final FIP as it pertains to installation of SCR at Wyodak is upheld (with a modifi
4d
Cholla Unit 4


Action
Item 5. Transmission Actions
5a
Energy Gateway Permitting

–
–
–
5b
Wallula to McNary 230 kilovolt Transmission Line


PACIFICORP – 2015 IRP UPDATE CHAPTER 1 - INTRODUCTION

9
CHAPTER 1 – INTRODUCTION
This 2015 IRP Update describes resource planning activities that occurred after the 2015 IRP
was filed in March 2015, presents an updated load and resource balance, an updated resource
portfolio consistent with changes in the planning environment, presents an updated action plan,
and provides a status update on the action plan filed with the 2015 IRP. In presenting the updated
load and resource balance assessment and updated resource portfolio, PacifiCorp shows changes
relative to the 2015 IRP and relative to its fall 2015 ten-year business plan (Business Plan),
which covers the 2016 to 2025 planning horizon. In this update PacifiCorp also addresses
recommendations and requirements identified by its state regulatory commissions during the
2015 IRP acknowledgement process.

In support of its business planning process, PacifiCorp refined the 2015 IRP Preferred Portfolio
to reflect updates to forecasted loads, resources, market prices, and other model inputs.
PacifiCorp’s business planning process also considers capital expenditure and operating cost
constraints with input from the business units (Pacific Power, Rocky Mountain Power, and
PacifiCorp Transmission). Consideration of both capital and operating cost constraints is critical
to ensure that PacifiCorp’s business plan is financially supportable and affordable to customers.
The 2015 IRP Preferred Portfolio served as the primary basis in establishing the resource
portfolio for the Business Plan. A similar process has been completed to develop the load and
resource balance and resource portfolio for this 2015 IRP Update, which considers updates to
forecasted loads, resources, market prices, and other model inputs since the intervening Business
Plan resource portfolio was developed.

The 2015 IRP Update also addresses recommendations and requirements identified by
PacifiCorp’s state regulatory commissions during the 2015 acknowledgement process. These
include requests from the Washington Utilities and Transportation Commission (WUTC)2 and
Public Utility Commission of Oregon (OPUC)3 regarding assumptions related to the use of
renewable energy attributes for compliance with both state renewable portfolio standards (RPS)
and the Clean Power Plan (CPP). The WUTC also requested PacifiCorp analyze its future
resource needs for Washington RPS compliance based on the same allocation methodology used
to allocate renewable energy generation to Washington. The OPUC also requested a study that
replaces base case DSM with accelerated DSM and to report the impact on the resource
portfolio. The Public Service Commission of Utah (PSCU)4 requested an explanation, as
necessary, of the interaction of requirements from the Federal Energy Regulatory Commission
(FERC) Order 1000 and any Energy Gateway Project. PSCU also directed PacifiCorp to present
an analysis on whether the available historical cooling degree day information is still an
appropriate predictor of future normal conditions in the load forecast.

This report first describes the current planning environment, load updates, resource updates, state
and federal policy updates, and Energy Gateway transmission planning and project completion
forecast (Chapter 2). Next, Chapters 3 and 4 describe the changes to key inputs and assumptions
2 Acknowledgement letter in PacifiCorp’s 2015 Electric Integrated Resource Plan, Docket UE-140546, dated
November 13, 2015. 3 Order No. 16-071 in PacifiCorp’s 2015 Integrated Resource Plan, Docket LC 62, dated February 29, 2016. 4 Report and Order in PacifiCorp’s 2015 Integrated Resource Plan, Docket No. 15-035-04, dated January 8, 2016.
PACIFICORP – 2015 IRP UPDATE CHAPTER 1 - INTRODUCTION
10
relative to those used for the 2015 IRP. The updated resource portfolio is then presented along
with a status update on the 2015 IRP Action Plan (Chapters 5 and 6, respectively). Appendix A
provides additional load forecast details. Confidential Appendix B presents PacifiCorp’s updated
Naughton Unit 3 analysis.

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CHAPTER 2 – PLANNING ENVIRONMENT
Business Plan Development

The 2015 IRP Preferred Portfolio served as the basis for the resource assumptions used in
PacifiCorp’s fall 2015 ten-year business plan (Business Plan), which covers the 2016 to 2025
planning horizon. Changes in the portfolio reflect updates to forecasted loads, resources, market
prices, and other model inputs. PacifiCorp’s business planning process also considers capital
expenditure and operating cost constraints to ensure that the resulting business plan is financially
supportable and affordable to customers.
Federal Policy Update
New Source Performance Standards for Carbon Emissions – Clean Air Act § 111(b)

New Source Performance Standards (NSPS) are established under the Clean Air Act for certain
industrial sources of emissions determined to endanger public health and welfare. On August 3,
2015, the U.S. Environmental Protection Agency (EPA) issued a final rule limiting carbon
emissions from coal- and natural gas-fired power plants. New natural gas fueled power plants
can emit no more than 1,000 pounds of carbon dioxide (CO2) per megawatt-hour (MWh). New
coal fueled power plants can emit no more than 1,400 pounds of CO2/MWh. The final rule
largely exempts simple cycle combustion turbines from meeting the standards.
Carbon Emission Guidelines for Existing Sources – Clean Air Act § 111(d)

EPA issued a final rule, referred to as the Clean Power Plan (CPP), regulating carbon emissions
from existing power plants on August 3, 2015. Under the final rule, states would be required to
submit compliance plans by September 6, 2016. However, a state may seek an extension to
September 6, 2018 to submit a state plan. On August 3, 3015, EPA also issued a proposed
federal plan and model trading rules for public comment. The public comment period closed
January 21, 2016. Under section 111(d) of the Clean Air Act, states are required to develop
standards of performance, which are the degree of emission limitation achievable through the
application of the best system of emission reduction (BSER).

In the final rule, EPA set forth emission reduction goals for each state based on EPA’s
formulation of BSER, which is made up of three building blocks: (1) heat rate improvements at
existing coal-fueled resources; (2) increased utilization of natural gas resources; and (3)
increased deployment of zero-emitting resources. States would be required to meet the emission
reduction goal by 2030, as well as interim goals, which would be met over three interim
compliance periods: 2022-2024, 2025-2027, and 2028-2029. Utilizing its formulation of BSER,
EPA established uniform national interim and final carbon emission performance standards as
1,305 lb CO2/MWh for coal-fired power plants and 771 lb CO2/MWh for natural gas-fired power
plants, which in turn were utilized to establish projected mass-based and rate-based compliance
targets for individual states.

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Under the final rule, states have a number of implementation options: states may choose to adopt
the rate-based standard and apply them on a subcategory or state-specific blended rate basis, or,
alternatively, states may choose to adopt the standards as a mass-based state goal. In the final
rule, EPA provided state mass-based goals that it stated are equivalent to the rate-based
emissions goals. Under a mass-based implementation program, compliance would be
demonstrated through reported stack emissions and the retirement of carbon allowances. Under a
rate-based implementation program, compliance would be demonstrated through the use of
megawatt-hour credits referred to as emission rate credits (ERCs) from renewable energy and,
potentially, energy efficiency. States also have the option to trade with other affected resources
in other states implementing similar approaches (e.g., rate state with other rate states or mass
state with other mass states) so long as those states meet certain “trading ready” minimum
requirements.

The federal plan proposal also includes model rules for rate-based and mass-based trading
programs for potential use by any state in developing its state plan. The mass-based federal plan
proposal includes a proposed allowance allocation methodology and a method for states to
address leakage through allowance set-asides. For this 2015 IRP Update, PacifiCorp developed
its updated resource portfolio with mass-based emission targets aligned with EPA’s proposed
allowance allocation methodology. PacifiCorp will develop additional CPP scenarios in
coordination with its stakeholders during the 2017 IRP public process.

On February 9, 2016, the U.S. Supreme Court issued a stay of the CPP suspending
implementation of the rule pending the outcome of the merits of litigation before the D.C. Circuit
Court of Appeals. If parties petition for a writ of certiorari before the U.S. Supreme Court, the
stay will remain in effect until the U.S. Supreme Court takes action to either deny the petition,
or, if the U.S. Supreme Court hears the case, the stay remains in effect until the court enters its
judgment. Oral argument on the CPP litigation is scheduled for June 2, 2016 before the D.C.
Circuit Court of Appeals.
Clean Air Act Criteria Pollutants – National Ambient Air Quality Standards

The Clean Air Act requires EPA to set National Ambient Air Quality Standards (NAAQS) for
certain pollutants considered harmful to public health and the environment. For a given NAAQS,
EPA and/or a state identifies various control measures that once implemented are meant to
achieve an air quality standard for a certain pollutant, with each standard rigorously vetted by the
scientific community, industry, public interest groups, and the general public.

Particulate matter (PM), sulfur dioxide (SO2), ozone (O3), nitrogen dioxide (NO2), carbon
monoxide (CO), and lead are often grouped together, because under the Clean Air Act, each of
these categories is linked to one or more NAAQS. These “criteria pollutants”, while undesirable,
are not toxic in typical concentrations in the ambient air. Under the Clean Air Act, they are
regulated differently from other types of emissions, such as hazardous air pollutants and
greenhouse gases. Within the past few years, EPA established new standards for PM, SO2, and
NO2.

In October 2015, EPA issued a final rule modifying the standards for ground-level ozone from
75 parts per billion (ppb) to 70 ppb. Under the final rule, EPA will designate areas in the country
as being in “attainment” or “nonattainment” of the revised standards by October 2017. State
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compliance dates will be set depending on the ozone level in the area. PacifiCorp facilities will
only be impacted to the extent they are located in an ozone nonattainment area.
Regional Haze

EPA’s regional haze rule, finalized in 1999, requires states to develop and implement plans to
improve visibility in certain national park and wilderness areas. On June 15, 2005, EPA issued
final amendments to its regional haze rule. These amendments apply to the provisions of the
regional haze rule that require emission controls known as the Best Available Retrofit
Technology (BART), for industrial facilities meeting certain regulatory criteria with emissions
that have the potential to impact visibility. These pollutants include fine PM, NOX, SO2, certain
volatile organic compounds, and ammonia. The 2005 amendments included final guidelines,
known as BART guidelines, for states to use in determining which facilities must install controls
and the type of controls the facilities must use. States were given until December 2007 to
develop their implementation plans, in which states were responsible for identifying the facilities
that would have to reduce emissions under BART guidelines as well as establishing BART
emissions limits for those facilities. States are also required to periodically update or revise their
implementation plans to reflect current visibility data and the effectiveness of the state’s long-
term strategy for achieving reasonable progress toward visibility goals. States are currently
required to submit the next periodic update by July 31, 2018. However, this date may be
extended as EPA has proposed that this date be changed to July 31, 2021.

The regional haze rule is intended to drive additional emissions reductions, particularly from
facilities operating in the Western United States. This includes the states of Utah and Wyoming
where PacifiCorp operates generating units, as well as Arizona where PacifiCorp owns but does
not operate a coal unit, and in Colorado and Montana where PacifiCorp has partial ownership in
generating units operated by others, but are nonetheless subject to the regional haze rule.

In May 2011, the state of Utah issued a regional haze SIP requiring the installation of SO2, NOx
and PM controls on Hunter Units 1 and 2 and Huntington Units 1 and 2. In December 2012, the
EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and PM
portions. EPA’s approval of the SO2 SIP was appealed to federal circuit court. In addition,
PacifiCorp and the state of Utah appealed EPA’s disapproval of the NOX and PM SIP.
PacifiCorp and the state’s appeals were dismissed. In June 2015, the state of Utah submitted a
revised SIP to EPA for approval with an updated BART analysis incorporating a requirement for
PacifiCorp to retire Carbon Units 1 and 2, recognizing NOX controls previously installed on
Hunter Unit 3, and concluding that no incremental controls (beyond those included in the May
2011 SIP and already installed) were required at the Hunter and Huntington units. On January
14, 2016, EPA issued a proposed rule including two co-proposals: one to approve the SIP in its
entirety and one to partially approve and partially disapprove the revised Utah SIP and propose a
FIP. The public comment period on EPA’s proposed action closed March 14, 2016.

On January 10, 2014, EPA issued a final action in Wyoming requiring installation of the
following NOX and PM controls at PacifiCorp facilities:

 Naughton Unit 3 by December 31, 2014 - selective catalytic reduction (SCR) equipment
and a baghouse
 Jim Bridger Unit 3 by December 31, 2015 - SCR equipment
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 Jim Bridger Unit 4 by December 31, 2016 - SCR equipment
 Jim Bridger Unit 2 by December 31, 2021 - SCR equipment
 Jim Bridger Unit 1 by December 31, 2022 - SCR equipment
 Dave Johnston Unit 3 - SCR within five years or a commitment to shut down in 2027
 Wyodak - SCR equipment within five years

Different aspects of EPA’s final action were appealed by a number of entities. PacifiCorp
appealed EPA’s action requiring SCR at Wyodak. PacifiCorp requested, and was granted, a stay
of EPA’s action as it pertains to Wyodak pending resolution of the appeals. With respect to
Naughton Unit 3, in its final action EPA indicated support for the conversion of the unit to
natural gas and that it would expedite action relative to consideration of the gas conversion once
the state of Wyoming submitted the requisite SIP amendment. PacifiCorp has obtained a
construction permit and revised regional haze BART permit from the state of Wyoming to
convert Naughton Unit 3 to natural gas in 2018. Wyoming has not yet submitted a revised
regional haze SIP incorporating this alternative compliance approach to EPA.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of
SO2, NOX and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by
Arizona Public Service. EPA approved in part, and disapproved in part, the Arizona SIP and
issued a FIP requiring the installation of SCR equipment on Cholla Unit 4. PacifiCorp filed an
appeal regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of
Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it
relates to their interests. With respect to the Cholla FIP requirements, the court has placed the
appeals in abeyance while parties attempt to agree on an alternative compliance approach. In
October 2015, EPA acknowledged receipt of the state of Arizona’s alternate compliance
approach for Cholla for review and final action. EPA is currently expected to propose their final
action in mid-2016 for public comment.

The state of Colorado issued a regional haze SIP requiring, among other things, the installation
of selective non-catalytic reduction (SNCR) technology at Craig Unit 1 by 2018. Environmental
groups appealed EPA’s action, in which PacifiCorp intervened in support of EPA. In July 2014,
parties to the litigation, other than PacifiCorp, entered into a settlement agreement which
requires installation of SCR equipment at Craig Unit 1 in 2021. The revised SIP, as reflected in
the settlement, is currently pending EPA approval. PacifiCorp opposed the settlement agreement
between the EPA and other parties to the litigation.
Mercury and Hazardous Air Pollutants

The Mercury and Air Toxics Standards (MATS) became effective April 16, 2012. The MATS
rule requires new and existing coal-fueled facilities achieve emission standards for mercury, acid
gases and other non-mercury hazardous air pollutants. Existing sources were required to comply
with the new standards by April 16, 2015. However, individual sources may have been granted
up to one additional year, at the discretion of the Title V permitting authority, to complete
installation of controls or for transmission system reliability reasons. In June 2015, the U.S.
Supreme Court found that EPA did not properly consider costs in making its determination to
regulate hazardous pollutants from power plants. In December 2015, the D.C. Circuit Court of
Appeals ruled that MATS may be enforced as EPA modifies the rule to comply with the
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Supreme Court decision. By April 2015, PacifiCorp had taken the required actions to comply
with MATS across its generation facilities.
Coal Combustion Residuals

Coal Combustion Residuals (CCRs), including coal ash, are the byproducts from the combustion
of coal in power plants. CCRs have historically been considered exempt wastes under an
amendment to the Resource Conservation and Recovery Act (RCRA); however, EPA issued a
final rule in December 2014 to regulate CCRs for the first time. Under the final rule, EPA will
regulate CCRs as non-hazardous waste under Subtitle D of RCRA and establish minimum
nationwide standards for the disposal of CCRs. The final rule was effective October 19, 2015.
Under the final rule, surface impoundments and landfills utilized for CCRs may need to close
unless they can meet more stringent regulatory requirements. At the time the rule was published
in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained
CCRs. Prior to the effective date in October 2015, nine surface impoundments and three landfills
were either closed or repurposed to no longer receive CCRs and hence are not subject to the final
rule.
Water Quality Standards

Cooling Water Intake Structures – The federal Water Pollution Control Act (“Clean Water
Act”) establishes the framework for maintaining and improving water quality in the United
States through a program that regulates, among other things, discharges to and withdrawals from
waterways. The Clean Water Act requires that cooling water intake structures reflect the “best
technology available for minimizing adverse environmental impact” to aquatic organisms. In
May 2014, EPA issued a final rule, effective October 2014, under § 316(b) of the Clean Water
Act to regulate cooling water intakes at existing facilities. The final rule established requirements
for electric generating facilities that withdraw more than two million gallons per day, based on
total design intake capacity, of water from waters of the U.S. and use at least 25% of the
withdrawn water exclusively for cooling purposes. PacifiCorp’s Dave Johnston generating
facility withdraws more than two million gallons per day of water from waters of the U.S for
once-through cooling applications. Jim Bridger, Naughton, Gadsby, Hunter, and Huntington
generating facilities currently utilize closed cycle cooling towers but withdraw more than two
million gallons of water per day. The rule includes impingement (i.e., when fish and other
aquatic organisms are trapped against screens when water is drawn into a facility’s cooling
system) mortality standards and entrainment (i.e., when organisms are drawn into the facility)
standards. The standards will be set on a case by case basis to be determined through site-
specific studies and will be incorporated into each facility’s discharge permit.

Effluent Limit Guidelines – EPA first issued effluent guidelines for the Steam Electric Power
Generating Point Source Category (i.e., the Steam Electric effluent guidelines) in 1974 with
subsequent revisions in 1977 and 1982. On November 3, 2015, EPA finalized revised effluent
limit guidelines. The rule does not allow the discharge of bottom ash or fly ash transport water,
and directly impacts the Wyodak, Dave Johnston, and Naughton facilities.
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2015 Tax Extender Legislation

On December 18, 2015, President Obama signed tax extender legislation (H.R. 2029) that
retroactively and prospectively extended certain expired and expiring federal income tax
deductions and credits.

Bonus Depreciation – Fifty percent bonus depreciation was extended for property acquired and
placed in service during 2015, 2016, and 2017. For property acquired and placed in service
during 2018, 40% of the eligible cost of the property qualifies for bonus depreciation. For
property acquired and placed in service during 2019, 30% of the eligible cost of the property
qualifies for bonus depreciation. For property placed in service after December 31, 2019, there
will be no bonus depreciation.5

Production Tax Credit (Wind) – The production tax credit (PTC), currently 2.3 cents per
kilowatt-hour (inflation adjusted), has been extended and phased out for wind property for which
construction begins prior to January 1, 2020 as follows:

 2015 – 100% retroactive
 2016 – 100% (construction begins prior to January 1, 2017)
 2017 – 80% (construction begins prior to January 1, 2018)
 2018 – 60% (construction begins prior to January 1, 2019)
 2019 – 40% (construction begins prior to January 1, 2020)

Production Tax Credit (Geothermal and Hydro) – The PTC for geothermal and hydro were
granted a two year extension as follows (no phase-out period was adopted):

 2015 – 100% retroactive
 2016 – 100% (construction begins prior to January 1, 2017)

30% Energy Investment Tax Credit (Wind) – The investment tax credit (ITC) has been
extended and phased out for wind property for which construction begins prior to January 1,
2020 as follows:

 2015 – 30% retroactive
 2016 – 30% (construction begins prior to January 1, 2017)
 2017 – 24% (construction begins prior to January 1, 2018)
 2018 – 18% (construction begins prior to January 1, 2019)
 2019 – 12% (construction begins prior to January 1, 2020)

30% Energy Investment Tax Credit (Solar) – The ITC has been extended steps down for solar
property for which construction begins prior to January 1, 2022 as follows:

 2015 – 30% retroactive
 2016 – 30% (construction begins prior to January 1, 2017)
5 There is an exception for long production period property (generally property with a construction period longer
than one year and a cost exceeding $1 million). Costs incurred on long production period property may qualify for
bonus depreciation if physical construction has begun prior to the placed in service date of the bonus phase-out.
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 2017 – 30% (construction begins prior to January 1, 2018)
 2018 – 30% (construction begins prior to January 1, 2019)
 2019 – 30% (construction begins prior to January 1, 2020)
 2020 – 26% (construction begins prior to January 1, 2021)
 2021 – 22% (construction begins prior to January 1, 2022)
 2022 – 10% (construction begins on or after January 1, 2022)
State Policy Update
California

Pursuant to the authority of the Global Warming Solutions Act, in October 2011, the California
Air Resources Board (CARB) adopted a GHG cap-and-trade program with an effective date of
January 1, 2012; compliance obligations were imposed on regulated entities beginning in 2013.
The first auction of GHG allowances was held in California in November 2012 and the second
auction in February 2013. PacifiCorp is required to sell, through the auction process, its directly
allocated allowances, and purchase the required amount of allowances necessary to meet its
compliance obligations.

In May 2014, CARB approved the first update to the Assembly Bill 32 Climate Change scoping
plan, which defined California’s climate change priorities for the next five years and set the
groundwork for post-2020 climate goals. In April 2015, Governor Brown issued an executive
order to establish a mid-term reduction target for California of 40 percent below 1990 levels by
2030. CARB has subsequently been directed to update the AB 32 scoping plan to reflect the new
interim 2030 target and previously-established 2050 target.

In 2002, California established a Renewable Portfolio Standard (RPS) requiring investor-owned
utilities to increase procurement from eligible renewable energy resources. California’s RPS
requirements have been accelerated and expanded a number of times since its inception. Most
recently, in October 2015, Governor Jerry Brown signed into law Senate Bill 350 which requires
utilities to procure 50 percent of their electricity from renewables by 2030. The California Public
Utilities Commission is currently developing rules to implement this new program.
Oregon

In 2007, the Oregon Legislature passed HB 3543 Global Warming Actions which establishes
GHG reduction goals for the state that (i) by 2010, cease the growth of Oregon greenhouse gas
emissions; (ii) by 2020, reduce greenhouse gas levels to 10 percent below 1990 levels; and (iii)
by 2050, reduce greenhouse gas levels to at least 75 percent below 1990 levels. In 2009, the
Legislature passed SB 101 which requires the Oregon Public Utility Commission (OPUC) to
report to the Legislature before November 1 of each even-numbered year on the estimated rate
impacts for Oregon’s regulated electric and natural gas companies associated with meeting the
GHG reduction goals of 10 percent below 1990 levels by 2020 and 15 percent below 2005 levels
by 2020. The OPUC submitted its most recent report November 1, 2014.

On July 3 2013, the Oregon Legislature passed Senate Bill 306 which directs the legislative
revenue officer to prepare a report examining the feasibility of imposing a clean air fee or tax as
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18
a new revenue option. The report includes an evaluation of how to treat imported and exported
energy sources. A final report was published December 2014.

In 2007, Oregon enacted Senate Bill 838 establishing an RPS requirement in Oregon. Under
Senate Bill 838, utilities are required to deliver 25 percent of their electricity from renewable
resources by 2025. On March 8, 2016, Governor Kate Brown signed Senate Bill 1547-B (SB
1547-B), the Clean Electricity and Coal Transition Plan, into law. Senate Bill 1547-B extends
and expands the Oregon RPS requirement to 50 percent of electricity from renewable resources
by 2040 and requires that coal-fired resources are eliminated from Oregon’s allocation of
electricity by January 1, 2030. The increase in the RPS requirements under SB 1547-B is staged:
27% by 2025, 35% by 2030, 45% by 2035 and 50% by 2040. The bill changes the Renewable
Energy Certificate (REC) life to five years while allowing RECs generated from the effective
date of the bill passage until the end of 2022 from new, long-term renewable projects to have
unlimited life. The bill also includes provisions to create a community solar program in Oregon
and encourage greater reliance on electricity for transportation.
Washington

In November 2006, Washington voters approved Initiative 937, the Washington Energy
Independence Act, which imposes targets for energy conservation and the use of eligible
renewable resources on electric utilities. Under I-937, utilities must supply 15% of their energy
from renewable resources by 2020. Utilities must also set and meet energy conversation targets
starting in 2010.

In 2008, the Washington State Legislature approved the Climate Change Framework E2SHB
2815, which establishes state GHG emissions reduction limits. Washington’s emission limits are
to (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25 percent
below 1990 levels; and (iii) by 2050, reduce emissions to 50 percent below 1990 levels, or 70
percent below Washington’s forecasted emissions in 2050. In July 2015, Governor Inslee
released an executive order which directed the Washington Department of Ecology to develop
new rules to reduce carbon emissions in the state. Ecology initiated the rulemaking process in
September 2015 and proposed a draft of the Clean Air Rule on January 5, 2016. After further
stakeholder engagement, on February 26, 2016, the proposed rule was withdrawn in order to
make updates. The Department of Ecology anticipates releasing a new proposed rule for public
review in spring 2016. The only PacifiCorp resource that would be subject to the proposed Clean
Air Rule is the Chehalis natural gas plant.
Utah

In March 2008 Utah enacted the Energy Resource and Carbon Emission Reduction Initiative
which includes provisions to require utilities to pursue renewable energy to the extent that it is
cost-effective to do so. It sets out a goal for utilities to use eligible renewable resources to
account for 20 percent of their 2025 adjusted retail electric sales.

On March 10, 2016, the Utah legislature passed Senate Bill 115 – the Sustainable Transportation
and Energy Plan (STEP). The bill supports plans for electric vehicle infrastructure and clean coal
research in Utah and authorizes the development of a renewable energy tariff for new Utah
customer loads. The legislation establishes a five year pilot program to provide mandated
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funding for electric vehicle infrastructure and clean coal research, and discretionary funding for
solar development, utility-scale battery storage, and other innovative technology and air quality
initiatives. The legislation also allows PacifiCorp to recover its variable power supply costs via
an energy balancing account, and establishes a regulatory accounting mechanism to manage risks
and provide planning flexibility associated with environmental compliance or other economic
impairments that may impact PacifiCorp’s coal-fueled resources in the future. The deferrals of
variable power supply costs will go into effect in June 2016, and implementation and approval of
the other programs are required by January 1, 2017. The bill will go into effect no later than
May 20, 2016, unless vetoed by Governor Gary Herbert.
Greenhouse Gas Emission Performance Standards

California, Oregon and Washington have all adopted GHG emission performance standards
applicable to all electricity generated within the state or delivered from outside the state that is no
higher than the GHG emission levels of a state-of-the-art combined-cycle natural gas generation
facility. The standards for Oregon and California are currently set at 1,100 lb CO2/MWh, which
is defined as a metric measure used to compare the emissions from various GHG based upon
their global warming potential. In March 2013, the Washington Department of Commerce issued
a new rule, effective April 6, 2013, lowering the emissions performance standard to 970 lb
CO2/MWh.
Energy Gateway Transmission Program Planning

As discussed in the 2015 IRP, the Energy Gateway transmission project continues to play an
important role in PacifiCorp’s commitment to provide safe, reliable, reasonably priced electricity
to meet the needs of our customers. Energy Gateway’s design and extensive footprint provides
needed system reliability improvements and supports the development of a diverse range of cost-
effective resources required for meeting customers’ energy needs. The IRP has incorporated
Energy Gateway as part of a solution for delivering the least cost resource portfolio for multiple
IRP planning cycles. PacifiCorp continues to develop methods, in parallel with current industry
best practices and regional transmission planning requirements, to better quantify all the benefits
of transmission that are essential to serve customers. For example, Energy Gateway is designed
to relieve operating limitations, increase capacity, and improve operations and reliability in the
existing electric transmission grid.

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Figure 2.1 – Energy Gateway Map

This map is for general reference only and reflects current plans. It may not reflect the final routes, construction
sequence or exact line configuration.
Energy Gateway Transmission Project Updates

Wallula to McNary (Segment A): This project is required to meet the requirements under
PacifiCorp’s Open Access Transmission Tariff to provide transmission service to a Point to Point
transmission customer when the existing transmission system does not have the capacity to serve
the need. In addition, this project is needed to improve reliability and support future resource
growth. These requirements will continue to drive the project forward. The OPUC issued a
Certificate of Public Convenience and Necessity (CPCN) in September 2011. In 2013, the
project was delayed to allow customers to determine their need as it pertains to ongoing projects
and ability to move resources to their markets. In 2015, a transmission customer confirmed their
need for transmission service requiring the completion of the transmission line agreed to by the
parties as terms of the Transmission Service Agreement and to meet requirements of
PacifiCorp’s Open Access Transmission Tariff. The project is on-track to complete permitting
efforts and construction for a 2017 in-service date.

Gateway West (Segments D and E): Under the National Environmental Policy Act, the Bureau
of Land Management (BLM) has completed the Environmental Impact Statement (EIS) for the
Gateway West project. The BLM released its final EIS on April 26, 2013, followed by the
Record of Decision (ROD) on November 14, 2013, providing a right-of-way grant for all of
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21
Segment D and part of Segment E. The agency chose to defer its decision on the western-most
portion of the project located in Idaho in order to perform additional review of the Morley
Nelson Snake River Birds of Prey Conservation Area. Specifically, the sections of Gateway
West that were deferred for a later ROD include the sections of Segment E from Midpoint to
Hemingway and Cedar Hill to Hemingway. A draft supplemental EIS for the deferred portions of
the project and the Record of Decision is anticipated in 2016.
Gateway South (Segment F): The BLM’s Notice of Intent was published in the Federal Register
in April 2011, followed by public scoping meetings throughout the project area. Comments on
this project from agencies and other interested stakeholders were considered as the BLM
developed the draft EIS, which was issued in February 2014. A final EIS and the Record of
Decision is anticipated in 2016.

Sigurd to Red Butte (Segment G): Project construction is complete and the line was placed in
service in May 2015. Sigurd to Red Butte is the third major segment of Energy Gateway to be
constructed, following Mona to Oquirrh (Segment C) which was placed in service in May 2013
and Populus to Terminal (Segment B) which was placed in service in November 2010.

Boardman to Hemingway (Segment H): Energy Gateway Segment H represents a significant
improvement in the connection between PacifiCorp’s east and west control areas and will help
deliver more diverse resources to serve its customers in Oregon, Washington and California.
Originally planned as a single circuit 500 kV line from the Hemingway substation south of
Boise, Idaho, to the Captain Jack substation near Klamath Falls, Oregon, PacifiCorp has
continued to pursue alternative joint-development opportunities on other proposed lines west of
Hemingway. Idaho Power leads the permitting efforts on this project and PacifiCorp continues to
support the permitting efforts under the conditions of the Boardman to Hemingway Transmission
Project Joint Permit Funding Agreement. The Record of Decision is anticipated in 2016 followed
by the Oregon Energy Facilities Siting Council’s final order on the Site Certificate.

Table 2.1 – Energy Gateway Segment In-Service Dates
Segment A: Wallula to McNary 2013-2014 2017 – Customer driven
Segment C: Mona to Oquirrh May 2013 Completed May 2013
Segment C: Oquirrh to Terminal June 2016 May 2017*
Segment D: Windstar to Populus 2019-2021 2021-2024*
Segment E: Populus to Hemingway 2020-2023 2020-2024*
Segment F: Aeolus to Mona 2020-2022 2020-2022
Segment G: Sigurd to Red Butte June 2015 Completed May 2015
Segment H: West of Hemingway Sponsor driven
* Estimated in-service date adjusted since last IRP.
PACIFICORP – 2015 IRP UPDATE CHAPTER 2 – PLANNING ENVIRONMENT

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Regional Markets

Energy Imbalance Market

PacifiCorp and the California ISO launched the Energy Imbalance Market (EIM) November 1,
2014. The EIM is a voluntary market and the first western energy market outside of California,
covering six states, California, Idaho, Oregon, Utah, Washington, and Wyoming, which uses
California ISO advanced market systems that automatically balance supply and demand for
electricity every 15 minutes, dispatching the least-cost resources every five minutes. Since the
launch of the EIM, NV Energy joined the market December 1, 2015, adding Nevada to the EIM
footprint. Puget Sound Energy and Arizona Public Service are scheduled to join October 1, 2016.
Portland General Electric is expected to join the EIM October 1, 2017, and other balancing
authorities in the west have indicated interest. PacifiCorp continues to work with the California
ISO, existing and prospective EIM entities, and stakeholders to enhance market functionality and
support market growth with the addition of new EIM entities.

As predicted in studies prior to commencement of the market, the EIM has produced significant
monetary benefits ($45.69 million total footprint-wide benefits as of December 31, 2015),
quantified in the following categories: (1) more efficient dispatch, both inter- and intra-regional,
by automating dispatch every 15 minutes and every five minutes within and across the EIM
footprint; (2) reduced renewable energy curtailment by allowing balancing authority areas to
export or reduce imports of renewable generation that would otherwise need to be curtailed; and
(3) reduced need for flexibility reserves in all EIM balancing authority areas, also referred to as
diversity benefits, which reduces cost by aggregating load, wind, and solar variability and
forecast errors of the EIM footprint.

Regional ISO

The California ISO is exploring expanding into a regional ISO. PacifiCorp is exploring joining
the regional ISO and becoming a full participating transmission owner (PTO). This effort is
aimed at reducing costs for consumers, enhancing coordination and reliability of western electric
networks, facilitating the integration of renewable resources, reducing emissions, and enhancing
regional transmission planning and expansion.

PacifiCorp and the California ISO signed a memorandum of understanding in April 2015 that
commits the two entities to explore the benefits of a regional ISO, recognizing that governance
and other existing California ISO tariff structures and frameworks would need to accommodate a
regional organization. Energy+Environmental Economics (E3) performed an initial analysis of
the potential incremental benefits, beyond EIM, of integrating PacifiCorp as a PTO in a regional
ISO. The study was released October 2015 and highlights that the full integration of the
PacifiCorp and California ISO systems would provide the potential for cost savings.6
Specifically, the E3 study quantifies benefits in the following four categories: (1) more efficient
unit commitment and dispatch, (2) more efficient over-generation management, (3) lower peak
capacity needs, and (4) renewable procurement savings. As described in more detail in the E3
study, under a regional ISO, PacifiCorp and ISO customers could develop capacity plans to meet
the combined system coincident peak load, which would be lower than the sum of the non-

6 For more background of the E3 benefit study and information:
http://www.pacificorp.com/about/newsroom/2015nrl/western-grid-integration.html
PACIFICORP – 2015 IRP UPDATE CHAPTER 2 – PLANNING ENVIRONMENT

23
coincident peak loads. As it relates to PacifiCorp’s updated load and resource balance and
resource portfolio, discussed in Chapter 3 and Chapter 5, respectively, this could reduce the need
for firm market purchases over the near- to mid-term and displace the need for resources in the
long term.

PacifiCorp continues to explore and evaluate the benefits and costs of becoming a PTO in a
regional ISO. PacifiCorp will seek approval from each of its state public utility commissions to
turn over operational control of its transmission assets to the ISO should further studies confirm
net benefits for customers and acceptable governance structure is adopted. Integration as a PTO
would result in the following primary impacts to PacifiCorp: (1) integration of PacifiCorp’s two
balancing authority areas (BAAs) into the regional ISO’s BAA (2) turning over operational
control of PacifiCorp’s networked transmission assets to the regional ISO; (3) becoming subject
to all requirements of the ISO tariff, as modified for regional integration, including resource
adequacy requirements, transmission access charges, integrated generator interconnection
studies, and many others; and (4) participation in the regional ISO’s real-time and day-ahead
markets.

PACIFICORP – 2015 IRP UPDATE CHAPTER 2 – PLANNING ENVIRONMENT

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PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

25
CHAPTER 3 – LOAD AND RESOURCE BALANCE
UPDATE
Introduction

This chapter presents the update to PacifiCorp’s load and resource balance, focusing on the
2016-2025 planning period covered by the fall 2015 ten-year business plan (Business Plan) and
2015 IRP Update. Updates to PacifiCorp’s long-term load forecast, resources, and capacity
position are presented and summarized in this chapter.
Load Forecast

PacifiCorp’s 2015 IRP Update and Business Plan use the same load forecast updated and
finalized in October 2015. Relative to the load forecast prepared for the 2015 IRP, PacifiCorp
system sales decrease over the planning period. Changes between these two forecasts reflect the
changes in economic conditions in the service territory that occurred between September 2014
and October 2015. While economic conditions continue to improve following the most recent
recession, projected load growth in the residential and commercial customer classes is offset by
weakness in the industrial class. A decline in commodities markets drives declines in industrial
sales on the east side of the system, while the projected loss of a large customer drives declines
on the west side of the system. Figures 3.1 and 3.2 compare annual load and coincident peak load
forecasts, respectively, for the 2015 IRP Update and 2015 IRP. These forecast data exclude load
reduction projections from new energy efficiency measures (Class 2 DSM), since such load
reductions are included as resources in the resource portfolio. Appendix A includes additional
details on the updated load forecast.

Figure 3.1 – Forecasted Annual Load Growth

60,000
61,000
62,000
63,000
64,000
65,000
66,000
67,000
68,000
69,000
70,000
GW
h
2015 IRP Update and Business Plan 2015 IRP
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

26

Figure 3.2 – Forecasted Annual Coincident Peak Load

Resource Updates
Existing and Firm Resources

The availability and capacity contribution from existing resources have been updated to reflect
changes since assumptions were locked down for the 2015 IRP. Updates to resource capacity
assumptions are presented in two steps – changes made between the 2015 IRP and the Business
Plan, and changes made between the Business Plan and this 2015 IRP Update.
Changes Made between the 2015 IRP and the Business Plan

 With reduced load, lower market prices, and increased costs for gas conversion, the Business
Plan assumes an early retirement of Naughton Unit 3 at the end of 2017 is a lower cost
alternative to the assessed natural gas conversion. This assumption aligns with updated
analysis of compliance alternatives for Naughton Unit 3 presented in Confidential Appendix
B of this 2015 IRP Update. With the assumed retirement of Naughton Unit 3, existing
thermal generation capacity is reduced by 337 MW over the period 2018 through 2029.

 With reduced load, lower market prices and uncertainties around state plans for
implementing the clean power plan (CPP), the Business Plan assumes Cholla Unit 4 is retired
at the end of 2024. PacifiCorp will continue to evaluate the most cost effective compliance
alternatives for Cholla Unit 4 in future IRPs. With the assumed retirement of Cholla Unit 4,
existing thermal generation capacity is reduced by 387 MW from 2025 and beyond.

 Since assumptions were locked down for the 2015 IRP, 440 MW of additional wind and solar
qualifying facility contracts are included in the Business Plan portfolio (representing an
increase of 167 MW of capacity at the time of system peak load). Inclusive of capacity
assumed in the 2015 IRP, qualifying facility contract capacity from wind and solar projects
10,000
10,200
10,400
10,600
10,800
11,000
11,200
11,400
MW
2015 IRP Update and Business Plan 2015 IRP
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

27
expected to come online in the 2015 to 2017 timeframe totals 1,162 MW (representing 409
MW of capacity at the time of system peak load). This increase is partially offset by a
reduction of 80 MW (11 MW of capacity at the time of system peak load) due to qualifying
facility contract terminations.

 An updated hydro generation forecast reflects current projections for hydro operations
accounting for planned water conditions, availability, and market prices. The Klamath River
hydro peak contribution is approximately 70 MW higher to reflect its storage capability and
ability to hold reserves prior to being decommissioned, assumed to occur at the end of 2020.
The increase is offset by a decrease in the Lewis River hydro forecast, in part, to incorporate
planned maintenance.

 Updates to interruptible contracts result in an increase in average peak capacity contribution
by 20 MW during the 2016-2025 timeframe.
Changes Made between the Business Plan and the 2015 IRP Update

 Since assumptions were locked down for the Business Plan, qualifying facility contract
capacity assumptions were updated. The update includes 65 MW of incremental qualifying
facility contracts from wind and solar projects (representing an increase of 25 MW of
capacity at the time of system peak load). Coupled with the updates applied in the Business
Plan, the total amount of qualifying facility contract capacity expected to come online in the
2015 to 2017 timeframe totals 1,227 MW (representing 434 MW of capacity at the time of
system peak load).

Tables 3.1 and 3.2 summarize the capacity from wind and solar power purchase agreements with
qualifying facilities (QFs) that have or are expected to come online over the 2015 – 2017
timeframe.

Table 3.1 – New Qualifying Facility Wind Contracts Online 2015-2017

2015 IRP Preferred
Portfolio 2015 IRP Update
Qualifying Facilities State Capacity
(MW)
L&R
Balance
Capacity at
System Peak
(MW)
Capacity
(MW)
L&R
Balance
Capacity at
System Peak
(MW)
Blue Mountain Power Partners UT 80 11
Chopin OR 10 3 10 3
Latigo Wind UT 60 9 60 9
Mariah Wind OR 10 3 10 3
Orem Family Wind OR 10 3 10 3
Pioneer Wind Park I WY 80 12 80 12
TOTAL – Purchased Wind 250 39 170 28

PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

28
Table 3.2 – New Qualifying Facility Solar Contracts Online 2015-2017

2015 IRP Preferred
Portfolio 2015 IRP Update
Qualifying Facilities State Capacity
(MW)
L&R
Balance
Capacity at
System
Peak (MW)
Capacity
(MW)
L&R
Balance
Capacity at
System Peak
(MW)
Adams Solar Center OR 10 4 10 4
Bear Creek Solar Center OR 10 4 10 4
Beatty Solar OR 5 2 5 2
Beryl Solar UT 3 1 3 1
Black Cap Solar II OR 8 3 8 3
Bly Solar Center OR 10 4 9 3
Buckhorn Solar UT 3 1 3 1
Cedar Valley Solar UT 3 1 3 1
Chiloquin Solar * OR 10 3
Collier Solar * OR 10 4
Elbe Solar Center OR 10 4 10 4
Enterprise Solar UT 80 31 80 31
Escalante Solar I UT 80 31 80 31
Escalante Solar II UT 80 31 80 31
Escalante Solar III UT 80 31 80 31
Ewauna Solar * OR 1 0
Ewauna Solar 2 * OR 3 1
Fiddler's Canyon Solar 1-3 UT 9 4 9 4
Granite Mountain - East * UT 80 31
Granite Mountain - West * UT 50 20
Granite Peak Solar UT 3 1 3 1
Greenville Solar UT 2 1 2 1
Iron Springs * UT 80 31
Ivory Pine Solar OR 10 4 10 4
Laho Solar UT 3 1 3 1
Manderfield Solar UT 2 1
Milford Flat Solar UT 3 1 3 1
Milford Solar 2 UT 3 1 3 1
Norwest Energy 2 (Neff) * OR 10 4
Norwest Energy 4 (Bonanza) * OR 6 2
Norwest Energy 5 (Arlington) * OR 3 1
Norwest Energy 7 (Eagle Point) * OR 10 4
Norwest Energy 9 Pendleton * OR 6 2
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

29

2015 IRP Preferred
Portfolio 2015 IRP Update
Qualifying Facilities State Capacity
(MW)
L&R
Balance
Capacity at
System
Peak (MW)
Capacity
(MW)
L&R
Balance
Capacity at
System Peak
(MW)
OR Solar 1, LLC (Sprague River) * OR 10 4
OR Solar 2, LLC (Agate Bay) * OR 10 4
OR Solar 3, LLC (Turkey Hill) * OR 10 4
OR Solar 4, LLC (Bly) * OR 10 4
OR Solar 5, LLC (Merrill) * OR 8 3
OR Solar 6, LLC (Lakeview) * OR 10 4
OR Solar 7, LLC (Jacksonville) * OR 10 4
OR Solar 8, LLC (Dairy) * OR 10 4
Pavant Solar UT 50 20 50 20
Pavant Solar II LLC * UT 50 20
Quichapa Solar 1- 3 UT 9 4 9 4
South Milford Solar UT 3 1 3 1
Sprague River Solar OR 7 3 7 3
Three Peaks Solar * UT 80 31
Tumbleweed Solar * OR 10 3
Utah Red Hills Renewable Park UT 80 31 80 31
Woodline Solar * OR 8 3
TOTAL – Purchased Solar 566 218 1,057 406
* New since 2015 IRP.
Updated Capacity Load and Resource Balance

Figure 3.3 summarizes the 2015 IRP Update capacity load and resource balance, prior to
acquiring any new resources and making firm market purchases, alongside the load and resource
balance from the 2015 IRP and the Business Plan. The load and resource balance has decreased
by an average of 209 MW, relative to the 2015 IRP, in 2016 and 2017 reflecting to changes in
the load forecast, hydro generation and qualifying facility contracts. The projected load and
resource balance position is shorter beginning in 2018, relative to the 2015 IRP, primarily due to
the assumed early retirement of Naughton Unit 3 at the end of 2017 and Cholla Unit 4 at the end
of 2024. This is partially offset by the addition of new wind and solar qualifying facility
contracts. The 2015 IRP Update load and resource balance shows is shorter by 128 MW in 2018
rising to 720 MW by 2025.

PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

30
Figure 3.3 – Capacity Position Comparison

Tables 3.3 through 3.5 summarize the capacity load and resource balance details from the 2015
IRP Update, Business Plan, and 2015 IRP, respectively. As was done in the 2015 IRP, the load
and resource balance tables show the system position alongside assumed FOT purchases given
current FOT limit assumptions, which were not updated for the 2015 IRP. PacifiCorp will
evaluate its FOT limit assumptions as part of the 2017 IRP. Differences between the 2015 IRP
and 2015 IRP Update are displayed in Table 3.6, and differences between the 2015 IRP and
Business Plan are shown in Table 3.7.

PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

31
Table 3.3 – System Capacity Load and Resource Balance without Resource Additions, 2015
IRP Update (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 6,397 6,397 6,116 6,116 6,116 6,113 6,110 6,108 6,105 5,717
Hydroelectric 109 109 112 112 112 112 112 112 92 92
Renewable 187 187 187 187 187 185 185 178 178 168
Purchase 355 249 249 249 249 221 221 221 221 121
Qualifying Facilities 304 469 463 460 454 447 436 434 381 378
Class 1 DSM 323 323 323 323 323 323 323 323 323 323
Sale (728)(653)(652)(652)(652)(171)(171)(171)(144)(144)
Non-Owned Reserves (38)(38)(38)(38)(38)(38)(38)(38)(38)(38)
East Existing Resources 6,910 7,044 6,760 6,758 6,752 7,192 7,179 7,167 7,119 6,617
East Total Resources 6,910 7,044 6,760 6,758 6,752 7,192 7,179 7,167 7,119 6,617
Load 6,963 7,084 7,235 7,359 7,447 7,548 7,637 7,717 7,809 7,880
Interruptible (195)(195)(195)(195)(195)(195)(195)(195)(195)(195)
Existing Class2 DSM (61)(61)(61)(61)(61)(61)(61)(61)(61)(61)
East obligation 6,707 6,828 6,979 7,104 7,191 7,292 7,381 7,462 7,553 7,624
Planning Reserves (13%)897 913 933 949 960 973 985 995 1,007 1,016
East Reserves 897 913 933 949 960 973 985 995 1,007 1,016
East Obligation + Reserves 7,604 7,741 7,912 8,052 8,151 8,265 8,366 8,457 8,560 8,640
East Position (695)(698)(1,151)(1,295)(1,400)(1,073)(1,186)(1,290)(1,441)(2,023)
Available Front Office Transactions 318 318 318 318 318 318 318 318 318 318
West
Thermal 2,251 2,248 2,248 2,248 2,248 2,245 2,241 2,239 2,239 2,239
Hydroelectric 841 826 837 736 793 623 548 654 643 632
Renewable 172 172 172 172 172 172 118 118 107 107
Purchase 18 18 18 1 1 1 1 1 1 1
Qualifying Facilities 108 177 175 174 176 166 163 155 154 154
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (165)(165)(165)(165)(165)(161)(110)(110)(80)(80)
Non-Owned Reserves (3)(3)(3)(3)(3)(3)(3)(3)(3)(3)
West Existing Resources 3,221 3,272 3,282 3,162 3,221 3,043 2,958 3,054 3,062 3,051
West Total Resources 3,221 3,272 3,282 3,162 3,221 3,043 2,958 3,054 3,062 3,051
Load 3,206 3,199 3,235 3,256 3,276 3,294 3,313 3,332 3,346 3,373
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class2 DSM (36)(36)(36)(36)(36)(36)(36)(36)(36)(36)
West obligation 3,171 3,163 3,199 3,221 3,240 3,258 3,278 3,296 3,311 3,337
Planning Reserves (13%)412 411 416 419 421 424 426 429 430 434
West Reserves 412 411 416 419 421 424 426 429 430 434
West Obligation + Reserves 3,583 3,575 3,615 3,640 3,661 3,682 3,704 3,725 3,741 3,771
West Position (361)(303)(333)(477)(440)(639)(746)(671)(679)(721)
Available Front Office Transactions 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352
System
Total Resources 10,131 10,316 10,042 9,920 9,973 10,235 10,137 10,221 10,181 9,668
Obligation 9,878 9,992 10,178 10,324 10,431 10,550 10,659 10,758 10,863 10,961
Reserves 1,309 1,324 1,348 1,368 1,381 1,397 1,411 1,424 1,438 1,450
Obligation + Reserves 11,187 11,316 11,527 11,692 11,813 11,947 12,069 12,182 12,301 12,412
System Position (1,056)(1,000)(1,484)(1,772)(1,840)(1,712)(1,932)(1,961)(2,120)(2,743)
Available Front Office Transactions 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

32
Table 3.4 – System Capacity Load and Resource Balance without Resource Additions,
Business Plan (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 6,397 6,397 6,116 6,116 6,116 6,113 6,110 6,108 6,105 5,717
Hydroelectric 109 109 112 112 112 112 112 112 92 92
Renewable 187 187 187 187 187 185 185 178 178 168
Purchase 355 249 249 249 249 221 221 221 221 121
Qualifying Facilities 304 444 437 435 429 422 412 409 407 403
Class 1 DSM 323 323 323 323 323 323 323 323 323 323
Sale (728)(653)(652)(652)(652)(171)(171)(171)(144)(144)
Non-Owned Reserves (38)(38)(38)(38)(38)(38)(38)(38)(38)(38)
East Existing Resources 6,910 7,018 6,735 6,733 6,727 7,167 7,155 7,143 7,144 6,643
East Total Resources 6,910 7,018 6,735 6,733 6,727 7,167 7,155 7,143 7,144 6,643
Load 6,963 7,084 7,235 7,359 7,447 7,548 7,637 7,717 7,809 7,880
Interruptible (195)(195)(195)(195)(195)(195)(195)(195)(195)(195)
Existing Class2 DSM (64)(64)(64)(64)(64)(64)(64)(64)(64)(64)
East obligation 6,704 6,825 6,976 7,101 7,188 7,289 7,378 7,459 7,550 7,621
Planning Reserves (13%)897 913 932 948 960 973 984 995 1,007 1,016
East Reserves 897 913 932 948 960 973 984 995 1,007 1,016
East Obligation + Reserves 7,601 7,738 7,908 8,049 8,148 8,262 8,362 8,454 8,557 8,637
East Position (691)(720)(1,173)(1,316)(1,421)(1,095)(1,208)(1,311)(1,413)(1,994)
Available Front Office Transactions 318 318 318 318 318 318 318 318 318 318
West
Thermal 2,251 2,248 2,248 2,248 2,248 2,245 2,241 2,239 2,239 2,239
Hydroelectric 841 826 837 736 793 623 548 654 643 632
Renewable 172 173 173 173 173 173 118 118 108 108
Purchase 18 18 18 1 1 1 1 1 1 1
Qualifying Facilities 112 190 202 200 202 190 186 179 178 178
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (165)(165)(165)(165)(165)(161)(110)(110)(80)(80)
Non-Owned Reserves (3)(3)(3)(3)(3)(3)(3)(3)(3)(3)
West Existing Resources 3,225 3,286 3,309 3,189 3,248 3,068 2,982 3,078 3,087 3,075
West Total Resources 3,225 3,286 3,309 3,189 3,248 3,068 2,982 3,078 3,087 3,075
Load 3,206 3,199 3,235 3,256 3,276 3,294 3,313 3,332 3,346 3,373
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class2 DSM (35)(35)(35)(35)(35)(35)(35)(35)(35)(35)
West obligation 3,171 3,164 3,199 3,221 3,241 3,259 3,278 3,297 3,311 3,338
Planning Reserves (13%)412 411 416 419 421 424 426 429 430 434
West Reserves 412 411 416 419 421 424 426 429 430 434
West Obligation + Reserves 3,583 3,575 3,615 3,640 3,662 3,682 3,704 3,725 3,741 3,772
West Position (358)(289)(306)(451)(414)(615)(722)(647)(655)(696)
Available Front Office Transactions 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352
System
Total Resources 10,134 10,305 10,044 9,922 9,975 10,235 10,137 10,221 10,231 9,718
Obligation 9,875 9,989 10,175 10,322 10,429 10,548 10,656 10,756 10,861 10,959
Reserves 1,309 1,324 1,348 1,367 1,381 1,397 1,411 1,424 1,437 1,450
Obligation + Reserves 11,184 11,313 11,524 11,689 11,810 11,944 12,067 12,179 12,298 12,409
System Position (1,050)(1,009)(1,480)(1,767)(1,835)(1,710)(1,930)(1,958)(2,067)(2,690)
Available Front Office Transactions 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

33
Table 3.5 – System Capacity Load and Resource Balance without Resource Additions, 2015
IRP (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 6,397 6,397 6,453 6,449 6,448 6,444 6,439 6,434 6,431 6,430
Hydroelectric 114 114 114 114 114 114 114 114 94 94
Renewable 187 187 187 187 187 184 184 177 177 168
Purchase 406 300 300 300 300 272 272 272 272 172
Qualifying Facilities 222 348 347 346 339 337 332 331 280 279
Class 1 DSM 323 323 323 323 323 323 323 323 323 323
Sale (732)(656)(656)(656)(656)(175)(175)(175)(144)(144)
Non-Owned Reserves (38)(38)(38)(38)(38)(38)(38)(38)(38)(38)
East Existing Resources 6,880 6,976 7,031 7,026 7,018 7,462 7,453 7,439 7,396 7,284
East Total Resources 6,880 6,976 7,031 7,026 7,018 7,462 7,453 7,439 7,396 7,284
Load 6,977 7,102 7,208 7,295 7,382 7,448 7,529 7,617 7,640 7,676
Interruptible (175)(175)(175)(175)(175)(175)(175)(175)(175)(175)
Existing Class2 DSM (73)(73)(73)(73)(73)(73)(73)(73)(73)(73)
East obligation 6,729 6,854 6,960 7,047 7,135 7,200 7,281 7,370 7,392 7,428
Planning Reserves (13%)894 910 924 935 947 955 966 977 980 985
East Reserves 894 910 924 935 947 955 966 977 980 985
East Obligation + Reserves 7,623 7,764 7,885 7,982 8,081 8,155 8,247 8,347 8,372 8,413
East Position (743)(789)(853)(957)(1,064)(693)(794)(908)(976)(1,129)
Available Front Office Transactions 318 318 318 318 318 318 318 318 318 318
West
Thermal 2,251 2,248 2,248 2,248 2,248 2,245 2,241 2,239 2,239 2,239
Hydroelectric 770 752 775 725 728 643 620 652 646 643
Renewable 170 170 170 170 170 170 115 115 105 105
Purchase 22 22 22 5 5 5 5 5 5 5
Qualifying Facilities 114 140 135 134 120 120 120 115 115 115
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (160)(160)(160)(160)(160)(156)(105)(105)(78)(78)
Non-Owned Reserves (3)(3)(3)(3)(3)(3)(3)(3)(3)(3)
West Existing Resources 3,163 3,167 3,185 3,119 3,107 3,023 2,993 3,019 3,029 3,025
West Total Resources 3,163 3,167 3,185 3,119 3,107 3,023 2,993 3,019 3,029 3,025
Load 3,237 3,271 3,301 3,323 3,354 3,406 3,429 3,455 3,476 3,506
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class2 DSM (36)(36)(36)(36)(36)(36)(36)(36)(36)(36)
West obligation 3,201 3,235 3,264 3,286 3,317 3,369 3,393 3,419 3,440 3,469
Planning Reserves (13%)416 421 424 427 431 438 441 444 447 451
West Reserves 416 421 424 427 431 438 441 444 447 451
West Obligation + Reserves 3,617 3,655 3,689 3,714 3,748 3,807 3,834 3,863 3,887 3,920
West Position (454)(488)(503)(595)(642)(784)(841)(844)(858)(895)
Available Front Office Transactions 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352 1,352
System
Total Resources 10,043 10,143 10,217 10,144 10,124 10,486 10,446 10,458 10,425 10,310
Obligation 9,930 10,089 10,225 10,333 10,452 10,569 10,674 10,788 10,832 10,897
Reserves 1,310 1,331 1,349 1,363 1,378 1,393 1,407 1,422 1,428 1,436
Obligation + Reserves 11,240 11,420 11,573 11,696 11,830 11,963 12,081 12,210 12,259 12,333
System Position (1,197)(1,277)(1,357)(1,552)(1,706)(1,477)(1,635)(1,752)(1,834)(2,023)
Available Front Office Transactions 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

34
Table 3.6 – System Capacity Load and Resource Balance without Resource Additions, 2015
IRP Update less 2015 IRP (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 0 0 (337)(333)(332)(331)(329)(326)(326)(713)
Hydroelectric (5)(5)(2)(2)(2)(2)(2)(2)(2)(2)
Renewable 0 0 0 0 0 0 0 0 0 0
Purchase (51)(51)(51)(51)(51)(51)(51)(51)(51)(51)
Qualifying Facilities 82 121 115 114 115 110 105 103 102 99
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale 4 4 4 4 4 4 4 4 0 0
Non-Owned Reserves 0 0 0 0 0 0 0 0 0 0
East Existing Resources 29 68 (271)(268)(266)(271)(273)(272)(277)(667)
East Total Resources 29 68 (271)(268)(266)(271)(273)(272)(277)(667)
Load (14)(18)27 65 64 100 108 100 169 204
Interruptible (20)(20)(20)(20)(20)(20)(20)(20)(20)(20)
Existing Class2 DSM 12 12 12 12 12 12 12 12 12 12
East obligation (22)(26)19 57 56 92 100 92 161 196
Planning Reserves (13%)3 3 8 13 13 18 19 18 27 31
East Reserves 3 3 8 13 13 18 19 18 27 31
East Obligation + Reserves (19)(23)27 70 70 110 119 110 188 227
East Position 48 91 (298)(338)(336)(381)(392)(382)(465)(894)
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
West
Thermal 0 0 0 0 0 0 0 0 0 0
Hydroelectric 70 74 62 11 65 (20)(72)2 (3)(11)
Renewable 3 3 3 3 3 3 3 3 3 3
Purchase (4)(4)(4)(4)(4)(4)(4)(4)(4)(4)
Qualifying Facilities (6)37 41 39 56 46 43 40 39 39
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (5)(5)(5)(5)(5)(5)(5)(5)(2)(2)
Non-Owned Reserves 0 0 0 0 0 0 0 0 0 0
West Existing Resources 59 105 97 44 115 20 (35)35 33 25
West Total Resources 59 105 97 44 115 20 (35)35 33 25
Load (31)(72)(66)(66)(78)(112)(116)(123)(130)(133)
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class2 DSM 1 1 1 1 1 1 1 1 1 1
West obligation (30)(71)(65)(66)(77)(111)(115)(122)(129)(132)
Planning Reserves (13%)(4)(9)(8)(9)(10)(14)(15)(16)(17)(17)
West Reserves (4)(9)(8)(9)(10)(14)(15)(16)(17)(17)
West Obligation + Reserves (34)(80)(74)(74)(87)(125)(130)(138)(146)(149)
West Position 93 185 170 118 202 145 95 173 179 174
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
System
Total Resources 88 173 (174)(224)(151)(251)(308)(237)(244)(641)
Obligation (52)(97)(47)(9)(20)(19)(15)(30)32 64
Reserves (1)(7)(0)5 3 3 4 2 10 14
Obligation + Reserves (53)(103)(47)(4)(17)(15)(11)(28)42 79
System Position 141 277 (128)(220)(134)(235)(297)(209)(286)(720)
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

35
Table 3.7 – System Capacity Load and Resource Balance without Resource Additions,
Business Plan less 2015 IRP (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 0 0 (337)(333)(332)(331)(329)(326)(326)(713)
Hydroelectric (5)(5)(2)(2)(2)(2)(2)(2)(2)(2)
Renewable 0 0 0 0 0 0 0 0 0 0
Purchase (51)(51)(51)(51)(51)(51)(51)(51)(51)(51)
Qualifying Facilities 82 95 90 89 90 85 80 79 127 125
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale 4 4 4 4 4 4 4 4 0 0
Non-Owned Reserves 0 0 0 0 0 0 0 0 0 0
East Existing Resources 29 43 (296)(293)(291)(296)(298)(297)(252)(641)
East Total Resources 29 43 (296)(293)(291)(296)(298)(297)(252)(641)
Load (14)(18)27 65 64 100 108 100 169 204
Interruptible (20)(20)(20)(20)(20)(20)(20)(20)(20)(20)
Existing Class2 DSM 9 9 9 9 9 9 9 9 9 9
East obligation (25)(29)16 54 53 89 97 89 158 193
Planning Reserves (13%)3 2 8 13 13 18 19 18 26 31
East Reserves 3 2 8 13 13 18 19 18 26 31
East Obligation + Reserves (22)(26)24 67 66 107 115 107 184 224
East Position 51 69 (320)(360)(358)(402)(413)(404)(437)(865)
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
West
Thermal 0 0 0 0 0 0 0 0 0 0
Hydroelectric 70 74 62 11 65 (20)(72)2 (3)(11)
Renewable 3 3 3 3 3 3 3 3 3 3
Purchase (4)(4)(4)(4)(4)(4)(4)(4)(4)(4)
Qualifying Facilities (2)51 67 66 83 70 67 63 63 63
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (5)(5)(5)(5)(5)(5)(5)(5)(2)(2)
Non-Owned Reserves 0 0 0 0 0 0 0 0 0 0
West Existing Resources 62 119 124 71 142 45 (11)60 58 50
West Total Resources 62 119 124 71 142 45 (11)60 58 50
Load (31)(72)(66)(66)(78)(112)(116)(123)(130)(133)
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class2 DSM 1 1 1 1 1 1 1 1 1 1
West obligation (30)(71)(65)(65)(77)(111)(115)(122)(129)(131)
Planning Reserves (13%)(4)(9)(8)(8)(10)(14)(15)(16)(17)(17)
West Reserves (4)(9)(8)(8)(10)(14)(15)(16)(17)(17)
West Obligation + Reserves (34)(80)(73)(74)(86)(125)(130)(138)(146)(148)
West Position 96 199 197 145 228 170 119 197 203 198
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
System
Total Resources 91 162 (173)(222)(149)(251)(309)(237)(194)(591)
Obligation (55)(99)(49)(12)(23)(22)(18)(33)29 62
Reserves (1)(7)(0)4 3 3 4 2 10 14
Obligation + Reserves (56)(106)(50)(7)(20)(18)(14)(31)39 76
System Position 148 268 (123)(215)(129)(233)(294)(206)(233)(667)
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

36
Figures 3.4 through 3.6 summarize the 2015 IRP Update annual capacity position for the system,
west balancing area, and east balancing area, respectively.

Figure 3.4 – 2015 IRP Update, System Capacity Position Trend

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Me
g
a
w
a
t
t
s
Obligation + 13%Planning Reserves
Obligation
East Existing Resources
West Existing Resources
13% Reserves Available Front Office Transactions
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

37
Figure 3.5 – 2015 IRP Update, West Capacity Position Trend

Figure 3.6 – 2015 IRP Update, East Capacity Position Trend

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Me
g
a
w
a
t
t
s
Obligation + 13%Planning Reserves
Obligation
West Existing Resources
13% Reserves
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Me
g
a
w
a
t
t
s
Obligation + 13%Planning Reserves
Obligation
East Existing Resources
13% Reserves
PACIFICORP – 2015 IRP UPDATE CHAPTER 3 – LOAD AND RESOURCE BALANCE UPDATE

38
Changes to the 2015 IRP Update load and resource balance relative to the 2015 IRP are
described below:
PacifiCorp West

 Peak loads are lower in the 2015 IRP Update than in the 2015 IRP. This difference is
primarily driven by changes in projected sales to several large commercial and industrial
customers, including a large industrial customer leaving the system in 2017.
 On average, the addition of incremental wind and solar qualifying facility contracts increase
system capacity at the time of peak load by 37 MW over the 2016-2025 timeframe.
 Updated hydro generation forecast reflecting Klamath River hydro facilities’ storage
capability and the current stream-flow projections result in an average increase of 56 MW in
system capacity from 2016 to 2020, and an average decrease of 21 MW over the 2021-2025
timeframe.
PacifiCorp East

 Peak loads are initially lower in the 2015 IRP Update than in the 2015 IRP due to a decline in
the oil market driving reductions in industrial sales on the east side of the system. Projected
increases in residential and commercial sales increase in the 2015 IRP Update peak forecast
as compared to the 2015 IRP starting in 2018.
 The assumed early retirement of Naughton Unit 3 at end of 2017 reduces system capacity by
337 MW from 2018 through 2029. The assumed early retirement of Cholla Unit 4 at end of
2024 reduces system capacity by 387 MW from 2025 and beyond.
 On average, the addition of incremental wind and solar qualifying facility contracts increase
system capacity at the time of peak load by 107 MW over the 2016-2025 timeframe, which is
partially offset by an average decrease of 50 MW of peak capacity from purchase contracts.
 Updated terms of interruptible contracts are updated to reflect the latest terms, which reduces
system capacity by 20 MW.

PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

39
CHAPTER 4 – MODELING ASSUMPTIONS UPDATE
General Assumptions

In line with the 2015 IRP, the study period for both the fall 2015 ten-year business plan
(Business Plan) and the 2015 IRP Update is 2015 through 2034, with a focus on the 2016-2025
planning horizon. Updated resource portfolios were developed assuming a 13% planning reserve
margin consistent with the stochastic loss of load probability study included in the 2015 IRP.

PacifiCorp has not made any changes to general inflation assumptions (1.9%) and its discount
factor (6.66%) in this 2015 IRP Update. However, PacifiCorp has modified the assumptions
regarding the federal production tax credits and federal investment tax credits for qualifying
renewable resources, as described in Chapter 2.
Natural Gas and Power Market Price Updates

Portfolio modeling for the 2015 IRP Update was prepared using PacifiCorp’s December 31,
2015 official forward price curve (OFPC). OFPCs are produced for both natural gas and power
prices by point of delivery. For both natural gas and power, PacifiCorp’s OFPCs are developed
using forward market prices in tandem with a fundamentals-based price forecast. The first 72
months of the OFPC, beginning with the prompt month, represent broker quotes or settled
forward prices per the end-of-quarter quote date, followed by 12 months of blended prices that
transition to a market fundamentals-based forecast, starting in month 85.

For the natural gas OFPC, the fundamentals-based component is developed using expert third-
party forecasting services with consideration given to underlying supply/demand assumptions,
forecast documentation, peer-to-peer forecast price comparisons, date of issuance, location
granularity, and forecast horizon. For power, the fundamentals-based component is produced
using AuroraXmp® (Aurora), a production cost simulation model. PacifiCorp’s fundamentals-
based natural gas price forecast is a key driver of Aurora’s electricity price forecast.
Natural Gas Market Prices

PacifiCorp’s December 2015 natural gas OFPC reflects a fundamentals-based forecast that was
issued in November 2015, which is heavily influenced by cost-effective domestic supply
expansion largely due to growth in the Marcellus and Utica shale plays.

The September 2014 natural gas OFPC, which was used in the 2015 IRP, was based on an expert
third-party long-term natural gas price forecast initially issued May 2014 with a front two-year
update in August 2014. This price forecast also reflected a considerable portion of domestic
natural gas demand being met by unconventional shale production.

In summer 2014, surveyed expert third-party natural gas price forecasters expected 57% to 70%
of 2020 production to come from shale, by December 2015 expectations had increased to 62% to
PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

40
75%. In the course of one year, 2014 to 2015, Marcellus and Utica shale production alone
increased from an average of 14.4 billion cubic feet per day (BCF/D) to almost 19 BCF/D.

Figure 4.1 compares the nominal annual Henry Hub natural gas prices from the September 2014
(2015 IRP), September 2015 (Business Plan), and December 2015 (2015 IRP Update) OFPCs.

Figure 4.1 – Henry Hub Natural Gas Prices (Nominal)

Power Market Prices

The natural gas fundamentals forecast described above is a key input to the Aurora model, and
consequently, the gas curve shape is reflected in wholesale electricity prices. Figures 4.2 and 4.3
compare the average annual flat and heavy-load-hour electricity prices for the Palo Verde market
hub from the September 2014, September 2015 (Business Plan), and December 2015 OFPCs,
and Figure 4.4 and 4.5 show the comparison for the Mid-Columbia market hub.

Figure 4.2 – Average Annual Flat Palo Verde Electricity Prices (Nominal)

2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
$/
M
M
B
t
u
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
20.00
30.00
40.00
50.00
60.00
70.00
80.00
$/
M
W
h
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

41

Figure 4.3 – Average Annual Heavy Load Hour Palo Verde Electricity Prices (Nominal)

Figure 4.4 – Average Annual Flat Mid-Columbia Electricity Prices (Nominal)

20.00
30.00
40.00
50.00
60.00
70.00
80.00
$/
M
W
h
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
20.00
30.00
40.00
50.00
60.00
70.00
80.00
$/
M
W
h
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

42
Figure 4.5 – Average Annual Heavy Load Hour Mid-Columbia Electricity Prices (Nominal)

Carbon Dioxide Emission Policy

After PacifiCorp filed its 2015 IRP, EPA issued its final CPP, setting emission reduction goals
for existing fossil generation. On February 9, 2016, the U.S. Supreme Court issued a stay of the
CPP suspending implementation of the rule pending the outcome of the merits of litigation
before the D.C. Circuit Court of Appeals. If parties petition for a writ of certiorari before the U.S.
Supreme Court, the stay will remain in effect until the U.S. Supreme Court takes action to either
deny the petition, or, if the U.S. Supreme Court hears the case, the stay remains in effect until the
court enters its judgment. Oral argument on the CPP litigation is scheduled for June 2, 2016
before the D.C. Circuit Court of Appeals. In the 2015 IRP Update, considering uncertainty in the
timing and details around individual state decisions related to CPP implementation, PacifiCorp
assumes a mass-based emission target based on EPA’s proposed mass-based FIP to limit CO2
emissions from its existing affected generation facilities.
Transmission Topology

The transmission topology modeled in the 2015 IRP Update was modified to represent and align
transmission rights consistent with the Idaho asset exchange agreement, which was finalized
November 4, 2015 between PacifiCorp and Idaho Power Company. In addition to maintaining
the 1,600 MW of westbound transfer capability, the Idaho asset exchange agreement now allows
PacifiCorp to serve its Goshen load directly from Jim Bridger plant.
Supply-side Resources

The supply side resource costs for 50 MWAC solar photovoltaic (PV) projects are updated to
reflect lower market costs for PV modules and mounting structures. A solar option is added for
Washington which includes an effective sales tax rate of about 2%. Engineering and owner costs
are decreased slightly to reflect increasing levels of certainty for large commercial PV projects.
20.00
30.00
40.00
50.00
60.00
70.00
80.00
$/
M
W
h
2015 IRP (Sept 2014)Business Plan (Sept 2015)2015 IRP Update (Dec 2015)
PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

43
Projected costs, in real terms, during the 20-year study period continue to reflect a downward
trend as in the 2015 IRP. Costs for five-MW fixed tilt solar array projects have not been updated
because those projects are being outperformed in the market by larger single axis projects. While
costs for solar projects have been reduced for the 2015 IRP Update, there is risk with adding
incremental solar resources that have generation profiles aligning with expected output from
increasing solar resource penetration levels in California. With increased solar generation,
market prices can be very low in the mid-afternoon, particularly during the spring season and
other low-load times of the year. Table 4.1 shows the updated costs of solar resources.

Table 4.1 – Updated Cost of Solar Resources, 2014$ - (50 MWAC Single Axis Tracking)
Location/Technology
2015 IRP Update
Total (with Owner's Costs)
$/WAC
2015 IRP Total (with Owner's
Costs)
$/WAC
Utah/Single Axis Tracking $2.318 $2.702
Oregon/Single Axis Tracking $2.429 $2.829
Washington/Single Axis Tracking $2.476 n/a

The supply side resource costs for wind resources have also been updated. Market conditions and
competition led to cost reductions for turbines and balance of plant costs on a $/kW basis.
PacifiCorp previously incorporated a combination of land lease and land ownership options for
new wind generation projects, but determined that using both ownership structures made it more
difficult to compare IRP cost assumptions to typical wind development projects. For the 2015
IRP Update, PacifiCorp structured the capital cost and fixed O&M to reflect wind projects based
on leased land which reduced capital costs by removing land purchase costs and increased fixed
O&M costs to cover annual lease payments. To provide greater definition of project costs,
PacifiCorp created separate line items for each state to address sales tax impacts. For Utah and
Oregon there are no state sales taxes whereas sales taxes of 2% are applied for Washington wind
resources and 6% for Idaho and Wyoming wind resources. Table 4.2 shows the updated costs of
wind resources.

Table 4.2 – Updated Cost of Wind Resources, 2014$
2015 IRP Update 2015 IRP
Location
Capital Cost
$/W
Fixed O&M
$/kW-year
Capital Cost
$/W
Fixed O&M
$/kW-year
Washington $1.712 $36.56 $2.135 $34.46
Oregon $1.672 $36.56 $2.135 $34.46
Idaho $1.735 $36.56 $2.188 $34.46
Utah $1.672 $36.56 $2.188 $34.46
Wyoming $1.735 $36.56 $2.156 $34.46

The 2015 IRP Update adds information for battery storage costs summarized in the table below.
Data from the Department of Energy (DOE) Global Energy Storage Database was compiled to
produce the information in this table. It shows how installed costs vary with nameplate duration.
The results differ from the tables produced in the 2015 IRP based on the limited sizing duration
data provided in the 2014 HDR storage study. Table 4.3 shows the updated costs of battery
storage resources.

PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

44
Table 4.3 – Updated Cost of Energy Storage, 2014$
Average 1 MW Battery Cost Duration
Standardized at a 20 year life 1 hour 2 hours 4 hours 8 hours
Lithium Ion

Installed Cost, $/kWh energy storage 1,725 1,223 972 846
Installed Cost, $/kW 1,725 2,446 3,887 6,770
Sodium Sulfur
Installed Cost, $/kWh energy storage N/A N/A N/A 720
Installed Cost, $/kW N/A N/A N/A 5,763
Vanadium Redox
Installed Cost, $/kWh energy storage 2,028 1,525 1,274 1,149
Installed Cost, $/kW 2,028 3,051 5,097 9,190

Due to extension in federal production tax credits and investment tax credits, the levelized cost
of renewable resources are lower, not only due to updated capital costs and O&M costs, but also
due to the application of tax credits that get passed through to customers. Table 4.4 shows
updated costs of the renewable resources with and without applicable tax credits, assuming the
projects are built as rate-based assets, considering timing of construction and in-service dates.
First year real levelized costs for wind and solar resources are presented for 2018, assuming a
2018 wind project meets IRS guidance demonstrating the project began construction by January
1, 2017, and for the last year in which PTCs (wind) and ITCs (solar) are phased down. Wind and
solar resources with online dates between 2018 and 2021/2023 were considered in the
Company’s analysis, but are now shown. Levelized costs for Pacific Northwest wind projects are
shown at two different capacity factors, 29% and 35%, reflecting the range of performance
anticipated from wind facilities in the region. The table also reports updated storage costs.

PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

45
Table 4.4 – Updated Supply Side Resource Table, 2014$

PACIFICORP – 2015 IRP UPDATE CHAPTER 4 – MODELING ASSUMPTIONS UPDATE

46
Table 4.4 – Updated Supply Side Resource Table, 2014$, Continued*

*Total costs shown in mills/kWh represent the first year real levelized cost, which escalates annually the assumed annual rate of inflation net of assumed annual real cost
declines that are applicable to solar resources.

PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

47
CHAPTER 5 – PORTFOLIO DEVELOPMENT
Introduction

PacifiCorp used the System Optimizer (SO) capacity expansion optimization model to develop
resource portfolios based on inputs and assumptions updated throughout its business planning
process. Similarly, the SO model was used to develop resource portfolios for the 2015 IRP
Update consistent with its most recent load and resource balance as described in Chapter 3. This
chapter presents the 2015 IRP Update and Business Plan portfolios along with comparisons to
the 2015 IRP preferred portfolio.
2015 IRP Update Resource Portfolio

The 2015 IRP Update focuses on changes that occurred after PacifiCorp filed its 2015 IRP and
includes comparisons to the resource portfolio developed for the Business Plan. These involve
updates to load forecasts, changes in existing resources and any additions to PacifiCorp’s
contracts with other entities.

Table 5.1 summarizes the annual capacity in the 2015 IRP Update relative to the 2015 IRP
preferred portfolio for the 10-year period 2016 through 2025. Consistent with the change in
PacifiCorp’s load and resource balance, driven by the assumed retirement of Naughton Unit 3 at
the end of 2017 and Cholla Unit 4 at the end of 2024, thermal resource capacity is lower in the
2015 IRP Update. The reduction in thermal generation is offset by increased front office
transactions (FOTs) and demand side management (DSM) resources. With the assumed
retirement of Cholla Unit 4 at the end of 2024, FOTs reach 1,440 MW in 2025, well beyond the
near-term action plan window. The level of FOTs shown in 2025 is 670 MW higher than in the
2015 IRP, yet below the assumed 1,575 MW FOT limit. PacifiCorp has not updated its FOT
limits for the 2015 IRP Update. PacifiCorp will review its FOT limits during the 2017 IRP public
process. Table 5.2 summarizes the 2015 IRP Update load and resource balance, inclusive of
incremental resources, for 2016-2025, and Table 5.3 displays the detailed 2015 IRP Update
resource portfolio through 2034.

Class 2 DSM selections in the 2015 IRP Update were updated to reflect updated information on
actual and projected acquisitions in the near-term and the value of Class 2 DSM resources to the
system. Energy selections of Class 2 DSM for 2015 were updated to reflect preliminary year-end
actual acquisitions in each state. For 2016 and 2017, Oregon and Washington projections were
modified to reflect current Energy Trust of Oregon projections and the approved “Demand Side
Management 2016-2017 Business Plan” filed with the Washington Utilities and Transportation
Commission (WUTC).7 For Utah, 2017 projections were set at 2015 IRP levels to reflect an
increase in funding from 3.62% to 4%, as approved by the Utah Public Service Commission in
2015. Beginning in 2018, the IRP model was optimized Class 2 DSM selections to provide
current information on the need for, and value of, Class 2 DSM in the medium- and long-term.

7 Washington Utilities and Transportation Commission, Docket UE-152072, Order 01, December 17, 2015.
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
48
Table 5.1 – Comparison of 2015 IRP Update with 2015 IRP Preferred Portfolio
(Megawatts)

2015 IRP Update
Capacity (MW)10- year Total
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2016-2025
Expansion Options
Gas - CCCT - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - -
DSM - Energy Efficiency 143 128 138 146 158 142 149 155 161 162 135 1,476
DSM - Load Control - - - - - - - - - - 39 39
Renewable - Wind - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - - -
Renewable - Biomass - - - - - - - - - - - -
Front Office Transactions *764 903 748 1,094 1,246 1,203 970 1,060 965 993 1,440 1,062
Existing Unit Changes
Coal Early Retirement/Conversions (222)- - (280) - - - - - - (387) (667)
Thermal Plant End-of-life Retirements - - - - - - - - - - - -
Coal Plant Gas Conversion Additions - - - - - - - - - - - -
Turbine Upgrades - - - - - - - - - - - -
Total 685 1,031 886 960 1,403 1,345 1,120 1,215 1,126 1,155 1,227
FOT in resource total are 10-year averages
2015 IRP Preferred Portfolio
Capacity (MW)10- year Total
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2016-2025
Expansion Options
Gas - CCCT - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - -
DSM - Energy Efficiency 133 139 146 146 153 135 137 144 146 149 123 1,419
DSM - Load Control - - - - - - - 5 11 - - 16
Renewable - Wind - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - - -
Renewable - Biomass - - - - - - - - - - - -
Front Office Transactions *727 937 904 870 935 979 769 791 761 754 771 847
Existing Unit Changes
Coal Early Retirement/Conversions (222) - - (280) - - - - - - (387) (667)
Thermal Plant End-of-life Retirements - - - - - - - - - - - -
Coal Plant Gas Conversion Additions - - - 337 - - - - - - 387 724
Turbine Upgrades - - - - - - - - - - - -
Total 638 1,077 1,050 1,073 1,088 1,113 906 941 917 903 893
FOT in resource total are 10-year averages
2015 IRP Update less 2015 IRP Preferred Portfolio
Capacity (MW)10- year Total
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2016-2025
Expansion Options
Gas - CCCT - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - -
DSM - Energy Efficiency 10 (11) (8) (0) 5 8 12 11 15 14 12 58
DSM - Load Control - - - - - - - (5) (11) - 39 23
Renewable - Wind - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - - -
Renewable - Biomass - - - - - - - - - - - -
Front Office Transactions *37 (34) (157) 224 311 224 202 269 205 239 670 215
Existing Unit Changes
Coal Early Retirement/Conversions - - - - - - - - - - - -
Thermal Plant End-of-life Retirements - - - - - - - - - - - -
Coal Plant Gas Conversion Additions - - - (337) - - - - - - (387) (724)
Turbine Upgrades - - - - - - - - - - - -
Total 47 (45) (164) (113) 315 232 214 275 209 252 333
FOT in resource total are 10-year averages
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

49
Table 5.2 – 2015 IRP Update Capacity Load and Resource Balance (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 6,397 6,397 6,116 6,116 6,116 6,113 6,110 6,108 6,105 5,717
Hydroelectric 109 109 112 112 112 112 112 112 92 92
Renewable 187 187 187 187 187 185 185 178 178 168
Purchase 355 249 249 249 249 221 221 221 221 121
Qualifying Facilities 304 469 463 460 454 447 436 434 381 378
Class 1 DSM 323 323 323 323 323 323 323 323 323 323
Sale (728)(653)(652)(652)(652)(171)(171)(171)(144)(144)
Non-Owned Reserves (38)(38)(38)(38)(38)(38)(38)(38)(38)(38)
Transfers 624 550 915 850 911 552 563 561 605 742
East Existing Resources 7,534 7,594 7,675 7,608 7,663 7,744 7,743 7,728 7,724 7,360
Front Office Transactions 0 0 0 109 64 0 0 0 0 315
Gas 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0
Class 1 DSM 0 0 0 0 0 0 0 0 0 40
Other 0 0 0 0 0 0 0 0 0 0
East Planned Resources 0 0 0 109 64 0 0 0 0 356
East Total Resources 7,534 7,594 7,675 7,717 7,726 7,744 7,743 7,728 7,724 7,715
Load 6,963 7,084 7,235 7,359 7,447 7,548 7,637 7,717 7,809 7,880
Interruptible (195)(195)(195)(195)(195)(195)(195)(195)(195)(195)
Existing Class 2 DSM (61)(61)(61)(61)(61)(61)(61)(61)(61)(61)
New Class 2 DSM (62)(131)(209)(297)(376)(461)(551)(646)(740)(817)
East obligation 6,645 6,698 6,770 6,807 6,815 6,831 6,830 6,816 6,813 6,806
Planning Reserves (13%)889 896 905 910 911 913 913 911 911 910
East Reserves 889 896 905 910 911 913 913 911 911 910
East Obligation + Reserves 7,534 7,594 7,675 7,717 7,727 7,744 7,743 7,728 7,724 7,717
East Position 0 0 0 (0)(0)0 0 0 (0)(1)
East Reserve Margin 13%13%13%13%13%13%13%13%13%13%
West
Thermal 2,251 2,248 2,248 2,248 2,248 2,245 2,241 2,239 2,239 2,239
Hydroelectric 841 826 837 736 793 623 548 654 643 632
Renewable 172 172 172 172 172 172 118 118 107 107
Purchase 18 18 18 1 1 1 1 1 1 1
Qualifying Facilities 108 177 175 174 176 166 163 155 154 154
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (165)(165)(165)(165)(165)(161)(110)(110)(80)(80)
Non-Owned Reserves (3)(3)(3)(3)(3)(3)(3)(3)(3)(3)
Transfers (625)(551)(916)(851)(912)(553)(564)(562)(606)(743)
West Existing Resources 2,596 2,721 2,366 2,311 2,309 2,490 2,394 2,492 2,456 2,307
Front Office Transactions 957 793 1,160 1,212 1,212 1,028 1,124 1,023 1,053 1,212
Gas 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Other 0 0 0 0 0 0 0 0 0 0
West Planned Resources 957 793 1,160 1,212 1,212 1,028 1,124 1,023 1,053 1,212
West Total Resources 3,553 3,514 3,526 3,523 3,521 3,518 3,517 3,515 3,509 3,519
Load 3,206 3,199 3,235 3,256 3,276 3,294 3,313 3,332 3,346 3,373
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class 2 DSM (36)(36)(36)(36)(36)(36)(36)(36)(36)(36)
New Class 2 DSM (26)(54)(79)(103)(125)(145)(165)(185)(206)(223)
West obligation 3,144 3,110 3,120 3,117 3,116 3,114 3,112 3,111 3,105 3,114
Planning Reserves (13%)409 404 406 405 405 405 405 404 404 405
West Reserves 409 404 406 405 405 405 405 404 404 405
West Obligation + Reserves 3,553 3,514 3,525 3,523 3,521 3,518 3,517 3,515 3,509 3,519
West Position 0 (0)0 0 0 (0)0 (0)(0)(0)
West Reserve Margin 13%13%13%13%13%13%13%13%13%13%
System
Total Resources 11,087 11,107 11,201 11,239 11,247 11,262 11,260 11,243 11,232 11,234
Obligation 9,789 9,807 9,890 9,924 9,931 9,944 9,942 9,927 9,918 9,920
Reserves 1,298 1,300 1,311 1,315 1,316 1,318 1,318 1,316 1,315 1,315
Obligation + Reserves 11,087 11,107 11,201 11,239 11,247 11,262 11,260 11,243 11,232 11,235
System Position 0 (0)0 (0)(0)0 0 0 (0)(1)
Reserve Margin 13%13%13%13%13%13%13%13%13%13%
PACIFICORP – 2013 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
50
Table 5.3 – 2015 IRP Update, Detailed Portfolio (Megawatts)

Capacity (MW)Resource Totals 1/
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year
East Existing Plant Retirements/Conversions
Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45)
Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33)
Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269)
Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450)
Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67)
Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105)
Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387)
DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106)
DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106)
DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220)
DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330)
Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156)
Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201)
Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330)
Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358)
Expansion Resources
CCCT - DJohns - F 2x1 - - - - - - - - - - - - - 635 - - - - - - - 635
CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423
CCCT - Utah-S - F 2x1 - - - - - - - - - - - - - - - 635 - - - - - 635
Total CCCT - - - - - - - - - - - - - 635 - 635 - - 423 - - 1,693
DSM, Class 1, ID-Curtail - - - - - - - - - - - - - - - - - - - 2.3 - 2.3
DSM, Class 1, ID-Irrigate - - - - - - - - - - 12.4 - 4.0 - - 3.5 - - 4.6 1.4 - 25.9
DSM, Class 1, UT-Curtail - - - - - - - - - - - - - - - - - - - 6.0 - 6.0
DSM, Class 1, UT-DLC-RES - - - - - - - - - - 13.1 24.0 10.7 - - - - - 15.0 5.0 - 67.7
DSM, Class 1, UT-Irrigate - - - - - - - - - - 13.2 - - - - 3.3 - - - 2.5 - 19.0
DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - - 1.0 - 1.0
DSM, Class 1, WY-Irrigate - - - - - - - - - - - - - - - - - - - 1.5 - 1.5
DSM, Class 1 Total - - - - - - - - - - 38.6 24.0 14.7 - - 6.9 - - 19.6 19.8 - 123.5
DSM, Class 2, ID 5 3 3 5 5 4 4 5 5 5 5 5 5 4 5 5 3 3 4 3 44 88
DSM, Class 2, UT 71 74 81 89 98 89 97 101 106 105 85 85 84 83 81 75 72 73 71 70 909 1,688
DSM, Class 2, WY 6 7 7 11 14 12 13 15 15 16 13 13 14 14 14 14 14 15 15 15 116 257
DSM, Class 2 Total 82 83 92 105 117 105 114 120 126 126 103 103 103 101 100 94 89 91 90 89 1,070 2,033
FOT Mona Q3 - - - - 103 60 - - - - 297 297 300 49 80 300 2 126 300 300 16 111
West Expansion Resources
CCCT - SOregonCal - J 1x1 - - - - - - - - - - - - - - - - 454 - - - - 454
CCCT - WillamValcc - J 1x1 - - - - - - - - - - - - - 477 - - - - - - - 477
Total CCCT - - - - - - - - - - - - - 477 - - 454 - - - - 932
DSM, Class 1, CA-Irrigate - - - - - - - - - - - - 3.6 - - - - - - 0.6 - 4.2
DSM, Class 1, OR-Curtail - - - - - - - - - - - - 10.6 - - - - - - 11.7 - 22.3
DSM, Class 1, OR-Irrigate - - - - - - - - - - - - 8.4 - - - - - - - - 8.4
DSM, Class 1, WA-Curtail - - - - - - - - - - - - 9.2 - - - - - - - - 9.2
DSM, Class 1, WA-Irrigate - - - - - - - - - - - - 4.5 - - - - - - 0.6 - 5.1
DSM, Class 1 Total - - - - - - - - - - - - 36.4 - - - - - - 12.9 - 49.3
DSM, Class 2, CA 2 1 2 2 2 1 1 2 2 2 1 2 2 1 1 1 1 1 1 1 16 29
DSM, Class 2, OR 49 36 37 31 29 27 25 25 23 24 22 22 22 21 21 20 19 19 19 18 305 508
DSM, Class 2, WA 10 8 8 9 10 9 9 9 11 11 9 9 9 9 8 7 7 7 7 6 93 170
DSM, Class 2 Total 61 45 47 42 41 37 35 35 36 36 32 32 32 30 30 29 27 27 27 25 415 707
FOT COB Q3 - 28 - 219 268 268 95 185 90 118 268 268 268 253 268 268 230 173 268 268 127 190
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 - 2 264 375 248 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 351 363
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
Existing Plant Retirements/Conversions (222) - - (280) - - - - - - (387) - - (762) - (807) (77) - (627) -
Annual Additions, Long Term Resources 143 128 138 146 158 142 149 155 161 162 173 159 186 1,244 130 764 571 118 560 147
Annual Additions, Short Term Resources 764 903 748 1,094 1,246 1,203 970 1,060 965 993 1,440 1,440 1,443 1,177 1,223 1,443 1,107 1,174 1,443 1,443
Total Annual Additions 907 1,031 886 1,240 1,403 1,345 1,120 1,215 1,126 1,155 1,614 1,600 1,629 2,421 1,353 2,207 1,678 1,292 2,003 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.
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

51
Business Plan Resource Portfolio

The Business Plan resource portfolio was updated from 2015 IRP preferred portfolio to reflect
changes in existing resource assumptions, as well as assumptions around DSM resources. The
main change in existing resources adopted in the Business Plan was the assumed early retirement
of Naughton Unit 3 at the end of 2017 and the assumed early retirement of Cholla Unit 4 at the
end of 2024. Class 2 DSM selections in the 2015 IRP preferred portfolio were finalized in
February 2015. In developing the business plan in the following months, certain Class 2 DSM
acquisition levels for 2015-2025 were modified to reflect updated near-term commitments,
delivery challenges in certain markets, and uncertainty around upcoming regulatory activity. No
modifications were made for the period 2026-2034.

The reduction in existing thermal resources and DSM, as discussed above, are offset by changes
in FOTs. Table 5.4 shows the capacity load and resource balance from the Business Plan,
inclusive of incremental resources, over the period 2016-2025. Table 5.5 summarizes the annual
capacity of incremental resources assumed in the Business Plan.

PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
52
Table 5.4 – 2015 Fall Business Plan Capacity Load and Resource Balance (Megawatts)

Calendar Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
East
Thermal 6,397 6,397 6,116 6,116 6,116 6,113 6,110 6,108 6,105 5,717
Hydroelectric 109 109 112 112 112 112 112 112 92 92
Renewable 187 187 187 187 187 185 185 178 178 168
Purchase 355 249 249 249 249 221 221 221 221 121
Qualifying Facilities 304 444 437 435 429 422 412 409 407 403
Class 1 DSM 323 323 323 323 323 323 323 323 323 323
Sale (728)(653)(652)(652)(652)(171)(171)(171)(144)(144)
Non-Owned Reserves (38)(38)(38)(38)(38)(38)(38)(38)(38)(38)
Transfers 612 559 932 888 949 608 638 661 682 800
East Existing Resources 7,521 7,577 7,667 7,620 7,675 7,774 7,793 7,803 7,826 7,443
Front Office Transactions 0 0 0 105 68 0 0 0 0 309
Gas 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Other 0 0 0 0 0 0 0 0 0 0
East Planned Resources 0 0 0 105 68 0 0 0 0 309
East Total Resources 7,521 7,577 7,667 7,725 7,744 7,774 7,793 7,803 7,826 7,752
Load 6,963 7,084 7,235 7,359 7,447 7,548 7,637 7,717 7,809 7,880
Interruptible (195)(195)(195)(195)(195)(195)(195)(195)(195)(195)
Existing Class 2 DSM (64)(64)(64)(64)(64)(64)(64)(64)(64)(64)
New Class 2 DSM (71)(142)(214)(286)(358)(431)(504)(576)(646)(783)
East obligation 6,633 6,683 6,762 6,814 6,830 6,858 6,874 6,883 6,904 6,838
Planning Reserves (13%)888 894 904 911 913 917 919 920 923 914
East Reserves 888 894 904 911 913 917 919 920 923 914
East Obligation + Reserves 7,521 7,577 7,667 7,725 7,744 7,775 7,792 7,803 7,826 7,752
East Position 0 (0)(0)(0)(0)(0)0 0 (0)(0)
East Reserve Margin 13%13%13%13%13%13%13%13%13%13%
West
Thermal 2,251 2,248 2,248 2,248 2,248 2,245 2,241 2,239 2,239 2,239
Hydroelectric 841 826 837 736 793 623 548 654 643 632
Renewable 172 173 173 173 173 173 118 118 108 108
Purchase 18 18 18 1 1 1 1 1 1 1
Qualifying Facilities 112 190 202 200 202 190 186 179 178 178
Class 1 DSM 0 0 0 0 0 0 0 0 0 0
Sale (165)(165)(165)(165)(165)(161)(110)(110)(80)(80)
Non-Owned Reserves (3)(3)(3)(3)(3)(3)(3)(3)(3)(3)
Transfers (613)(560)(933)(889)(950)(609)(639)(662)(684)(802)
West Existing Resources 2,612 2,726 2,376 2,301 2,298 2,459 2,343 2,417 2,403 2,274
Front Office Transactions 936 781 1,140 1,212 1,212 1,047 1,155 1,068 1,076 1,212
Gas 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0
Class 1 DSM 0 0 0 0 0 0 5 17 17 17
Other 0 0 0 0 0 0 0 0 0 0
West Planned Resources 936 781 1,140 1,212 1,212 1,047 1,161 1,085 1,092 1,228
West Total Resources 3,548 3,507 3,517 3,512 3,510 3,506 3,504 3,501 3,495 3,502
Load 3,206 3,199 3,235 3,256 3,276 3,294 3,313 3,332 3,346 3,373
Interruptible 0 0 0 0 0 0 0 0 0 0
Existing Class 2 DSM (35)(35)(35)(35)(35)(35)(35)(35)(35)(35)
New Class 2 DSM (31)(60)(87)(113)(135)(156)(177)(198)(218)(239)
West obligation 3,140 3,104 3,112 3,108 3,106 3,103 3,101 3,099 3,093 3,099
Planning Reserves (13%)408 403 405 404 404 403 403 403 402 403
West Reserves 408 403 405 404 404 403 403 403 402 403
West Obligation + Reserves 3,548 3,507 3,517 3,512 3,510 3,506 3,504 3,502 3,495 3,502
West Position 0 (0)0 (0)0 0 0 (0)(0)0
West Reserve Margin 13%13%13%13%13%13%13%13%13%13%
System
Total Resources 11,069 11,084 11,183 11,237 11,253 11,281 11,297 11,305 11,321 11,254
Obligation 9,773 9,787 9,874 9,922 9,936 9,961 9,974 9,982 9,996 9,937
Reserves 1,296 1,298 1,309 1,315 1,317 1,320 1,322 1,323 1,325 1,317
Obligation + Reserves 11,069 11,085 11,183 11,238 11,253 11,281 11,296 11,305 11,321 11,254
System Position 0 (0)0 (0)(0)0 0 0 (0)(0)
Reserve Margin 13%13%13%13%13%13%13%13%13%13%
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

53
Table 5.5 –Business Plan, Detailed Portfolio (Megawatts)

Renewable Portfolio Standard Compliance
Oregon

On March 8, 2016, Oregon Senate Bill 1547-B (SB 1547-B), the Clean Electricity and Coal
Transition plan, was signed into law, which doubles the Oregon RPS target to 50% by 2040.
Table 5.6 summarizes how the bill affects RPS targets for Oregon relative to those assumed in
the 2015 IRP. In addition to revising RPS targets, SB 1547-B includes other provisions that
influence how the company will plan to meet its RPS compliance requirements. One of these
provisions introduces a five year banking limitation on renewable energy credits (RECs) issued
after March 8, 2016. RECs issued on or before March 8, 2016 can be banked indefinitely.
Another provision in SB 1547-B provides an early action incentive that allows for indefinite
banking of RECs from new qualifying renewable resources that are issued over the first five
years of the renewable resource’s operation. New qualifying renewable resources include
facilities that come online between March 8, 2016 and December 31, 2022. At the same time, SB
1547-B eliminates the requirement to surrender older vintage RECs for compliance first, prior to
the surrender of newer vintage RECs.

Table 5.6 – Oregon RPS Targets
Year 2015 IRP 2015 IRP Update
2016 15% 15%
2020 20% 20%
2025 25% 27%
2030 25% 35%
2035 25% 45%
2040 25% 50%

Capacity (MW)Resource
Totals 1/
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 10-year
East Existing Plant Retirements/Conversions
Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - -
Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - -
Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) (387)
Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - (280)
Expansion Resources
DSM, Class 2, ID 3 3 3 3 4 3 3 3 3 3 3 32
DSM, Class 2, UT 61 61 63 63 63 63 64 63 63 61 65 629
DSM, Class 2, WY 4 6 7 7 7 7 8 8 7 8 8 73
DSM, Class 2 Total 67 70 73 73 74 73 75 75 73 72 76 734
FOT Mona Q3 - - - - 99 64 - - - - 291 45
West Expansion Resources
DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6
DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - 5.0
DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 15.6
DSM, Class 2, CA 1 1 2 2 2 1 1 1 1 1 1 14
DSM, Class 2, OR 33 32 27 24 22 19 18 18 17 16 15 208
DSM, Class 2, WA 8 8 8 8 8 6 7 7 8 7 6 73
DSM, Class 2 Total 43 41 36 34 32 26 26 26 26 24 23 295
FOT COB Q3 - 8 - 201 268 268 113 215 133 140 268 161
FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400
FOT MidColumbia Q3 - 2 261 375 237 375 375 375 375 375 375 375 375 361
FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100
Existing Plant Retirements/Conversions (222) - - (280) - - - - - - (387)
Annual Additions, Long Term Resources 110 111 109 107 106 99 102 106 110 96 99
Annual Additions, Short Term Resources 761 883 737 1,076 1,242 1,207 988 1,090 1,008 1,015 1,434
Total Annual Additions 871 994 846 1,183 1,348 1,306 1,090 1,196 1,117 1,111 1,533
1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10-year annual average.
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
54
Figure 5.1 shows PacifiCorp’s baseline RPS compliance position for Oregon for the front ten
years of the planning horizon if no further action were taken. The baseline position indicates an
initial shortfall, with the use of the existing bank, would occur in 2025.

Figure 5.1 – Baseline Oregon RPS Compliance Position

Considering the flexible provisions in the new law, updated RPS targets, updated REC banking
provisions and the market potential for RECs, PacifiCorp can meet its Oregon RPS obligations
through the 20-year IRP planning horizon through a number of flexible alternatives including the
purchase of eligible RECs.8 Figure 5.2 shows PacifiCorp’s RPS compliance forecast for Oregon,
inclusive of REC purchase volumes that contribute to meeting RPS targets through the IRP
planning horizon. Over the front ten years of the planning horizon, nearly 19 million RECs are
needed to build the bank, which can be used to meet RPS requirements as the target rises over
time. Over this same period, PacifiCorp estimates that there will be at least 23 million RECs
generated from qualifying facility projects that have power purchase agreements with PacifiCorp
in which the project developers hold title to the RECs. This volume is over and above eligible
RECs from other facilities in the market with whom PacifiCorp is familiar through its industry
leading Blue Sky program.

8 Under the Oregon RPS, RECs purchased from qualifying facility projects located in Oregon do not apply toward
the 20% annual unbundled REC limit. RECs purchased from qualifying facilities in other states could be acquired as
a bundled REC if the REC is purchased with the energy in the same contract.
0
2,000
4,000
6,000
8,000
10,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
RE
C
s

(
T
h
o
u
s
a
n
d
s
)
Oregon RPS
Unbundled Surrrendered Bundled Surrendered
Unbundled Bank Surrendered Bundled Bank Surrendered
Shortfall Year-end Unbundled Bank Balance
Year-end Bundled Bank Balance Requirement
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

55
Figure 5.2 – Oregon RPS Compliance Position with REC Purchases

REC purchases represent one avenue for achieving RPS compliance. PacifiCorp has also
identified the potential for near-term, time-sensitive renewable resource acquisition opportunities
that may reduce RPS compliance costs. The current planning environment, as fully described in
Chapter 2, creates a potentially unique opportunity for the company to pursue low-cost
renewable resources in the near-term as a way to reduce long-term RPS compliance costs. As
discussed in Chapter 2, federal tax extender legislation passed in late 2015 retroactively and
prospectively extended certain expired and expiring federal income tax deductions and credits
over a multi-year phase out period. The most time-sensitive of these income tax credits is the
federal production tax credit (PTC) for wind resources. To take advantage of the full PTC,
currently set at 2.3 cents per kilowatt-hour, growing at inflation, for the first ten years of
operation, a wind facility must commence construction by January 1, 2017. Under Internal
Revenue Service (IRS) guidance, projects can demonstrate they have commenced construction
by either starting work of a significant physical nature or by paying or incurring at least five
percent of the total cost of the facility by January 1, 2017.

The PTC equates to over 3.7 cents per kilowatt-hour when grossed up by PacifiCorp’s marginal
tax rate. Consequently, the after-tax cost of a wind project that is eligible for 100% of the PTC is
reduced by over $37/MWh growing at inflation for the first ten years. For a 100 MW wind
facility operating at a 29% capacity factor, this equates to over $102 million over ten years—
after-tax cost savings that are passed through to customers. If the up-front capital cost for this
wind facility is $180 million (about $1,800/kW), then the PTCs received through the first ten
years of operation cover 57% of the initial capital investment. If the project operates at a 35%
capacity factor, the PTC savings increase to nearly $124 million, representing about 69% of the
initial capital investment. If a wind facility is unable to demonstrate it has commenced
construction by January 1, 2017 but can commence construction by January 1, 2018, then the
PTC is reduced by 20%. This one year delay would reduce PTC savings by between $20 million
(29% capacity factor) to $25 million (35% capacity factor) for a 100 MW project.

In addition to the time-sensitive opportunity to take full advantage of PTC benefits, SB 1547-B
also includes an opportunity to lower RPS compliance costs through the near-term acquisition of
0
5,000
10,000
15,000
20,000
25,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
RE
C
s

(
T
h
o
u
s
a
n
d
s
)
Oregon RPS
Unbundled Surrrendered Bundled Surrendered
Unbundled Bank Surrendered Bundled Bank Surrendered
Shortfall Year-end Unbundled Bank Balance
Year-end Bundled Bank Balance Requirement
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
56
renewable resources since RECs issued during the first five years of a new renewable facilities’
operation can be banked indefinitely. RECs generated during this time period will allow
PacifiCorp to build a bank of RECs that are not subject to a five year banking limit. Growing the
bank now will allow the company to defer future RPS compliance needs, when cost savings from
tax incentives will no longer be available.

Near-term renewable resource procurement also provides value to customers because new
renewable resources provide incremental energy and capacity that can also reduce system
emissions. This additional energy and capacity will immediately offset fuel costs, purchased
power and associated emissions. It will also offset the need for replacement resources as existing
generating assets retire and reduce the Company’s risk associated with the future greenhouse gas
regulations. Procurement of renewable resources can further enable access to high quality
renewable resource sites, which can provide future repowering and/or redevelopment value.
With increased state RPS targets (i.e., Oregon and California targets now reach 50%) and the
anticipated need to reduce greenhouse gas emissions through both state and federal policies such
as the Clean Power Plan, demand for renewable resources is expected to grow and place upward
pressure on future renewable resource costs, particularly if incremental transmission
infrastructure is needed. Therefore, the acquisition of renewable resources now has the potential
to optimally position the company and its Oregon customers in the face of increased and
expanded carbon regulation.

To fully evaluate Oregon RPS compliance alternatives that consider potential near-term, time-
sensitive resource procurement opportunities, PacifiCorp intends to issue requests for proposals
(RFPs) seeking both REC purchase and resource procurement alternatives. Resource proposals
will be evaluated concurrent with REC proposals to comprehensively assess RPS compliance
alternatives, considering both cost and risk metrics. Because proposals for new wind facilities
must be able to demonstrate that they initiated construction by January 1, 2017 to take full
advantage of PTC cost savings, PacifiCorp intends to issue this RFP in spring 2016 to complete
the RFP evaluation, selection and contracting process by fall 2016. This schedule provides the
best opportunity for customers to benefit from potentially cost effective wind and solar proposals
that can take full advantage of the PTC and ITC.

Notwithstanding the near-term renewable resource value incentives and opportunities,
PacifiCorp will also consider longer term opportunities to take advantage of retiring coal
facilities on its network that will free up transmission in renewable resource rich areas and
provide access to low cost resources which today are constrained by lack of transmission.
Washington

Figure 5.3 shows PacifiCorp’s baseline RPS compliance position for Washington for the front
ten years of the planning horizon, prior to procuring incremental unbundled RECs. This baseline
position incorporates PacifiCorp’s most recent procurement of unbundled RECs for
Washington’s RPS. The baseline position indicates a potential shortfall in 2018 if no further
action were taken.

PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

57
Figure 5.3 – Baseline Washington RPS Compliance Position

Washington RPS rules do not impose restrictions on the use of unbundled RECs and effectively
impose a one year life on all banked RECs. PacifiCorp can meet its Washington RPS targets with
unbundled REC purchases through the IRP planning horizon. Figure 5.4 shows PacifiCorp’s
Washington RPS compliance position with unbundled REC purchase volumes required to
achieve compliance. As requested by the Washington Utilities and Transportation Commission
in its 2015 IRP acknowledgement letter, Washington RPS compliance is presented consistent
with how Washington is currently allocated eligible renewable resources. Over the front ten
years of the planning horizon, nearly 2.3 million additional unbundled RECs are needed to meet
Washington RPS targets. As discussed above, PacifiCorp will consider whether near-term, time-
sensitive resource procurement provides a low cost opportunity to displace or supplement
unbundled REC purchases as an alternative approach to achieving compliance with the
Washington RPS.

Figure 5.4 – Washington RPS Compliance Position with REC Purchases

0
200
400
600
800
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
RE
C
s

(
T
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Washington RPS
Unbundled Surrrendered Bundled Surrendered
Unbundled Bank Surrendered Bundled Bank Surrendered
Shortfall Year-end Unbundled Bank Balance
0
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2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
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Washington RPS
Unbundled Surrrendered Bundled Surrendered
Unbundled Bank Surrendered Bundled Bank Surrendered
Shortfall Year-end Unbundled Bank Balance
Year-end Bundled Bank Balance Requirement
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
58

California

In October 2015, California Senate Bill No. 350 (SB 350) was signed into law, expanding the
RPS target to 50% by 2030. Table 5.7 summarizes how the bill affects interim RPS targets for
California relative to those assumed in the 2015 IRP.

Table 5.7 – California RPS Targets
Year 2015 IRP 2015 IRP Update
2016 25% 25%
2017 27% 27%
2018 29% 29%
2019 31% 31%
2020 33% 33%
2024 33% 40%
2027 33% 45%
2030 33% 50%

Figure 5.5 shows PacifiCorp’s baseline RPS compliance position for California for the front ten
years of the planning horizon. This baseline position includes unbundled RECs that have been
procured for California RPS compliance.9 The baseline position indicates a potential shortfall
beginning 2018 if no further action were taken.

Figure 5.5 – Baseline California RPS Compliance Position

PacifiCorp is not restricted from using unbundled RECs to meet its RPS targets in California,
and unbundled REC purchases can be used to achieve compliance through the IRP planning
horizon. Figure 5.6 shows PacifiCorp’s California RPS compliance position with unbundled
REC purchase volumes required to achieve compliance. Over the front ten years of the planning
horizon, over one million additional unbundled RECs are needed to meet California RPS targets.
As discussed above, PacifiCorp will consider whether near-term, time-sensitive resource

9 PacifiCorp selected a response to an unbundled REC RFP which meets the Company’s needs and pricing criteria.
The contract is currently under review with the California Public Utilities Commission.
0
50
100
150
200
250
300
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
RE
C
s

(
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)
California RPS
Unbundled Surrrendered Bundled Surrendered
Unbundled Bank Surrendered Bundled Bank Surrendered
Shortfall Year-end Unbundled Bank Balance
Year-end Bundled Bank Balance Requirement
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

59
procurement provides a low cost opportunity to displace or supplement unbundled REC
purchases as an alternative approach to achieving compliance with the California RPS.

Figure 5.6 – California RPS Compliance Position with REC Purchases

Utah

Utah Senate Bill 202, the Energy Resource and Carbon Emission Reduction Initiative, provides
that beginning in 2025, 20% of adjusted retail sales of all Utah utilities be supplied by renewable
energy, if cost effective. Retail electric sales are adjusted by deducting the amount of generation
from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of
energy efficiency and demand side management programs. Qualifying renewable energy sources
can be located anywhere in the Western Electricity Coordinating Council area, and unbundled
RECs can be used for up to 20% of the annual qualifying electricity target. Solar facilities
located in Utah receive credit for 2.4 kilowatt-hours of qualifying electricity for each kilowatt-
hour of generation. PacifiCorp has been building a bank of RECs from existing and contracted
qualifying resources since 1995. This bank will be used to meet Utah’s RPS goals well beyond
the IRP planning horizon.

Carbon Dioxide Emissions

Figure 5.7 shows annual total CO2 emissions of the resource portfolio and from coal-fueled
generation facilities for both the 2015 IRP preferred portfolio and 2015 IRP Update resource
portfolio. Emissions from the 2015 IRP Update resource portfolio are lower primarily due to
reduced generation levels from fossil fired resources. Figure 5.8 shows the total generation and
generation from coal-fueled facilities from the 2015 IRP and 2015 IRP Update. Figure 5.9
shows emissions from affected units under the FIP-based mass cap proposed by EPA for the
Clean Power Plan.

0
50
100
150
200
250
300
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
RE
C
s

(
T
h
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a
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)
California RPS
Unbundled Surrrendered Bundled Surrendered
Unbundled Bank Surrendered Bundled Bank Surrendered
Shortfall Year-end Unbundled Bank Balance
Year-end Bundled Bank Balance Requirement
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
60
Figure 5.7 – Total CO2 Emissions

Figure 5.8 – Total Thermal Generation

20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
mi
l
l
i
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s
h
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r
t

t
o
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2015 IRP Pref Port, Total 2015 IRP Pref Port, Coal
2015 IRP Update, Total 2015 IRP Update, Coal
0
10,000
20,000
30,000
40,000
50,000
60,000
GW
h
2015 IRP Pref Port, Total 2015 IRP Pref Port, Coal
2015 IRP Update, Total 2015 IRP Update, Coal
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

61
Figure 5.9 – Mass-Cap and Emissions from Affected Units

Oregon SB 1547-B requires that coal-fired resources are eliminated from Oregon’s allocation of
electricity by January 1, 2030. Figure 5.10 shows the reduction in emissions from coal resources
allocated to Oregon customers accounting for this provision of SB 1547-B.

Figure 5.10 – Oregon Share of CO2 Emission from Coal-fueled Resources

Sensitivity Studies and Responses to Commission Requests
Clean Power Plan and Allocation of Renewable Energy Attributes

In its 2015 IRP acknowledgement letter, the WUTC encouraged the Company to use the 2015
IRP Update as an opportunity to begin modeling EPA’s final CPP rule and to actively and
constructively participate in Washington’s process and any multi-state or regional efforts that
emerge. The WUTC further requested PacifiCorp re-run Sensitivity Case S-15 in the 2015 IRP
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
mi
l
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s
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Emissions of Affected Units Mass-Cap
0.0
2.0
4.0
6.0
8.0
10.0
12.0
mi
l
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s
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t

t
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Pre-SB 1547-B SB 1547-B
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
62
Update, accounting for the final CPP rule, to determine whether lower cost compliance options
that do not assume an early retirement of the Chehalis plant are available to meet its obligations
without having to double allocate renewable energy.

PacifiCorp has and will continue to actively and constructively participate in the Washington
Department of Ecology’s CPP stakeholder process, which has included two utility stakeholder
meetings so far. PacifiCorp is also engaging with state agencies on an informal basis and is
participating in various regional efforts including efforts being led by the Center for New Energy
Economy, WEST Associates, and the Western Interstate Energy Board.

Sensitivity Case S-15 from the 2015 IRP assumes state RPS-eligible RECs and CPP renewable
attributes would need to be surrendered at the same time, forcing PacifiCorp to meet its share of
emission rate targets outlined in the draft CPP rule with either situs-assigned renewable
resources, or alternatively, by eliminating PacifiCorp’s CPP compliance obligation in
Washington by retiring the Chehalis plant. Given the low emission rate targets in EPA’s draft
rule for the state of Washington, PacifiCorp concluded that significant levels of situs-assigned
renewable resources would be required to achieve compliance with draft emission rate targets
proposed for the state of Washington, and determined that an early retirement of Chehalis would
be lower cost when developing the resource portfolio for Sensitivity Case S-15.

When developing Sensitivity Case S-15 for the 2015 IRP, PacifiCorp determined an early
retirement of Chehalis would be lower cost than adding situs-assigned renewable resources based
on preliminary analysis performed during the public process that was presented to stakeholders
at the January 29-30, 2015 public input meeting.10 This preliminary sensitivity analysis was
produced for Sensitivity Case S-10, which developed standalone resource portfolios for the east
and west balancing authority areas. In its preliminary modeling for this Sensitivity Case S-10,
PacifiCorp developed one CPP compliance scenario assuming Chehalis retired early, eliminating
PacifiCorp’s CPP obligation in Washington, and another scenario assuming incremental
renewable resources were added to meet then-current emission rate targets. This preliminary
analysis showed that a renewable-based compliance solution would require over 1,100 MW of
incremental renewable resources and that the present value revenue requirement (PVRR) of
system costs were $515 million higher (over 77%) than the Chehalis early retirement alternative.

Since PacifiCorp performed these sensitivity analyses for the 2015 IRP, EPA issued its final CPP
rule as summarized in Chapter 2. In its final rule, EPA significantly increased the emission rate
targets for the state of Washington and provided states with a number of implementation options,
including an alternative to adopt mass-based goals that EPA has determined are equivalent to the
updated rate-based targets. Considering that the emission rate of the Chehalis plant falls below
the final rate-based targets established for the state of Washington, PacifiCorp would not
anticipate needing to eliminate its CPP compliance obligation by retiring Chehalis early or
needing to acquire emission reduction credits (ERCs) to reduce its share of the Washington state
emission rate targets should Washington adopt a rate-based plan. Moreover, should Washington
adopt a mass-based plan, ERCs would not be used to achieve compliance, eliminating the
concern of double-allocating renewable energy altogether.

10 The referenced analysis is summarized beginning on slide 78 of the presentation, which is available on
PacifiCorp’s website:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2015IRP/Pacifi
Corp_2015IRP_PIM06_2015-01-29-30.pdf
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT

63
Considering that the U.S. Supreme Court issued a stay of the CPP suspending implementation of
the rule, PacifiCorp has not performed comprehensive resource portfolio analysis of the CPP
final rule in this 2015 IRP Update. PacifiCorp developed its updated resource portfolio assuming
system mass cap emission rate targets consistent with EPA’s proposed mass-based FIP to limit
CO2 emissions from its existing affected generation facilities. PacifiCorp will evaluate CPP
compliance scenarios, with input from its stakeholders, during the 2017 IRP public process.
Historical Cooling Degree Days

In its order regarding PacifiCorp’s 2013 IRP, the Public Service Commission of Utah (PSCU)
directed PacifiCorp to perform a study on whether the available historical cooling degree day
information, or some other alternative, is an appropriate predictor of future normal conditions.
The request for the study was a result of a discussion on whether PacifiCorp should consider
climate change implications when forecasting load. Changes in climate would ultimately be
reflected by the data on historical weather and load, and the impact on the forecast of load would
be guided by the historical relationship between weather on load. To respond to this order,
PacifiCorp prepared a study to test the impacts of different historical weather patterns on the load
forecast. There are no meaningful differences between using a five-year, ten-year, or 20-year
normal weather pattern in the models. The results are presented on page nine of Appendix A to
PacifiCorp’s 2015 IRP report.11 PacifiCorp also prepared extreme weather scenarios to study the
impacts of less likely weather patterns, which are presented on page 18 of Appendix A to
PacifiCorp’s 2015 IRP report. The portfolio impact of different levels of load forecast is
reflected by Sensitivity Cases S-01, S-02 and S-03 in PacifiCorp’s 2015 IRP.
Interaction of FERC Order 1000 and Energy Gateway

The PSCU also requested that PacifiCorp explain, as necessary, the interaction of requirements
by the FERC Order 1000 and any Energy Gateway Project. PacifiCorp continues to participate in
the Northern Tier Transmission Group that satisfies regional transmission planning requirements
under the FERC’s Order No.1000 in addition to PacifiCorp’s local transmission planning
requirements pursuant to Attachment K of its Open Access Transmission Tariff. Energy
Gateway is also considered in the NTTG biennial transmission planning cycle efforts as well as
at the Western Electricity Coordinating Council’s Transmission Expansion Policy and Planning
Committee.
Accelerated Class 2 DSM

As recommended by the OPUC, PacifiCorp performed a sensitivity study on Class 2 DSM by
replacing baseline DSM potential with accelerated DSM potential when developing an optimized
resource portfolio. Table 5.8 shows the portfolio with accelerated DSM, the 2015 IRP Update
portfolio with baseline DSM, and the differences between these two portfolios.

11
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2015IRP/Pacifi
Corp_2015IRP-Vol2-Appendices.pdf

PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
64
The sensitivity shows that when accelerated DSM potential is assumed, a slightly higher amount
of Class 2 DSM resource is selected in the early years, while the total amount of Class 2 DSM
selected over the 20-year study period is lower. The amount of DSM in 2015 through 2017 is the
same between the two portfolios, because, as described earlier in this chapter, Class 2 DSM
selections are fixed to reflect the most up to date planning for 2015 through 2017 and optimized
beginning in 2018. The amount of Class 2 DSM in 2015 through 2017 exceeds the amount
selected in the 2015 IRP, and thus, they were not modified in the accelerated sensitivity case.
The portfolio with accelerated DSM also includes a larger CCCT in 2028 and delayed a CCCT in
2031. FOTs are generally less until 2031. For the 20-year study period, the portfolio added 41
MW less CCCT capacity, and added a total of 88 MW of utility solar on the east side of
PacifiCorp’s system. The present value revenue requirement (PVRR) of system costs from the
portfolio with accelerated DSM is approximately $45 million higher than the portfolio developed
with baseline DSM assumptions.

PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
65
Table 5.8 – Portfolio Comparison of Accelerated DSM Study and 2015 IRP Update (Megawatts)
Accelerated DSM portfolio

2015 IRP Update

Summary Portfolio Capacity by Resource Type and Year, Installed MW
Installed Capacity, MW
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Total
Expansion Options
Gas - CCCT - - - - - - - - - - - - - 1,314 - 635 - - 635 - 2,584
Gas- Peaking - - - - - - - - - - - - - - - - - - - - -
DSM - Energy Efficiency 143 128 138 149 164 149 153 155 157 155 128 128 126 107 110 103 101 101 101 96 2,590
DSM - Load Control - - - - - - - - - - 22 29 63 - - - - - 86 9 208
Renewable - Wind - - - - - - - - - - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - 1 3 - - - - - - - 84 88
Renewable - Biomass - - - - - - - - - - - - - - - - - - - - -
Front Office Transactions 764 903 748 1,088 1,231 1,179 942 1,032 941 975 1,443 1,443 1,441 984 1,044 1,286 1,359 1,441 1,438 1,443 1,156
Existing Unit Changes
Coal Early Retirement/Conversions (222) - - (280) - - - - - - (387) - - - - (450) - - (269) - (1,608)
Thermal Plant End-of-life Retirements - - - - - - - - - - - - - (762) - (357) (77) - (358) - (1,554)
Coal Plant Gas Conversion Additions - - - - - - - - - - - - - - - - - - - - -
Turbine Upgrades - - - - - - - - - - - - - - - - - - - - -
Total 685 1,031 886 957 1,395 1,328 1,095 1,188 1,098 1,129 1,207 1,602 1,630 1,643 1,154 1,217 1,383 1,541 1,634 1,632
Summary Portfolio Capacity by Resource Type and Year, Installed MW
Installed Capacity, MW
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Total
Expansion Options
Gas - CCCT - - - - - - - - - - - - - 1,112 - 635 454 - 423 - 2,625
Gas- Peaking - - - - - - - - - - - - - - - - - - - - -
DSM - Energy Efficiency 143 128 138 146 158 142 149 155 161 162 135 136 135 131 130 122 117 118 117 114 2,740
DSM - Load Control - - - - - - - - - - 39 24 51 - - 7 - - 20 33 173
Renewable - Wind - - - - - - - - - - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - - - - - - - - - - - -
Renewable - Biomass - - - - - - - - - - - - - - - - - - - - -
Front Office Transactions 764 903 748 1,094 1,246 1,203 970 1,060 965 993 1,440 1,440 1,443 1,177 1,223 1,443 1,107 1,174 1,443 1,443 1,164
Existing Unit Changes
Coal Early Retirement/Conversions (222) - - (280) - - - - - - (387) - - - - (450) - - (269) - (1,608)
Thermal Plant End-of-life Retirements - - - - - - - - - - - - - (762) - (357) (77) - (358) - (1,554)
Coal Plant Gas Conversion Additions - - - - - - - - - - - - - - - - - - - - -
Turbine Upgrades - - - - - - - - - - - - - - - - - - - - -
Total 685 1,031 886 960 1,403 1,345 1,120 1,215 1,126 1,155 1,227 1,600 1,629 1,659 1,353 1,400 1,600 1,292 1,376 1,590
PACIFICORP – 2015 IRP UPDATE CHAPTER 5 – PORTFOLIO DEVELOPMENT
66
Portfolio Difference

Summary Portfolio Capacity by Resource Type and Year, Installed MW
Installed Capacity, MW
Resource 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Total
Expansion Options
Gas - CCCT - - - - - - - - - - - - - 202 - - (454) - 212 - (41)
Gas- Peaking - - - - - - - - - - - - - - - - - - - - -
DSM - Energy Efficiency - - - 3 7 6 3 (0) (4) (8) (6) (8) (9) (24) (21) (20) (16) (18) (16) (19) (150)
DSM - Load Control - - - - - - - - - - (17) 5 12 - - (7) - - 66 (24) 35
Renewable - Wind - - - - - - - - - - - - - - - - - - - - -
Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - -
Renewable - Utility Solar - - - - - - - - - - 1 3 - - - - - - - 84 88
Renewable - Biomass - - - - - - - - - - - - - - - - - - - - -
Front Office Transactions - - - (6) (15) (24) (28) (28) (25) (18) 3 3 (2) (194) (179) (157) 253 267 (4) 0 (8)
Existing Unit Changes
Coal Early Retirement/Conversions - - - - - - - - - - - - - - - - - - - - -
Thermal Plant End-of-life Retirements - - - - - - - - - - - - - - - - - - - - -
Coal Plant Gas Conversion Additions - - - - - - - - - - - - - - - - - - - - -
Turbine Upgrades - - - - - - - - - - - - - - - - - - - - -
Total 0 0 0 (3)(8)(17)(25)(28)(29)(26)(19)2 1 (16)(199)(184)(218)249 258 42
PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE
67
CHAPTER 6 – ACTION PLAN STATUS UPDATE
This chapter provides an update to the action items listed in the Action Plan of PacifiCorp’s 2015
IRP. Some of the action items have been superseded or eliminated since they were identified in
the 2015 IRP. The status for all action items is provided in Table 6.1 below.

PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE

68
Table 6.1 – 2015 IRP Action Plan Status Update

 The Company will pursue unbundled REC request for proposals
(RFP) to meet its state RPS compliance requirements.
– Issue at least annually, RFPs seeking then current-year
or forward-year vintage unbundled RECs that will
qualify in meeting Washington renewable portfolio
standard targets through 2017.
– Issue at least annually, RFPs seeking then current-year
or forward-year vintage unbundled RECs that will
qualify in meeting California renewable portfolio
standard targets through 2017.
– With a projected bank balance extending out through
2027, defer issuance of RFPs seeking unbundled RECs
that will qualify in meeting Oregon renewable portfolio
standard targets until states begin to develop
implementation plans under EPA’s draft 111(d) rule,
providing clarity on whether an unbundled REC strategy
is the least cost compliance alternative for Oregon
customers.
For the Washington renewable portfolio standard, the
Company did not issue a REC RFP in 2015. The
Company determined that its current needs did not
warrant issuance of a RFP.

For the California renewable portfolio standard
requirements, the Company issued a REC RFP on
October 2, 2015 with bids due October 22, 2015. An
offer meeting the Company’s needs and specific pricing
criteria was selected and is currently under review with
the California Public Utilities Commission.

Action Item 1a has been revised in the 2015 IRP
Update, as presented in the Executive Summary, to
reflect changes in state RPS targets and banking
provisions and changes in federal tax credits.

 On a quarterly basis, and through calendar year 2016, issue
reverse RFPs to sell 2016 vintage or older RECs that are not
required to meet state RPS compliance obligations.
The Company issued a reverse RFP in February 2015
and June 2015 to sell RECs. The Company will continue
to issue reverse RFPs in 2016 to seek REC sale
opportunities for RECs allocated to states that do not
have a state RPS compliance need.
 Conclude negotiations with shortlisted bids from the 2013S
Request for Proposals (RFP), seeking up to 7 MWAC of
competitively priced capacity from qualifying solar systems
that will be used to satisfy PacifiCorp’s obligation under
Oregon’s 2020 solar capacity standard.
The Oregon Solar Capacity Standard was eliminated
with the passage of Oregon Senate Bill 1547-B. This
action item was deleted from the updated action plan
presented in the Executive Summary.
PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE
69
Action
Item Activity Status
2a
Front Office Transactions
–

–
–
–
3a
Class 1 DSM
–

PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE

70
Action
Item Activity Status
3b
Class 2 DSM

following table. PacifiCorp’s implementation plan to acquire
Year Annual Incremental
Energy (GWh)
Annual Incremental
Capacity* (MW)
2015 551 133
2016 584 139
2017 616 146
2018 634 146
*Class 2 DSM capacity figures reflect projected maximum annual hourly energy
savings, which is similar to a nameplate rating for a supply side resource.
4a
Naughton Unit 3


“short listed” bidders were asked to refresh all pricing
informed PacifiCorp’s
PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE
71
Action
Item Activity Status
4b
Dave Johnston Unit 3
 The portion of EPA’s final Regional Haze Federal
 If following appeal, EPA’s final FIP as it pertains to Dave
 If following appeal, EPA’s final FIP as it pertains to Dave
PacifiCorp is still awaiting results of appeal of EPA’s
4c
Wyodak
 Continue to pursue the Company’s appeal of the portion of
EPA’s final Regional Haze FIP that requires the installation
 If following appeal, EPA’s final FIP as it pertains to installation
appeal of EPA’s
4d
Cholla Unit 4
 amend the facility’s Title V permit and the Arizona
PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE

72
Action
Item Activity Status

5a
Energy Gateway Permitting

–
–
–
–

–

–

5b
Wallula to McNary 230 kilovolt Transmission Line

–

–

–
PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE
73
Action
Item Activity Status

–

–

PACIFICORP – 2015 IRP UPDATE CHAPTER 6 – ACTION PLAN STATUS UPDATE

74

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PACIFICORP – 2015 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS

75
APPENDIX A – ADDITIONAL LOAD FORECAST
DETAILS
The load forecast presented in Chapter 3 represents the data used for capacity expansion
modeling, and excludes load reductions from incremental energy efficiency resources (Class 2
DSM). Tables A.1 and A.2 report the October 2015 (2015 IRP Update) annual load and
coincident peak load forecasts. These forecast data include reduction in loads for both distributed
generation and new energy efficiency measures (Class 2 DSM), and have not been adjusted for
line-losses.

Table A.1 – October 2015 (2015 IRP Update): Forecasted Annual Load Growth, 2016
through 2025 (Megawatt-hours)
Year Total OR WA CA UT WY ID SE-ID
2016 56,920,222 13,022,611 4,099,940 745,074 24,830,260 9,591,503 3,477,804 1,153,030
2017 55,580,892 12,715,915 4,085,272 737,702 24,908,433 9,685,196 3,448,374
2018 55,896,683 12,822,029 4,079,018 730,863 25,049,965 9,763,711 3,451,096
2019 56,207,036 12,849,252 4,069,749 722,665 25,284,842 9,827,527 3,453,001
2020 56,314,053 12,819,960 4,063,519 716,384 25,457,899 9,803,611 3,452,680
2021 56,205,931 12,769,059 4,039,095 707,205 25,487,966 9,752,466 3,450,140
2022 56,233,170 12,773,767 4,025,178 700,233 25,577,211 9,702,548 3,454,232
2023 56,243,085 12,799,681 4,007,953 690,117 25,652,375 9,633,596 3,459,363
2024 56,424,298 12,867,245 4,003,015 679,539 25,792,573 9,613,965 3,467,962
2025 56,360,934 12,865,292 3,979,977 663,862 25,846,991 9,538,532 3,466,281
Average Annual Growth Rate for 2016-2025
2016-2025 -0.11% -0.13% -0.33% -1.27% 0.45% -0.06% -0.04%

Table A.2 – October 2015 (2015 IRP Update): Forecasted Annual Coincident Peak Load
(Megawatts)
Year Total OR WA CA UT WY ID SE-ID
2016 9,951 2,267 723 144 4,771 1,331 714
2017 9,911 2,227 721 144 4,765 1,340 713
2018 9,980 2,240 720 142 4,817 1,347 714
2019 10,003 2,241 716 141 4,839 1,352 713
2020 10,005 2,243 716 138 4,856 1,346 706
2021 10,006 2,242 714 138 4,859 1,339 714
2022 9,996 2,244 712 137 4,857 1,331 716
2023 9,973 2,246 708 136 4,847 1,320 716
2024 9,959 2,261 715 135 4,830 1,300 719
2025 9,961 2,274 715 130 4,852 1,290 700
Average Annual Growth Rate for 2016-2025
2016-2025 0.01% 0.03% -0.12% -1.17% 0.19% -0.34% -0.22%

PACIFICORP – 2015 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS
76
Tables A.3 and A.4 report the September 2014 (2015 IRP) annual load and coincident peak load
forecasts. These forecast data include reduction in loads for both distributed generation and new
energy efficiency measures (Class 2 DSM), and have not been adjusted for line-losses.

Table A.3 – September 2014 (2015 IRP): Forecasted Annual Load Growth, 2016 through
2025 (Megawatt-hours)
Year Total OR WA CA UT WY ID SE-ID
2016 57,520,472 13,130,326 4,053,343 770,324 24,859,021 10,093,387 3,461,042 1,153,030
2017 56,674,813 13,134,849 4,048,309 767,939 25,090,125 10,164,886 3,468,704
2018 57,004,095 13,146,512 4,053,605 767,434 25,294,074 10,260,988 3,481,482
2019 57,346,137 13,185,105 4,057,536 766,591 25,568,374 10,271,982 3,496,549
2020 57,741,106 13,214,731 4,060,617 764,114 25,830,740 10,359,862 3,511,043
2021 57,818,735 13,189,208 4,040,875 758,757 25,994,725 10,316,336 3,518,834
2022 58,154,197 13,224,659 4,036,682 756,518 26,245,188 10,359,347 3,531,804
2023 58,505,705 13,278,459 4,040,509 755,385 26,541,576 10,341,950 3,547,826
2024 59,070,023 13,358,920 4,057,429 756,514 26,910,407 10,417,356 3,569,396
2025 59,291,219 13,347,506 4,052,651 753,447 27,180,526 10,376,693 3,580,395
Average Annual Growth Rate for 2016-2025
2016-2025 0.34% 0.18% 0.00% -0.25% 1.00% 0.31% 0.38%

Table A.4 – September 2014 (2015 IRP): Forecasted Annual Coincident Peak Load
(Megawatts)
Year Total OR WA CA UT WY ID SE-ID
2016 9,949 2,265 722 148 4,734 1,385 696
2017 9,985 2,269 721 148 4,756 1,393 698
2018 10,044 2,268 725 147 4,800 1,403 700
2019 10,082 2,272 722 147 4,836 1,404 701
2020 10,139 2,281 724 145 4,883 1,412 695
2021 10,189 2,286 723 145 4,921 1,407 706
2022 10,243 2,294 723 146 4,960 1,411 710
2023 10,295 2,301 724 146 5,005 1,408 712
2024 10,357 2,304 725 146 5,054 1,415 714
2025 10,406 2,316 729 143 5,121 1,410 686
Average Annual Growth Rate for 2016-2025
2016-2025 0.50% 0.25% 0.11% -0.33% 0.88% 0.20% -0.16%

Tables A.5 and A.6 show the October 2015 (2015 IRP Update) forecast changes relative to the
September 2014 (2015 IRP) load forecast for loads and coincident system peaks. These forecast
data include reduction in loads for both distributed generation and new energy efficiency
measures (Class 2 DSM), and have not been adjusted for line-losses.

Changes between these two forecasts are due to increases in Class 2 DSM and changes in
economic conditions in the service territory that occurred between September 2014 and October
2015. While economic conditions continue to improve following the most recent recession,
projected load growth in the residential and commercial customer classes is offset by forecasted
increases in utility-sponsored energy efficiency programs. Weakness in commodities markets
drove additional demand decreases in the Wyoming commercial and industrial and Utah
industrial customer classes.
PACIFICORP – 2015 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS

77

Table A.5 – Annual Load Growth Change: October 2015 (2015 IRP Update) Forecast less
September 2014 (2015 IRP) Forecast (Megawatt-hours)
Year Total OR WA CA UT WY ID SE-ID
2016 -600,250 -107,716 46,598 -25,250 -28,761 -501,884 16,762
2017 -1,093,921 -418,934 36,963 -30,237 -181,692 -479,691 -20,330
2018 -1,107,412 -324,483 25,414 -36,571 -244,109 -497,277 -30,386
2019 -1,139,101 -335,854 12,213 -43,925 -283,533 -444,454 -43,548
2020 -1,427,053 -394,770 2,902 -47,730 -372,841 -556,251 -58,362
2021 -1,612,803 -420,149 -1,779 -51,551 -506,760 -563,870 -68,694
2022 -1,921,028 -450,892 -11,504 -56,285 -667,977 -656,798 -77,571
2023 -2,262,620 -478,778 -32,556 -65,268 -889,201 -708,354 -88,463
2024 -2,645,725 -491,675 -54,415 -76,975 -1,117,834 -803,391 -101,434
2025 -2,930,284 -482,215 -72,674 -89,585 -1,333,535 -838,161 -114,114

Table A.6 – Annual Coincidental Peak Growth Change: October 2015 (2015 IRP Update)
Forecast less September 2014 (2015 IRP) Forecast (Megawatts)
Year Total OR WA CA UT WY ID SE-ID
2016 1 2 2 -3 38 -54 18
2017 -74 -42 0 -4 9 -53 15
2018 -64 -29 -5 -5 17 -56 14
2019 -79 -30 -6 -6 3 -52 12
2020 -134 -39 -8 -7 -27 -65 11
2021 -183 -44 -9 -8 -62 -68 8
2022 -247 -50 -11 -9 -103 -80 6
2023 -322 -55 -15 -10 -157 -88 4
2024 -397 -43 -10 -11 -224 -115 5
2025 -445 -43 -13 -14 -269 -120 14

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