20140331Redacted Update.pdf

Y ROCKY MOUNHIN
HP,yy,E*.B.".,
March 31,2014
VA OWRNIGHT DELIWRY
Ted Weston
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 84111
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise, ID 83702
RE: Case No. PAC-E-13-05
In the Matter of the Filing of Roclry Mountain Power of its 2013 Integrated
Resource PIan
Dear Ms. Jewell:
Please find enclosed an original and nine (9) copies, along with a CD of PacifiCorp's 2013
Integrated Resource Plan ("IRP") Update. Confidential information in the 2013 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 pf the non-disclosure agreement that must be executed and submitted prior to obtaining a
copy of the confidential information.
The main changes included in the 2013 IRP Update include:l) updated load forecast with a320 MW average reduction to forecasted system peaks,
2) updated the power and natural gas forward price curve to incorporate lower prices,
3) updated Energy Gateway in-service dates to coincide with revised permitting dates,
generation facility needs and load growth assumptions,
4) updated to incorporate recent EPA rulings on the Wyoming Regional Haze state
implementation plan (SIP) and federal implementation plan (FIP).
With a reduced coincident system peak forecast and lower market prices, the 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 through energy efficiency.
PacifiCorp continues to pursue acceleration of cost-effective energy effrciency consistent with its
2013 IRP Action Plan.
All formal correspondence and regarding this filing should be addressed to:
Daniel E. Solander
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 841I I
Telephone: (80 I ) 220-2963
Fax [phone]
Email : ted.weston@pacifi corp.com
Telephone: [phone]
Fax: [phone]
Email : daniel. solander@racifi com. com
Communications regarding discovery matters, including data requests issued to Rocky Mountain
Power, should be addressed to the following:
By E-mail (preferred):
By regular mail:
datarequest@oacifi corp. com
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,
)#tr r /"",,,"a/duT
Y Jeffref K. Larsen
Vice President, Regulation & Govemment Affairs
Enclostres
cc: Terrie Carlock, Idaho Public Utilities Commission
Rick Sterling, Idaho Public Utilities Commission
Jim Yost, State of Idaho - Governor's Office
Mark Stokes, Idaho Power Company
Nancy Kelly, Western Resource Advocates
Randall Budge, Racine, Olson, Nye, Budge & Bailey
Benjamin J. Otto, Idaho Conservation League
Megan Walseth Decker, Renewable Northwest Project
20r3
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This 2013 Integrated Resource Plan Update Report is based upon the best available information
at the time of preparation. The IKP 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 lessfrequently 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
(s03) 813-s245
[e-mail]
http ://www. pac i fi corp. com
This report is printed on recycled paper
Cover Photos (Top to Bottom):
Transmission: Sigurd to Red Butte Transmission Segment G
Hydroelectric: Lemolo I on North Umpqua River
Wind Turbine: Leaning Juniper I Wind Project
Thermal-Gas: Chehalis Power Plant
Solar: Black Cap Photovoltaic Solar Project
PecrrrConp- 2013 IRP UPDATE TeeI-s Or CoNrsNrs
Taglp oF CONTENTS
TABLE OF CONTENTS
INDEX OF TABLES
INDEX OF FIGURES
EXECUTIVE SUMMARY
CHAPTER 1 _ INTRODUCTION
CHAPTER 2 - PLANNING ENVIRONMENT
BUSTNESS PI-aN DpvslopMENT...... .........................9
Cnolle UNrr 4 UPDATE ......................9
T}D FUTURE OF FEDERAL ENVIRONMENTAL REGULATION AND LEGISLATION ................ IO
Federal Climate Change Legislation ................. l0
Federal Renewable Portfulio Standards ... ......... 11
EPA REGULAToRY UPDATE _ GREENHOUSE GAS EMISSIONS.. ..................... I I
New Source Review / Prevention of Significant Deterioration Q,{SR / PSD) ............ ..... I I
Guidancefor Best Available Control Technologt (BACD ........................ 12
New Source Performance Standards QIISPS) for Greenhouse Gqses .......... .................. 12
EPA REGULAToRY UPDATE-NoN-GREENHOUSE GAS EMISSIoNS.. ...,........13
Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards .............. 13
CleanAir Transport Ru1e............ ....................... 14
Regional Ha2e........... ..................... 14
Mercury and Hazardous Air Pollutants............ ..................... /5
Coal Combustion Residuals................. .............. 16
Water Quality Standards ................ 16
Cooling Water Intake Structures ...........................16
SrarE Cr-ruere CHaNcs REGULATToN ................. 17
Oregon and 11ashington.................. ................... 18
Greenhouse Gas Emission Performance Standards .............. 19
ENERGY GeTsway TRANSMISSION PROGRAM PLAI.INTNG.. ..,,,.19
Energt Gateway Transmission Project Updates....... ............. 20
CHAPTER 3 - RESOURCE NEEDS ASSESSMENT UPDATE
IV
V
7
9
)a
PACIFICoRP _ 20 I3 IRP Upoarg TABLE OF CoureNrs
PacifiCorp West ............ ................. 37
CHAPTER 4 - MODELING ASSUMPTIONS UPDATE. ..................39
GBNSRAT- AssuMprroNs ................. .......................39
NaruRel Gas eNo PowER MARKET PRrcE UPDATES.............. ....................39
Natural Gas Market Prices............ ....................39
Power Market Prices........ ..............40
CansoN DroxDE EMrssroN Cosrs AND CoMpLrANCE.......... .......................42
TRANSMTSSIoN Topolocy................. ....................43
SuppLy-sros RESoURCES ...................43
CHAPTER 5 - PORTFOLIO DEVELOPMENT...... .........45
INTRoDUCTToN ............... ....................45
WrND RESoURcES AND RENEwABLE PoRtrolro STANDARD CouplnNcE ........................................45
Renewable Energt Credit Value ........... .............45
ll'ind Resources................ .............. 46
Renewable Portfulio Standard Compliance. ......47
2013 IRP UPDATE REsouRcB PoRTFoLro .............51
BusrNESs Pr-aN RrsouRCE PoRTFoLro.............. .......................55
SBNSIUvITY STUDIES ARoI.]ND PERFoRMANCE oF RENEWABLE RESoURCES............ .......59
CHAPTER 6 _ ACTION PLAN STATUS UPDATE .........69
APPENDIX A - ADDITIONAL LOAD FORECAST DETAILS
APPENDIX B - COMBINED HEAT AND POWER EXECUTIYE SUMMARY................87
EXECUTTVE SUMMARY .......................87
BACKGRoUND................. ....................87
Forest Thinnings ........89
Market Barriers...... ........................ 89
Air Permitting Requirements ...........90
Lack of Financial Recognition of Environmental Benefits .........90
Cost of Fuel Transportation,.......,........... ...............90
APPENDIX C - ENERGY AIIALYSIS REPORT 9t
PACIFICoRP _ 20 I 3 IR.P UPDATE TABLE OF CoxrsNrs
Hyntington P1ant........... .................97
Potentially Cost-Effective Projects...... ..................97
Systems Requiring Further Research ....................97
Unlikely to be Cost-Effective.............. ..................98
Currant Creek Plant .......................98
Potentially Cost-Effective Projects...... ..................98
Systems Requiring Additional Research ...............98
Unlikely to be Cost-Effective.............. ..................98
Hunter Unit 3 .............99
Potentially Cost-Effective Projects...... ..................99
Systems Requiring Further Research ................... .......................99
Unlikely to be Cost-Effective.............. ..................99
Lakeside P1ant........... ................... 100
Potentially Cost-Effective Projects...... ................100
Systems Requiring Further Research ..................100
Unlikely to be Cost-Effective.............. ................100
Blundell P1ant........... .................... 100
Potentially Cost-Effective Projects...... ................100
Systems Requiring Further Research ...,.,....,.......100
Unlikely to be Cost-Effective.............. ................101
Gadsby P1ant........... ..................... l0l
APPENDIX D - ACCELERATED CLASS 2 DSM DECREMENT STUDY......................103
MoDELTNG APPROACH ..................... 103
Generation Resource Capacity Deferral Bene/it Methodologt ............... 103
CLASS 2 DSM DECREMENT VALUE RESULTS ...... 104
APPENDIX E - IRP TABLE A.7 CORRECTION ............111
CONFIDENTIAL APPENDIX F _ BREAKEYEN ANALYSIS ................1 13
lll
PACIFICoRP _ 20 I3 IRP Upoerg INDEX oF TABLES
INnpx OF TABLES
Table ES.l - Comparison of 2013 IRP Update with 2013 IRP Prefened Portfolio ..........5
Table 3.1 - October 2013 (2013IRP Update): Forecasted Annual Load Growth, 2014 through 2023 (Megawatl-
Table 3.2 - October 2013 (2013IRP Update): Forecasted Annual Coincident Peak Load (Megawatts). ...................24
Table 3.3 - June 2013 (Business Plan): Forecasted Annual Load Growth, 2014 through2023 (Megawatt-hours)....25
Table 3.4 - June 2013 (Business Plan): Forecasted Annual Coincident Peak Load (Megawatts). ........25
Table 3.5 - June 2012 (2013 IRP): Forecasted Annual Load Growth, 2014 through2023 (Megawatt-hours)...........26
Table 3.6 - June 2012 (2013 IRP): Forecasted Annual Coincident Peak Load (Megawatts). ...............26
Table 3.7 - Annual Load Growth Change: October 2013 (2013IRP Update) Forecast less June 2012 (2013 IRP)
Forecast (Megawatt-hours) ............... ...............26
Table 3.8 - Annual Coincidental Peak Growth Change: October 2013 (2013IRP Update) Forecast less June 2012
(2013 IRP) Forecast (Megawatts). ...................27
Table 3.9 - Annual Load Growth Change: June 2013 (Business Plan) Forecast less June 2012 (2013 IRP) Forecast
Table 3.10 - Annual Coincidental Peak Growth Change: June 2013 (Business Plan) Forecast less June 2012 (2013
IRP) Forecast (Megawatts) ........27
Table 3.1 I - Load and Resource Balance, 2013 IRP Update (Megawatts). ............,.......30
Table 3.12 - Load and Resource Balance, Business Plan (Megawatts) .............. ............31
Table 3.13 - Load and Resource Balance, 2013 IRP (Megawatts) ...........32
Table 3.14 - Load and Resource Balance, 2013 IRP Update less 2013 IRP (Megawatts)..........................................33
Table 3.15 -Load and Resource Balance, Business Plan less 2013 IRP (Megawatts) .........................34
Table 4.1 - Updated Cost of Solar Resources, 2013$ - (50 MW AC)............... ..............43
Table 5.1 - Wind Additions, 2013 IRP Preferred Portfolio, Business Plan, 2013 IRP Update... ..........47
Table 5.2 - Renewable Portfolio Standard Targets, Requirements, and Initial Eligible Existing RECs by State for
2013 IRP, Business Plan, and 2013 IRP Update.......... ..........48
Table 5.3 - Comparison of 2013 IRP Update with 2013 IRP Preferred Portfolio....... ..........................52
Table 5.4 -2013 IRP Update Capacity Load and Resource Balance......... .....................53
Table 5.5 -20I3IRP Update, Detail Portfo1io................... .......................54
Table 5.6 - Comparison of Business Plan with 2013 IRP Preferred Portfolio ................56
Table 5.7 -Business Plan Capacity Load and Resource Balance ..............57
Table 5.9 - Peak Contribution of Renewable Resources, sensitivity study............. ........59
Table 5.10-Updated Costs of SolarResources, sensitivity study (50 MW AC)....... ...........................59
Table 5.12 -Portfolio Comparison of Case EG2-C0I and Peak Contribution Sensitivity Study ...............................61
Table 5.13 - Portfolio Comparison of Case EG2-C07 and Solar Cost Sensitivity Study........ ..............64
Table 5.14 -Portfolio Comparison of Case EG2-Cl0 and Solar Cost Sensitivity Study........ ..............65
Table 5. I 5 - Comparison of Risk-Adjusted PVRR between Cases EG2-C07 and the Capacity Contribution
Table 6.1 - IRP Action Plan Status Update.......... ...............70
Table A.l -2013IRP Update Annual Retail Sales Forecast in Megawatt-hours by State..........................................85
Table A.2 - Change in Annual Retail Sales Forecast in Megawatt-hours by State compared to the 2013 IRP ..........85
Table A.3 - System Annual Retail Sales Forecast in Megawatt-hours by Class.....,....... ......................86
Table A.4 - Change in System Annual Retail Sales Forecast in Megawatt-hours by Class Compared to the 2013
Integrated Resource Plan .............. ...................86
Table B.l - PacifiCorp's existing Biomass QF Power Purchase Agreements by State. .......................88
Table B.2 - Woody Biomass Generation on PacifiCorp's System...... ............................88
Table D.l - Nominal Levelized Accelerated Class 2 DSM Avoided Costs (2013-2032) ...................105
Table D.2 - Difference - Nominal Levelized Class 2 DSM Avoided Costs (2013-2032) ..................106
Table D.3 - Annual Nominal Accelerated Class 2 DSM Avoided Costs, 2013-2032.... .....................107
Table D.4 - Annual Nominal Accelerated Class 2 DSM Avoided Costs, 2013-2032 (continued)............................108
Table D.5 - Portfolio Difference - Appendix N (Non-Accelerated DSM) ...................109
Table D.6 - Portfolio Difference - Non-Accelerated DSM .................... I l0
lv
PACIFICoRP_2013 IRP UpoArr INDEX oF TABLES AND FIGURES
Table E.l - Jurisdictional Contribution to Coincident Peak 1997 through 2012............. ...................1I I
Confidential Table F.l - Hunter I APR Emission Control PVRR(d) Analysis Results, 2026 SCR ......................... I 16
Confidential Table F.2 - Bridger 3 and 4 CPCN Emission Control PVRR(d) Analysis Results ..,.....1 l9
Confidential Table F.3 -Naughton 3 CPCN Emission Control PVRR(d) Analysis Results.......... .....120
INoex oF FIGURES
Figure ES.2 - Power and Natural Gas Price Comparisons. .......---...............2
Figure ES.3 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013 IRP Update ....................4
Figure 3.1 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013 IRP Update .....................29
Figure 3.2 -2013IRP Update, System Capacity Position Trend............ .....................'..35
Figure 3.3 -20|3IRP Update, West Capacity Position Trend........... ............................36
Figure 3.4 - 2013 IRP Update, East Capacity Position Trend............ .......36
Figure 4.1 - Henry Hub Natural Gas Prices (Nominal)..... ........................40
Figure 4.2 - Average Annual Flat Palo Verde Electricity Prices ..............41
Figure 4.3 - Average Annual Heavy Load Hour Palo Verde Electricity Prices..... .........41
Figure 4.4 - Average Annual Flat Mid-Columbia Electricity Prices....... ..........-.............42
Figure 4.5 - Average Annual Heavy Load Hour Mid-Columbia Electricity Prices........... ...---.............42
Figure 5.1 -20I3IRP Update RPS Compliance Position.. .......................49
Figure 5.2 - Business Plan RPS Compliance Position ........50
Figure 5.3 -20I3IRP RPS Compliance Position ...............50
Figure F.l - Natural Gas Price Forecast for 2013 IRP Update... .............1l5
Confidential Figure F.2 - Relationship between Gas Prices and the PVRR(d) (Benefit/Cost of the Baghouse and
LNB Investments at Hunter Unit I ........... .....117
Confidential Figure F.3 - Relationship between CO2 Prices and the PVRR(d) (Benefit)/Cost of the SCR Investments
Confidential Figure F.4 - Relationship between Gas Prices and the PVRR(d) (Benefit/Cost of the SCR Investments
at Jim Bridger Units 3 & 4 ............... ..............1l9
Confidential Figure F.5 - Relationship between CO2 Prices and the PVRR(d) (Benefit)/Cost of the SCR Investments
at Jim Bridger Units 3 &.4............ .................120
Confidential Figure F.6 - Relationship between Gas Prices and the PVRR(d) (Benefit/Cost of the SCR and
Baghouse Investments at Naughton Unit 3........... ...............121
Confidential Figure F.7 - Relationship between CO2 Prices and the PVRR(d) (Benefit/Cost of the SCR and
Baghouse Investments at Naughton Unit 3 ........... ...............122
PACIFICoRP _2013 IRP UPDATE EXECUTIVE SUN,IN,IARY
ExpCUTIVE SUVTVTARY
PacifiCorp submitted its 2013 Integrated Resource Plan (2013 IRP) to state regulatory
commissions in April 2013. That plan provides a framework for future actions that PacifiCorp
will take to provide reliable, reasonable-cost service with manageable risks for customers. This
2013 IRP Update describes resource planning and procurement activities that occurred
subsequent to the filing of the 2013 IRP, presents an updated resource needs assessment, an
updated resource portfolio consistent with changes in the planning environment, and provides an
IRP Action Plan status update. In presenting the updated resource needs assessment and updated
resource portfolio, PacifiCorp shows changes relative to the 2013 IRP and relative to
PacifiCorp's fall 2013 ten-year business plan, which covers the 2014 to 2023 planning horizon.
ln this update PacifiCorp also addresses recommendations and requirements identified by its
state regulatory commissions during the 2013 [RP acknowledgement process.
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 2013 IRP Update:
. As shown in Figure ES.l the Company's most recent coincident system peak load
forecast is down relative to the 2013 IRP, and the intervening fall 2013 ten-year business
plan. The coincident peak forecast decreased through the planning period. Driving the
reduction in peak load are a reduced residential class load forecast relative to the 2013
IRP due to increased energy efficiency and continued phase in of the Energy
Independence and Security Act federal lighting standards. [n addition, recent history has
seen low growth in the peak, which in turn reduces the long-term forecast peak load
growth expectations. With a reduced coincident system peak forecast, the need for new
resources is pushed further out in the planning horizon as compared to the 2013 IRP. In
the 201 3 IRP Update resource portfolio, a new thermal resource is not neede d until 2027 .
Figure ES.l - Load Forecast Comparison
12,000
I 1,500
I t,000
t0,500
10,000
9,500
9,000
Forecasted Annual System Coincident Peak (MW)
20t6 2017 2018 20t9 2020 2021
+.2013 IRP *Business Plan +-20|3IRP Updste
20152014
PACIFICoRP _ 2OI3 IRP UPDATE ExECUTTvE Suvnraanv
o Figure ES.2 shows that forecast natural gas and energy prices have declined from those
assumed in the 2013 IRP and the fall 2013 ten-year business plan. 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
Eenty Eub Nrturrl Grs Prlccs
s8
r/
!E-s6-a
It"z
04
lli
!h9FOO9-dO8888R88R88
+Bod!6Pte (ScD2013) +2013 IRP(S@2O!2)..,il-2013 IRPUDAI (Dc
80
70
f,a-ar50.IIZn
30
20
Avenge of Mld C/Pdo Verde Fht Power Prlcec
thsFaOe-dO888RRRR8R8
+BDdo6 Pt& (S.! 2013) +2013 IRP (S.p 2012) +2013 IRP UpAb (Dc 2013)
o With a reduced coincident system peak forecast and lower market prices, the 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
through energy efficiency. PacifiCorp continues to pursue acceleration of cost-effective
energy efficiency consistent with its 2013 IRP Action Plan.
The Energy Gateway transmission project continues to play an important role in the
Company's commitment to provide safe, reliable, reasonably priced electricity to meet
the needs of our customers. Several Energy Gateway developments have occurred since
the Company's 2013 IRP was filed, including reaching construction and permitting
milestones, adjusting in-service dates for future segments, and developing activities on
joint-development projects. Accordingly, in-service dates have been updated relative to
those assumed for the 2013IRP. These date adjustments coincide with revised permiuing
dates, generation facility needs and updated load growth assumptions.
The Environmental Protection Agency (EPA) partially approved and partially rejected the
Wyoming Regional Haze state implementation plan (SIP) and issued a federal
implementation plan (FIP) to cover those areas of SIP disapproval in January 2014. This
action established compliance requirements and schedules for specific Wyoming coal
units under the Regional Haze program, including a requirement for installation of
selective catalytic reduction (SCR) at Wyodak by early March 2019. For purposes of the
2013 IRP Update, the resource needs assessment and updated resource portfolio reflects
the continued operation of Wyodak as a coal-fired generating asset through the planning
PACIFICORP _ 20 I 3 IRP UPDATE Executrve SutwteRv
horizon. PacifiCorp will be analyzing the Wyodak SCR investment and alternatives to
this investment in its 2015 IRP.
In EPA's action on the Wyoming SIP in January 2014, it explicitly stated its support for
the natural gas conversion of Naughton Unit 3, but noted that because the Wyoming SIP
documentation did not include a natural gas conversion option, EPA has no basis to
disapprove the Wyoming SIP requirement for low NOx burners/overfired air, SCR, and
baghouse, with its authority and obligation to take action on the SIP as submitted by the
state. PacifiCorp has since been working with the state of Wyoming Division of Air
Quality to identiff amendments necessary to support the Naughton Unit 3 natural gas
conversion and to clearly document the compliance requirements and timeline for
implementation of the project under the RegionalHaze program. In the 2013 IRP Update,
the resource needs assessment and updated resource portfolio continues to reflect a gas
conversion completed by summer 2015.
Since 2010, no significant activity has occurred with respect to the development of a
federal renewable portfolio standard (RPS). In addition, current political environments
are shifting focus from items such as the extension of federal incentives for renewables
and portfolio standards to EPA's development of greenhouse gas standards. Accordingly,
the 2013 IRP Update assumes no federal RPS requirement over the course of the
planning horizon. With the removal of the federal RPS assumptions requirements, the
updated resource portfolio shows a reduced need for renewable resources required solely
to meet state RPS obligations in2024 and2025.
After PacifiCorp filed the 2013 IRP, President Obama issued a Presidential Memorandum
in June 2013 directing EPA to issue standards, regulations, or guidelines, as appropriate
that address greenhouse gas emissions from modified, reconstructed, and existing power
plants. The proposed standards, regulations, or guidelines are to be issued by June l,
2014, finalized by June 1,2015, with implementation of regulations as proposed in SIPs
required by June 30,2016. EPA would then review the implementation plan proposed by
each state, and the effective compliance dates for these standards, regulations, or
guidelines would become applicable sometime thereafter. Absent information on how
EPA intends to proceed with its rule-making process, and without any information on
how individual states will propose to implement those regulations through a SIP, there is
currently no means to develop a specific CO2 price assumption that accurately reflects
potential CO2 regulation. PacifiCorp's review of current third-party CO2 price forecasts
shows that despite issuance of the Presidential Memorandum, these forecasters have not
materially altered either their assumed COz start date or price level. In the 2013 IRP
Update, PacifiCorp continues to assume a COz price signal beginning 2022 at $16/ton
escalating at three percent plus inflation thereafter, and expects to update its COz policy
assumptions and scenarios in the 2015 IRP, taking into consideration the proposed
standard, regulation, or guidelines expected to be issued by EPA later this year.
Figure ES.3 shows the 2013 tRP Update resource need, prior to acquiring any new resources,
alongside the resource need from the 2013 IRP and the fall2013 ten-year business plan. Overall,
PACIFICoRP - 2OI 3 IRP UpoIre E)GCI.].ITVE SUT.tr\,IARY
the forecasted need has declined with the most recent needs assessment. Primarily driven by an
updated load forecast, the most recent resource needs assessment shows an average reduction in
peak resource need of approxim ately 320 megawatts (MUD as compared to the 20 I 3 IRP for the
period 2014-2023. Relative to the fall 2013 ten-year business plan, the most recent projection of
resource need is reduced by approximately 135 MW over the same period.
Figure ES.3 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013
IRP Update
(Lm0)
a
$ooolT
Gm)
(4s)
(3,m)
r 2013 IRP
t BuCnc.s Ph[
Table ES.l reports the 2013 IRP Update resource portfolio and a comparison of portfolio
changes relative to the 2013 IRP Preferred Portfolio.l The table shows the resource mix targeted
to fill the resource need summarized above with resource capacities at time of coincident system
peak reported in the years for which the resources are available to meet summer peak loads. As
compared to the 2013 IRP Preferred Portfolio, the changes in resource mix for the 2014-2023
planning period are minor. Relative to the 2013 IRP Preferred Portfolio, which did not include
any significant new thermal resources in the front ten years of the planning horizon, the updated
resource portfolio shows a reduction in front office transactions (FOTs), consistent with a
reduced resource need. As was the case in the 2013 IRP Preferred Portfolio, PacifiCorp
continues to plan to meet its customers' needs largely through acquisition of cost effective
energy efficiency resources and FOTs over the next ten years. Considering the relatively small
changes in energy efficiency resources between the 2013 IRP and 2013 IRP Update portfolios,
PacifiCorp has not modified its 2013 IRP Action Plan and continues to target accelerated energy
efficiency savings.
I A comparison ofthe portfolio changes relative to the fall 2013 ten-year business plan is presented in Chapter 5.
PecnrConp - 2013 IRP Uppers E)ccunvE Sumaanv
Table ES.l - Comparison of 2013 IRP Update with 2013 IRP Preferred Portfolio
FrcIi Ofice Tretbre h rcmme total ue lo-yer awnge. r
Less 2013 IRP Prtferrtd Portfolio
Frcrn Oftr Tmrctiru h resuce total ue I Gyer amge. t
PacifiCorp has not modified its 2013 IRP Action Plan, which remains consistent with the
updated resource needs assessment and resource portfolio as summarized above. Chapter 6 of
this IRP Update provides a status update of PacifiCorp's 2013 IRP Action Plan action items. A
variety of action items have been completed and are noted as such, while other action items will
continue forward into the 2015 IRP process.
PACIFICoRP _ 2OI3 IRP UPDATE CHAPTER I . INTRoDUCTION
Cueprpn 1 - INTnoDUCTIoN
This 2013 Integrated Resource Plan Update (2013 IRP Update) describes resource planning
activities that occurred subsequent to the filing of the 2013 Integrated Resource Plan (2013 tRP)
in April 2013, presents an updated resource needs assessment, an updated resource portfolio
consistent with changes in the planning environment, and provides an IRP Action Plan status
update. In presenting the updated resource needs assessment and updated resource portfolio,
PacifiCorp shows changes relative to the 2013 IRP and relative to PacifiCorp's fall 2013 ten-year
business plan (Business Plan), which covers the 2014 to 2023 planning horizon. In this update
PacifiCorp also addresses recommendations and requirements identified by its state regulatory
commissions during the 2013 IRP acknowledgement process.
In support of its business planning process, PacifiCorp refined the 2013 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 PacifiCorp business units (PacifiCorp Energy, Pacific Power, and
Rocky Mountain Power). 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 2013 IRP Preferred Portfolio served as the primary basis in establishing the resource
portfolio for the Business Plan, and as summarized herein, differences between the two resource
portfolios are minor.
A similar process has been completed to develop the resource needs assessment and resource
portfolio for this 2013 IRP Update, which considers updates to forecasted loads, resources,
market prices, and other model inputs since the intervening Business Plan resource portfolio was
developed. For purposes of assessing an updated resource needs assessment and updated
resource portfolio in this 2013 IRP Update, PacifiCorp has not completed new financial analysis
of pending environmental compliance decisions applicable to specific coal units on its system.
PacifiCorp will analyze specific environmental compliance decisions applicable to Cholla Unit 4,
Wyodak, and Dave Johnston Unit 3 in its 2015 IRP, with the full engagement of PacifiCorp's
diverse stakeholder group. PacifiCorp will also provide an update on its efforts working with the
Wyoming Division of Air Quality to identify amendments necessary to support the Naughton
Unit 3 natural gas conversion and to clearly document the compliance requirements and timeline
for implementation of the natural gas conversion under the RegionalHaze program. In this 2013
IRP Update, PacifiCorp continues to assume the Naughton Unit 3 natural gas conversion is
completed by summer 2015.
The 2013 IRP Update also addresses recommendations and requirements identified by its state
regulatory commissions during the 2013 acknowledgement process. This includes presentation
of solar resource modeling sensitivities developed in response to a request by the Public Service
Commission of Utah (PSCU) of and analysis of how CO2 price and natural gas price
assumptions affect the analysis of environmental compliance decisions for specific coal units as
requested by the Washington Utilities and Transportation Commission.
This report first describes the current planning environment, load updates, resource updates,
emissions/climate change regulatory outlook, and Energy Gateway transmission planning and
PACIFICoRP - 2OI3 IRP Upmrr Cueprsn I - INrnooucrron
project completion forecast (Chapter 2). Next, Chapters 3 and 4 describe the changes to key
inputs and assumptions relative to those used for the 2013lRP. The updated resource portfolio is
then presented along with a status update on the 2013 IRP Action Plan (Chapters 5 and 6,
respectively).
Appendices include the following:
. Appendix A - Additional Load Forecast Details. Appendix B - Executive Summary of the CHP Study. Appendix C - Energy Analysis Report. Appendix D - Accelerated DSM Decrement Study. Appendix E - Correction to 2013 IRP Table A.7o Redacted Appendix F - Breakeven Analysis for Select Coal-Fired Plants
PACTFICoRP - 20 13 IRP UpNErg CHAPTER 2 - PLANNTNG ENVIRONMENT
CHapTER 2 _ PTEUNING ENVINONMENT
The 2013 IRP Preferred Portfolio served as the basis for the resource assumptions used in
PacifiCorp's fall 2013 ten-year business plan @usiness Plan), which covers the 2014 to 2023
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. As it relates to PacifrCorp's resource plan, differences
between the 2013 IRP Prefened Portfolio and the Business Plan portfolio are minor and
consistent with an updated load forecast. The Business Plan portfolio also considers updated
assumptions for the Energy Gateway transmission project, which continues to play an important
role in the Company's commitment to provide safe, reliable, reasonably priced elqctricity to meet
the needs of our customers. Several Energy Gateway developments have occurred since the
Company's 2013 IRP was filed, including reaching construction and permitting milestones,
adjusting in-service dates for future segments, and developing activities on joint-development
projects. Accordingly, in-service dates have been updated relative to those assumed for the 2013
IRP. These date adjustments coincide with generation facility needs and load growth
assumptions.
ln March 201I, the state of Arizona submitted its RegionalHaze state implementation plan (SIP)
to the Environmental Protection Agency (EPA) for review. The SIP requires currently installed
low NOx burners (LNB) as best available retrofit technology (BART) for NOx emissions at
Cholla Unit 4. By final rule dated December 5,2012, EPA disapproved portions of the Arizona
Regional Haze SIP and issued a federal implementation plan (FIP). The FIP requires, among
other things, installation of selective catalytic reduction (SCR) on Cholla Unit 4 by January 4,
2018. The FIP also institutes an averaged NOx emissions rate of 0.055 lbA,tMBtu for Cholla
Units 2, 3 and 4. In January and February 2013, PacifiCorp, the state of Arizona and other
Arizona utilities filed separate appeals of EPA's FIP with the U.S. Ninth Circuit Court of
Appeals. In February 2013, PacifiCorp and other Arizona utilities filed petitions for
reconsideration at the EPA and requests for administrative stay of the FIP until judicial appeals
are completed. In March 2013, PacifiCorp and other Aizona utilities filed motions for judicial
stay of the FIP with the U.S. Ninth Circuit Court of Appeals until the appeals are complete.
On April 3,2013, the court consolidated the various appeals into a single docket before a single
judicial panel. On April 9, 2013, EPA granted various petitions for reconsideration for the
averaged NOx emissions rate only, but has taken no further action to date. Although EPA may
propose a new NOx rate at some time in the future, which will undergo public comment, it is not
under any timing requirement to do so. EPA did not address the various requests for
administrative stay in its April 9,2013 action.
PaCrICOnp - 20 13 IRP UPDATE CHAPTER 2 - PLA}{NTNG ENVIRoNMENT
On April 23,2013, the court set the following case schedule:
o June 2013 - briefing on motions for judicial stay to be completedo January 2014 - briefing on the merits of appeals to be completed
On September 9, 2013, the court denied the motions for stay. The court is now expected to issue
a final decision on the appeals in 2015. However, there are no mandatory dates by which the
court must issue decisions.
With the denial of requests for administrative stay and judicial stay, the January 4, 2018
compliance deadline for installing SCR at Cholla Unit 4 remains in place. PacifiCorp continues
to work closely with the state of Arizona and the other Arizona utilities in connection with the
now consolidated appeals. Various environmental groups have intervened in the appeals in
support of EPA's FIP.
With the ongoing activities outlined above, PacifiCorp continues to explore potential alternatives
to the installation of SCR at Cholla Unit 4, and consequently, the Company has not finalized an
analysis of compliance alternatives nor made a decision on this pending investment. The
Company intends to finalize its analysis in 2014 and will file its analysis in a future IRP filing.2
For purposes of the 2013 IRP Update, PacifiCorp assumes Cholla Unit 4 continues to provide
both system capacity and energy through the planning horizon.
PacifiCorp faces a continuously changing environment with regard to electricity plant emission
regulations. Although the exact nature of these changes remains uncertain, they are expected to
impact the cost of future resource alternatives and the cost of existing resources in the
Company's generation portfolio. PacifiCorp monitors these regulations to determine the potential
impact on its generating assets. PacifiCorp also participates in the rulemaking process by filing
comments on various proposals, participating in scheduled hearings, and providing assessment of
such proposals.
Federal Climate Change Legislation
PacifiCorp continues to evaluate the potential impact of climate change legislation at the federal
level. The impact of a given legislative proposal can vary significantly depending on selection of
key design criteria (i.e., level of emissions cap, rate of decline of the cap, the use of carbon
offsets, allowance allocation methodology, the use of safety valves, etc.) and macro-economic
assumptions (i.e., electricity load growth, fuel price impacts - especially natural gas, commodity
prices, new technologies, etc.).
To date, no federal legislative climate change proposal has successfully been passed by both the
U.S. House of Representatives and the U.S. Senate for consideration by the President. The two
most prominent legislative proposals introduced for attempted passage through Congress have
' The Public Utility Commission of Oregon's draft 2013 IRP acknowledgement order outlines a requirement for
PacifiCorp to make a supplemental IRP filing on Cholla Unit 4 in 2014. With the appropriate protections in place,
PacifiCorp intends to summarize the information from this filing for its broader stakeholder group during the 2015
IRP public process and summarize this same analysis in a confidential volume of the 2015 IRP.
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P,6\CFTCORP - 20 13 IRP UPDATE CH.npTsn 2 _ PLANNTNG ENVIRoNMENT
been the Waxman-Markey bill in 2009 and the Kerry-Lieberrnan bill in 2010; neither measure
was able to accumulate enough support to pass.
The l13ft Congress was challenged by the President to pursue a bipartisan, market-based
solution to climate change. The President stated that if Congress did not act soon, then he would
direct his Cabinet to implement executive action to reduce greenhouse gas (GHG) emissions. To
date, such bipartisan action has not occurred. ln 2013, a bill was introduced by the Energy &
Power Subcommittee Chairman Whitfield (R-KY) called the Electricity Security and
Affordability Act, which provides direction to EPA regarding the establishment of standards for
GHG emissions from fossil-fueled generating facilities. This bill is expected to pass the House
of Representatives but not the Senate.
On June 25,2013, President Obama directed the EPA to complete GHG standards for both new
and existing power plants. With regard to existing sources, EPA was directed to issue
"standards, regulations, or guidelines, as appropriate" that address GHG emissions from
modified, reconstructed, and existing power plants.3 The proposed standards, regulations, or
guidelines are to be issued by June 1,2014, finalized by June 1,2015, with implementation of
regulations as proposed in state implementation plans required by June 30,2016. EPA would
then review the implementation plan proposed by each state. The June 25, 2013 directive did not
include detail with respect to how EPA will approach GHG regulation or what the resulting
standards, regulations, or guidelines will ultimately entail.
Federal Renewable Portfolio Standards
Since 2010, no significant activity has occurred with respect to the development of a federal
renewable portfolio standard (RPS). In addition, current political environments are shifting focus
from items such as the extension of federal incentives for renewables and portfolio standards to
EPA's development of greenhouse gas standards. Accordingly, the 2013 IRP Update assumes no
federal RPS requirement over the course of the planning horizon.
New Source Review / Prevention of Significant Deterioration (NSR / PSD)
On May 13, 2010, the EPA issued a final rule that addresses GHG emissions from stationary
sources under the Clean Air Act (CAA) permitting programs, known as the "tailoring" rule. This
final rule sets thresholds for GHG emissions that define when permits under the New Source
Review (NSR) / Prevention of Significant Deterioration (PSD) and Title V Operating Permit
programs are required for new and existing industrial facilities. This final rule "tailors" the
requirements of these CAA permitting programs to limit which facilities will be required to
obtain PSD and Title V permits. The rule also establishes a schedule that will initially focus
CAA permitting programs on the largest sources with the most CAA permiuing experience.
Finally, the rule expands to cover the largest sources of GHGs that may not have been previously
covered by the CAA for other pollutants.
3 Presidential Memorandum - Power Sector Carbon Pollution Standards, June 25, 2013.
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PecrrConp - 2013 IRP Upners CHAPTER 2 - PLANNING ENVIRONMENT
Guidance for Best Available Control Technology (BACT)
On November 10, 2010, the EPA published a set of guidance documents for the tailoring rule to
assist state permitting authorities and industry permitting applicants with the Clean Air Act PSD
and Title V permitting for sources of GHGs. Among these publications was a general guidance
document entitled "PSD and Title V Permitting Guidance for Greenhouse Gases," which
included a set of appendices with illustrative examples of Best Available Control Technology
(BACT) determinations for different types of facilities, which are a requirement for PSD
permitting. The EPA also provided white papers with technical information conceming available
and emerging GHG emission control technologies and practices, without explicitly defining
BACT for a particular sector. In addition, the EPA has created a "Greenhouse Gas Emission
Strategies Database," which contains information on strategies and control technologies for GHG
mitigation for two industrial sectors: electricity generation and cement production.
The guidance does not identiff what constitutes BACT for specific types of facilities, and does
not establish absolute limits on a permitting authority's discretion when issuing a BACT
determination for GHGs. Instead, the guidance emphasizes that the five-step top-down BACT
process for criteria pollutants under the CAA generally remains the same for GHGs. While the
guidance does not prescribe BACT in any area, it does state that GHG reduction options that
improve energy effrciency will be BACT in many or most instances because they cost less than
other environmental controls (and may even reduce costs) and because other add-on controls for
GHGs are limited in number and are at differing stages of development or commercial
availability. Utilities have remained very concerned about the NSR implications associated with
the tailoring rule (the requirement to conduct BACT analysis for GHG emissions) because of
great uncertainty as to what constitutes a triggering event and what constitutes BACT for GHG
emissions.
New Source Performance Standards (NSPS) for Greenhouse Gases
On December 23,2010, in a settlement reached with several states and environmental groups in
New York v. EPA, the EPA agreed to promulgate emissions standards covering GHGs from both
new and existing electric generating units under Section 1l I of the CAA by July 26,2011 and
issue final regulations by May 26,2012.4 NSPS are established under the CAA for certain
industrial sources of emissions determined to endanger public health and welfare and must be
reviewed every eight years. While NSPS were intended to focus on new and modified sources
and effectively establish the floor for determining what constitutes BACT, the emission
guidelines will apply to existing sources as well. In September2013, the EPA issued a revised
NSPS proposal for new fossil-fueled generating facilities and withdrew its April 2012 NSPS
proposal. The new proposal would limit emissions of carbon dioxide to 1,000 pounds per
megawatt hour (MWh) for large natural gas plants and 1,100 pounds per MWh for smaller
natural gas plants. The revised proposal continues to largely exempt simple cycle combustion
turbines from meeting the standards. The standard for new coal units would be set based on the
availability of partial carbon capture and sequestration technology. The public comment period
will close in May 2014 and, a final rule is expected in June 2014.
4 The deadlines for EPA to take proposed and final actions have since been extended. EPA also entered into a
similar settlement the same day to address GHG emissions from refineries with proposed regulations by December
l5,20ll and final regulations by November 15,2012.
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PACIFICoRP _ 2OI3 IRP UPDATE CHAPTER 2 _ PLANNING ENVIRoNMENT
In January 2014, Senate Minority Leader Mitch McConnell (R-KY) filed a resolution of
disapproval in an attempt to block EPA's NSPS for GHG emissions from new fossil-fueled
power plants. A vote has not yet been scheduled on this resolution. In addition, in January 2014
the State of Nebraska sued the EPA in federal district court arguing that the rule's requirements
for carbon capture and sequestration wrongfully rely on federally funded and unviable control
technology. In support of this claim Nebraska relies on a provision of the Energy Policy Act of
2005 which restricts reliance on technology developed with federal assistance when setting
performance standards.
The EPA is also under a consent decree obligation to establish GHG NSPS for modified and
existing sources. Consistent with the presidential directive mentioned above, EPA has indicated
that it will issue a proposed rule for existing sources in June 2014.The proposed rule to be issued
by the EPA for modified and existing sources is to be used by states to develop plans for
reducing emissions and/or emissions intensity and may include targets based on demonstrated
controls, efficiency related emission reductions, or even beyond the fence-line compliance
alternatives intended to meet best system of emissions reduction parameters. States are expected
to be required to submit their implementation plans to the EPA by June 2016 pursuant to the
President's direction. States are expected to have the ability to apply less sffingent standards or
longer compliance schedules if they demonstrate that following the federal guidelines is
unreasonably cost-prohibitive, physically impossible, or that there are other factors that
reasonably preclude meeting the guidelines. States may also impose more stringent standards or
shorter compliance schedules.
Several categories of EPA regulations for non-GHG emissions are discussed below:
Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards
The CAA requires the EPA to set National Ambient Air Quality Standards (NAAQS) for certain
pollutants considered harmful to public health and the environment. For a given NAAQS, the
EPA and/or a state identifies various control measures that once implemented are meant to
achieve an air quality standard for a certain pollutant, with each standard rigorously vetted by the
scientific community, industry, public interest groups, and the general public.
Particulate matter (PM), sulfur dioxide (SOz), ozone (O3), nitrogen dioxide (NOz), carbon
monoxide (CO), and lead are often grouped together because under the CAA, 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 CAA, they are regulated
differently from other types of emissions, such as hazardous air pollutants and GHG.
Within the past few years, the EPA established new standards for particulate matter, sulfur
dioxide, and nitrogen dioxide. The EPA is currently tasked with reviewing ozone standards, as
well.
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PACIFICoRP _ 20I3 IRP UpoarE CHAPTER 2 -PLANNTNG ENVIRoNMENT
Clean Air Transport Rule
In July 2009, EPA proposed its Clean Air Transport Rule (Transport Rule), which would require
new reductions in SOz and nitrogen oxide (NOa) emissions from large stationary sources,
including power plants, located in 31 states and the District of Columbia beginning in 2012. The
Transport Rule was intended to help states attain NAAQS set in 1997 for ozone and fine
particulate matter emissions. The rule replaced the Bush administration's Clean Air Interstate
Rule (CAIR), which was vacated in July 2008 and rescinded by a federal court because it failed
to effectively address pollution from upwind states that is hampering efforts by downwind states
to comply with ozone and PM NAAQS. While the rule was finalized as the Cross-State Air
Pollution Rule (CSAPR) in July 2011, litigation in the D.C. Circuit Court of Appeals resulted in
a stay on the implementation of the CSAPR in December 2011. Ultimately, in August 2012,the
D.C. Circuit Court of Appeals vacated the CSAPR in a 2-l decision after it determined the rule
exceeded the EPA's statutory authority. The EPA sought a full review of the CSAPR ruling by
the entire D.C. Circuit; however, in January 2013, the court denied the request. In June 2013, a
petition for certiorari filed by EPA was granted by the U.S. Supreme Court, meaning until the
Supreme Court issues a decision or a replacement rule is adopted and implemented, the CAIR
remains in place.
PacifiCorp does not own generating units in states identified by the CAIR or CSAPR and thus
will not be directly impacted; however, the Company intends to monitor amendments to these
rules closely in the event that the scope of a replacement rule extends the geographic scope of
impacted states.
Regional Haze
EPA's rule to address Regional Haze visibility concerns will drive additional NO* reductions
particularly from facilities operating in the Western United States, including the states of Utah
and Wyoming where PacifiCorp operates generating units, in 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 nonetheless subject to the Regional Haze
Rule.
On June 15,2005, EPA issued final amendments to its July 1999 RegionalHaze rule. These
amendments apply to the provisions of the Regional Haze rule that require emission controls
known as BART, for industrial facilities meeting certain regulatory criteria that with emissions
that have the potential to impact visibility. These pollutants include PMz.s, NOx, SOz, certain
volatile organic compounds, and ammonia. The 2005 amendments included final guidelines,
known as BART guidelines, for states to use in determining which facilities must install controls
and the type of controls the facilities must use. States were given until December 2007 to
develop their implementation plans, in which states were responsible for identifying the facilities
that would have to reduce emissions under BART as well as establishing BART emissions limits
for those facilities.
The state of Utah issued a regional haze state implementation plan (SIP) requiring the installation
of SOz, NO* and particulate matter (PM) controls on Hunter Units I and2 and Huntington UnitsI and2.In December 2012, the EPA approved the SOz portion of the Utah Regional Haze SIP
and disapproved the NO* and PM portions. Certain groups have appealed the EPA's approval of
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PecruConp - 2OI3 IRP UPDATE CHAPTER 2 _PLANNING ENVIRONMENT
the SOz SIP. PacifiCorp and the state of Utah appealed EPA's disapproval of the NO* and PM
SIP. In addition, and separate from the EPA's approval process and related litigation, the Utah
Division of Air Quality is undertaking an additional BART analysis for each of Hunter Units I
and2 and Huntington Units I and2, which will be provided to the EPA as a supplement to the
existing Utah SIP. It is unknown whether and how the Utah Division of Air Quality's
supplemental analysis will impact the EPA's approval and disapproval of the existing SIP.
The state of Wyoming issued two regional haze SIPs requiring the installation of SOz, NO, and
PM controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA
approved the SOz SIP in December 2012, but initially proposed to disapprove portions of the
NO* and PM SIP and instead issue a FIP. However, in 2013, the EPA issued a re-proposal of a
NO* and PM FIP which included substantial changes to the control equipment required in the
original proposal. On January 10,2014, the EPA issued a final action which largely approved the
original Wyoming SIP. Ultimately, EPA's final determination requires installation of the
following NO* and PM controls at PacifiCorp facilities: SCR equipment and a baghouse at
Naughton Unit 3 by December 31, 2014; SCR equipment at Jim Bridger Unit 3 by December 31,
2015; SCR equipment at Jim Bridger Unit 4 by December 31, 2016; SCR equipment at Jim
Bridger Unit I by December 31, 2022; SCR equipment at Jim Bridger Unit 2 by December 31,
2021; SCR within five years or a commitmentto shut down in 2027 at Dave Johnston Unit 3;
and SCR at Wyodak within 5 years. With respect to Naughton Unit 3, EPA indicated its 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 submiued the requisite SIP
amendment. The EPA action became final on March 3,2014.In the meantime, certain groups
have appealed the EPA's approval of the Wyoming SOz SIP which, consistent with the Utah SO2
SIP, required emission reductions of SOz to be enforced through a three-state milestone and
backstop trading program. EPA's final action on the Wyoming NO* and PM SIP may also be
appealed.
The state of Arizona issued a Regional Haze SIP requiring, among other things, the installation
of SO2, NO* and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by
Arizona Public Service. The EPA approved in part, and disapproved in part, the Arizona SIP and
issued a FIP for the disapproved portions. PacifiCorp filed an appeal in the Ninth Circuit Court
of Appeals regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of
Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it
relates to their interests.
Mercury and Htzardous Air Pollutants
In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to permanently limit and
reduce mercury emissions from coal-fired power plants under a market-based cap-and-trade
program. However, the CAMR was vacated in February 2008, with the court finding the mercury
rules inconsistent with the stipulations of Section I l2 of the CAA.
The vacated CAMR was replaced by EPA with the more extensive Mercury and Air Toxics
Standards (MATS) with an effective date of April 16, 2012. The MATS rule requires that new
and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other
non-mercury hazardous air pollutants. Existing sources are required to comply with the new
standards by April 16,2015. tndividual sources may be granted upto one additional year, atthe
l5
PACIFICORP - 20 13 IRP UPDATE CHaprsn 2 - PLANNING ENvIRoNMENT
discretion of the Title V permitting authority, to complete installation of controls or for
transmission system reliability reasons. While the final MATS requirements continue to be
reviewed by PacifiCorp, the Company believes its emission reduction projects completed to date
or currently permitted or planned for installation, including the scrubbers, baghouses and
electrostatic precipitators required under other EPA requirements, are consistent with achieving
the MATS requirements and will support PacifiCorp's ability to comply with the final standards
for acid gases and non-mercury metallic hazardous air pollutants. PacifiCorp will be required to
take additional actions to reduce mercury emissions through the installation of controls or use of
sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the
standards.
PacifiCorp continues to plan for retirement of its Carbon facility in early 2015 as the least-cost
alternative to comply with MATS and other environmental regulations. Implementation of the
transmission system modifications necessary to maintain system reliability following
disconnection of the Carbon facility generators from the grid are underway.
CoaI Combustion Residuals
Coal Combustion Residuals (CCRs), including coal ash, are the byproducts from the combustion
of coal in power plants. CCRs are currently considered exempt wastes under an amendment to
the Resource Conservation and Recovery Act (RCRA); however, EPA proposed in 2010 to
regulate CCRs for the first time. EPA is considering two possible options for the management of
CCRs. Both options fall under the RCRA. Under the first option, EPA would list these residual
materials as special wastes subject to regulation under Subtitle C of RCRA with requirements
from the point of generation to disposition including the closure of disposal units. Under the
second option, EPA would regulate coal combustion residuals as nonhazardous waste under
Subtitle D of RCRA and establish minimum nationwide standards for the disposal of coal
combustion residuals. Under either option for regulation, surface impoundments utilized for coal
combustion byproducts would have to be closed unless they could meet more stringent
regulatory requirements. PacifiCorp operates 16 surface impoundments and six landfills that
contain coal combustion byproducts.
The public comment period on EPA's proposal to regulate coal combustion byproducts closed in
November 2010 and the EPA has indicated that the rule will be finalized in2014.In a preamble
to the recently proposed effluent guideline limitations discussed herein, EPA stated that non-
hazardous management of CCRs may be adequate.
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 July 2004, the EPA established
significant new technology-based performance standards for existing electricity generating
l6
PACIFICoRP _ 2013 IRP UpONrg CH.q,prEn 2 - PLANTNTNG ENVTRoNMENT
facilities that take in more than 50 million gallons of water per day. These rules were aimed at
minimizing the adverse environmental impacts of cooling water intake structures by reducing the
number of aquatic organisms lost as a result of water withdrawals. [n response to a legal
challenge to the rule, in January 2007, the Court of Appeal for the Second Circuit remanded
almost all aspects of the rule to the EPA without addressing whether companies with cooling
water intake structures were required to comply with these requirements. On appeal from the
Second Circuit, in April 2009, the U.S. Supreme Court ruled that the EPA permissibly relied on a
cost-benefit analysis in setting the national performance standards regarding best technology
available for minimizing adverse environmental impact at cooling water intake structures and in
providing for cost-benefit variances from those standards as part of the $316(b) Clean Water Act
Phase II regulations. The Supreme Court remanded the case back to the Second Circuit Court of
Appeals to conduct further proceedings consistent with its opinion.
In March 2011, the EPA released a proposed rule under $316(b) of the Clean Water Act to
regulate cooling water intakes at existing facilities. The proposed rule establishes requirement for
electric generating facilities that withdraw more than two million gallons per day, based on total
design intake capacity, of water from waters of the U.S. and use at least 25 percent of the
withdrawn water exclusively for cooling purposes. PacifiCorp's Dave Johnston generating
facility withdraws more than two million gallons per day of water from waters of the U.S for
once-through cooling applications. Jim Bridger, Naughton, Gadsby, Hunter, Carbon and
Huntington generating facilities currently utilize closed cycle cooling towers but withdraw more
than two million gallons of water per day. The proposed rule includes impingement (i.e., when
fish and other aquatic organisms are trapped against screens when water is drawn into a facility's
cooling system) mortality standards to be met through average impingement mortality or intake
velocity design criteria and entrainment (i.e., when organisms are drawn into the facility)
standards to be determined on a case-by-case basis. The standards are required to be met as soon
as possible after the effective date of the final rule, but no later than eight years thereafter. While
the rule was required to be finalized by the EPA by July 2012, the rule is now expected to be
finalized in the second quarter of 2014. Assuming the final rule in that timeframe, PacifiCorp's
generating facilities impacted by the final rule will be required to complete impingement and
entrainment studies by mid-2015.
Elfluent Limit G uidelines
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 April 19,2013, EPA proposed revised effluent limit guidelines and is required,
under the terms of a stipulated extension to a consent decree, to finalize the rule by May
2014. Until the technology-based effluent limitation guidelines are frnalized, PacifiCorp is
incorporating proxy compliance costs for certain units reasonably likely to be impacted by the
rule into its business plans and analyses. Of importance to note, the effluent limit guidelines will
also apply to gas-fired generation.
While national GHG legislation has not been successfully adopted, state initiatives continue with
the active development of climate change regulations that will impact PacifiCorp.
t7
PACFICoRP - 2013 IRP Upnlrs CHApTER 2 - Pr-a.N[.trNc E]wTRoNMENT
California
An executive order signed by California's governor in June 2005 would reduce GHGs emissions
in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 levels by
2050. In 2006, the California Legislature passed, and Governor Schwarzenegger signed,
Assembly Bill 32, the Global Warming Solutions Act of 2006, which set the 2020 GHG
emissions reduction goal into law. It directed the California Air Resources Board (CARB) to
begin developing discrete early actions to reduce GHG while also preparing a scoping plan to
identifu how best to reach the 2020 limit.
Pursuant to the authority of the Global Warming Solutions Act, in October 201l, 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 October 2013, CARB kicked off an Assembly Bill 32 scoping plan update designed to build
upon the initial scoping plan. The scoping plan update defines climate change priorities for the
next five years and sets the groundwork for post-2020 climate goals. A proposed first update
issued in February 2014 indicated a post-2020 GHG reduction goal of 80 percent below 1990
levels by 2050.
Oregon and Washington
ln2007,the Oregon Legislature passed HB 3543 Global Warming Actions which establishes
GHG reduction goals forthe state that (i) bV 2010, cease the growth of Oregon greenhouse gas
emissions; (ii) by 2020, reduce greenhouse gas levels to l0 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 I 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 1990levels by 2020 and l5 percent below 2005 levels
by 2020. The OPUC submitted its most recent report November 1,2012.
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
a new revenue option. The report is to include an evaluation of how to treat imported and
exported energy sources. A final report is expected November 1,2014.
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. The Washington Legislature
established the Climate Legislative and Executive Workgroup to develop recommendations to
achieve the state's GHG emission limits. The workgroup issued two reports in January 20141'
both reports included recommendations to continue workgroup efforts through 2014.
l8
PACTICoRP - 2OI3 IRP UPDATE Csaprsn 2 - PLANNTNG ENVTRoNMENT
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 pounds of carbon
dioxide equivalent per 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 pounds of carbon dioxide per MWh.
As discussed in the 2013 IRP, the Energy Gateway transmission project continues to play an
important role in the Company'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 beffer
quantiff 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.
Several Energy Gateway developments have occurred since the Company's 2013 IRP was filed,
including reaching construction and permitting milestones, adjusting in-service dates for future
segments, and developing activities on joint-development projects. Also, in response to feedback
from interested stakeholders, the Company has completed its 2013 IRP Action Plan item to
solicit feedback from stakeholders regarding the System Operational and Reliability Benefit Tool
(SBT) that identifies and quantifies a range of transmission benefits. Please see Chapter 6 for
status updates on the 2013 IRP Action Plan. An updated Energy Gateway map is provided below
as Figure 2.1.
t9
20r3
lntegrated
ResounEe
Plan
Update
REDACTED
SPaqnConp Rocky Mountain Power
Pacific Porm
hcifiC-orp Enerry
dnswers on.Mareh 31, 2ql4 Let's turn the
This 201i 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 os circumstances change. k is
PacifiCorp's intention to revisit and refresh the IkP action plan no lessfrequently than annually.
Any refreshed IRP action planwill be submitted to the State Commissionsfor their information.
For more information, contact:
PacifiCorp
IRP Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
(s03) 813-5245
[e-mail]
http ://www.pac i fi corp.com
This report is printed on recycled paper
Cover Photos (Top to Bottom):
Transmission: Sigurd to Red Butte Transmission Segment G
Hydroelectric: Lemolo I on North Umpqua River
Wind Turbine: LeaningJuniper I Wind Project
Thermal-Gas: Chehalis Power Plant
Solar: Black Cap Photovohaic Solar Project
PACIFICoRP _ 20 I3 IRP Upoarg TABLE OF CoNTENTS
Teglp oF CONTENTS
TABLE OF CONTENTS
INDEX OF TABLES
INDEX OF FIGURES
EXECUTIVE SUMMARY
CHAPTER I - INTRODUCTION
CHAPTER 2 - PLAI\INING ENYIRONMENT
BusrNESs PLAN DEVELoPMENT...... .........................9
CHor-la UNrr 4 UpoarB ......................9
THE FUTURE oF FEDERAL ENVIRoNMENTAL REGULATIoN AND LEGISLATIoN ................ IO
Federal Climate Change Legislation. ................ l0
Federal Renewable Portfolio Standards... ......... 11
EPA REcULAToRy UPDATE-GREENHoUSE GAS EMrssroNS.................. ......................... I I
New Source Review / Prevention of Signfficant Deterioration Q,{SR / PSD) ................. 11
Guidancefor Best Available Control Technologt (BACD ........................ 12
New Source Performance Standards QI{SPS) for Greenhouse Gases .......... .................. 12
EPA REGULATORY UPDATE - NON-GREENHOUSS GAS EMISSIONS .. ............ I 3
Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards .............. 13
Clean Air Transport Ru1e............ ....................... 14
Regional Haze ............14
Mercury and Hazardous Air Po||utants............... .................. 15
Coal Combustion Residuals................. .............. 16
Water Quality Standards... .............16
Cooling Water Intake Structures ...........................16
Srarr Cluarp CHANGE REGULATToN .................17
Oregon and Washin9ton.................. ................... /8
Greenhouse Gas Emission Performance Standards .............. 19
ENERGY GATBWAY TRANSMISSION PROGRAM PLANNING.. ...... 19
Energt Gateway Transmission Project Updates....... ............. 20
CHAPTER 3 - RESOURCE NEEDS ASSESSMENT UPDATE
ry
7
9
23
PACIFICoRP _ 20 13 IRP Upoerg TABLE OF CoNTENTS
CHAPTER 4 - MODELING ASSUMPTIONS UPDATE
CHAPTER 5 _ PORTFOLIO DEVELOPMENT...... .........45
INTRoDUCTroN.............. .....................45
WIND RESoURCES AND RENEWABLE PoRTFoLro SraNoaRo CoMPLTANCE ........................................45
Renewable Energt Credit Value ........... ............. 45
Wind Resourcer................ ..............46
Renewable Portfolio Standard Compliance. ......47
20 I 3 IRP UPDATE RESoURCE PoRTFoLIo ............. 5 I
BUSTNESS PLAN RESoURCE PoRTFoLro.............. .......................55
SBNSITIVITy SruoIpS ARoI.]ND PERFoRMANCE oF RENEwABLE RESoURCES............ .......59
CHAPTER 6 _ ACTION PLAI\ STATUS UPDATE .........69
APPENDIX A - ADDITIONAL LOAD FORECAST DETAILS
APPENDIX B - COMBINED HEAT AI\D POWER EXECUTIYE SUMMARY................87
EXECUTTVE SUMMARY .......................87
Mill Waste ..................88
Forest Thinnings ........89
Market Barriers...... ........................ 89
Air Permitting Requirements ...........90
Lack of Financial Recognition of Environmental Benefits .........90
Cost of Fuel Transportation.................... ...............90
APPENDIX C - ENERGY AIIALYSIS REPORT 9l
PACIFICoRP _ 20 13 IRP UpOArg TABLEOF CoNTENTS
Huntington P1ant........... .................97
Potentially Cost-Effective Projects...... .....,............97
Systems Requiring Further Research ....................97
Unlikely to be Cost-Effective.............. ..................98
Currant Creek Plant ....................... 98
Potentially Cost-Effective Projects...... ..................98
Systems Requiring Additional Research....... ........98
Unlikely to be Cost-Effective.............. ..................98
Hunter Unit 3 .............99
Potentially Cost-Effective Projects...... ..................99
Systems Requiring Further Research ....................99
Unlikely to be Cost-Effective.............. ..................99
Lakeside P1ant........... ................... 100
Potentially Cost-Effective Projects...... ................100
Systems Requiring Further Research ..................100
Unlikely to be Cost-Effective.............. ................100
Blundell P1ant........... .................... 100
Potentially Cost-Effective Projects...... ........,.......100
Systems Requiring Further Research ..................100
Unlikely to be Cost-Effective.............. ................101
Gadsby P1ant........... ..................... 101
APPENDIX D _ ACCELERATED CLASS 2 DSM DECREMENT STUDY......................103
MoDELTNG APPROACH ..................... 103
Generation Resource Capacity Deferral Bene/it Methodologt ............... 103
CLASS 2 DSM DBcRpNreNt VALUE ITEST]LTS ...... IO4
APPENDIX E _ IRP TABLE A.7 CORRECTION
CONFIDENTIAL APPENDIX F _ BREAKEVEN ANALYSIS
111
113
lll
PACIFICoRP _ 20 I3 IRP Upnerg INDEX OF TABLES
INnpx OF TABLES
Table ES.l - Comparison of 2013 IRP Update with 2013 IRP Preferred Portfolio ..........5
Table 3.1 - October 2013 (2013IRP Update): Forecasted Annual Load Growth, 2014 through2023 (Megawatt-
Table 3.2 - October 2013 (2013IRP Update): Forecasted Annual Coincident Peak Load (Megawatts). ...................24
Table 3.3 - June 2013 (Business Plan): Forecasted Annual Load Growth, 2014 through2023 (Megawatt-hours).,,.25
Table 3.4 - June 2013 (Business Plan): Forecasted Annual Coincident Peak Load (Megawatts). ........25
Table 3.5 - June2012 (2013 IRP): Forecasted Annual Load Growth, 2014 through2023 (Megawatt-hours)...........26
Table 3.6 - June2012 (2013 IRP): Forecasted Annual Coincident Peak Load (Megawatts). ...............26
Table 3.7 - Annual Load Growth Change: October 2013 (2013IRP Update) Forecast less June 2012 (2013 IRP)
Forecast (Megawatt-hours) ............... ...............26
Table 3.8 - Annual Coincidental Peak Growth Change: October 2013 (2013IRP Update) Forecast less June 2012
(2013 IRP) Forecast (Megawatts). ...................27
Table 3.9 - Annual Load Growth Change: June 2013 (Business Plan) Forecast less June 2012 (2013IRP) Forecast
Table 3.10 - Annual Coincidental Peak Growth Change: June 2013 (Business Plan) Forecast less June 2012 (2013
IRP) Forecast (Megawatts) ........27
Table 3.ll -Load and Resource Balance,2013 IRP Update (Megawatts). ....................30
Table 3.12 -Load and Resource Balance, Business Plan (Megawatts) .............. ............31
Table 3.13 -Load and Resource Balance,2013 IRP (Megawatts) ...........32
Table 3.14 - Load and Resource Balance, 2013 IRP Update less 2013 IRP (Megawatts)..........................................33
Table 3.15 -Load and Resource Balance, Business Plan less 2013 IRP (Megawatts) .........................34
Table 4.1 - Updated Cost of Solar Resources, 2013$ - (50 MW AC)............... ..............43
Table 5.1 - Wind Additions, 2013 IRP Prefened Portfolio, Business Plan, 2013 IRP Update... ..........47
Table 5,2 - Renewable Portfolio Standard Targets, Requirements, and Initial Eligible Existing RECs by State for
2013 IRP, Business Plan, and 2013 IRP Update.......... ..........48
Table 5.3 - Comparison of 2013 IRP Update with 2013 IRP Preferred Portfolio....... ..........................52
Table 5.4 -2013 IRP Update Capacity Load and Resource Balance.,....... .....................53
Table 5.5 -2013IRP Update, Detail Portfo1io................... .......................54
Table 5.6 - Comparison of Business Plan with 2013 IRP Preferred Portfolio ................56
Table 5.7 -Business Plan Capacity Load and Resource Balance ..............57
Table 5.9 - Peak Contribution of Renewable Resources, sensitivity study............. ........59
Table 5.10 - Updated Costs of Solar Resources, sensitivity study (50 MW AC)....... ...........................59
Table 5.12 - Portfolio Comparison of Case EG2-C0l and Peak Contribution Sensitivity Study ...............................61
Table 5.13 - Portfolio Comparison of Case EG2-C07 and Solar Cost Sensitivity Study....... ...............64
Table 5.14 - Portfolio Comparison of Case EG2-Cl0 and Solar Cost Sensitivity Study....... ...............65
Table 5.15 - Comparison of Risk-Adjusted PVRR between Cases EG2-C07 and the Capacity Contribution
Table 6.1 - IRP Action Plan Status Update.......... ...............70
Table A.l -2013IRP Update Annual Retail Sales Forecast in Megawatt-hours by State..........................................85
Table A.2 - Change in Annual Retail Sales Forecast in Megawatt-hours by State compared to the 2013 IRP ..........85
Table A.3 - System Annual Retail Sales Forecast in Megawatt-hours by Class............. ......................86
Table A.4 - Change in System Annual Retail Sales Forecast in Megawatt-hours by Class Compared to the 2013
Integrated Resource Plan .............. ...................86
Table B.l - PacifiCorp's existing Biomass QF Power Purchase Agreements by State. .......................88
Table B.2 - Woody Biomass Generation on PacifiCorp's System...... ............................88
Table D.l - Nominal Levelized Accelerated Class 2 DSM Avoided Costs (2013-2032) ...................105
Table D.2 - Difference - Nominal Levelized Class 2 DSM Avoided Costs (2013-2032) ..................106
Table D.3 - Annual Nominal Accelerated Class 2 DSM Avoided Costs, 2013-2032.... .....................107
Table D.4 - Annual Nominal Accelerated Class 2 DSM Avoided Costs, 2013-2032 (continued)............................108
Table D.5 - Portfolio Difference - Appendix N (Non-Accelerated DSM) ........... ........109
Table D.6 - Portfolio Difference - Non-Accelerated DSM ....................1 l0
lv
PACIFICORP _20I3 IRP UPOETE INDEX OF TABLES AND FIGURES
Table E.l - Jurisdictional Contribution to Coincident Peak 1997 through 2012.............. ...................1I I
Confidential Table F.l -Hunter I APR Emission Control PVRR(d) Analysis Results, 2026 SCR.........................1l6
Confidential Table F.2 - Bridger 3 and 4 CPCN Emission Control PVRR(d) Analysis Results ........1 l9
Confidential Table F.3 -Naughton 3 CPCN Emission Control PVRR(d) Analysis Results.......... .....120
INngx oF FIGURES
Figure ES.2 - Power and Natural Gas Price Comparisons. .........................2
Figure ES.3 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013 IRP Update ....................4
Figure 3.1 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013 IRP Update .....................29
Figure 3.2 -2013 IRP Update, System Capacity Position Trend............ ........................35
Figure 3.3 -2013IRP Update, West Capacity Position Trend ........... ...........................,36
Figure 3.4 - 2013IRP Update, East Capacity Position Trend............ .......36
Figure 4.1 - Henry Hub Natural Gas Prices (Nominal)...., ........................40
Figure 4.2 - Average Annual Flat Palo Verde Electricity Prices ..............41
Figure 4.3 - Average Annual Heavy Load Hour Palo Verde Electricity Prices..... .........41
Figure 4.4 - Average Annual Flat Mid-Columbia Electricity Prices....... ........................42
Figure 4.5 - Average Annual Heavy Load Hour Mid-Columbia Electricity Prices........... ...................42
Figure 5.1 -20I3IRP Update RPS Compliance Position.... ....,................49
Figure 5.2 - Business Plan RPS Compliance Position ........50
Figure 5.3 - 2013 IRP RPS Compliance Position ...............50
Figure F.l - Natural Gas Price Forecast for 2013 IRP Update... ............. 1 l 5
Confidential Figure F.2 - Relationship between Gas Prices and the PVRR(d) (Benefit)/Cost of the Baghouse and
LNB Investments at Hunter Unit I ........... .....117
Confidential Figure F.3 - Relationship between CO2 Prices and the PVRR(d) (Benefit)/Cost of the SCR Investments
at Hunter Unit I ........... ............1l8
Confidential Figure F.4 - Relationship between Gas Prices and the PVRR(d) (Benefit/Cost of the SCR Investments
at Jim Bridger Units 3 & 4............ .................1l9
Confidential Figure F.5 - Relationship between CO2 Prices and the PVRR(d) (Benefit/Cost of the SCR Investments
at Jim Bridger Units 3 &. 4............ .................120
Confidential Figure F.6 - Relationship between Gas Prices and the PVRR(d) (Benefit/Cost of the SCR and
Baghouse Investments at Naughton Unit 3........... ...............121
Confidential Figure F.7 - Relationship between CO2 Prices and the PVRR(d) (Benefit)/Cost of the SCR and
Baghouse Investments at Naughton Unit 3 ........... ...............122
PecruConp - 20 I 3 IRP Upoers EXECUTwE SutvIt\4ARY
ExgcurIVE Suutr,tARY
PacifiCorp submitted its 2013 lntegrated Resource Plan (2013 IRP) to state regulatory
commissions in April 2013. That plan provides a framework for future actions that PacifiCorp
will take to provide reliable, reasonable-cost service with manageable risks for customers. This
2013 IRP Update describes resource planning and procurement activities that occurred
subsequent to the filing of the 2013 IRP, presents an updated resource needs assessment, an
updated resource portfolio consistent with changes in the planning environment, and provides an
IRP Action Plan status update. In presenting the updated resource needs assessment and updated
resource portfolio, PacifiCorp shows changes relative to the 2013 IRP and relative to
PacifiCorp's fall 2013 ten-year business plan, which covers the 2014 to 2023 planning horizon.
In this update PacifiCorp also addresses recommendations and requirements identified by its
state regulatory commissions during the 2013IRP acknowledgement process.
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 2013 IRP Update:
o As shown in Figure ES.l the Company's most recent coincident system peak load
forecast is down relative to the 201 3 IRP, and the intervening fall 2013 ten-year business
plan. The coincident peak forecast decreased through the planning period. Driving the
reduction in peak load are a reduced residential class load forecast relative to the 2013
IRP due to inmeased energy efficiency and continued phase in of the Energy
Independence and Security Act federal lighting standards. In addition, recent history has
seen low growth in the peak, which in turn reduces the long-term forecast peak load
growth expectations. With a reduced coincident system peak forecast, the need for new
resources is pushed further out in the planning horizon as compared to the 2013 IRP. In
the 2013IRP Update resource portfolio, a new thermal resource is not needed until2027 .
Figure ES.l- Load Forecast Comparison
12,000
I 1,500
I 1,000
10,500
10,000
9,500
9,000
F'orecasted Annual System Coincident Peak (MW)
2016 2017 2018 20t9 2020 2021
.-(>2013 IRP *Buiness Plan -r-2013 IRP Update
20152014
PECTTICONT _ 20 13 IRP UPDATE E)GCUTIVE SUMMARY
o Figure ES.2 shows that forecast natural gas and energy prices have declined from those
assumed in the 2013 IRP and the fall 2013 ten-year business plan. 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
Eenry Eub Netural Glr Prlcer
s8
s,
Ba!Xs6
EI"
5z
t4
t3 i69FO6O-da8888888RRR
+BuiEPla (scp 2013) +mr3 RP(S?20!2) +20t3
Averrge of MId C/Prlo Verde Flat Power Prlcer
80
70
,&
E
l50IE*
30
20
+Bdoa Pta (S? 2013) +ml3 IRP (S.D 2012) +2013 lnP Up.l! (Dc 2Or3)
!69FO6a-dORRR8888RRR
With a reduced coincident system peak forecast and lower market prices, the 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
through energy efficiency. PacifiCorp continues to pursue acceleration of cost-effective
energy efficiency consistent with its 2013 IRP Action Plan.
The Energy Gateway transmission project continues to play an important role in the
Company's commitment to provide safe, reliable, reasonably priced electricity to meet
the needs of our customers. Several Energy Gateway developments have occurred since
the Company's 2013 IRP was filed, including reaching construction and permitting
milestones, adjusting in-service dates for future segments, and developing activities on
joint-development projects. Accordingly, in-service dates have been updated relative to
those assumed for the 2013IRP. These date adjusfrnents coincide with revised permitting
dates, generation facility needs and updated load growth assumptions.
The Environmental Protection Agency (EPA) partially approved and partially rejected the
Wyoming Regional Haze state implementation plan (SIP) and issued a federal
implementation plan (FIP) to cover those areas of SIP disapproval in January 2014. This
action established compliance requirements and schedules for specific Wyoming coal
units under the Regional Haze program, including a requirement for installation of
selective catalytic reduction (SCR) at Wyodak by early March 2019. For purposes of the
2013 IRP Update, the resource needs assessment and updated resource portfolio reflects
the continued operation of Wyodak as a coal-fired generating asset through the planning
PACFICoRP - 2OI 3 IRP UPDATE E)<rcurrvE Suunaenv
horizon. PacifiCorp will be analyzing the Wyodak SCR investment and alternatives to
this investment in its 2015 IRP.
In EPA's action on the Wyoming SIP in January 2014, it explicitly stated its support for
the natural gas conversion of Naughton Unit 3, but noted that because the Wyoming SIP
documentation did not include a natural gas conversion option, EPA has no basis to
disapprove the Wyoming SIP requirement for low NO1 burners/overfired air, SCR, and
baghouse, with its authority and obligation to take action on the SIP as submitted by the
state. PacifiCorp has since been working with the state of Wyoming Division of Air
Quality to identiff amendments necessary to support the Naughton Unit 3 natural gas
conversion and to clearly document the compliance requirements and timeline for
implementation of the project under the RegionalHaze program. In the 2013 IRP Update,
the resource needs assessment and updated resource portfolio continues to reflect a gas
conversion completed by summer 2015.
Since 2010, no significant activity has occurred with respect to the development of a
federal renewable portfolio standard (RPS). [n addition, current political environments
are shifting focus from items such as the extension of federal incentives for renewables
and portfolio standards to EPA's development of greenhouse gas standards. Accordingly,
the 2013 IRP Update assumes no federal RPS requirement over the course of the
planning horizon. With the removal of the federal RPS assumptions requirements, the
updated resource portfolio shows a reduced need for renewable resources required solely
to meet state RPS obligations in2024 and2025.
After PacifiCorp filed the 2013IRP, President Obama issued a Presidential Memorandum
in June 2013 directing EPA to issue standards, regulations, or guidelines, as appropriate
that address greenhouse gas emissions from modified, reconstructed, and existing power
plants. The proposed standards, regulations, or guidelines are to be issued by June 1,
2014, finalized by June 1,2015, with implementation of regulations as proposed in SIPs
required by June 30,2016. EPA would then review the implementation plan proposed by
each state, and the effective compliance dates for these standards, regulations, or
guidelines would become applicable sometime thereafter. Absent information on how
EPA intends to proceed with its rule-making process, and without any information on
how individual states will propose to implement those regulations through a SlP, there is
currently no means to develop a specific CO2 price assumption that accurately reflects
potential CO2 regulation. PacifiCorp's review of current third-party CO2 price forecasts
shows that despite issuance of the Presidential Memorandum, these forecasters have not
materially altered either their assumed COz start date or price level. In the 2013 IRP
Update, PacifiCorp continues to assume a COz price signal beginning 2022 at $16/ton
escalating at three percent plus inflation thereafter, and expects to update its COz policy
assumptions and scenarios in the 2015 IRP, taking into consideration the proposed
standard, regulation, or guidelines expected to be issued by EPA later this year.
Figure ES.3 shows the 2013 IRP Update resource need, prior to acquiring any new resources,
alongside the resource need from the 2013 IRP and the fall 2013 ten-year business plan. Overall,
PACFICORP - 20 13 IRP UPDATE D{ECUTTVE SUMMARY
the forecasted need has declined with the most recent needs assessment. Primarily driven by an
updated load forecast, the most recent resource needs assessment shows an average reduction in
peak resource need of approximately 320 megawatts (MW) as compared to the 2013 IP.P for the
period 2014-2023. Relative to the fall2013 ten-year business plan, the most recent projection of
resource need is reduced by approximately 135 MW over the same period.
Figure ES.3 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013
IRP Update
(Lm)
I
Itr,ml-
(4m)
(1m;
(3,m0)
r 2013 IRP
r Burbocr Plrn
Table ES.l reports the 2013 IRP Update resource portfolio and a comparison of portfolio
changes relative to the 2013 IRP Preferred Portfolio.l The table shows the resource mix targeted
to fill the resource need summarized above with resource capacities at time of coincident system
peak reported in the years for which the resources are available to meet summer peak loads. As
compared to the 2013 IRP Preferred Portfolio, the changes in resource mix for the 2014-2023
planning period are minor. Relative to the 2013 IRP Preferred Portfolio, which did not include
any significant new thermal resources in the front ten years of the planning horizon, the updated
resource portfolio shows a reduction in front office transactions (FOTs), consistent with a
reduced resource need. As was the case in the 2013 IRP Preferred Portfolio, PacifiCorp
continues to plan to meet its customers' needs largely through acquisition of cost effective
energy efficiency resources and FOTs over the next ten years. Considering the relatively small
changes in energy efficiency resources between the 2013 IRP and 2013 IRP Update portfolios,
PacifiCorp has not modified its 2013 IRP Action Plan and continues to target accelerated energy
efficiency savings.
I A comparison ofthe portfolio changes relative to the fall 2013 ten-year business plan is presented in Chapter 5.
4
PACIFICoRP - 2013 IRP UPDATE EXECUTIVE SutrmaeRv
Table ES.l - Comparison of 2013IRP Update with 2013 IRP Preferred Portfolio
Frcnt Ofice TMtbE h rcsue total re I Glsr a]wge. *
Lcss 2013 IRP Prcferred Portfolio
Frcrt Ofto Tffietbrc il resuce total re 10-yeu awnge. *
PacifiCorp has not modified its 2013 IRP Action Plan, which remains consistent with the
updated resource needs assessment and resource portfolio as summarized above. Chapter 6 of
this IRP Update provides a status update of PacifiCorp's 2013 IRP Action Plan action items. A
variety of action items have been completed and are noted as such, while other action items will
continue forward into the 2015 IRP process.
PecmrConp - 2013 IRP Upoere CHAPTER I - INTRoDUCTION
CuaprER 1 - INTNODUCTION
This 2013 Integrated Resource Plan Update (2013 IRP Update) describes resource planning
activities that occurred subsequent to the filing of the 2013 Integrated Resource Plan (2013 IRP)
in April 2013, presents an updated resource needs assessment, an updated resource portfolio
consistent with changes in the planning environment, and provides an IRP Action Plan status
update. In presenting the updated resource needs assessment and updated resource portfolio,
PacifiCorp shows changes relative to the 2013 IRP and relative to PacifiCorp's fall 2013 ten-year
business plan (Business Plan), which covers the 2014 to 2023 planning horizon. In this update
PacifiCorp also addresses recommendations and requirements identified by its state regulatory
commissions during the 2013 IRP acknowledgement process.
In support of its business planning process, PacifiCorp refined the 2013 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 PacifiCorp business units (PacifiCorp Energy, Pacific Power, and
Rocky Mountain Power). 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 2013 IRP Preferred Portfolio served as the primary basis in establishing the resource
portfolio for the Business Plan, and as summarized herein, differences between the two resource
portfolios are minor.
A similar process has been completed to develop the resource needs assessment and resource
portfolio for this 2013 IRP Update, which considers updates to forecasted loads, resources,
market prices, and other model inputs since the intervening Business Plan resource portfolio was
developed. For purposes of assessing an updated resource needs assessment and updated
resource portfolio in this 2013 tRP Update, PacifiCorp has not completed new financial analysis
of pending environmental compliance decisions applicable to specific coal units on its system.
PacifiCorp will analyze specific environmental compliance decisions applicable to Cholla Unit 4,
Wyodak, and Dave Johnston Unit 3 in its 2015 IRP, with the full engagement of PacifiCorp's
diverse stakeholder group. PacifiCorp will also provide an update on its efforts working with the
Wyoming Division of Air Quality to identiff amendments necessary to support the Naughton
Unit 3 natural gas conversion and to clearly document the compliance requirements and timeline
for implementation of the natural gas conversion under the RegionalHaze program. In this 2013
IRP Update, PacifiCorp continues to assume the Naughton Unit 3 natural gas conversion is
completed by summer 2015.
The 2013 IRP Update also addresses recommendations and requirements identified by its state
regulatory commissions during the 2013 acknowledgement process. This includes presentation
of solar resource modeling sensitivities developed in response to a request by the Public Service
Commission of Utah (PSCU) of and analysis of how CO2 price and natural gas price
assumptions affect the analysis of environmental compliance decisions for specific coal units as
requested by the Washington Utilities and Transportation Commission.
This report first describes the current planning environment, load updates, resource updates,
emissions/climate change regulatory outlook, and Energy Gateway transmission planning and
PACTFTCoRP - 201 3 IRP Upoarp CrnpreR I - INTRoDUCTIoN
project completion forecast (Chapter 2). Next, Chapters
inputs and assumptions relative to those used for the 2013
then presented along with a status update on the 2013
respectively).
Appendices include the following:
. Appendix A - Additional Load Forecast Details. Appendix B - Executive Summary of the CHP Study. Appendix C - Energy Analysis Report. Appendix D - Accelerated DSM Decrement Studyo Appendix E - Correction to 2013 IRP Table A.7
3 and 4 describe the changes to key
IRP. The updated resource portfolio is
IRP Action Plan (Chapters 5 and 6,
o Redacted Appendix F - Breakeven Analysis for Select Coal-Fired Plants
PecrrICoRp - 20 13 IRP UPDATE Crupren 2 -Prer.rNnrc ENvIRoNMENT
CHapTER 2 - PTANNING ENvTnONMENT
The 2013 IRP Preferred Portfolio served as the basis for the resource assumptions used in
PacifiCorp's fall 2013 ten-year business plan (Business Plan), which covers the 2014 to 2023
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. As it relates to PacifiCorp's resource plan, differences
between the 2013 IRP Preferred Portfolio and the Business Plan portfolio are minor and
consistent with an updated load forecast. The Business Plan portfolio also considers updated
assumptions for the Energy Gateway transmission project, which continues to play an important
role in the Company's commitment to provide safe, reliable, reasonably priced electricity to meet
the needs of our customers. Several Energy Gateway developments have occurred since the
Company's 2013 IRP was filed, including reaching construction and permitting milestones,
adjusting in-service dates for future segments, and developing activities on joint-development
projects. Accordingly, in-service dates have been updated relative to those assumed for the 2013
IRP. These date adjustments coincide with generation facility needs and load growth
assumptions.
ln March 2011, the state of Arizona submitted its RegionalHaze state implementation plan (SIP)
to the Environmental Protection Agency (EPA) for review. The SIP requires currently installed
low NOx burners (LNB) as best available retrofit technology (BART) for NOx emissions at
Cholla Unit 4. By final rule dated December 5,2012, EPA disapproved portions of the Arizona
Regional Haze SIP and issued a federal implementation plan (FIP). The FIP requires, among
other things, installation of selective catalytic reduction (SCR) on Cholla Unit 4 by January 4,
2018. The FIP also institutes an averaged NOx emissions rate of 0.055 lb/MMBtu for Cholla
Units 2, 3 and 4. In January and February 2013, PacifrCorp, the state of Arizona and other
Arizona utilities filed separate appeals of EPA's FIP with the U.S. Ninth Circuit Court of
Appeals. In February 2013, PacifiCorp and other Arizona utilities filed petitions for
reconsideration at the EPA and requests for administrative stay of the FIP until judicial appeals
are completed. In March 2013, PacifiCorp and other Arizona utilities filed motions for judicial
stay of the FIP with the U.S. Ninth Circuit Court of Appeals until the appeals are complete.
On April 3,2013, the court consolidated the various appeals into a single docket before a single
judicial panel. On April 9, 2013, EPA granted various petitions for reconsideration for the
averaged NOx emissions rate only, but has taken no further action to date. Although EPA may
propose a new NOx rate at some time in the future, which will undergo public comment, it is not
under any timing requirement to do so. EPA did not address the various requests for
administrative stay in its April 9,2013 action.
PACIFICoRP - 2OI3 IRP UPDATE CHAPTER 2 -PLANNING ENVIRONMENT
On April 23,2013, the court set the following case schedule:
o June 2013 - briefing on motions for judicial stay to be completedo January 2014 - briefing on the merits of appeals to be completed
On September 9, 2013, the court denied the motions for sky. The court is now expected to issue
a final decision on the appeals in 2015. However, there are no mandatory dates by which the
court must issue decisions.
With the denial of requests for administrative stay and judicial stay, the January 4, 2018
compliance deadline for installing SCR at Cholla Unit 4 remains in place. PacifiCorp continues
to work closely with the state of Arizona and the other Arizona utilities in connection with the
now consolidated appeals. Various environmental groups have intervened in the appeals in
support of EPA's FIP.
With the ongoing activities outlined above, PacifiCorp continues to explore potential alternatives
to the installation of SCR at Cholla Unit 4, and consequently, the Company has not finalized an
analysis of compliance alternatives nor made a decision on this pending investment. The
Company intends to finalize its analysis in20l4 and will file its analysis in a future IRP filing.2
For purposes of the 2013 IRP Update, PacifiCorp assumes Cholla Unit 4 continues to provide
both system capacity and energy through the planning horizon.
PacifiCorp faces a continuously changing environment with regard to electricity plant emission
regulations. Although the exact nature of these changes remains uncertain, they are expected to
impact the cost of future resource alternatives and the cost of existing resources in the
Company's generation portfolio. PacifiCorp monitors these regulations to determine the potential
impact on its generating assets. PacifiCorp also participates in the rulemaking process by filing
comments on various proposals, participating in scheduled hearings, and providing assessment of
such proposals.
Federal Climate Change Legislation
PacifiCorp continues to evaluate the potential impact of climate change legislation at the federal
level. The impact of a given legislative proposal can vary significantly depending on selection of
key design criteria (i.e., level of emissions cap, rate of decline of the cap, the use of carbon
offsets, allowance allocation methodology, the use of safety valves, etc.) and macro-economic
assumptions (i.e., electricity load growth, fuel price impacts - especially natural gas, commodity
prices, new technologies, etc.).
To date, no federal legislative climate change proposal has successfully been passed by both the
U.S. House of Representatives and the U.S. Senate for consideration by the President. The two
most prominent legislative proposals introduced for attempted passage through Congtess have
'The Public Utility Commission of Oregon's draft 2013 IRP acknowledgement order outlines a requirement for
PacifiCorp to make a supplemental IRP filing on Cholla Unit 4 ir,20l4. With the appropriate protections in place,
PacifiCorp intends to summarize the information from this filing for its broader stakeholder group during the 2015
IRP public process and summarize this same analysis in a confidential volume of the 2015 IRP.
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PaCrrICOnp _ 20 13 IRP UPDATE Cseprsn 2 - PLANNTNG ENvTRoNMENT
been the Waxman-Markey bill in 2009 and the Kerry-Lieberrnan bill in 2010; neither measure
was able to accumulate enough support to pass.
The ll3ft Congress was challenged by the President to pursue a bipartisan, market-based
solution to climate change. The President stated that if Congress did not act soon, then he would
direct his Cabinet to implement executive action to reduce greenhouse gas (GHG) emissions. To
date, such bipanisan action has not occurred. ln 2013, a bill was introduced by the Energy &
Power Subcommittee Chairman Whitfield (R-KY) called the Electricity Security and
Affordability Act, which provides direction to EPA regarding the establishment of standards for
GHG emissions from fossil-fueled generating facilities. This bill is expected to pass the House
of Representatives but not the Senate.
On June 25,2013, President Obama directed the EPA to complete GHG standards for both new
and existing power plants. With regard to existing sources, EPA was directed to issue
"standards, regulations, or guidelines, as appropriate" that address GHG emissions from
modified, reconstructed, and existing power plants.3 The proposed standards, regulations, or
guidelines are to be issued by June l, 2014, finalized by June I , 2015, with implementation of
regulations as proposed in state implementation plans required by June 30,2016. EPA would
then review the implementation plan proposed by each state. The June 25, 2013 directive did not
include detail with respect to how EPA will approach GHG regulation or what the resulting
standards, regulations, or guidelines will ultimately entail.
Federal Renewable Portfolio Standards
Since 2010, no significant activity has occurred with respect to the development of a federal
renewable portfolio standard (RPS). In addition, current political environments are shifting focus
from items such as the extension of federal incentives for renewables and portfolio standards to
EPA's development of greenhouse gas standards. Accordingly, the 2013 IRP Update assumes no
federal RPS requirement over the course of the planning horizon.
New Source Review / Prevention of Significant Deterioration (NSR / PSD)
On May 13,2010, the EPA issued a final rule that addresses GHG emissions from stationary
sources under the Clean Air Act (CAA) permiuing programs, known as the "tailoring" rule. This
final rule sets thresholds for GHG emissions that define when permits under the New Source
Review (NSR) / Prevention of Significant Deterioration (PSD) and Title V Operating Permit
programs are required for new and existing industrial facilities. This final rule "tailors" the
requirements of these CAA permitting programs to limit which facilities will be required to
obtain PSD and Title V permits. The rule also establishes a schedule that will initially focus
CAA permiuing programs on the largest sources with the most CAA permitting experience.
Finally, the rule expands to cover the largest sources of GHGs that may not have been previously
covered by the CAA for other pollutants.
3 Presidential Memorandum - Power Sector Carbon Pollution Standards, June 25, 2013.
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PACIFICoRP _ 20 I3 IRP Upoerg CHAPTER 2 _PLANNTNG ENVIRONMENT
Guidance for Best Available Control Technology (BACT)
On November 10, 2010, the EPA published a set of guidance documents for the tailoring rule to
assist state permitting authorities and industry permiuing applicants with the Clean Air Act PSD
and Title V permitting for sources of GHGs. Among these publications was a general guidance
document entitled "PSD and Title V Permitting Guidance for Greenhouse Gases," which
included a set of appendices with illustrative examples of Best Available Control Technology
(BACT) determinations for different types of facilities, which are a requirement for PSD
permitting. The EPA also provided white papers with technical information concerning available
and emerging GHG emission control technologies and practices, without explicitly defining
BACT for a particular sector. In addition, the EPA has created a "Greenhouse Gas Emission
Strategies Database," which contains information on strategies and control technologies for GHG
mitigation for two industrial sectors: electricity generation and cement production.
The guidance does not identiff what constitutes BACT for specific types of facilities, and does
not establish absolute limits on a permitting authority's discretion when issuing a BACT
determination for GHGs. lnstead, the guidance emphasizes that the five-step top-down BACT
process for criteria pollutants under the CAA generally remains the same for GHGs. While the
guidance does not prescribe BACT in any area, it does state that GHG reduction options that
improve energy efficiency will be BACT in many or most instances because they cost less than
other environmental controls (and may even reduce costs) and because other add-on controls for
GHGs are limited in number and are at differing stages of development or commercial
availability. Utilities have remained very concerned about the NSR implications associated with
the tailoring rule (the requirement to conduct BACT analysis for GHG emissions) because of
great uncertainty as to what constitutes a triggering event and what constitutes BACT for GHG
emissions.
New Source Performance Standards (NSPS) for Greenhouse Gases
On December 23,2010, in a settlement reached with several states and environmental groups in
New York v. EPA, the EPA agreed to promulgate emissions standards covering GHGs from both
new and existing electric generating units under Section I I I of the CAA by July 26,2011 and
issue final regulations by May 26, 2012.4 NSPS are established under the CAA for certain
industrial sources of emissions determined to endanger public health and welfare and must be
reviewed every eight years. While NSPS were intended to focus on new and modified sources
and effectively establish the floor for determining what constitutes BACT, the emission
guidelines will apply to existing sources as well. In September 2013, the EPA issued a revised
NSPS proposal for new fossil-fueled generating facilities and withdrew its April2012 NSPS
proposal. The new proposal would limit emissions of carbon dioxide to 1,000 pounds per
megawatt hour (MWh) for large natural gas plants and 1,100 pounds per MWh for smaller
natural gas plants. The revised proposal continues to largely exempt simple cycle combustion
turbines from meeting the standards. The standard for new coal units would be set based on the
availability of panial carbon capture and sequestration technology. The public comment period
will close in May 2014 and a final rule is expected in June 2014.
4 The deadlines for EPA to take proposed and final actions have since been extended. EPA also entered into a
similar settlement the same day to address GHG emissions from refineries with proposed regulations by December
15,2011 and final regulations by November 15,2012,
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PecrICoRp _ 20 13 IRP UPDATE CHAPTER 2 _PLA}.INTNG ENVIRoNMENT
In January 2014, Senate Minority Leader Mitch McConnell (R-KY) filed a resolution of
disapproval in an attempt to block EPA's NSPS for GHG emissions from new fossil-fueled
power plants. A vote has not yet been scheduled on this resolution. In addition, in January 2014
the State of Nebraska sued the EPA in federal district court arguing that the rule's requirements
for carbon capture and sequestration wrongfully rely on federally funded and unviable control
technology. In support of this claim Nebraska relies on a provision of the Energy Policy Act of
2005 which restricts reliance on technology developed with federal assistance when setting
performance standards.
The EPA is also under a consent decree obligation to establish GHG NSPS for modified and
existing sources. Consistent with the presidential directive mentioned above, EPA has indicated
that it will issue a proposed rule for existing sources in June 2014.The proposed rule to be issued
by the EPA for modified and existing sources is to be used by states to develop plans for
reducing emissions and/or emissions intensity and may include targets based on demonstrated
controls, efficiency related emission reductions, or even beyond the fence-line compliance
alternatives intended to meet best system of emissions reduction parameters. States are expected
to be required to submit their implementation plans to the EPA by June 2016 pursuant to the
President's direction. States are expected to have the ability to apply less stringent standards or
longer compliance schedules if they demonstrate that following the federal guidelines is
unreasonably cost-prohibitive, physically impossible, or that there are other factors that
reasonably preclude meeting the guidelines. States may also impose more stringent standards or
shorter compliance schedules.
Several categories of EPA regulations for non-GHG emissions are discussed below:
Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards
The CAA requires the EPA to set National Ambient Air Quality Standards (NAAQS) for certain
pollutants considered harmful to public health and the environment. For a given NAAQS, the
EPA and/or a state identifies various control measures that once implemented are meant to
achieve an air quality standard for a certain pollutant, with each standard rigorously vetted by the
scientific community, industry, public interest groups, and the general public.
Particulate matter (PM), sulfur dioxide (SOz), ozone (O3), nitrogen dioxide (NOz), carbon
monoxide (CO), and lead are often grouped together because under the CAA, 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 CAA, they are regulated
differently from other types of emissions, such as hazardous air pollutants and GHG.
Within the past few years, the EPA established new standards for particulate matter, sulfur
dioxide, and nitrogen dioxide. The EPA is currently tasked with reviewing ozone standards, as
well.
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PecrrConp - 2013 IRP Upoere CHAPTER 2 _PLANNING ENVIRoNMENT
Clean Air Transport Rule
In July 2009, EPA proposed its Clean Air Transport Rule (Transport Rule), which would require
new reductions in SOz and nitrogen oxide (NOy) emissions from large stationary sources,
including power plants, located in 3l states and the District of Columbia beginning in 2012. The
Transport Rule was intended to help states attain NAAQS set in 1997 for ozone and fine
particulate matter emissions. The rule replaced the Bush administration's Clean Air Interstate
Rule (CAIR), which was vacated in July 2008 and rescinded by a federal court because it failed
to effectively address pollution from upwind states that is hampering efforts by downwind states
to comply with ozone and PM NAAQS. While the rule was finalized as the Cross-State Air
Pollution Rule (CSAPR) in July 2011, litigation in the D.C. Circuit Court of Appeals resulted in
a stay on the implementation of the CSAPR in December 201 I . Ultimately, in August 2012, the
D.C. Circuit Court of Appeals vacated the CSAPR in a 2-l decision after it determined the rule
exceeded the EPA's statutory authority. The EPA sought a full review of the CSAPR ruling by
the entire D.C. Circuit; however, in January 2013, the court denied the request. In June 2013, a
petition for certiorari filed by EPA was granted by the U.S. Supreme Court, meaning until the
Supreme Court issues a decision or a replacement rule is adopted and implemented, the CAIR
remains in place.
PacifiCorp does not own generating units in states identified by the CAIR or CSAPR and thus
will not be directly impacted; however, the Company intends to monitor amendments to these
rules closely in the event that the scope of a replacement rule extends the geographic scope of
impacted states.
Regional Haze
EPA's rule to address Regional Haze visibility concerns will drive additional NO* reductions
particularly from facilities operating in the Western United States, including the states of Utah
and Wyoming where PacifiCorp operates generating units, in Arizona where PacifiCorp owns
but does not operate a coal unit, and in Colorado and Montana where PacifiCory has partial
ownership in generating units operated by others, but nonetheless subject to the Regional Haze
Rule.
On June 15, 2005, EPA issued final amendments to its July 1999 Regional Haze rule. These
amendments apply to the provisions of the Regional Haze rule that require emission controls
known as BART, for industrial facilities meeting certain regulatory criteria that with emissions
that have the potential to impact visibility. These pollutants include PMz.s, NOx, SOz, 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 identiffing the facilities
that would have to reduce emissions under BART as well as establishing BART emissions limits
for those facilities.
The state of Utah issued a regional haze state implementation plan (SIP) requiring the installation
of SOz, NO* and particulate matter (PM) controls on Hunter Units I and 2 and Huntington Units
I and 2.In December 2012, the EPA approved the SOz portion of the Utah Regional Haze SIP
and disapproved the NO* and PM portions. Certain groups have appealed the EPA's approval of
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PecnrConp - 2013 IRP Upoare CHAPTER 2 _PLAI.INING ENVIRoNMENT
the SOz SIP. PacifiCorp and the state of Utah appealed EPA's disapproval of the NO* and PM
SIP. In addition, and separate from the EPA's approval process and related litigation, the Utah
Division of Air Quality is undertaking an additional BART analysis for each of Hunter Units I
and2 and Huntington Units I and2, which will be provided to the EPA as a supplement to the
existing Utah SIP. It is unknown whether and how the Utah Division of Air Quality's
supplemental analysis will impact the EPA's approval and disapproval of the existing SIP.
The state of Wyoming issued two regional haze SIPs requiring the installation of SOz, NO* and
PM controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA
approved the SOz SIP in December 2012, but initially proposed to disapprove portions of the
NO" and PM SIP and instead issue a FIP. However, in 2013, the EPA issued a re-proposal of a
NO* and PM FIP which included substantial changes to the control equipment required in the
original proposal. On January 10,2014, the EPA issued a final action which largely approved the
original Wyoming SIP. Ultimately, EPA's final determination requires installation of the
following NO* and PM controls at PacifiCorp facilities: SCR equipment and a baghouse at
Naughton Unit 3 by December 31,2014; SCR equipment at Jim Bridger Unit 3 by December 31,
2015; SCR equipment at Jim Bridger Unit 4 by December 31, 2016; SCR equipment at Jim
Bridger Unit I by December 31, 2022; SCR equipment at Jim Bridger Unit 2 by December 31,
2021; SCR within five years or a commitment to shut down in 2027 at Dave Johnston Unit 3;
and SCR at Wyodak within 5 years. With respect to Naughton Unit 3, EPA indicated its 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. The EPA action became final on March 3,2014.In the meantime, certain groups
have appealed the EPA's approval of the Wyoming SOz SIP which, consistent with the Utah SO2
SIP, required emission reductions of SOz to be enforced through a three-state milestone and
backstop trading program. EPA's final action on the Wyoming NO* and PM SIP may also be
appealed.
The state of Arizona issued a Regional Haze SIP requiring, among other things, the installation
of SOz, NO* and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by
Arizona Public Service. The EPA approved in part, and disapproved in part, the Arizona SIP and
issued a FIP for the disapproved portions. PacifiCorp filed an appeal in the Ninth Circuit Court
of Appeals regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of
Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it
relates to their interests.
Mercury and Hazardous Air Pollutants
ln March 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to permanently limit and
reduce mercury emissions from coal-fired power plants under a market-based cap-and-trade
program. However, the CAMR was vacated in February 2008, with the court finding the mercury
rules inconsistent with the stipulations of Section I l2 of the CAA.
The vacated CAMR was replaced by EPA with the more extensive Mercury and Air Toxics
Standards (MATS) with an effective date of April 16, 2012. The MATS rule requires that new
and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other
non-mercury hazardous air pollutants. Existing sources are required to comply with the new
standards by April 16, 2015. Individual sources may be granted up to one additional year, at the
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PACFICoRP _ 20 13 IRP UPDATE CHAPTER 2 _ PLANNING ENVIRoNMENT
discretion of the Title V permitting authority, to complete installation of controls or for
transmission system reliability reasons. While the final MATS requirements continue to be
reviewed by PacifiCorp, the Company believes its emission reduction projects completed to date
or currently permiued or planned for installation, including the scrubbers, baghouses and
electrostatic precipitators required under other EPA requirements, are consistent with achieving
the MATS requirements and will support PacifiCorp's ability to comply with the final standards
for acid gases and non-mercury metallic hazardous air pollutants. PacifiCorp will be required to
take additional actions to reduce mercury emissions through the installation of controls or use of
sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the
standards.
PacifiCorp continues to plan for retirement of its Carbon facility in early 2015 as the least-cost
altemative to comply with MATS and other environmental regulations. lmplementation of the
transmission system modifications necessary to maintain system reliability following
disconnection of the Carbon facility generators from the grid are underway.
Coal Combustion Residuals
Coal Combustion Residuals (CCRS), including coal ash, are the byproducts from the combustion
of coal in power plants. CCRs are currently considered exempt wastes under an amendment to
the Resource Conservation and Recovery Act (RCRA); however, EPA proposed in 2010 to
regulate CCRs for the first time. EPA is considering two possible options for the management of
CCRs. Both options fall under the RCRA. Under the first option, EPA would list these residual
materials as special wastes subject to regulation under Subtitle C of RCRA with requirements
from the point of generation to disposition including the closure of disposal units. Under the
second option, EPA would regulate coal combustion residuals as nonhazardous waste under
Subtitle D of RCRA and establish minimum nationwide standards for the disposal of coal
combustion residuals. Under either option for regulation, surface impoundments utilized for coal
combustion byproducts would have to be closed unless they could meet more stringent
regulatory requirements. PacifiCorp operates 16 surface impoundments and six landfills that
contain coal combustion byproducts.
The public comment period on EPA's proposal to regulate coal combustion byproducts closed in
November 2010 and the EPA has indicated that the rule will be finalized in2014.In a preamble
to the recently proposed effluent guideline limitations discussed herein, EPA stated that non-
hazardous management of CCRs may be adequate.
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 July 2004, the EPA established
significant new technology-based performance standards for existing electricity generating
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PecHCoRp - 2013 IRP Upoers CHAPTER 2 _PLANNING ENVIRoNMENT
facilities that take in more than 50 million gallons of water per day. These rules were aimed at
minimizing the adverse environmental impacts of cooling water intake structures by reducing the
number of aquatic organisms lost as a result of water withdrawals. In response to a legal
challenge to the rule, in January 2007, the Court of Appeal for the Second Circuit remanded
almost all aspects of the rule to the EPA without addressing whether companies with cooling
water intake structures were required to comply with these requirements. On appeal from the
Second Circuit, in April 2009, the U.S. Supreme Court ruled that the EPA permissibly relied on a
cost-benefit analysis in setting the national performance standards regarding best technology
available for minimizing adverse environmental impact at cooling water intake structures and in
providing for cost-benefit variances from those standards as part of the $316(b) Clean Water Act
Phase II regulations. The Supreme Court remanded the case back to the Second Circuit Court of
Appeals to conduct further proceedings consistent with its opinion.
In March 2011, the EPA released a proposed rule under $316(b) of the Clean Water Act to
regulate cooling water intakes at existing facilities. The proposed rule establishes requirement for
electric generating facilities that withdraw more than two million gallons per day, based on total
design intake capacity, of water from waters of the U.S. and use at least 25 percent of the
withdrawn water exclusively for cooling purposes. PacifiCorp's Dave Johnston generating
facility withdraws more than two million gallons per day of water from waters of the U.S for
once-through cooling applications. Jim Bridger, Naughton, Gadsby, Hunter, Carbon and
Huntington generating facilities currently utilize closed cycle cooling towers but withdraw more
than two million gallons of water per day. The proposed rule includes impingement (i.e., when
fish and other aquatic organisms are trapped against screens when water is drawn into a facility's
cooling system) mortality standards to be met through average impingement mortality or intake
velocity design criteria and entrainment (i.e., when organisms are drawn into the facility)
standards to be determined on a case-by-case basis. The standards are required to be met as soon
as possible after the effective date of the final rule, but no later than eight years thereafter. While
the rule was required to be finalized by the EPA by July 2012, the rule is now expected to be
finalized in the second quarter of 2014. Assuming the final rule in that timeframe, PacifiCorp's
generating facilities impacted by the final rule will be required to complete impingement and
entrainment studies by mid-2015.
El/luent Limit G uidelines
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 April 19,2013, EPA proposed revised effluent limit guidelines and is required,
under the terms of a stipulated extension to a consent decree, to finalize the rule by May
2014. Until the technology-based effluent limitation guidelines are finalized, PacifiCorp is
incorporating proxy compliance costs for certain units reasonably likely to be impacted by the
rule into its business plans and analyses. Of importance to note, the effluent limit guidelines will
also apply to gas-fired generation.
While national GHG legislation has not been successfully adopted, state initiatives continue with
the active development of climate change regulations that will impact PacifiCorp.
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PACIFICoRP _ 20 13 IRP Upoerr Cueprgn 2 -PLANTNTNG ENvTRoNMENT
California
An executive order signed by California's governor in June 2005 would reduce GHGs emissions
in that state to 2000 levels by 201 0, to I 990 levels by 2020 and 80 percent below I 990 levels by
2050. In 2006, the California Legislature passed, and Governor Schwarzenegger signed,
Assembly Bill 32, the Global Warming Solutions Act of 2006, which set the 2020 GHG
emissions reduction goal into law. It directed the California Air Resources Board (CARB) to
begin developing discrete early actions to reduce GHG while also preparing a scoping plan to
identiS how best to reach the 2020 limit.
Pursuant to the authority of the Global Warming Solutions Act, in October 2011, CARB adopted
a GHG cap-and-trade program with an effective date of January 1,2012; compliance obligations
were imposed on regulated entities beginning in2013. 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 October 2013, CARB kicked off an Assembly Bill 32 scoping plan update designed to build
upon the initial scoping plan. The scoping plan update defines climate change priorities for the
next five years and sets the groundwork for post-2020 climate goals. A proposed first update
issued in February 2014 indicated a post-2020 GHG reduction goal of 80 percent below 1990
levels by 2050.
Oregon and Washington
[n2007, the Oregon Legislature passed HB 3543 Global Warming Actions which establishes
GHG reduction goals forthe state that (i) bV 2010, cease the growth of Oregon greenhouse gas
emissions; (ii) by 2020, reduce greenhouse gas levels to l0 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 l0l which requires the Oregon Public Utility Commission (OPUC) to
report to the Legislature before November I 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 I 0 percent below 1990 levels by 2020 and 1 5 percent below 2005 levels
by 2020. The OPUC submitted its most recent report November 1,2012.
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
a new revenue option. The report is to include an evaluation of how to treat imported and
exported energy sources. A final report is expected November 1,2014.
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, rcduce 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. The Washington Legislature
established the Climate Legislative and Executive Workgroup to develop recommendations to
achieve the state's GHG emission limits. The workgroup issued two reports in January 2014;
both reports included recommendations to continue workgroup efforts through 2014.
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PACIFICoRP _ 20 13 IRP UPDATE Cueprsn 2 - PLANNTNc ENVTRoNMENT
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 pounds of carbon
dioxide equivalent per 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 pounds of carbon dioxide per MWh.
As discussed in the 2013 IRP, the Energy Gateway transmission project continues to play an
important role in the Company'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
quantiff 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.
Several Energy Gateway developments have occurred since the Company's 2013 IRP was filed,
including reaching construction and permitting milestones, adjusting in-service dates for future
segments, and developing activities on joint-development projects. Also, in response to feedback
from interested stakeholders, the Company has completed its 2013 IRP Action Plan item to
solicit feedback from stakeholders regarding the System Operational and Reliability Benefit Tool
(SBT) that identifies and quantifies a range of transmission benefits. Please see Chapter 6 for
status updates on the 2013 IRP Action Plan. An updated Energy Gateway map is provided below
as Figure 2.1.
l9
PACIFICoRP _ 20 I3 IRP UPDATE CHapren 2 - PLANNTNG ENvTRoNMENT
Figure 2.1 - Energy Gateway Map
WASHINGTON
*ag
Jr..tril
MONTANA
tg-!
I/sG o IDAHO
MING
CALIFORN IA
!t.(fl-l-t<rloul
NEVADA cotoRADo
ff PrdffCorp retatl scrvk€ arca
Na tranrmirsirn lhcr:
- Sfi) kV mlninum rolage
- 3{5 kV mlnimum volage
- 230 kV mhrnrm rolage
O Existhg srlstetbn
O Ncrv sub.ai:o
Enerry Gateway Transmission Project Updates
Wallula to McNary (Seernent A): The OPUC issued a Certificate of Public Convenience and
Necessity (CPCN) in September 20ll.In2013, 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. Once the customer need decision is made the future of the project will be determined
and communicated to landowners and stakeholders.
Mona to Oquirrh (Segment C): Project construction is complete and the line was placed into
service in May 2013. Mona to Oquirrh is the second major segment of Energy Gateway to be
constructed, following Populus to Terminal (Segment B) which was placed in service in
November 2010. Timing of Oquirrh to Terminal continues to be evaluated and the in-service
date adjusted accordingly. Please see Table 2.1 below.
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
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. Given delays in the permitting activity and the
20
PACIFICoRP _ 2OI3 IRP UPDATE CHAPTER 2 - PLANNING ENVIRONMENT
bifurcation of the ROD, the in-service dates for Gateway West have been adjusted accordingly.
Please see Table 2.1 below for updated segment in-service dates.
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.
Sigurd to Red Butte (Segment G): The BLM issued a final record of decision in December 2012.
ln March 2013, a CPCN was issued by the PSCU. Construction began in May 2013 and the
project is on track to be placed into service in June 2015.
West of Hemingway (Seement 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 PacifiCorp's Oregon, Washington and California
customers. 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, the Company
has continued to pursue alternative joint-development opportunities on other proposed lines west
of Hemingway. In January 2012, the Company signed a permitting agreement with Idaho Power
and the Bonneville Power Administration (BPA) on the proposed Boardman to Hemingway
project. PacifiCorp further notes that it had a memorandum of understanding with Portland
General Electric Company (PGE) with respect to the development of Cascade Crossing that
terminated by its own terms. PacihCorp had continued to evaluate potential partnership
opportunities with PGE once it announced its intention to pursue a Cascade Crossing solution
with BPA. However, because PGE decided to end discussions with BPA and instead pursue
other options, PacifiCorp will not be actively pursuing this development. PacifiCorp will
continue to look to partner with third parties on transmission development as opportunities arise.
able 2.1 - Enersv Gatewav Sesment In-Sr rvice Dates
Segment A: Wallula to McNary 2013-20r4 Sponsor 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 June 2015
Segment H: West of Hemingway Sponsor driven
stnce
21
PACIFICoRP - 20 I 3 IRP Upo.IrE CHAPTER 3 _ RESoT,RCE NEEDS ASSESSMENT UpoaTT
CHAPTER 3 _ RBSOURCE Npgos ASSpSSMENT
Upoars
This chapter presents the update to PacifiCorp's resource needs assessment, focusing on the
2014-2023 planning period covered by the fall 2013 ten-year business plan (Business Plan).
Updates to the Company's long-term load forecast, resources, and capacity position are
presented and summarized.
Load Forecast
PacifiCorp's Business Plan reflected an updated load forecast finalized in June 2013. Relative to
the load forecast prepared for the 2013 IRP, PacifiCorp system sales initially decrease in the
short term and then increase over the planning period. The primary driver of the changes in the
forecast are an increase in the industrial forecast due to improving economic conditions and a
decrease in the residential forecast due to changes in energy efficiency and lower average-use per
customer.
The coincident peak forecast decreased through the planning period due to decreases in forecast
residential loads and a relatively flat peak load growth over the last five years. The coincident
peak forecast decreased even though overall loads are increasing due to industrial and
commercial class loads increasing relative to the decreasing residential loads and historically flat
peak load growth over the last five years, which in turn reduces the long-term forecast peak load
growth expectations.
In October 2013, the Company updated the load forecast for the residential class loads. Due to
lower than expected weather normalized residential usage in the summer of 2013, the Company
incorporated February through August 2013 actual loads for the residential class. The change
between the October 2013 forecast and the June 2013 forecast reflects the changes in the
residential forecast. The October 2013 load forecast is used for the 2013 IRP Update resource
needs assessment.
Tables 3.1 and 3.2 rcport the October 2013 Q0l3lRP Update) annual load and coincident peak
load forecasts, respectively. Note that 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.
23
PecrrConp - 20 13 IRP Upnars Cgeprgn.3 -RrsoURCE NEEDs AssessugNT UPDATE
Table 3.1 - October 2013 Q0l3 IRP Update): Forecasted Annual Load Growth, 2014
through 2023 (Megawatt-hours)
2014 61.671.810 14.y23.3ffi 4.486.7W 893.190 25.045.480 0.363.830 3.718.360 22q.890
2015 63220.770 15.189220 4.518200 8%.110 25.029.690 0.579.850 3.744.330 2263.370
2016 63.s43.020 15.330.480 4.567.610 902.370 27.06/..tw 0.799.120 3-777-310 l-l0l-950
2017 63.426.044 15.523.770 4-592.920 903.900 27-ffi1-650 0.943.s00 3.800.300
2018 64.379.000 15.654.580 4.630.880 907.500 28-254.680 1.103.180 3.828.180
2019 65.325.3ffi 15.794210 4.668.890 9tt.2N 28.825.4n 1.268.210 3.857.430
2020 65.909.690 15.958.3,10 4.715.380 915.940 29.n3.s20 1.456.530 3.889.9E0
2021 6?.6r.5.770 16.038.280 4.736.y70 916.E50 30.487.500 r.572.410 3.9t3.7fi
2022 68.636.570 16.176.320 4.772.sfi v20,630 31.103.380 1.719.810 3-943-8,0
2023 69-701-V20 16.336.850 4809.360 EA-510 3l^783-990 1.870.410 3.95.900
2014-2023 1.37o/o l.0lo/o 0.77o/o 0.38%2.6Eo/o 1.52o/o 0.75o/o
Table 3.2 - October 2013 (2013 IRP Update): Forecasted Annual Coincident Peak Load
(Megawatts)
20r4 9.984 229s 733 t45 4.505 t.3ll 67 327
2015 10.152 2.338 738 147 4.574 1.335 691 330
2016 10,u2 2,3s7 7M 149 4.729 1,358 7M
2017 10.210 2,395 749 149 4-828 1.378 7tt
2018 10.3s2 2.416 759 50 4.915 1.3l)6 716
2019 10.483 2.438 7ffi 5l 4.98 1.415 721
2020 10,777 2,465 767 50 s243 t-433 718
2021 t0-929 2.488 773 5l 5-334 1.4s0 733
2022 11.076 2.s12 778 52 5.426 r.467 7q
2023 11.232 2.538 7U 53 5.527 1.485 746
2014-2023 l32o/o l.l2o/o 0.74o/o 0.52o/o 230o/o 1.39o/o 1.25o/o
Tables 3.3 and 3.4 report the June 2013 @usiness Plan) annual load and coincident peak load
forecasts, respectively. Note that 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.
24
PACFICoRP - 20 13 IRP UpoErS Cuarrsn 3 - RESoURCE NEEDs ASSESSMENT UpDATE
Table 3.3 - June 2013 (Business Plan): Forecasted Annual Load Growth,2014 through
2023 (Megawatt-hours)
2014 62-L71-830 15.005.950 4.489.050 891.410 2s.394.530 0.375.030 3.727.y70 2"240"8n
2015 63.611.520 t5.276.2N 4.s21.040 893,660 26.333.s90 0.578.830 3.74"830 2.263.370
2016 63.973.4q 5.423.510 4.570,970 899,510 27-40t-880 0.797.7ffi 3.777.860 1,r01,950
2017 63.890.800 5-621-740 4.59('.860 900-720 28-028.7s0 0.941.880 3.800.850
2018 &.876.7N 5-757-330 4.635.330 904.040 28.&9.9s0 1.101.360 3.828.730
2019 6s.851.820 5.898.700 4.673.860 907.350 29.247"&0 L26.2n 3.857.980
2020 67.4U.070 6.074.530 4.7n.800 912.030 30.431.910 1.4s4.2n 3.890.510
2021 68.27t.540 6.157.930 4.742.870 912.560 30.973"840 1.570.050 3.914.2n
2022 69"273.920 6.29.700 4,778,9N 916.100 31,617,430 1.717.390 3.944.m
2023 70.368"520 6-M2.710 4.816.130 919.800 32.325.530 1.867.930 3.976.420
2014-2023 1.39o/o 1.03o/o 0.7Eo/o 0.35o/o 2.72o/"l.50Vo 0.72o/o
Table 3.4 - June 2013 (Business Plan): Forecasted Annual Coincident Peak Load
(Megawatts)
2014 10,086 2.314 735 146 4.586 -312 68 327
2015 l0-u:8 2"358 740 147 4.&9 .335 690 330
2016 0"t44 2.379 746 148 4.810 .357 705
2017 0.317 2.418 752 149 4,911 .377 710
2018 0.463 2.m 761 149 5.001 396 7ts
2019 0-597 2.M3 763 50 5.086 .414 720
2020 0.898 2"492 770 49 5.338 .433 717
2021 1.054 2.515 776 50 5.431 .450 732
2022 1"205 2.540 782 5l 5.s26 .M7 739
2023 1.365 2,s67 787 52 s.a9 .4U 745
2014-2023 1.33o/o l.160/o 0.77o/o 0.48o/"2.30o/"1.38%1.22o/o
Tables 3.5 and 3.6 report the June 2012 (2013 IRP) annual load and coincident peak load
forecasts, respectively. Note that 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.
25
PACTFICoRP _ 20 13 IRP UpoIrp CHAPTER 3 - RESOTIRCE NEEDS ASSESSMENT UPDATE
Table 3.5 - June 2012 (2013IRP): Forecasted Annual Load Growth,2014 through 2023
(Megawatt-hours)
Tables 3.7 and 3.8 show the October 2013 (2013 IRP Update) forecast changes relative to the
June 2012 (2013IRP) load forecast for loads and coincident system peaks, respectively.
Table 3.7 - Annual Load Growth Change: October 2013 (2013 IRP Update) Forecast less
Julne 2012 (2013 IRP) Forecast (Megawatt-hours)
2014 4.698.447 15.150.179 4.479"U8 905.134 25.7t8.951 10.408.489 3.779.47 2.257.219
201s 63.527.998 15.371.tt4 4.510.405 m8.752 26.010.382 10.626.524 3.8r9.y27 2"280.894
2015 63.431.505 l5^638.182 4-s6t-49s 916004 26.478252 r0.856.135 3.868.348 l.l 13.089
2017 63.2M.311 15.821.900 4.587.861 918237 n.0rc.0D 11.012.432 3.895.86r
2018 &.219.328 16.003.367 4.630.2fi7 923.755 n.542.259 11.188259 3.%1.482
2019 6s.183.187 16.181.469 4.672.594 y28,941 28.073.t52 tt-3ffi-999 3.965.432
2020 6.226-672 t6-377-833 4-722-54 935-083 28-622-538 11.563.805 4-004.870
2021 6.917.769 16.491.188 4.746.086 935.580 29.02L169 11.698.580 4.V25.t65
2022 67.814.244 16.652.789 4.7U.Ut 938.914 29.514"5n ll.866.488 4.0s6.614
2023 68.781288 16838-823 4.&25.0s8 942.144 30-M9-623 1L039-497 4086.143
2014-2023 1,030/o 1.180 0.83%0.45o/o L.740h 1.630/o 0.E70h
Table 3.6 -June 2012 Q0L3IRP): Forecasted Annual Coincident Peak Load (Megawatts)
2014 0-331 2.377 79 t4 4,74s 1,3u2 6U 33r
2015 0-494 2-n8 758 t4t 4-826 t-326 701 334
20t6 0.359 2.457 765 t43 4.%0 1.349 714
2017 0.513 2.492 772 t4 5.014 1.371 721
2018 0 687 2-522 803 145 5.100 l-390 7n
2019 0.815 2.547 76 t6 5.194 1.410 732
2020 o-972 2,576 795 144 5,2n LAg 737
2021 1.133 2-ffi 801 145 5-387 1.448 748
2022 1.280 2.631 807 146 5.475 t.67 7il
2023 t-42'l 2,6s9 813 147 5,556 1.487 758
2013-2022 l.l2o/o 1.25o/o 0.87o/o 0.s5%1.77o/o 1.49o/"l.lsYo
2014 0.026.637 (226.819\7.652 11.94 673.471\(4.6s9 /61.067,(16.329)
20ls $a7228\081.8%)7.795 (r2.&2',19.308 (6.674,(75-sET (r7-524
2015 I I l-515 (307-7U2)6.115 fl3.6341 585.1128 (57.01t (91.0381 r 1.139)
2017 179.729 (298.130')5.059 (L4.337 651.631 (68.932 (95.561'
2018 159.672 G48.787)673 (16.2s5',7D,At (85.0791 fl03.302'
2019 to-173 G87-259'G.7M (r7-741'7st-6r,8 (92-789 fl08.0021
2020 683.018 Ar9.493\(7.1&(r9.143 1.3s0.982 0u7.27s'14.8901
2021 748,001 (4s2.908)(9.116 (l8.7301 1.ffi.331 /,126-17o',ll1.405'
2022 822.325 @76-M9',12.281 fl82M.1.s88.783 (L46,-678',12.74
2023 919.732 (s01.973)(l5.698 (r7.634 1.734.367 (l69.087 n0.243
26
PACIFICoRP _ 20 13 IRP UPDATE CHAPTER 3 _RESoURCE NEEDS ASSESSMENT UPDATE
Table 3.8 - Annual Coincidental Peak Growth Change: October 2013 (2013 IRP Update)
Forecast less June 2012 Q0l3IRP) Forecast (Megawatts)
Finally, Tables 3.9 and 3.10 show the June 2013 (Business Plan) forecast changes relative to the
June 2012 (2013IRP) load forecast for loads and coincident system peaks, respectively.
Table 3.9 - Annual Load Growth Change: June 2013 (Business PIan) Forecast less June
2012 Q0l3 IRP) Forecast (Megawatt-hours)
EEII/16.329)2014 (573.617 /r44,229,10.002 /L3.724 G24.42r',(33.4s9 (s1.457)
201s 83,522 (94-914'10.635 rLs.w2'323-208 47.694 05.wn (r7.524
2016 s4t-935 (214.672\9-475 /16.494 y23.628 (58.375](90.488)I 1.139)
2011 644.489 (200.160)8.999 17.517'1.018.731 (70.ssz\(95.011
2018 6s7.412 (246.037's.123 (19.715 1.107.691 (86.899)fi02.752\
2019 6r,8.633 (282.769)1.26 (2l.s9l 1,173.888 04.7W)0u.4s2'
2020 t-2s7-398 (303,303)1.744 Q3,0s3 1.809-372 (09.515 1r4-360
2021 t-353-771 1333.258.)(3.216 Q3-020't-952-671 (28.s30'I 10.875
2022 t-459-676 (353.089)6.94t Q2.814 2-102-833 (49.098'tt2.2t4
2023 1.587.232 G76.tt3'(8.928'Q2.344 2"275.W (71.567)0w.723
Table 3.10 - Annual Coincidental Peak Growth Change: June 2013 (Business Plan)
Forecast less June 2012 Q0L3IRP) Forecast (Megawatts)
2014 (347 (82 09 6 (240)9 1V (3
201s (342)(70)(20)6 (253)9 (l0 (5'
2016 (3rT 000)02)6 (201'8 o
2017 (303'(e7 (23 5 (186 7 (0
2018 (33s'(06 (44',5 (185'6 I
2019 (333)(09 06)5 nq')5 (I
2020 (195)l1 (28 5 (47 4 (8l
2021 QM\(t6 (28^6 (s3 2 (5
2022 (2M'l8 Q9 6 (49 (01 (4
2023 fl89 (2l 09 6 (29 o (2
2014 o45'rc4 /r7'5 (59)t0 (L7',(3
2015 Q46 (50 081 6 (77)9 l1 (5'
2016 (2rs (7&'./L9'6 (2t 8 001
20r7 fi96 (73 e0 5 (03'7 001
2018 o24 (811 (42'4 (99)6 (L2'
2019 (219 (u (23',,4 008'5 /L2'
2020 (74 (85 (25 5 47 J (20',
2021 (78'(88 os 5 M I (161
2022 0s (90'(2s 5 5l I fl5t
2023 (561 (v2'QO,5 73 G (l3'
See also Appendix A for further load details.
PlcrrConp - 20 13 IRP Uponrr CHAPTER 3 _ T{ESoURCE NsTnS ASSESSN,IENT UPDATE
Existing and Firm Resources
The availability and capacity contribution from existing resources have been reviewed and
updated to reflect changes since the inputs were locked down for the 2013 IRP. The most recent
results of this review process are summarized for the 2013 IRP Update and for the intervening
Business Plan, aligning with updates made to PacifiCorp's load forecast since filing of its 2013
IRP as discussed above. Updates to existing and firm resources are presented in two steps - from
the 2013 IRP to the Business Plan and from the Business Plan to the 2013 tRP Update. Updates
applied in each of these steps include:
Business Plan
o Added new, and updated existing contracts to reflect changes between the 2013 IRP and
the Business Plan. Adjustnents to existing firm contracts and inclusion of new sales
contracts result in a net increase of firm sales that average 54 MW annually over the 2014
to 2024 period. Since filing the 2013 IRP, there is also an inuemental 25 MW purchase
in2014.
o The peak contribution of wind resources was updated from 4.2% (2013 IRP) to 4.0%
(Business Plan). The update reflects inclusion of 2011 and20l2 historical data using the
same methodology as described in Volume [[, Appendix O of PacifiCorp's 2013 IRP.5
Updated wind generation profiles.
. Updated reserve obligations for non-owned generation is reduced by 106 MW by 2015.
o The hydro generation forecast is updated to reflect the forecast developed in support of
Business Plan, reflecting then current projections for hydro operations accounting for
planned water conditions, availability, and market prices. Over the 2014 to 2024 period,
the average peak contribution of hydro generation is reduced by l6 MW annually.
2013 IRP Update
o Included ten new quali$ing facility contracts representing approximately l0 MW of peak
capacity that were entered into following development of the Business Plan. These
contracts are scheduled to come online in 2015 and2016.
o Included a new 25 MW sale contract that was entered into following development of the
Business Plan. The contract expires year-end 2014.
Figure 3.1 shows the 2013 IRP Update resource need, prior to acquiring any new resources,
alongside the resource need from the 2013 tRP and the Business Plan. Overall, the forecasted
s PacifiCorp includes a set of sensitivity studies showing resource portfolio impacts of using alternative capacity
contribution assumptions for both wind and solar resources in Chapter 5.
28
PlcnrConp - 2013 tRP Upplre CHAPTER 3 _ ResouRce NEEDS ASSESS}VG,NT UPDATE
need has declined with the most recent needs assessment. Primarily driven by an updated load
forecas! the most recent resource needs assessment shows an average reduction in peak resource
need of approximately 320 MW as compared to the 2013 IRP for the period 2014-2023. Relative
to the Business Plan, the most recent projection of resource need is reduced by approximately
135 MW over the same period.
Figure 3.1 - Capacity Position Comparison, 2013 IRP versus Business Plan versus 2013
IRP Update
r 2013 IRP
I BudnogPtrn
Tables 3.ll through 3.13 reportthe capacity load and resource line items from the 2013 IRP
Update, Business Plan, and 2013 IRP respectively. Differences between the line items for the
2013 IRP and 2013 IRP Update are in Table 3.14, while differences between the line items for
the 2013 IRP and Business Plan are in Table 3.15.
29
PACFICORP - 20 13 IRP Upoers CmpTsR 3 - RESoURCE NEEDS ASSESSMENT UPDATE
Table 3.11 - Load and Resource Balance, 2013 IRP Update (Megawatts)
CCcadarYcr
IheoC q626 6460
Hydrodcctric lll ll0
Rcaem$le 92 82
hrctesc 62 ffi,
QeffyhgFrlities 79 A
Sdc 063) (R8)
lfro0rmedRcscn'es (38) (3CI
DertErirtirg Rrrarca 5J69 5,621
Lrd 6810 q930
Edrtia3 Rcrorcer:
hteaupSle (159 (159
Qass I DSM (319 G29
ErtoUi3rtia 6322 6A12
Haahg Rcscrves (13%) 822 837
EertR:rcrru 822 t37
I:nOtlig*ior+Rrlrrr ll{4 7]19
EatPcitic (375) (658)
DatRalcrotr&gh 7.1% Le,r
20la 2015 ,016 2017 20lE 2019 2020 2021 2022
6,4v q454
t25 t25
82 82
425 312
93 9?
o30 (663)
(39 G06/403 6365
6,7n 6.916
4454 6.454 q454 6454 4454 6,4v
122 125 D5 125 U5 t25
82 82 82 81 8l 79
312 312 312 283 283 283
939t93n8888
(663) (663) (6' (r83) (183) (r83)
08) (38) (30 G8) (39 G06362 5?6s 6r6s 6tr. 6110 6'g)8
7,9)8 7,t3t 7.?95 7,317 7,635 1ln
(r80 o8o (l8o 086) (l8o 086') (l8o (l8o
(329) G29 (329 (32e) (32s) (32e) (32e) (329
6)71 6,.01 6Jr3 5rr8 6Xr0 7,002 7120 7)a2
816 ts2 47 80 894 910 926 941u6 83' eU 860 89a 910 926 9at
7,093 7,233 7 160 1,a7e 1,77a 7912 8pa6 t,183(690) (868) (eer) (r,rl3) o,.oe) Gpes) (r:s6) (1379
2.0/o (0.8.i) (23?0 G.8Pr6) C1.f,6) @7lo) (4.4qO G.eh)
Thcod
Hydmdectic
Rraqr$lc
hrctasc
Qatifyhg Fectitier
Snb
I$a€nacdRcscwcs
WrtErirtirg Rercrcc
l,od
Bistiag Rcsorccr:
Intenop$le
Cbss I DSM
N'etoUigrtic 3,17a
Haahg Rcsaves (1370)
WctRscu al3
IT'ortOtiSeior*Rrrer 35e7
$rtPcitic (27f)
TfcatRererroll&3ir 4.596
\324
n7
38
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99
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3r16
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L1A
n5
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190
86
(207)
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3,403
3,2r
0
0
3,22r
d19
1t9
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(237)
3-7./o
25c[,
774
38
2t
16
(157)
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3,255
t23t
0
0
3,2Sr
4ts
123
3,67a
(1r9}
0.lort
1503
n4
38
21
76
(r56)
(3)
3153
3,29.1
0
0
\303
747
38
2t
7t
(150
(3)
3,22r
3,325
0
0
2543
7n
38
t
7t
(157)
(3)
3,rt5
3349
0
0
1503
7y
38
3
7t
(r57)
(,
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3,382
0
0
2,503
641
38
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053)
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62
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652
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61
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0
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452
as2
3927
Qe2'
(e.F..0
413
tl91 3125
428 432
128 a32
3J22 3;t57
(46e) (sso
(t."li) (3-1c..)
3ra, 3382 3,aU 3112
435 440 M U7(35 a{0 au a17
3,7t4 3,.22 3156 3rt9(see) (633) (7s6) Cr.s)
(4.9/o) (5.P/o) (9.1'ln) (8,77")
TcdRrrcrce 10.G5 10,@4
OUig*ic 9,496 9.64
Rrlrrrr 1,ts4 1,256
olligric +Rrecw 10.R0 10,919
Syr3erPcitic (64, (89t
Rrmnr!&3ir 6.rh 3.TA
9,658 9,618 9,583 9150 9.554 9,914 9.954 9943
9J28 9,695 9,838 9961 ro,E r0,4r,l 10,562 r0:1r7
1239 1.260 \n9 r,295 r.334 r.354 r.373 1393
10.767 10.955 1t,ll7 u263 11.596 u.768 u.985 l2,ll0(r.ls) 0.337) 0.ro (1.713) (lorD 0,854) o.e8r) (2.16,
l.4r,i (0.8,c,O G.6e6) @.n/o\ (6.90 (4.8p6) (5.8C,0 Q.!,6)
30
PACIFICoRP - 2013 IRP UpoArg CHAPTER 3 _ RESoURCE NEEDS ASSESSTVGNT UPDATE
Table 3.12 - Load and Resource Balance, Business Plan (Megawatts)
CCcaderYcar
Ilecd
Hydrodecttic
Rrlcndle
hrrctarc
QueIfuhg Frliticr
S.te
l$a-Oq'!ed Rcccrvca
lDd
BistiagRaorcer:
htcnupSlc
Cbg IDSM
6,626 Affi
tll ll0
92 82
62 662
79S
(738) (730
(3D G8)
Xaohg Rcscrver (13c../o) 833 847
EertR:lcs t33 t17
Elrt ()lliador +Xmerrrr 7 )17 7r6t
EntPaitic (aa3) Oas)
DrtRrecrutrfu:ir 6.loh Len
20ta 2015 20t6 2017 20lt 2019 2020
6ls4 4454 6454 6.4y q454 A4s4 q454 6.454
r25 125 122 125 t25 rB n5 l2382 82 82 82 82 81 8l 79
425 312 3r2 3U 3t2 2A A3 283
8383838}$827878(73S (663) (663) (663) (663) (183) (183) 0a)(38) (38) (30 (38) (30 (38) (38) (3S
6193 6rs5 6rs2 6155 6r5s 6por 6100 6,79t
6En 7.m0 7,113 7221 7.81 7,6n 7,7rt 78'p
08o (l8o o8o (186) (r8o (186) (18o (l8o
ary G2e) 429 02e) 42, (3D) Q2' (329
6357 6,at5 6591 6J06 6972 7,097 12t6 73.1
826 843 858 8n 906 n3 938 955t26 tts tst n2 906 923 93t 955
7'rl3 732t 7,t36 7,57t 7,7t 3p20 tlsa tlrg
oeo) (e73) o,10.) or23) GJ23) (r,2r5) Grs.) oJor)
0S'/c (20'6) (3.7c6) (5."h') (8,Pn) (4.10,6) (5-8q,o) Q.4W
ErtErirtr3Rlrcrcr 6;191 6,6ft
q892 7.m4
o59 (r5'
Q2e) (329
E toUig.lic 61011 6i5f6
TIeod
Hydrodcctric
Rcaer$lc
hrcbese
Qalfyhg Frlitics
S.L
ISo0rlrredRcscn'cc
L.rd
Birtiag Rcrorccr:
IatcmrpSlc
Chsr IDSM
\524 \54n7 n3
38 38
187 190
99 86
(30o @7)(, (1)
W'rtDrirdr;Rrlcrcc 3rf6 3/a03
25c5 1J03 1103 25ts 2.103 \fl3 2,500 2,4n774 n4 747 7n 7A At 62 652
38 38 38 38 38 38 21 2t
212t2133331
1616117t7t7t71O
ofD (l5o (r5o G57) (157) (153) (l0o) (1oI)(3) (3) C,, (3) G) G) (3) (3)
3JS5 3,253 3lrr 3,rt5 3,r$ 3J00 3la4 lJ35
32n 3318 3,350 *n ?,412 3,42 3.473 3J6
00000000
00000000
3J72 3rrt 3rs0 3377 3{t2 ',.12 '173 3F08
.125 43t 436 419 W 41 45t 4X
125 a3l a36 t39 lU a17 a5l aS6
3,697 t,7a9 3j786 3116 3rs6 3rr9 392a 3r6a(u2) (.e6) (s6s) (63r) (667) Ore) CrEo) (82e)
(0J%) QOh) (3Jo6) (5.7.6) (6 506) (996) (9.5s6) 00.e/o)
1,t95 3,244
00
00
l,Vctollfurtic aJrS 3314
Iaahg Rcocrver (13%)4t5 4n
WctRrcru 415 422
ltVct Otll3dor iR:rcrrcr trf0 3,666
IYgtPcitic (294) (263)lWctRrrcrnllhgir 1.9;L 4.rn
IolBrlcrcr lqtl0 10.021 9,648 9,608 9,573 95.O 9.344 9,qX 9,944 9933
Ollfietic 9,99 9.7O 9S?9 9,S3 9,948 10.04 1q384 10,539 1q,689 10152
R;rrrrr 1248 \NB 1252 \n4 L293 lSll 1,350 1,370 1,390 llll
Otli3ric +Rrarrs 10.847 11.08 10381 ll,tl1 ll,2A I lt3g{ ll.R4 11,909 l\Og U:A
sptcrPcitia (R7) (Lm) (1233) (r,469) (1,660 (l,8tl) (2.r9 (2,mS1 (2.13' (2J30)
Eacrel&rir 5.?h L?rt 02rh (LOh) (3.8%) (5.+h> (8.106) (6.0.6) Q.@h> G.f,|
3l
PACTICoRP _ 20 13 IRP Upoarg CHApTER 3 - RESoURCE NEEDS ASSESSMENT UpDATE
Table 3.13 - Load and Resource Balance,2013 IRP (Megawatts)
Calendar Year 2014 2015 2016 2017 201t 2019
Thenml 6,626 6,m 6,454 6A54
Hydroelectric 14 140 135 135
RenewableS5ABS3
Purchase 611 611 398 285
Qualifring Facilities 73 73 73 73
Sale (732) (730) (724) (638)
Non0wned Reserves (103) (138) (138) (138)
frEt &isting Resources 6;100 6499 6,28f 6254
load 7,61 7,188 6,94 7,105
2021
6,454 6,4il 6,4il 6,4* 6,4v 6,4v
132 135 135 135 t35 135
8383839,$80
285 285 285 257 257 2s7
73 73 73 7l 25 25
(638) (638) (63e) (158) (158) (ls8)
(138) (138) (138) (r38) (r38) (138)
6251 6254 6253 6;tO5 6,655 6,655
7,217 7,337 7,455 7,5U 7,697 7,W2
Existing Resources:
Intemrptible (143) (lss) (ls, (15, (15, (ls, (ls, (15, (lss) (15,
Class I DSM (37e) (37e) Q7e) Q7e) Q7e) Q1e) (37e) (37e) (t7e) Q7e)
Erst ouigation 6,539 6$54 6460 6,571 6,683 6103 6921 7p50 7,163 7268
Plannin g Reserves (l 3%)850 865 840 854 869 884 900 9t7 931 Ets
&stReserres 850 865 840 854 869 884 900 917 931 945
Erst OHigetion + Reserrrs 7389 7,519 7 3OO 7,425 7,552 7,687 1$21 7967 E,094 t2l3
nrst Paition (6E9) (1,020) (1,0r9) (l,t7l) (1,301) (1,433) 0568) (t262t (1139) 05s8)
&st Resene ltrlrrgin T/o e/") (3o/o) (5%) (60/o) (g/o) (|ff/o) (5o/o) (T/o) (e/o)
Thenral
Hydroelectric
Renewable
Purchase
Qualifring Facilities
Sale
NonOwned Reserves
West Risting Resources
toad
2,5Vt
751
x
aa<
I
(?-60)
(e)
3166
),2@
2,524
n6
'i6
BI
I
(r60)
(e)
tA91
3,W7
\s03
7n
%
l3
89
(l l0)
(e)
33O2
3,470
2,503
723
'36
)
88
(1 l0)
(e)
3233
3,4n
2,fi3
n6
%
)
89
(110)
(e)
3237
3,516
2,503
a7
%
2
89
(l0e)
(e)
3,159
3,v9
x500
6s0
l9
)
89
(103)
(e)
3,14E
3,s83
\4s7
648
l9
2
85
(103)
(e)
3,139
3,6n
zs$
782
%
l3
89
(110)
(e)
332t
3,X5
\fi3
780
x
l3
89
(1 10)
(e)
3302
3,q7
00
(28) (28)
3337 3319
434 439
434 4t9
t;771 3rlr
(4s0) (sl6)
(tr/o) (yh)
Enisting Resources:
Interruptible 0 0
Class I DSM (28) (28)
WestoHigation 3241 3279
Planning Reserves (13%) Al 426
WestResen$ 421 426
West OHigetion + Resents 3$62 3,705
WestPmition (296) (20t)
West Resenr llhrgin 4% T/o
00
(28) Q8)3442 34sr
47 49
447 449
3,t89 3800
(s87) (667)
(4o/o) (6/0)
0000
(28) (28) (28) (28)
3,4EE 3,521 3555 3,592
453 458 42 M?
453 45E 462 467
3p41 3p79 4,017 4,059
(7041 (820) (r6e) (e20)
(Th) (|tr/o) (l l%) (t3o/o)
Total Resourcec
OHigetion
Resencc
OHigation + Reserrcs
Syrtem Position
Resene *Argin
rq066 9,96
9,78 9,933
\n\ \Dt
11,0s1 1122,4
(e8, (t228)
3% 1o/o
9,ff2 9,5$ q5s3 9lC7 9,490 9,W 9,803 9,7Et
9,7v1 9,9s0 10,125 10254 t0,&9 l0,s7l lq7l8 10,860
\n4 \D4 1,316 1,333 1,3s3 1,374 1,3% rAr2
11,071 112A4 l,4t 11,587 1r,762 11,945 12,111 Dm
(r.46e) (1,688) (1,888) (2100) Q2n) (2,081) (2,308) Q.478)(T/o) (4%) (6vo) (V/o) (91A) (T/") (9 ) (tw/o)
32
PACFICoRP _ 20 I 3 IRP UPDATE CHAPTER 3 _RESoURCE NEEDS AssESsIt{ENT UPDATE
Table 3.14- Load and Resource Balance,20l3lRP Update less 2013IRP (Megawatts)
CCco&rYca 20la 2015 2016 2017 20tt 2019 2020 2021 2022
Ttead
Ilydrodetric
Rcncndlc
hrctrsc
QuaIShg Frlitie:
Sale
l$oOnncd Rcscrycs
frtErirtirg Rrrarcce
lod
Erirtiag Rsorces:
IatctnpSlc
DSM
(lo (4)
50 50
Ertolllgrtia eU) eU)
0000
(10 (10) (lo) (10)
(l) (l) (l) (l)
n272?nm2020n(14) (2' (2' (2'
100 t00 100 l0t22 rll llt lll
(20?) (189 089 e04)
(3r) (3r) 0r) (31)
50 50 50 50(rtS) (r70) (u0) (1r5)
(2O QZ) 8x) {a)(21) (22> (22) (24)
(207) (re2) (re2) (20e)
329 30' 303 320
50$ 4% 4'6 4!6
00
(2' (30)
70)
3l 5l
610
(31) (0
65 lmg, t22
(251) (258)
00
(10) (10)
o) (l)
27?5?o19
Q4) (25)
lm lmlu l(l9
(60) (67)
(31) (3r)
50 50({r) ({E}
(, (q
(s) (6)
(.6) (s.)
lst 163
li v,6
00(10 00I (1)?sx
6363
(2' (2'
100 lo155 tss
(64 (4'
(31) (3r)
50 50
(4s) (26)
(o (3)
(5) (3)
(.e) (2e,
20a 182
1.h 2ch
Eaohg Rcsorer (13!6)(2D GO
EatRarerrar (2E) (28)
Eut Olli3lior +Rrrrrcr (245) (240)
EeatPcitia 3la 362
EatRrlcrrclhgir 9,6 }16
Thcod
Hydrodcctric
RcaewSle
Purciasc
Qalfyhg Frlitir:s
Srh
l$a0uncd Rcscrves
IVertErirtrj Rracrcc
Lod
&isdl3 Rcsourccs:
Iatcrruptblc
Chss IDSM
ItrrctoHigrtic
Eaahg Rcccmcg (13-%)
Sctf,mcru
Sert Ollfutior *Rrrrrrs
W'ctPcitic
WcltRarrrrlfugir
00
26 0)
al
(30 (41)
0 (lo
(40 $7)
66(s0) (er)
(e, (80
0
28
0
n
(86)
(ll)
(rr)
(e7)
3l
t%
0
28
(67'
(9
(e)
(76)
,5
fh
(r.r) 0(0 (q
at
88
03) 03)(47) (4O
66
(66} (1e)
(rlo (ll3)
00
24
22
tl
(10 08,3t
66
(4) (4)
(141) 04'
00
28 28(rs) GrD G02) (106) (roe) G13) Gu)
(11) 0, (13) oo (14) (1, o,ol) (ro (r3) Gl) (14) (ts) (ro
(e6) (r32) Grs) o20) (rx) G2E) (r32)
11 5l 67 72 6a L21 12r
lvo lc6 l.h lc6 lo,6 9/o 3o6
0000
G3) 7 8 (6)
,1rt
8l1l
(18) (17) O0 (18)
(4O (47) (47) (44)
6566(Er) (4r) (.r) (se)
(14, 030) (13O (137)
0000
28?82828
0
28
(58)
(9
(r)
(65)
(28)
o%)
Tcel Rercrccr
OUi;etic
R:ccrra
Olligric +Rcrcea
SyrtaPaitic
Raoru!&3ir
19?8
(284) @0)(37) €'(321) (30'
340 333
?6 vfr
fi62
(26e) (2r'
(3t (33)
(304) (280
3A 3J0
3% lh
304(nT e87)
G7, (37)
(324) €2r)
35{ 3C'
!'/o 3!6
64 50
(147) (157)
(re) (20)
(160 Qm
230 Et
Di T/o
151 t49(r5o o43)(2o) (19(r7o (l6a
127 31r
!n6 1q.
33
PacnrConp - 20 13 IRP Upoare CHAPTER 3 -RESoURCE NEEDS ASSESS}I4ENT UPDATE
Table 3.15 - Load and Resource Balance, Business Plan less 2013 IRP (Megawatts)
CdcadrYccr 20la 2015 2016 2017 20tt 2019 2020 2021 2022 2023
IlcoC
Hy&odcctric
Rracv*lc
Arrcbesc
Qrlfyhg F*litics
Sde
l$o€*lcd Rcrctves
ErrtErirdr3 Rorcrcer
IDd
Birting Rcsourccs
IlterupSle
DSM
oo (o
50 50
EertoEigetic G35) G3t)
000(10) 00 (10)(l) (1) 0)2127n
l0 l0 10(2' (2t (25)
100 100 lm
lot l0l rot
00, (l0o 016)
(3r) 6l) (31)
5050fi(86) (8t (e7)
(11) 0l) (13)
or) (1r) 03)
(e7) (eo Gr0)
198 t97 2lt
396 30h ?h
00
(29 (30)
7 (l)
5t 5l
67
(6) (9
65 tm
9a ll9
(169 (18O
0
(10)
(l)
n
l0
(14)
1m
ll2
(r?c)
(3t)
50
o0s)
(t3)
o3)
(uo
228
loh
0
(10)
o)
)1
10
(20
lm
102
32
0
(10)
(l)
x
9
(25)
tm
99
28
00(r0) (r0)
I (l)
2626
53 53
(2' (2'
100 lm
las las
14 51
Hoahg Rcscrvcs (13%)08) (18)
ErtRrrrrr (tB) GB)
FrrtOlli3lior+Rsm (I53) (f 56)
ErltPcltic 211 215
ErtR:rcrc!&3ir M 476
(31) (3r) (31) (31)
50$5050
51 17 53 76
76710
76710
5E 53 60 t6
u,6t557
l.h 1.,6 l.h 196
Thcod
I{ydrodcaric
Rcacw$lc
Purc,Lase
QdiBhgFdities
&h
IilooOrmed Rcccrveg
NctErirdr3 Rlrarcc
Ird
Bistiog Rcsorccs:
Iatemp$lc
Class I DSM
Scatoili3etic
Eaahg Rrsew* (B7o)
IYctRsrcrr
IYcrt 0Ui3lior *Rercu
IYstPcitic
lWctRrorrlbgir
0004)0
26 0) (0 (0
2222
(30 (41) 8 8
0 (1, (r3) (13)
(4O W) (4?) (4O
6666(s0) (e1) (66) ({e)
(74) (63) (e3) (89
0
€3),
8
(18)
(40
6
(tr)
(120,
0
a
t
I
00
3
6
(4)
(1lo)
(e3)
t9
D6
0
4
1
I
(18)
I
6
(.)
0lD
0
7,
I
(17) (10 (18)
(47) (47) (44)
666(.r) (.r) (se)
002) (r0o (107)
000?82828
o.) 05) (lel
(10) o0, (10)(r0) (ro) G0)
00
8 (6)
1)
ll
00
28 28
(82) (8.)
(lr) (lD(rr) (rr)
000002828?82828({6) (3s) (6s) (6r) (e2)
(o (t (8) (0 Ga(6) (5) (8) (8) (r2)
(et
9l
2.h
(s2) (.0)
2 (s4)
(Vr6) (2P,O
(6e) (r0.) (E.)
20 23 36
W. @/c l'i
o3)
7
(0".,.)
(16)
38
l.h
CIe)
30
ah
Tdel Rrrcrcr
Otllrtic
Rerrr
Olligric+Rerrr
SyrtrrPcilic
Roecrntr&3ir
44?5(r8r) 073)(24) QD(20t 0e,u9u
T/o Z%
52 20
(147) (177)
(19 e3)
060 (?0o)
218 D0
Z.tr'o 2'/o
141 t3!)
(29 (8)
(4) (1)
(33) (9
t74 148
No l%
4
o68,(9
oe0
2X
2Vo
53
(l7l)
(D)
0e3)
2$
T16
54 {0
(2' (32)
(, (4)
(20 (36)
82 76
l',6 lt/o
34
PACIFICORP _ 20 I 3 IRP UpOarA CHAPTER 3 _ RESoURCE NEEDS ASSESSMENT UpoaIe
Figures 3.2 through 3.4 summarize for the 2013 IRP Update annual capacity position for the
system, west balancing area, and east balancing area, respectively.
Figure 3.2 -2013IRP Update, System Capacity Position Trend
rilert Erbtln3 Rerourcer
35
PacrlConp _ 2OI 3 IRP UPDATE CHaprgn 3 - RSSoURCE NEEDS ASSESSMENT UpOere
Figure 3.3 - 2013 IRP Update, West Capacity Position Trend
r.roc
llX
r0,0I
t.a
aaas-6,044
4,0.t
1,0a4
0
Figure 3.4 -2013IRP Update, East Capacity Position Trend
36
PacrICOnp _ 2OI3 IRP UPDATE CHAPTER 3 _RESoURCE NEEDS ASSESSMENT UPDATE
On a total Company basis, the Business Plan sensitivity shows that the peak resource need has
fallen by over 200 MW through 2019 and approximately 100 MW in the later years as compared
to the 2013 IRP. On a total Company basis, the 2013 IRP Update shows further reduction in
resource needs from the Business Plan. This is mainly due to a further reduction in the load
forecast. As compared to the 2013 IRP, changes to the resource needs assessment are driven by
the following:
PaciliCorp East
o Average annual peak loads are forecast 215 MW lower over the 2014-2019 timeframe and 59
MW lower over the 2020-2024 timeframe.. Updates to existing resources and additions of new sale and purchase contracts net to an
average increase in system capacity of approximately 2l MW over the 2014-2023 timeframe.. Updates to non-owned reserves reduce PacifiCorp's planning obligation by 65 MW in 2014
and 100 MW over the20l5-2023 timeframe.
PacifiCorp West
o Average annual peak loads are forecast 124 MW lower over the 2014-2023 timeframe.. Updates to existing resources and additions of new sale and purchase contracts net to an
average decrease in system capacity averaging 66 MW over the 2014-2021timeframe and l0
MW in 2022 and2023.. Updates to non-owned reserves reduce PacifiCorp's planning obligation of 6 MW in each
year of the 2014-2023 planning period.
System
o Primarily driven by lower forecast peak load, the average annual system obligation plus
planning reserves is reduced by 3ll MW over the 2014-2019 timeframe and by 177 MW
over the 2020-2023 timeframe.o After accounting for updates to existing resources, additions of new sale and purchase
contracts, an updated non-owned reserves, the average system capacity position required to
achieve a l3o/o planning reserve margin has improvedby 352 MW over the 2014-2019 period
and by 274MW over the 2020-2023 timeframe.
37
PACTICoRP - 2OI3 IRP UPDATE Cseprsn 4 - MooELTNG AssuNprroNs UpDATE
CrMprER 4 - MOPELING ASSUIT,TPTIONS UPnATB
In line with the 2013 IRP, the study period for both the fall 2013 ten-year business plan
(Business Plan) sensitivity and the 2013 tRP Update studies is 2013 through 2032, with a focus
on the 2014-2023 planning horizon. Updated resource portfolios were developed assuming a
l3o/o planning reserve margin consistent with the stochastic loss of load probability study
included in the 2013 IRP.
PacifiCorp has not made any changes to general inflation assumptions (1.9%) and has not
modified its discount factor (6.882%) in this 2013 IRP Update. PacifiCorp continues to assume
federal production tax credits are expired and that federal investment tax credits for qualifring
renewable resources will expire at the end of 2016.
The Business Plan portfolio modeling was based upon PacifiCorp's September 30,2013 official
forward price curve (OFPC). Portfolio modeling for the 2013 IRP Update was prepared using
PacifiCorp's December 31, 2013 OFPC. All OFPCs in the 2013 IRP and IRP Update are
composed of market forwards for the ftst 72 months, followed by 12 months of blended prices
which tansition to a market fundamentals-based forecast, starting in month 85. An OFPC is
produced for both natural gas and power prices by point of delivery. The fundamentals forecast
for natural gas is selected from three expert third-party sources with consideration given to
underlying supply/demand assumptions, forecast documentation, peer-to-peer forecast price
comparisons, date of issuance, location granularity, and forecast horizon. Natural gas price
forecasts are a key driver of electricity price forecasts, as produced by MIDAS, a production cost
simulation model.
Natural Gas Market Prices
The fundamentals portion of the September 2013 natural gas OFPC is based on expert third-party
long-term gas price forecasts issued between May 2013 and September 2013 with short-term
updates in August 2013. The fundamentals portion of the December 2013 natural gas OFPC was
based on expert third-party long-term gas price forecasts issued between October 2013 and
December 2013 with short-term updates in November and December 2013. Both the September
2013 and December 2013 natural gas OFPCs reflect a fundamentals-based forecast heavily
influenced by cost-effective domestic supply opportunities largely due to growth in
unconventional shale gas plays.
The September 2012 natural gas OFPC, which was used in the 2013 [RP, was based on an expert
third-party long-term natural gas forecast issued May 2012 with a short-term update in August
2012. The September 2012 OFPC also reflects a considerable portion of domestic natural gas
demand being met by unconventional shale production.
39
PacrrConp - 2013 IRP Upoers CgapTgn 4 _ MoDELING ASSUMPTIONS UPDATE
In summer 2012, surveyed expert third-party natural gas price forecasters expected 50% -58%
of 2020 production to come from shale, by summer 2013 expectations had increased to 50% -
67Yo, and by winter 2013 expectations ranged from 50% - 7l%. In the course of one year alone,
2012 to 2013, Marcellus production increased from approximately seven billion cubic feet per
day (BCF/D) to over l1 BCF/D.
Figure 4.1 compares the nominal annual Henry Hub natural gas prices from the September 2012
(2013IRP), September 2013 (Business Plan), and December 2013 OFPCs (2013IRP Update).
Figure 4.1 - Henry Hub Natural Gas Prices (Nominal)
EE
EO
,
E
oz
10.00
9.00
8.00
7.00
6.00
5.00
4.00
3.00 $ u1 \O r- @ O\ a F-r N (v) e 'ln A t-- A q a - N- - - ; 6l N N N d 6t 6l N 6l al (rl (n (noooooooooeoooooaoooc\l 6l (\t Ft N N N N t\l N N 6l N ol c.l (\| (\| N N
-
2013 IRP (Sep 2012) +-Bushess Pbn (Sep 2013) + ZOl3 IRP Updsb (Dec 2013)
Power Market Prices
The natural gas fundamentals forecast described above was a key input to the MIDAS model,
and consequently, the gas curve shape is reflected in the electricity prices from the September
2012, September 2013, and December 2013 OFPCs. Figures 4.2 through 4.5 compare the
average annual electricity prices for the Palo Verde and Mid-Columbia market hubs from the
September 2012, September 2013, and December 2013 OFPCs.
40
PACIFICoRP _ 20 I 3 IRP UPDATE CHAPTER 4 _ MoDELING ASSUN{PTIoNS UPDAIE
Figure 4.2 - Average Annual Flat Palo Verde Electricity Prices
90.@
80.00
E 70.m
E *.*
E ,.*E
2 q.m
30.00
20.m S 'f.) \O t\ 6 O\ e n e{ cQ t Q A h a q Q E cJ--NNNCINNNNNN(n(n(nooooooooooooooooooo({l d 6t (\r ol at N N N Gl o| 6r N N et N cl 6l (\
+2013 IRP(Sep2012) +gudaessPlm (Sep2013) +2013 IRPUpdate @cc2013)
Figure 4.3 - Average Annual Heavy Load Hour Palo Verde Electricity Prices
90.00
80.00
70.00
E *.*
E3 so.ooI
E m.ooz
30.00
20.00 $ r \o r\ & o\ Q n ol (') { ra \Q F a o\ Q E clF 61 6l N N 61 6l N N 6l (\l (n (n (noooooooooooooooooooOl N N N 6I N N N N N 6I (\l 6t N fi 61 6I d 6I
+2013 IRP (Sep 20 12) ...r-Bueiness Plan (Sep 201 3) *20 I 3 IRP Update @cc 20 13)
4t
PecnrConp - 201 3 IRP Upoars CHAPTER 4 _ MoDELING ASSUMPTIoNS UPDATE
Figure 4.4 - Average Annual Flat Mid-Columbia Electricity Prices
$ Y.) \o r- 6 o\ a E d (a1 { ra \o F a 6 a E ol- 6l N N C| e{ N N 6t 61 6t (n (n (noooooooooooooooooooN t\ 6I N 6l 6l 6l 6l N N N 6I N N t\I 6l CI N N
--2013IRP (S€p 2012) +BusiaessPhn(S€p 2013) a26l3 IRPUpdsb@ec2013)
60.00
d!u
$ so.m
E
**
Z m.m
20.00
Figure 4.5 - Average Annual Heavy Load llour Mid-Columbia Electricity Prices
70.00
E *.*
EG
E
50.m
E ao.ooZ
30.00
20.00 t u.) \o r- o o\ Q n cl (Q t rr1 \o .> a o Q E doooooooooooooooooooN N N N t\ N N 6I N 61 61 6I 6l N (\l 6I N 6I N
<-2013 IRP (SeP 2012) ---BusircasPha (Sq 20Il) .a-2pljl IRP Up&E @ec 2013)
After PacifiCorp filed the 2013 [RP, President Obama issued a Presidential Memorandum in
June 2013 directing EPA to issue standards, regulations, or guidelines, as appropriate that
address greenhouse gas emissions from modified, reconsffucted, and existing power plants. The
proposed standards, regulations, or guidelines are to be issued by June 1,2014, finalized by June
1,2015, with implementation of regulations as proposed in SIPs required by June 30, 2016. EPA
would then review the implementation plan proposed by each state, and the effective compliance
42
PacruCoRp - 2013 IRP Upoars Cuaprsn 4 -MooELING Assutv{prroNs UpDATE
dates for these standards, regulations, or guidelines would become applicable sometime
thereafter.
Absent information on how EPA intends to proceed with its rule-making process, and without
any information on how individual states will propose to implement those regulations through a
SIP, there is currently no means to develop a specific CO2 price assumption that accurately
reflects potential CO2 regulation. PacifiCorp's review of current third-pafty CO2 price forecasts
shows that despite issuance of the Presidential Memorandum, these forecasters have not
materially altered either their assumed COz start date or price level. In the 2013 IRP Update,
PacifiCorp continues to assume a COz price signal beginning 2022 at $16/ton escalating at three
percent plus inflation thereafter, and expects to update its COz policy assumptions and scenarios
in the 2015 IRP, taking into consideration the proposed standard, regulation, or guidelines
expected to be issued by EPA later this year.
The topology used in the Business Plan sensitivity and the 2013 IRP Update studies are
consistent with what was used for Energy Gateway Scenario 2 in the 2013 IRP, except the
changes in timing of Energy Gateway Segment D as noted in Chapter 2 of the 2013 IRP Update.
The supply side resource costs and performance parameters did not change from the 2013 IRP,
except that the costs of utility scale solar photovoltaic resources are updated based on a
Company commissioned study completed by Black & Veatch in December 2013. Updated costs
are summarized in Table 4.1, along with those included in the 2013 IRP. The costs of solar
reduced by over l0%o for both single tacking and fixed tilt.
Table 4.1 - Updated Cost of Solar Resources, 20f3$ - (50 MW AC)
For this filing, PacifiCorp performed two sensitivity studies around the performance of
renewable resources and costs of the solar resources. The first sensitivrty study changed the peak
contribution of wind resource to 20.5Yo, and solar resources to 68Yo and 84Yo for fixed tilt and
single axis tracking, respectively. This sensitivity study was requested by the PSCU in its order
acknowledging the Company's 2013 IRP. The second sensitivity was performed using updated
the costs consistent with those shown above, in addition to changes to the peak contributions
consistent with those requested by the PSCU. Both sensitivities are discussed in Chapter 5.
43
PACIFICoFJ - 201 3 IRP UPDATE CHAPTER 5 _PoRTFoLIo DEVELoPMENT
Crnprsn 5 - PonrFoLIo DBvpToPMENT
PacifiCorp used the System Optimizer (SO) capacity expansion optimization model to develop
resource portfolios based on inputs and assumptions updated throughout its business planning
proc€ss. Similarly, the SO model was used to develop resource portfolios for the 2013 IRP
Update consistent with its most recent resource needs assessment as described in Chapter 3. As
was done in the 2013 IRP, the Company devised minimum wind resource acquisition targets for
renewable portfolio standards using the RPS Scenario Maker model and treated these targets as a
minimum fixed resource schedule in the capacity expansion modeling. The Company also
maintained the natural gas resources and the combined heat & power (CHP) resources from the
2013 IRP Preferred Portfolio. Consequently, the Business Plan resource portfolio was developed
by allowing demand side management programs and front office transactions (FOTs) to balance
system capacity and energy. The 2013 IRP Update study was developed by allowing for a fully
optimized selection of resource alternatives. This chapter first describes the development of the
wind resource addition timing, and then presents the 2013 IRP Update and Business Plan
portfolios along with comparisons to the 2013 IRP Preferred Portfolio.
Renewable Enerry Credit Value
Parties in Utah questioned PacifiCorp's treatment of renewable energy credits (RECs) in the
2013 IRP; as such the PSCU requested the Company address two specific issues in this IRP
Update. These were the risks of relying on unbundled RECs as opposed to physical resources,
and inclusion of the value of a REC as an offset to the cost of a renewable resource.
The Company expressly addressed the risk of relying on unbundled RECs in the 2013 IRP.
Specifically, the determination of the preferred portfolio was made after calculating the cost and
financial risk of meeting incremental renewable portfolio standard (RPS) compliance in
Washington using physical resources.u This analysis showed that on an expected value basis,
unbundled REC prices would need to exceed $514/twh before the unbundled REC strategy
would prove to be higher cost than meeting Washington RPS obligations with physical
resources. Similarly, when the stochastic risk benefits of physical wind resources were factored
into this analysis, PacifiCorp's study showed that unbundled REC prices would need to exceed
$48/I{Wh for the physical supply strategy to be more cost effective. Based on its participation in
the REC market, PacifiCorp does not expect unbundled REC prices to reach, let alone exceed,
these levels and that pursing a physical compliance stategy would increase costs for Washington
customers. In fact, PacifiCorp has already been using unbundled REC purchases to satisff
Washington RPS requirements.
6 PacifiCorp notes that existing physical resources have been and will continue to be used to meet Washington RPS
requirements. Use of unbundled RECs is planned for meeting incremental Washington RPS needs as the target
grows over time.
45
PacrICoRp _ 20 13 IRP UPDATE Cseprsn 5 -Ponrrolro DEVELoPMENT
PacifiCorp's experience in the REC market leads it to believe that it is unlikely it will be unable
to purchases sufficient tradable RECs to cover its Washington and California RPS compliance
obligations. As identified in the 2013 IRP Action Plan, PacifiCorp has identified the steps it will
take to procure unbundled RECs required for RPS compliance, including issuance of requests for
proposals (RFPs) seeking both current-year and forward-year vintage unbundled RECs. By
continuing to monitor REC availability and pricing through these competitive solicitation
process, PacifiCorp can readily observe potential, yet unlikely, changes in the REC market that
would limit opportunities to purchase unbundled RECs as needed for the Washington RPS.
Considering that PacifiCorp does not have an incremental need for Washington RPS RECs until
2016, and further considering that this incremental need can be deferred using flexible banking
provisions allowed in the Washington RPS, the Company has the flexibility to pursue alternative
compliance strategies, including compliance with physical supply, should circumstances change.
PacifiCorp continues to assume in its 2013 IRP Update that incremental Washington RPS
requirements will be met with unbundled REC purchases.
As to the inclusion of a REC value as an offset to renewable resource costs, this assumption
would ascribe a monetary value that PacifiCorp could not realize, and is therefore, inappropriate
as a means to justify acquiring physical renewable resources. The recommended approach is not
suitable for renewable resources that are being added to the preferred portfolio for purposes of
complying with a RPS. This is not practical for a load serving entity having to meet an RPS
obligation, which effectively requires that a REC be "retired" when used for RPS compliance,
making that REC unavailable for sale, and therefore, eliminating the ability to monetize the
unbundled REC as a means to offset project costs. If a renewable resource is added for a reason
other than RPS compliance, given current REC market conditions, it is not appropriate to assume
REC revenues can offset the cost of the renewable project over the life of the asset. The REC
market lacks transparency, and while the Company is comfortable assessing the upper limits of
REC prices going forward, the lack of transparency makes it inappropriate to assume a pre-
determined REC revenue stream that can offset renewable resource costs over a 25 to 30 year
period. Moreover, the sale of unbundled RECs can limit the use of the underlying "green
attributes" associated with the REC, limiting its potential use for meeting future environmental
compliance obligations to reduce greenhouse gas emissions. PacifiCorp has not assumed a REC
value as an offset to renewable resource costs in the 2013 IRP Update.
Wind Resources
Table 5.1 presents a comparison of the wind additions from the 2013 IRP Preferred Portfolio,
Business Plan, and 2013 IRP Update. The projected wind capacity additions declined somewhat
from the 2013 IRP to the Business Plan, and again from the Business Plan to the 2013 IRP
Update. The main drivers include updated regulatory assumptions, decline in forecasted load,
and an overall increase in forecasted generation from current renewable resources. The capacity
additions decrease in2024, but those decreases are partially offset by 2025 increases. As was the
case in the 2013 IRP, wind resources included in the resource portfolio are not economic and are
included to meet state RPS obligations.
The capacity additions in the IRP assumed implementation of a Federal RPS standard. The
assumed federal RPS requirements were applied to retail sales, with a target of 4.5 percent
beginning in 2018, 7.1 percent in 2019-2020,9.8 percent in 2021-2022, 12.4 percent in 2023-
2024, and 20 percent in 2025. However, since 2010, no significant activity has occurred with
46
PACFICORP _ 20 I 3 IRP UPOETE CHAPTER 5 - PORTFOLIO DEVELOPIVIENT
respect to the development of a federal renewable portfolio standard. In addition, current
political environments are shifting focus from items such as the extension of federal incentives
for renewables and portfolio standards to EPA's development of greenhouse gas standards.
Accordingly, at this time the Company does not have a basis to make assumptions regarding any
future federal renewable portfolio standard.
Table 5.1 - Wind Additions,2013IRP Preferred Portfolio, Business Plan,2013 IRP Update
Renewable Portfolio Standard Compliance
Table 5.2 summarizes the forecasted state annual RPS targets as defined by each state's RPS
program, the forecasted annual megawatt-hour RPS requirements, and the quantity of megawatt-
hours available from existing eligible renewable resources. The RPS Scenario Maker model is
used to ensure compliance with RPS requirements through the planning period.
The RPS Scenario Maker model uses retail sales forecast inputs, state-specific targets, state
specific banked REC balances, forecasted generation from existing RPS-eligible renewable
resources and cost and performance assumptions for potential new resources to optimize the
type, timing, and location of additional renewable resources needed to meet future RPS
compliance obligations. The RPS Scenario Maker model considers compliance flexibility
mechanisms specific to any give RPS program including unbundled REC rules and banking rules
that cannot be configured in the SO model to establish a least cost renewable resource mix that
meets RPS requirements.
This RPS compliant wind schedule is shown above in Table 5.1. Note that acquisition of an
incremental 549 MW and 480 MW of wind for the Business Plan and 2013 IRP Update
respectively, is needed to comply with RPS requirements through the planning period. An
overview of the RPS compliance picture for each state is provided below.
47
oo+
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c
PaCTTICORp _ 20 13 IRP UPDATE CHAPTER 5 _PoRTFoLIo DEVELoPMENT
For reference, Figure 5.1 indicates how RPS compliance is forecasted to be met through2022
using current tRP Update assumptions. Figure 5.2 shows the compliance forecast for the
Business Plan. These two sets of graphs are limited to the compliance forecast for the states, as
the federal RPS assumption has been dropped. For comparison purposes, Figure 5.3 has the RPS
compliance forecast as included in the 2013 IRP.
Figure 5.1 - 2013 IRP Update RPS Compliance Position
Oregon RPS Compliance Outcome
12,(m
lOpm
t(I)o
5,(trO
a,(I)o
2,mo
0
2013 2014 2015 2m5 20t7 20ra 2019 2020
-Ul$ddbdltcsq..ld.rd
slNkr&da.nt$miH
IGrrcil Yrtuffi Sumddrd
-Yr.d
lulld g.*Llm
@Y-.d Urtud.d EC hnl &lm
-Aill
ne&ffd
Washington RPS Gompllance Outcome
7m
6(I,
50)
a /rmit9:m
2m
1q)
o
2013 2014 2015 2m6 2017 20,tA 2019 2@O 2021 2Ut7
rurtrniditcCrrfitrad Nlurdadlst$rhdand
Icumd Ya G6..h9-riid.d IYtld &rdhd 3r*8dre
@Yr+rd
Callfornla RPS Compllance Outcome
3(I)
2v,
2q)
E] rso(,
1m
50
0
2073 2011 2015 2016 2071 70tA 2019 2020 20rt
rurtondbdrCcsrsir.d N&rd.d!.nlsomnd.rtd
-CumnYrhdlmsfirJ-rd
rY*+dEutiLd&il&l@
@!Y{ird Ur$und.d REC 8.nl hlmo
-Arul
Redr.mnl
Fcdcral RPS Compllance Outcomc
l{ot Appllcable
PACTFICoRP - 2013 IRP Upnnrs CHAPTER 5 _Ponrror-Io DBwLopw,Nr
Figure 5.2 - Business Plan RPS Compliance Position
Oregon RPS Compllance Outcome
10,(m
9,(m
8,(m
7,m
I 6.(I)0
= s,mo9 l,m
3,(m
21I!
1,(m
0
2013 2014 2m5 2016 2077 2(nA 2019 2@0 2g21 2gt2
IurtendLd lEC SE6d.nd NBurd.d a.nltorrrd-.d
Ivorcri torihd &nlhLno
EYr{dUtunnd
Washlngton RPS Compllanc€ Outcome
7(n
6(x)
5(D
a 4(n
=93m
2@
1(I)
0
2013 2014 2015 2015 2017 2018 2019 2(n0 2s2.1 2422
I(fitu.dbdnEcsuodrld Ntund.dhl$mid.r.d
ICudil Y*GanaEtldlrMdafld lYfraid luidLd Bol( lds6
@Y.rr{rd Unbund.d l[C bk Bdr6
-Amol
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Callfornla RPS Compliance Outcome
3(I)
250
2(I,
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=
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o
2013 2(n4 2(ns 2016 2st7 20tA 2Ct9 zqn 2C2t 2022
rudoidadltcirrEdarad N*r.d.dblhdrrd
IClmiYu (lEffi lrridr.d rY*{d MH hl&Lno
Federal RPS Compllance Outcome
l{ot App!lcable
Figure 5.3 -2013IRP RPS Compliance Position
Oregon RPS Compllance Outcome
12,00
10,0@
8,@0
5 .,.0(,
'1,O0
2,O0
0
2013 2014 2m5 2016 2017 2018 2019 2(20 2021 2022
ruilondlditcsurrnd.nd Sllund.dLnls'rdaffi
romnY-hl&hfu rYr{dHHHbh
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WashlnSlon RPS Compllance Outcome
2013 2O1,t 2015 2015 20d7 zota 2019 2o2O 2o2t 2022
-U&ndldffiffird
N8lll#b*ffid.d
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:!{D
250
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! rsootq,
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0
2013 20t1 2015 20t6 20tf 20ta 2019 2(,20 2021 2@,2
rurtq|dbd8Esurtd.od @&ndhlsafu
-cmilYr&mtu$mnddd
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Federal RPS @mpllance Outcome
12pq,
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8,(nO
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2013 2014 2015 2(}16 2017 2018 2019 2(n0 2027 2(p2
-t,ffiffi$rilrtr
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@Yo{d thmd.dllc htLbr-bud t{dffi
50
PecnrConp - 2013 IRP Uppare CHAPTER 5 _PoRTFoLIo DEVELoPMENT
The 2013 IRP Update focuses on changes that occurred after PacifiCorp filed its 2013 IRP and
includes comparisons to the resource portfolio developed for the Business Plan. These primarily
involve updates to load forecasts, and any additions to the Company's contract assortment.
Table 5.3 summarizes the annual megawatt capacity, timing and differences in resources for the
2013 IRP Update and 2013 IRP preferred portfolios for the comparative lO-year period of 2014
through 2023. Consistent with the reduction in resource need, driven primarily by a lower load
forecast, the addition of new resources was reduced in the Business Plan and again in the 2013
IRP Update resource portfolios. This is primarily evident with reduced reliance on FOTs, and
given the relatively minor changes in demand side management (DSM) resource selections,
PacifiCorp has not modified its 2013 IRP Action Plan and continues to target accelerated
acquisition of cost-effective energy efficiency. Outside of the first ten years, the first major
thermal resource is deferred from 2024 (2013 IRP Preferred Portfolio) to 2027 (2013 IRP
Update), and as discussed above, wind resource needs in the 2024-2025 timeframe have been
lowered by 170 MW. Table 5.4 summarizes the 2013 IRP Update load and resource balance for
2014-2023, and Table 5.5 displays the detailed 2013 IRP Update resource portfolio through
2032.
5l
PACIFICORP _ 20 I3 IRP Uponrs CHeprrn 5 -Ponrrolro DEVELoPMENT
Table 5.3 - Comparison of 2013 IRP Update with 2013 IRP Preferred Portfolio
fiod Ofu tcrtirns irresorc oal art lGltu nragr. '
2013 IRP - Prefcmrd Portfofio
lm ItI,
2altt ilu ,I3 ,0ta 'ot7 ^,,ola frb tctl t*at lrrr I-l
6{5 613
k:- Perkir Efti6'115 ll7 103 l0l 91 9:o0 81 80 ll 68 otD
{6
- flidnill S.il,I t{l8 11 t.{l4 li l5 l5 l$
:odrirdllcet& Pmu I I I ll
7fl0 L I IJ I l0l ta7 It,
hrhIntb.
larlF*'RaimC (50:RM
DL*Fd-^er#
;oal H:r Gls Collrrioo Addibls l3E 338
Iirtin l-iomdcs 14
forll ?91 l-t86 m,1.102 lllS l-1lt l-!21 lJlS l:87 l-fin lslt
Fro[ Ofu Trcrtbos bresqJrcc oEl ert l01trr ltnge. t
52
PACFICoRP - 2OI3 IRP UPDATE CHAPTER 5 -PoRTFoLIo DEVELoPMENT
Table 5.4 - 20[3IRP Update Capacity Load and Resource Balance
2016 2011 201t 2019 2020 2021
Theml
Ilydmelecuic
Raewble
Purchce
Quali$ing Frcilitics
Sale
l.IotrOmed Rcscryos
Tmsftn
EEt &i!6n8 R.!uct! 1162 1,132
Corbined heat md Forcr 0 I
Frcnt Offce Tmsrctions 0 0
&s00
Wild 0 0
Sole 2 4
Other 0 0
btPl.ednd@rca 2 5
DttTocd n luccr 7551 1.111
6454 6.454 6,4v 6,454125 t25 tn n5
82 g2 82 82
425 3t2 312 3t2
93 93 93
(R8) (663) (653) (663)
(38) (38) (38) (38)
491 615 6n 5M
6195 5pr0 69t9 6949
6,454 6,4y 6,4y 6,454
tE t25 t25 tU
8a818179
3t2 2s3 A3 83
v) 8t 88
(653) 083) (183) (183)
(38) (38) (38) (38)
903 650 7& 1
125t 1464 75s0 7506
4466
1010043
0000
0000
13 15 t8 2'0000
llt t9 21 59
1)85 lAEa 7F14 7675
1,395 7,511 7,635 1,757
6,626 6,460
lll ll0
v) a2
62 62
7983
Q63\ (738)
(38) (38)
zEt 5ll
33
00
00
00
6E00
911
33
a t7t
00
00
l0 t200
77 tt6
5105 6191 1066 7,t35
6,N2 6,916 7,028 7,1336,8t0 6,%0
Erdsting REsourc$ :
Intemptiblc (lse) (159) (186) (186) 086) (186) (186) 08O (l8O (186)
Class I DSM (3?9\ (32e) (32e) (3ze) (32e) Qze) Q2e) Oze') Q2e) (3ze)
NwRaourccs:
ClasslDBM 0 0 0 0 0 0 0 0 0 0
Class 2D8M (105) (152) (l%) (u4') (28e) (330) (370) $aD (443) (478)
EEtouitdi@ 6217 5290 5rtl 6'ls7 6221 6rEE 6510 6595 5$71 6J64
PfanoingResencs (137o) 808 818 791 800 809 817 8,16 857 868 879
EltRscro tot ElE 791 t00 t09 tl7 t45 t57 E5t 479
trrtouig.tio+n lcre! 1P25 7'l0E 6812 5951 7'033 7'105 7356 7452 7541 1543
ErtP6itim 39 29 33 34 33 30 30 31 29 12
ht RBGru l&rtitr 14% l3o/o l4o/o l4yo l4/o l3'/o l3o/o l3o/o l3o/o 13%
Themrl \5U 2,5U 2,506
$drcelectric m T5 n4
Rcnemble 38 38 38
Purch$e lE7 190 2l
Qualifying Frcilities 99 86 76
Sale (306) (M 05,
Nonomed Reservcs (3) (3) (3)
Tmsftn (29i) (512) (493)
WcltHldr8 nBrucB 3P2a 2r9l 2J52
Codbined hest ud Fowr | 2 2
FDnt Oftc Tmsrctions 503 659 Tn
G6000
Wind000
Solsr 0 0 0
Other 0 0 0
WcltPlredRtlarcGr 504 551 795
W.ltTotrl Rdarcd t521 3552 3557
load 3,174 3Pl 3,251
L503 2,503 2,503 2,fi3 Zflt 2,500 2.91
v4 70 730 734 st 652 652
3E 38 38 38 38 2t 2t
212t3 133r76 7t 7t 7t 7t 7t 61
056) (156) (r57) (157) (r53) (100) (ro2)
(3) (3) (3) (3) (3) (3) (3)(516) (52e) (585) (eos) (651) (740) (800)
2517 2592 2599 22t1 2A49 2AO1 2135
3344556939 989 989 1.325 I,178 t24t 1,325
0000
0000
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00942 992 993 t)29 1,113 1215 rrSr
t57e 35E4 3F92 3613 '5t2 3650 3666
3,294 3,325 3,349 3,382 3tt2 3,442 3,475
Eiistirg R6ourcs :
Inremptible0000000000
ChsslDSM 0 0 0 0 0 0 0 0 0 0
New R6ources:
ClasslDSM 0 0 0 0 0 0 0 0 0 0
o8s 2DsM (60) (84) (loe) (13, (158) (175) (187) Qa]) (218) (240\
WcltoBitdio 3,11,1 3,111 3,142 3'159 t,161 3,114 3'195 3109 1221 3r3S
Plming Reserues (137o) 405 ,lO8 ,tO8 4ll 412 413 4t5 417 419 Al
WcltRrlcmr 405 il0t 40t 4ll 412 ,413 il15 411 419 421
Wcltouitdio + R.lcru! 3519 3,545 3550 3570 3F19 3,5t7 3,510 3626 1513 3,556
W6tP6ilioa71955367l0
Wst Rtlcru l}turitr lv/o l3yo l!/o 13% l!/o l!/. l3o/o l!/o 13% l!/o
Toad n loreq 10,591 10,68!)
Ouigaio q33l 9,427
Rcrcro l2l3 1,26
OHit.lio + Rsrru! 10,544 1q653
S}lbDP6iiio 47 36
n lcru li,tu8ltr le/. l3o/o
t0,62 10,570 1q650 to,7n 10,999 ll,ll5 ltp{ ll,341
9,U 9,316 9,391 9,$2 9,705 9,8& q90t 9,999
I,l9 t?ll t,Dl t,Bo 1,262 1275 t,287 l,3m
rc,4n rc,s27 10,612 t0,92 1q967 il,o79 n,lE8 n,299,10 43 38 35 32 36 36 42
t30/o 13% t30/o t3% tT/o 130/o 130/o t3%
53
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PACFICoRP _ 2OI3 IRP UPDATE CHAPTER 5 _PoRTFoLIo DEVELoPMENT
The Business Plan expansion resource portfolio is similar to the 2013 IRP Preferred Portfolio
with the exception of DSM and FOTs. The DSM values are slightly different from what were in
the 2013 IRP Preferred Portfolio due to updated and slightly lower load forecast, and the changes
in FOTs reflect the change in resource need as described in Chapter 3.
Table 5.6 summarizes the annual megawatt capacity, timing and differences in resources for the
Business Plan resource portfolio and the 2013 IRP Preferred Portfolio during the comparative
ten-year period of 2014 through 2023. Major changes within the ten-year period include
reduction of FOTs and DSM. Outside of the front ten-years is a reduction in wind resources by
248megawattin2024, partially offset by an increase of 147 megawatts in 2025.
Table 5.7 shows the capacity load and resource balance for 2014-2023. A more detailed table of
portfolio resources is provided as Table 5.8.
PACIFICoRP _ 20I 3 IRP UPDATE CHAPTER 5 - PoRTFoLIo DEVELoPMENT
Table 5.6 - Comparison of Business Plan with 2013 IRP Preferred Portfolio
2014 Business Plan Portfolio
Frcrt Oftce Tmrctbre in resowe total tre lo-yeil arerage. *
Differrnce - 2014 Business Plan Pofifolio Less 2013 IRP Prtferrtd Pofifolio
Frort Offce Tmactbre h resouce total ae I o-yeil average. *
2013 IRP - Prtferrtd Portfolio
Reroure
Iilbllrd ..rm.itu- Mttr,t lLw..r
2013 2014 2015 2016 2017 2018 2019 2ff20 2Al 20,2 2l}23 Tot l
ernubnOotiom
la - CCCT 645 645
ia- Peakim
)SM - Ferw Fficiprw u5 103 t0t 97 92 90 8l 80 82 68 909
)SM-Inr.laotr^l
tenemble - Wid
lerewble - Utilitv Solar 4 3 6
tereMble - D6trbued Sohr 7 ll l4 l6 l8 t4 l4 t4 l5 l5 t5 147
lombired Heat & Power I I I I 1l
;rom Ofice Tm*tbro *650 709 845 983 I l02 )09 1 1)1 1 4)O I 19 I ji?1.421 1.154
Erbtim Unit Ctruei
loal Early Retirenrerr/Corenbro (502 (502
lleml Plam End-ofllift Rairements
loal Phrr Gc Conersbn Addtom 338 338
lubire Uosades t4
fob I 191 I.4A6 8t2 r.102 1218 t3l5 l.a7 1.515 1287 1.,tilt l.5l I
INtrled Crmcitv. MW lGyeer
20t3 2014 2011 2n16 2017 20t8 2019 2$2n 2tD1 2m2 2(D!Tnfil
lrmroirn ootiou
ias - ('(-("I
ias- Peakip
)QM - Fero FfrrGmt 2 (0 (o II II fl (o (o (4 t4 (14
)SM - load Corrol 21 2l
-not!/akla \l/mi
lerewable - lltiliru Solar 12 3 II 2
kremble - Dbttrued Solar
lombred Heat & Power
rrofr ()llice Tmnectbns ll71 093 (l76 fl86 (r71 |'7'7 fl98 (80 (69 fl55 ( 133 o54
hirtinc lJnit (lercer
loal Eah Retrererr;/Coruersinro
:tEtml Plarf Erd-of life Retftmenls
'oal Plafr Ges Cowersnn Additnns
lubire ljooades
lotsl lt1l (190 (fi4 (r87 (172 (174'(198',459'.(70 (r59 (r37
Frort Ofice Trcactbre ir resorce total ue l0-yeil average. *
56
PlcnrConp - 20 I 3 IRP Upnnrs CHAPTER 5 - PoRTFoLIo DEVELoPMENT
Table 5.7 -Business Plan Capacity Load and Resource Balance
Yes
Thcmd 6,626 6,m 6,454 6,4Y 6,4Y 6A5r'. 6A54 6,454 6,4s4 6,4Y
Hydrcel€ctdc lll ll0 125 125 ln D5 125 125 125 125
Rencuable C2 A n g2 82 tZ 82 81 8l 79
Purchse 62 62 425 112 312 312 312 283 253 83
QuafiryingFrcilitios D 80 83 83 83 83 83 82 78 ?8
Salc (R8) (28) (738) (663) (663) (653) (66, (183) (183) (183)
Ilon.O^dedRoscrvg (38) (38) (18) (38) (38) (38) (38) (38) (38) (38)
Tmsfes 353 5&7 578 A2 fi3 562 906 742 &25 801
htEdtlitrtn6oret 7'147 72oS 697t 6997 6955 6917 725t 1;16 7S2s 7599
Cor$iaedhcatmdPowr 0 I 3 3 3 3 4 4 6 6
Fmnt Omce Tmsetions 0 0 0 63 178 2A 190 o 7 138
&s0000000000
wbd0000000000
Sohr2168t01213l5l820
Other0000000000
FltPlmdR.lNcct 2 5 9 74 l9l 297 201 19 3l l6il
htTotdRB@cc! 1,149 12to 6p80 1,P71 7,116 1214 7A6E 7'555 15s6 1J63
Load 6,89 7,W 6872 7,000 1,113 1,221 7,4W 7,612 7,731 7,t59
Edstirg Resourcd :
htenptible
Class I DSM
New Resources :
Clas I DSM
Class 2DSM
00000000
(2{B') (256) (304) (34e) (3ez) (431) (468) (5o4)
6,r{1 5229 6294 5)51 5510 6565 5J1t 6110
Tr9 810 8t8 826 855 U7 8n 889
799 Elo 81E E26 E55 867 811 EE9
Plmning Rcsewes (l 37o)8t8 826
EBtRclcm! EIE t26
htouitdiil+ndcrut 7'll0 7,1E0
FstP6itim 39 30
EltnrtcreltlrrtiD le/o Bo/o
6911 7039 7,112 7,tE3 7435 7533 7$25 1J29
33 '2 31 3t 33 32 3l 34
t{/o t{/o te/. B% t3% t!/o r30/. t!/o
(r59) O5e) (186)(32e\ (329\ (32e\
(lE6) (186) (186)(32e\ Qze\ (32e)
(186)
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(185)
(329\
(r85)
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EltoHitdio 5392 6r5a
Corbined hcat md Powr
Frcnt Office TEsrctions
&s
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Tmsfere
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Bbting Resoure:
Intcmptftla
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New Res ourccs :
Class I DSM
Class 2 DSM
Phaning Reserucs (137o)
W6tEirdogx.lwca 2963 2rl7
\su \54m Tl5
38 38
187 190
986(305) (201)
(3) (3)
(353) (586)
I
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WcltPl@dRssrcc! sEl 758
WcltTo(ll R.!0rcct 3547 3575
\503 \s03 15m 2,497
734 At 652 652
38 38 2t 2l
3333
7t 7t 71 67(ls7) 053) (rm) 002)(3) (3) (3) (3)
(e06) (142) (8m G03)22E 2r5r 2)t7 2332
4566
t,325 1,258 1,325 t,325
0000
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1329 1273 rJ31 rr31
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WdtRB.rur 407 411
wdtoHitdim +nBcre! 3,54f 3569
Wdt Pdilio 5 6
Wst Rdcre lt&rtio lT/o l1o/o
3,5E0 3,60J 3,60E 4,514 3512 3,531 3,6{E 3$6'
3,272 3,318 3350 $n 3,412 3,442 3,473 3,508
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0 0 0 0 (2r) (21) (21) (21\
(n3) (r3e) (162) (180) (le4) (214) (231) (2s4)
3,159 t,119 3,ttt t,197 3,197 t)07 3221 3133
4ll 413 414 416 416 4t7 419 42n
'lll 413 114 416 115 117 119 420
3570 t592 3502 3,613 t613 3524 t64O 3,65tl0 116lo)7410
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Totrl RBUcrr 10,696 10,?85
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f,.!.re! lzs lP1
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SyIEE Pcili[ 45 36
Rcrcru lllrgir l3o/o l3o/o
10,560 10,04 to,1y 10,828 ll,0m ll,l% 11,304 |,4?n
93A7 9,,$8 9,4U q554 9,m 9,873 9,969 lqoRr2l0 1,223 1,233 I,A2 \nt 1,283 t2s6 1,309
10,517 10,631 lq15 rq796 11,048 ll,156 t, s 11,382
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PACIFICoRP - 20 I 3 IRP UponrS CHAPTER 5 _PoRTFoLIo DEVELoPMENT
In its order acknowledging the Company's 2013 IRP, the PSCU directed the Company to
perform a sensitivity case with stochastic analysis using the capacity contribution of wind and
solar resources applied to determine avoided costs in Utah. The peak contributions, represented
as percentage of resource nameplate, for avoided costs are shown in Table 5.9.
Table 5.9 - Peak Contribution of Renewable Resources, sensitivity study
2013 IRP Uodate 20.5o/o 69/o 84o/o
2OI3IRP 4.2o/o 13.60/o 13.6%
In addition, the Company has performed studies addressing the impact of reduced costs of solar
resources while also applying the capacrty contribution assumptions shown above. The updated
costs of solar resources are shown in Table 5.10.
The Company performed sensitivity studies using the SO model to determine the impact on
resource portfolio composition, and using the Planning and Risk model (PaR) to determine the
performance of the portfolio against stochastic risk. The case definitions assumed for the
sensitivity studies are based on Case EG2-C01, Case EG2-C07 and Case EG2-CIO as defined in
the Company's 2013 IRP. The cases all relied on the Energy Gateway 2 build-out, assuming
segments C, D, and G are constructed. The variable assumptions for the core cases analyzed are
summarized in Table 5.11.
Table 5.12 is a portfolio comparison between Case EG2-C01 from the 2013 IRP and the
comparable sensitivity study using the capacity contribution assumptions from Table 5.9. In the
sensitivity study, the peak conffibutions for both existing and potential renewable resources are
revised to match what are in Table 5.9. The purpose of this sensitivity study is to demonstrate
Table 5.10 - Updated Costs of Solar Resources, sensitivity study (50 MW AC)
Table 5.11- Core Case Definitions
59
PACIFICORP _ 20 13 IRP UPDATE CHAPTER 5 - PORTFOLIO DEVELOPMENT
whether there would be more renewable resources selected on an economic basis if their peak
contributions are assumed to be higher than what the Company assumed in the 2013 [RP. Note,
with higher capacity contribution assumptions, the resource need is deferred, as evidenced by the
overall reduction in resource additions. The sensitivity shows that relative to Case EG2-C01, an
additional 52 megawatt Wyoming wind resource in 2024 and an additional 598 megawatt wind
resource is added in 2032. No additional utility scale solar resources were added in the
sensitivity, and no incremental renewable resources were added in the front ten years of the
planning period.
60
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PACIFICoRP _ 2OI3 IRP Upoerr CHAPTER 5 _PORTFOLIO DEVELOPMENT
Table 5.13 is a comparison between Case EG2-C07 in the 2013 IRP and the sensitivity study
using higher capacity contribution and updated costs of solar resources. Results of this sensitivity
study show that there are no additional renewable resources added beyond what were added in
the 2013 IRP Prefened Portfolio. However, the higher capacity contribution reduces resource
need resulting in the elimination or deferral of other resources that were included in the 2013 IRP
Preferred Portfolio.
Table 5.14 is a comparison between Case EG2-CIO in the 2013 IRP and the sensitivity study
using higher capacity contribution and updated costs of solar resources. Results of this sensitivity
are similar to those discussed above; however, an additional 52 megawatt Wyoming wind
resource is added in2024.
63
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PecnrConp - 2013 IRP Upoare CHAPTER 5 -Ponrrorlo DEVELoPMENT
At the request of the PSCU, a Planning and Risk (PaR) study was completed on the Case EG2-
C07 sensitivity that assumes higher capacity contribution inputs for wind and solar resources (i.e.
the sensitivity resource portfolio shown in Table 5.12). Table 5.15 compares the risk-adjusted
PVRR between Case EG2-C07 and the sensitivity case.
Table 5.15 - Comparison of Risk-Adjusted PYRR between Cases EG2-C07 and the
Capacity Contribution Sensitivity
67
PACFICORP - 2OI3 IRP UPDATE CHAPTER 6 _ ACTIoN PLAN UpoeTe
CuaprER 6 - AcuoN PreN Srarus Upoare
This chapter provides an update to the 2013 IRP Action Plan. The status for all action items is
provided in Table 6.1 below.
Related to the Action Plan is the Acquisition Path Decision Mechanism, included as Table 9.2 in
the 2013 IRP. The PSCU noted that this was a "very useful table." The acquisition path analysis
focused on load trigger events, and combinations of environmental policy and market price
trigger events that would require alternative resource acquisition strategies. For each trigger event,
there were potential ramifications to both short-term (2013-2022) and long-term (2023- 2032)
resource strategies. The PSCU encouraged expansion of the table going forward.
The analysis contained herein looked at updates as included in Chapter 3 (load); and Chapter 4
(modeling updates). Specific updates were provided for gas costs, solar costs and capabilities, as
well as specific resources. Sensitivities focused on the changes in solar cost and capabilities.
Overall with all of the updates, the major finding is that resource acquisitions are pushed further
out, mainly due to the decline in load forecasts.
For the 2015 IRP PacifiCorp will work with Stakeholders on more fully developing the
acquisition path decision mechanism. This will incorporate input for variables to include, as well
as potential triggering events to examine. There will be a robust look at impacts on both near-
and long-term acquisition strategies.
69
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PeCrIConp - 20 13 IRP UPDATE AppsNolx A - ADDITIoNAL LoAD FoRECAST DETAILS
ApppNDIx A - AooIUONAL LOen FonpcAST
Dprans
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). To arrive at the retail sales forecast, the initial load forecast is reduced by total Class 2
DSM as well as line losses. Table A.1 shows the retail sales forecast by state that is consistent
with the 2013 tRP Update load forecast. Table A.2 shows the change in the load forecast as
compared to the 2013 IRP.
Table A.1 - 2013 IRP Update Annual Retail Sales Forecast in Megawatt-hours by State
2014 13.01l.l2l 3.971,s79 769.s97 D.,&ffi.795 9.705269 3.389.r70 53.707.529
2015 13.t6271 3.%7.n7 767,691 n.671.994 9.877.707 3.N2.45 s4.80322s
2016 13.13.018 3.979,083 768.813 24.536.991 0.04925r 3.421.656 55.868.812
2017 13.67.161 3.%9219 765,290 24.8V2.3@ 0.147.190 3,431.597 56.282.76
2018 l3 78,870 3-975-811 7&,323 25.076.147 0.257.657 3,4/'3,919 56.6%.727
20t9 13206..4U 3.983-129 763,62 25.421246 o-371.679 3.457.402 57.203.@2
2020 13267.439 3,999,8s4 763.991 26.333407 0-50'7.412 3.474"599 58.34r.703
2021 t3-258-936 3.991.501 7@.W 26.6il.633 0.572.081 3-483.313 58.7243M
2022 13.302.688 4.001.736 760.086 27.W6.817 0.653.730 3.4y7,362 59302-4,9
2023 13.3il.939 4.0r6.918 7fi.m 27.ffi2.U1 0.7il257 3.s16.168 ffi.44-723
2014-2023 030%0.130/"4.13o/"2.12V"l.l6Yo 0.4lYo l24Yo
Table A.2 - Change in Annual Retail Sales Forecast in Megawatt-hours by State compared
to the 2013 IRP
2014 /L56.999\,27,583 4.491\@ss.637)(16.052)(41.1 10)(ffi.70s)
2015 o17.fiv 27,720 (4.70r)279,ffi fl6.8s2)(54.378'114.31s
2016 Q29.8ts)26.734 rs.138)%r,49 Q5.728\(68.4s61 598.566
2017 o2t-3&\26,M9 (s.774)859.171 (36.0s9)(f1.2a'550,14
2018 o59-135)22.1@ (7.4r',9\819-281 (50.663)(79.sssl w,587
2019 Q93,60/.)18.755 (8.720\856.91I (57-516\$3.734i 432.W3
2020 822.ffi)16.2N (l0.Vzz^.4r9.8v2 (70.559)(90.0021 942.9M
2021 (350.931)15.136 0.Ms .528.901 (86.64s)(.86.72t\,1.010274
2022 (363.r39)t32so (8.84e1 .ffi.430 004.lro (87.9091 1.w3.ffi
2023 (378,659)I 1,100 (8,136 ,781,7n (123,375)(85,636)1,197,04
Tables A.3 shows the retail sales forecast by class that is consistent with the 2013 IRP Update
load forecast. Table A.4 is the change in the retail sales forecast as compared to the 2013 IRP.
85
PACFICORP - 2OI 3 IRP Upoare APPENDX A -ADDIIONAL LOAD FORECAST DETAI.S
Table A.3 - System Annual Retail Sales Forecast in Megawatt-hours by Class
2014 5,425,806 t7,252,5M t9,346,275 1,262,775 143,080 277,050 53,707,529
201s s-419.29 17-578.512 20.126-314 r.252-W 143.090 n4-w 54-W3.225
2016 5.503.658 17.865.986 20.819.565 t-261-233 143.630 274-740 55.868.812
2017 5-520.233 18.102.730 20.982.24 1.260.301 t43-2ffi 274.M 56.282.76
2018 5.607.m6 t8-2ffi.895 2t-146.431 t-259.ffi 143.330 n4-w 56-696-727
2019 5.7W.357 18.405.178 2t.413.K5 t.257.8t3 143,390 274.m s7.203-fi2
2020 5.814.139 18.fi6,427 22,250.818 1.256.749 143,830 274,740 58.346.703
2021 5.86r..n9 18.704.7%22.480.323 r.255,459 143.500 274,000 58.724.307
2022 5.982.47E 18.865.953 22.782.n1 1.254.177 143.540 274,W 59.3W.4t9
2023 6"t26.149 19.095.913 23.131.650 1.253.4[143.600 274.000 fi.04.723
2014-2023 0.49V"l.llo/"2.Olo/"4.08%O.O4Y"4.lzYo l24o/o
Table A.4 - Change in System Annual Retail Sales Forecast in Megawatt-hours by Class
Compared to the 2013Integrated Resource Plan
20r4 (6s.322\(52.058)/L49-0tr6'7.761 1.430 550 (ffi-705'
201s (541.943',(825)639-445 7.630 1.370 n.360 lt4.3l5
20t6 (6ls.7w\9.042 1.186.215 7.489 1.430 100 598.566
2017 (657.851)65.756 t-123.761 7.il1 1.430 40 550-782
2018 (713-482 88.712 l-050-177 7.300 1.450 430 444-587
2019 (758.034 lL9.254 1.051.546 7.137 LM 730 432.W3
2020 (817.@9\l53-562 t^587-063 5.888 1.450 1.590 94L9M
2021 (823.357 t90-01I la4-571 6-519 l-450 1.080 t-010-274
2022 (838.930 235-713 1.678.009 6-233 1.450 1.190 t.@3-ffi
2023 (861.821)280.156 1.759.975 6.053 1,450 1.270 t.tEt-082
The change in the retail sales forecast is driven by a decrease in residential loads, due to
increases in energy efficiency and slowing $owth in central air-conditioning saturation, and an
increase in commercial and industrial loads due to changes in self-generation assumptions as
well as continued economic recovery.
86
PlcrrrConp - 2OI 3 IRP UPDATE APPENDX B _ CoN{BINED HEAT & PowER EXECUTIVE SUTTIUARY
APPENDIX B - COTT,TSINED HPATAND POWEN
Exe c url vE S utr,ttrteny
Action ltem 2b in the 2013 IRP Action Plan states that PacifiCorp will pursue combined heat and
power (CHP) opportunities primarily through the Public Utilities Regulatory Policies Act
(PURPA) qualiffing facility (QF) contracting process and states that the Company will complete
a market analysis of combined heat & power (CHP) opportunities in the 2013 IRP Update. This
appendix summarizes CHP opportunities consistent with Action Item 2b. This study covers
opportunities across PacifiCorp's jurisdictions with a focus on PacifiCorp's western balancing
authority area covering the states of Oregon, California and Washington due to available woody
biomass fuel supply across those states. Among these states, Oregon is the most progressive and
supportive of the development of biomass CHP projects with specific state initiatives and task
forces to encourage the development of biomass generation.
The use of biomass across PacifiCorp's territory to generate electrical power has stagnated as a
result of the decline in home construction caused by the recession and uncertainty related to the
control of federal forestland for harvesting. The reduction in wood products production due to
mill closures has reduced the availability of lower cost and clean woody biomass fuel for thermal
and power generation as well as the thermal processing need that supports the base load
operation of a steam turbine for power generation. [n addition, changing market value and
conditions for environmental attributes under the available renewable portfolio standards (RPS),
decreasing avoided cost prices for QF regulation, and reduced or uncertainty around tax credits
or incentives in the western states served by PacifiCorp have contributed to a pull-back by
independent developers of biomass CFIP facilities as well as the forest products businesses
whose core strengths are the management and acquisition of timber for production as well as
supply of energy for use on-site or sale to the electric utility. Results of this evaluation suggest
that the Company should continue being responsive to independent or customer developed new
generation opportunities through PURPA projects and assisting those developments on their
decisions as they determine the use of the generation for off-setting on-site load or selling to the
utility. The Company should also continue to participate with organizations in their effort to
develop the appropriate legislative, governmental and regulatory incentives for biomass projects
within the Pacific Northwest.
Biomass energy is derived from four distinct energy sources: garbage, wood, waste, and landfill
gases. Of these four fuels, garbage and landfill gas are generally not applicable as a CHP and the
most prevalent in PacifiCorp's territory is the use of woody biomass.
Table B.1 summarizes PacifiCorp's existing QF power purchase agreements by state that are
biomass and operate as CHP.
87
PACIFICoRP _ 20 13 IRP Upmre AppENDx B - CorIBTNED HEAT & PowER Er<ecurNr Suuu.qny
Dairy and plant waste (Methane)
There are two major fuel sources for biomass power generation, mill waste and forest thinnings.
A minor, but growing, source is urban waste wood which is generally a source procured by forest
products firms and is treated in this report as inclusive with mill waste.
Mill Waste
Forest products manufacturing produces waste including bark, sawdust and planer shavings.
Chips are sold to pulp mills. Mill waste is consumed by plants to produce steam for internal use.
Table B.2 summarizes the existing, proposed and potential biomass generation on PacifiCorp's
system based on the four generation methods. These generation plants are fueled mainly by mitl
waste, either generated internally or purchased, and to a much smaller extent, fuel purchases in
the market (i.e., urban wood waste). No projects were found on PacifiCorp's system in ldaho. Of
the existing projects below, PacifiCorp is the purchaser of the output from the plants as QFs and
owns the turbine asset at Georgia Pacific in Camas Washington. All are directly interconnected
to PacifiCorp's transmission system. Approximately 114 MW are currently under contract to
PacifiCorp or self-supplying their load. More and more QFs are moving to self-supply of their
load first and selling excess due to the price differential between retail rates and avoided cost
prices.
Table B.2 - Woody Biomass Generation on PacifiCorp's System
* Roseburg Forest Products @illard) - 20 MW is exported to PacifiCorp** Georgia Pacific Corporation - currently operating at 14 MW
7 There are six landfill gas plants with a total capacity of 14.6 MW, three each in Oregon and Utah which are not
considered for this analysis.
CA Rosebure Forest Products Weed OF - Self suoolv first and sell excess 10.0
OR Roseburs Forest Products *Dillard OF - Selfsupply first and sell excess 4s.0
OR Biomass One Medford QF 32.0
OR Warm Sprines Warm Sorinss Self-suoplv 9.0
OR Douslas County Forest Products Roseburg OF - Selfsupply first and sell excess 6.3
OR Roueh & Readv Lumber Cave Junction QF 1.5
OR Freres Lumber Mill Citv QF 10.0
WA Georsia Pacific Corporation **Camas PacifiCom Asset 52.0
TOTAL 166
88
PACIFICoRP_20I3 IRP UPDATE AppgT.IoIx B _ CoNasINeo Heer & Powrn EXECUTIVE SUMMARY
Forest Thinnings
Forest thinnings represents a significant amount of fuel and electricity potential. However, it is
inaccessible in the current market environment in the near or mid-term. The Energy Trust of
Oregon and Oregon Forest Resources Institute suggest that up to 300 to 500 MW might be
produced given available forest fuel, but is greatly dependent on workable and efficient supply
and contracting mechanisms. Forest residue, if collected, represents the largest potential source
of biomass energy in Oregon. Depending on the generation facility or facilities, the total
electricity production could be 300 to 500 MW or more for approximately l0 years, if all of the
residue could be collected and used. None of this potential is available in the near or mid-term.
There is no infrastructure to gather forest residue, and costs to gather that material alone are
estimated at $40-504{Wh, which is comparable to current wholesale market electricity prices.
There are also significant administrative and regulatory barriers to gathering and using forest
thinning. No generation projects exist today that use forest thinnings as their source of fuel to the
plant. Current air regulations make it extremely difficult to permit such an operation, and
contracts for supply, which must be made with the U.S. Forest Service, are limited at this time.
These issues are beyond PacifiCorp's control at this point in time and therefore this market
segment, while potentially promising in the long term, does not present near- or mid-term
opportunities for PacifiCorp. Consequently, PacifiCorp is focusing on real project opportunities
at a known customer's site and will continue to work with government agencies and/or private
business to develop further incentives at the federal and state level to encourage the development
of biomass generation.
Market Barriers
Low Electricity Prices
Current wholesale market electricity prices do not support the development of new biomass
power plants. Even the current standard QF avoided cost prices do not support the development
of a stand-alone QF project. Most of the standard QF projects under development are utilizing
the available incentives and low-cost financing to incrementally construct the generation portion
of a boiler up-grade or replacement project. In particular, the price of electricity is not suffrcient
to support the total cost of building and operating a plant including any fuel transportation costs.
Low retail prices in the Pacific Northwest also limit the value of self-generation. Low wholesale
prices limit the opportunities for selling electricity. There are a limited number of QF projects
being developed at operating mills because natural gas costs have remained at a level whereby
biomass fuel is not competitive.
89
PaCrrCOnp _ 20I3 IRP UPDATE AppgNoIx B _ CoTT,TsINeo HEAT & POWER EXECUTIVE SUMMARY
High Installation Costs
The capital cost of developing biomass-based generation systems is high, especially in smaller-
scale operations. The estimated capital cost of a greenfield biomass cogeneration plant is in
excess of $3,500 per installed kilowatt. This is because the project consists of designing, siting,
and constructing an entirely new power plant with all ancillary facilities and grid
interconnection, not just installing new equipment at an existing site. Many forest products firms
indicate that capital costs often contribute to unfavorable internal rates of return, and that this
limits generation projects from moving forward. In other cases (in particular, wood burning
plants) the inability to guarantee a long-term fuel supply has kept companies from obtaining
financing.
Air Permitting Req uirements
Obtaining required air quality approvals increases the project development costs and, in some
cases, the operating costs of biomass projects. The smaller projects run by end-users are not
familiar with air quality requirements and many cannot afford the cost of compliance.
Lack of Financial Recognition of Environmental Benetits
Although renewable energy credits (RECs) provide benefits to biomass-produced energy, the
value of RECs in the market is low whether for compliance or the voluntary market. Many
developers are unfamiliar with how to pursue the sale of RECs in the market. There are other
benefits that are not accounted for as yet in the market such as greenhouse gas emission
reduction. For the forest residue resources, an added benefit is reduced emissions from controlled
combustion with emissions controls as compared to the open forest slash burn practice.
However, these benefits have not been quantified. The biomass industry would benefit from
policies and assistance that recognize that biomass offers superior benefit related to greenhouse
gas emissions.
Cost of Fuel Transportation
The cost of collecting and transporting hard biomass fuels is expensive. This is especially true
for forest residue. In addition, any regional plant that collects waste from nearby forest sites and
delivers it to a central processing facility will face high transportation costs. The cost to ship the
fuel 100 miles needs to be evaluated against transmission costs for the electricity. In general, for
projects less than 5 MW, it is impractical to transmit electricity for long distances because the
costs associated with the required transaction costs, wheeling charges, and line losses are not
offset by the value received for the electricity. In the case of some larger projects, the economies
of scale of developing a larger project can offset the cost of wheeling electricity from the site to
the host utility. These larger projects, however, are limited in number. With a mature fuel market
and transportation network in place, it is expected that mill waste would flow to the projects
within the PacifiCorp service areas.
90
PaCnICOnp - 20 I 3 IRP UPDATE AppsNDx C-ENERGy ANALYSTS REpoRT
ApppNDIx C - ENBNCY ANIALYSIS RBponT
ENERGY
ANALYSIS
REPORT
A mdti-plant anatysis ofpotoutid €oqgf msurntion opporflrnitiee at
cfiolty onmed PeciffCorp Energy gwatioo frcilities.
PngnCoRP ENERGY
ADTVE|oXOf Actn@e'
PacnrConp - 201 3 IRP Upoare APPENDX C _ ENERGY ANALYSIS REPORT
TABLE OF CONTENTS
EXECUTIVE SUMMARY
PROJECTS BY PLAI\T
Potentially Cost-Effective Projects ....................95
Systems Requiring More Research. ....................95
Unlikely to be Cost-8ffective............ ..................95
Potentially Cost-Effective Projects ....................96
Systems Requiring More Research. ....................96
Unlikely to be Cost-8ffective............ ..................97
HUNTTNGTON PLANT ,..,,,97
Potentially Cost-Effective Projects ....................97
Systems Requiring Further Research.................. ...................97
Unlikely to be Cost-Effective............ ..................98
CURRANTCREEK PLANT ....................98
Potentially Cost-Effective Projects ....................98
Systems Requiring Additional Research........... ...................... 98
Unlikely to be Cost-Effectiye............ ..................98
HUNTER UNrr 3 ............. .....................99
Potentially Cost-Effective Projects ....................99
Systems Requiring Further Research. ................99
Unlikely to be Cost-Effective............ ..................99
LAKESTDE PLANT......... ..................... 100
Potentially Cost-Effective Projects .................. 100
Systems Requiring Further Research. .............. 100
Unlikely to be Cost-Effective............ ................ 100
BLUNDELL PLANT......... .................... 100
Potentially Cost-Effective Projects .................. 100
Systems Requiring Further Research. .............. 100
Unlikely to be Cost-Effective............ ................ 101
GADSBYPTaNT ............101
92
93
95
92
PACIFICoRP _ 20 I3 IRP UPDATE APPENDIX C - E}.TERGY ANALYSIS RgponT
Background
The 2013 [RP Action Plan calls for an assessment of the wholly owned PacifiCorp Energy
generation facilities to determine possible areas for energy effrciency improvements. This
assessment was to be done in light of the results of the studies completed for the Washington
Initiative 937 (I-937). In response to this action item, PacifiCorp completed inspections at the
following eight plants:
Dave Johnston Plant - Glenrock, Wyoming
Naughton Plant - Kemmerer, Wyoming
Huntington Plant - Huntington, Utah
Currant Creek Plant - Mona, Utah
Hunter Unit 3 - Castle Dale, Utah
Lakeside Plant - Lindon, Utah
Blundell Plant - Milford, Utah
Gadsby Plant - SLC, Utah
The purpose of this report is to outline the methods used to identi$ potential systems and
equipment providing cost-effective energy efficiency improvements, summarize the outcomes of
the inspections and rank the identified systems and equipment according to cost-effective
analysis. The systems identified will be separated into three categories for each plant: (1)
Having a high potential to be cost-effective, (2) needing further study to determine cost-
effectiveness, or (3) as being unlikely to be cost-effective.
Methodology
Using the experience gained from energy efficiency studies for l-937 that were performed at Jim
Bridger and Chehalis, systems and equipment at each plant were evaluated for potential to
investigate. This was done by reviewing the operating characteristics of major plant systems
using the plant distributive control system (DCS) information. Load dependent systems and
equipment were evaluated at or near full plant capacity. The amount of wasted energy at full
load is an indicator of the potential for cost-effective energy savings. Once the most likely
candidates were identified, the systems and equipment were inspected to gather additional data
and to discuss the operation with plant personnel. Systems not controlled through the plant DCS,
typically load independent (lighting, compressed air, etc.), were also reviewed.
Summary of Results
The following systems and equipment were generally found to hold a high potential for cost-
effective energy savings improvements:
o Compressed Air Controls and Dyer Upgrades/Controls - Huntington (-l,800MWh/yr),
Hunter (-l,000MWh/yr)
o Heat Trace Thermostatic Control - Huntington (-80MWh/yr), Naughton (-l00MWh/yr),
Dave Johnston (-l 20MWh/yr)
o RO Water Treatment Systems -Naughton (-200Mwh/yr), Dave Johnston
(-l90MWh/yr)
o Lighting Controls - All plants*
93
PecrnConp - 20 13 IRP UPDATE APPENDIX C - E}.TERGY ANALYSIS REPoRT
* Lighting retrofits to accomplish production efficiency gains do not meet the cost effective test
due to the initial cost of preferred LED lighting technologies. Two opportunities for lighting
efficiency improvements exist generally at each plant:
l. All plants can use new or upgraded controls for lighting to save energy. A common
theme at each plant was that exterior lighting is on during daylight hours. The controls
for these types of fixtures tend to malfunction or become inoperable quickly due to the
harsh environment. These controls should be replaced and/or upgraded. Another
commonality is that many outbuildings and unoccupied areas had lighting on at all times.
Areas like this that use fluorescent lighting would benefit from occupancy sensors.
2. Emergency lighting is typically left on at all times. In some plants, emergency lighting
consists almost entirely of incandescent lights. Upgrading these lights to CFL or LED and
ensuring that they only turn on in loss of power has potential to be a cost-effective way to
save energy.
The following systems show potential but require further study:o ID Booster Fan - Huntington Unit I
o Coal Conveyors - Huntington Plant
. Condensate Pumps - Hunter Unit 3, Naughton, Lakeside, and Currant Creek Plants
o Compressed Air System - Naughton Plant
o PA Fans - Hunter Unit 3, Dave Johnston Planto Boiler Water Feed Pumps - Dave Johnston Units I & 2
o Demineralization Water Pumps - Lakeside, Currant Creek Plants
94
PACIFICoRP _ 20 I 3 IRP UPDATE APPENDIX C_ENERGY ANALYSIS REPoRT
Dave Johnston
The systems inspected during the site visit to Dave Johnston Power Plant include the following:
Boiler Feed Water Pumps
FD and ID Fans
PA Fans
Condensate Pumps
Potentially Cost-Effeaive Proj ects
Compressed Air System
Reverse Osmosis (RO) Water Treatment
Lighting
Reverse Osmosis (RO) Water Treatment Svstem: The RO system at Dave Johnston has a
high potential for energy efficiency upgrades to be cost-effective. This system has new motors
which are inverter duty rated. Also, there is space available to install VFD's. The control valves
were mostly closed making the installation of VFD's worth considering. The projected savings
would be approximately 125 MWh per year for stage one and approximately 75 MWh per year
for stage two.
Heat Trace Controls: There are potential opportunities for efficiency improvements by fixing
or upgrading the thermostatic controls on the heat trace runs around the plant.
Liehtine Controls: There are opportunities for efficiency improvements through lighting control
upgrades.
Systems Requiring More Research
Boiler Feedwater Pumns: The boiler feed water pumps for units I & 2 are electric driven
pumps. At near full load the control valve was only 25o/o open for unit I and 33Yo open for unit
2. T"he cost of this project would be high due to the voltage of the pumps, the need to purchase
new motors, the size of the motors being replaced (2500 hp), the cost of the VFD's for the
voltage/size of the motors and the lack of space nearby. A detailed analysis of the energy
savings as well as the costs of the project would need to be conducted to determine cost
effectiveness. The Feedwater pumps for Units 3 & 4 do not have sufficient potential for cost-
effective energy savings as they are configured differently than I & 2.
Primarv Air (PA) Fans: The PA Fans for units I & 2 represent another potential opportunity.
There are six 200 hp motors providing primary air for units I & 2. These are smaller motors
which would bring costs down for replacement, however space for the VFD's would be a major
factor. The fan dampers are about 50% closed or slightly more. The energy saved on this
project may not be sufficient to offset the cost. The PA Fans for units 3 & 4 have two large
motors each and run with less damping at full load. Due to the large size of the motors and the
more efficient configuration, potential for cost-effective energy savings is very low.
Unlikely to be Cost-Effec'tive
Comnressed Air: The compressed air system at Dave Johnston Plant did not contain any cost-
effective energy effi ciency measures.
Forced Draft (FD) & Induced Draft flD) Fans: The FD and ID fans were not damped enough
to provide cost-effective energy efficiency measures.
Lishtine Retrofit: The following table shows the cost-effective calculation for the lighting at
Dave Johnston Plant. The cost and energy savings numbers are taken from the Evergreen study
95
PeCrICOnp -2013 IRP UPDATE APPENDIX C - ENERGY ANALYSIS REPORT
included in the appendix8. The columns under "Net" show the cost-effective ratio for the project
based on the depreciation life. Any project with a ratio under I is not cost-effective.
Naughton
The systems inspected during the site visit to the Naughton Power Plant include the following:
Reverse Osmosis Water Treatment System Booster Fan
Condensate Pumps
Boiler Feed Water Pumps
FD & ID Fans
Cooling Tower
Compressed Air
Lighting
Reverse Osmosis Water Treatment System
Potentially Cost-Effective Projects
Reverse Osmosis (RO) Water Treatment Svstem: The RO system at Naughton has a high
possibility for energy efficiency upgrades to be cost-effective. There are two separate RO
systems, one acting as a backup for the other. The valves were only about l0% open. The
motors are new 480 volt, inverter-duty rated motors. There is room nearby for VFD placement.
The costs to implement the energy savings on this system should be relatively low. The
projected savings would be approximately 190 MWh per year for each unit.
Heat Trace Controls: There are potential opportunities for efficiency improvements by fixing
or upgrading the thermostatic controls on the heat trace runs around the plant.
Lightins Controls: There are opportunities for efficiency improvements through lighting control
upgrades.
Systems Requiring More Research
Condensate Pumps: The costs of upgrading the condensate pumps will be high. However, there
is enough potential in energy savings (a high-level estimate of 3,500 MWh per year) to justiff
further researching the costs to evaluate cost-effectiveness. The motors are large, 1000 - 1500
hp, at the medium voltage level and space will be an issue.
Compressed Air: There may be potential at Naughton to save energy on the compressed air
system. The system requires more research because all the compressors were not running. The
system needs to be operating in the normal condition in order to determine how much potential
there is in the project.
Boiler Feed Water Pumns: The boiler feed water pumps for Naughton 1 & 2 are electric
driven. The control valves areTTYo open, which means the potential for energy savings is small.
This system may still warrant more research before being discarded as a potential cost-effective
energy efficiency project.
I Appendices to the Energy Analysis Report have been included on a CD with the 2013 IRP Update filing.
2014 IRP Cola Efiec{ye Lighling Cost and Bsnsfit Revonus Roqulr€mont C.lculatons
PDj*t Cct in O$mtrt Cost Cure
2014 $s MWh Sa\,inos Used
PV Rev Rdt Bs€fits PV Rev Rot (Costs)Net
Nm OR OR Non OR OR Non OR OR
NmOR OR
)€preciable Depreciable
Lib Lib
)eE Johnston M.711.8O0 4.89i Wst CommeEial Liohtino S1.lo2 949 STrA 154 (S2.805.147\ $2.il2.35o'0.50 o.2a 2M7 2024
96
PACIFICoRP _ 2OI3 IRP UpperE AppsNnrx C - ENERGy ANALysrs REpoRT
Unlikely to be Cost-Effective
Coolins Tower: The cooling towers for units I & 3 do not have VFD control. The operating
procedure of the plant is to keep the water temperature as low as possible. The installation of
VFD"s would not provide much in the way of saved energy.
Booster Fan: The booster fan damper was not closed enough to make project cost-effective. For
a VFD, this project would require a new motor as well as long runs for the wire making project
costs too high.
FD & ID Fans: The FD & [D fans were not damped enough to offset the potential costs of the
upgrade. There were considerable space restrictions as well as the need for new motors along
with the other costs of VFD installation.
Lishtine Retrofit: The following table shows the cost-effective calculation for the lighting at
Naughton Plant. The cost and energy savings numbers are taken from the Evergreen study
included in the appendix. The columns under "Net" show the cost-effective ratio for the project
based on the depreciation life. Any project with a ratio under 1 is not cost-effective.
Huntington Plant
The systems inspected at Huntington Plant include the following:
Raw Water Supply
Coal Conveyor (Reddler Deck) Motors
Heat Trace Controls
Reverse Osmosis Water Treatment
Potentiolly Cost-Effective Proj ects
Compressor Controls: The compressed air system at Huntington Plant is comprised of 4 new
Cameron compressors. During the site inspection one of the compressors was running unloaded.
Also, the dryers were not efficient and the dew points settings were aggressive. The proposed
upgrades to this system include new dryer, upgraded controls for the dryers and a central control
system for the compressors and dryers with only two compressors running at a time. Two of the
existing dryers would not be needed and turned off. The potential energy savings with this
configuration would be 1,800 MWh per year. The plant compressed air load requirements would
need to be confirmed before implementing the proposed configuration.
Heat Trace Controls: There are potential opportunities for efficiency improvements by fixing
or upgrading the thermostatic controls on the heat trace runs around the plant. The plant has a
large amount of heat trace. The amount of heat trace not currently on thermostatic control needs
to be identified and quantified. There appears to be potential to capture savings in this area.
Lishtins Controls: There are opportunities for efficiency improvements through lighting control
upgrades.
Systems Requiring Further Research
RO Water Treatment Svstem: The RO system flow is controlled with a manual control valve.
This system has potential for saving energy but more research is needed to determine cost-
Compressor Controls
ID Booster Fans
Lighting
2014 IRP Colt Efiac0v6 Llghting Colt lnd Bonoft Rovonue Requirsmont Calculatons
97
PacmrConp - 20 13 IRP UPDATE ApppNoIx C _ ENgncy ANALYSIS REPORT
effectiveness. There wasn't as much throttling on the valve and therefore the benefit will be
lower at Huntington than at other plants in the fleet.
ID Booster Fan: The Unit I booster fan is a system which is comprised of two 5,000 hp,4160
volt fans. There was a significant amount of damping at full load. This project is on the border
of being unlikely to be cost-effective but it does warrant a further look. Unit 2 was damped less
at full load and will be considered after the cost-effective calculation for unit 1 is finished.
Unlikely to be Cost-Effective
Raw Water Svstem: The raw water system was wasting energy. However, the potential costs
of the upgrade would have been high due to the size and location of the pump motors. Also,
upgrading the controls for the system would have a high cost.
Liehtins Retrofit: The following table shows the cost-effective calculation for the lighting at
Huntington Plant. The cost and energy savings numbers are taken from the Evergreen study
included in the appendix. The columns under "Net" show the cost-effective ratio for the project
based on the depreciation life. Any project with a ratio under I is not cost-effective.
Currant Creek Plant
The systems inspected during the visit to Currant Creek Plant include the following:
Condensate Pumps
Compressed Air
Reverse Osmosis Water Treatment
Water Storage Tank Recirculation Pumps
Boiler Feed Pumps
Lighting
Potentially Cost-Effective Proj ects
Liehtine Controls: During the site visit there were unoccupied buildings and open areas that
had lights on unnecessarily. These areas would benefit from motion sensor control of the
lighting. Also, there were a number of exterior lights that were on during the day. These lights
need to have the photo sensors fixed or replaced.
Systems Requiring Additional Research
Condensate Pumps: The condensate pumps at Currant Creek were wasting a high amount of
energy across the control valve. The costs to upgrade this system will be high, though, so it
requires additional study to determine cost-effectiveness. It has the potential to save roughly
2,000 MWh of energy per year if installed.
Compressed Air: The compressed air system was running efficiently. However, there did seem
to be an opportunity to make improvements in the air drying controls. This system will need
further scrutiny.
Unlikely to be Cost-Effective
RO Water Treatment: The RO system already had VFD's installed. This system was inspected
due to the high potential for savings at the other plants. No opportunity available to save energy.
2014 IRP Cost Efiac{ivs Lighling Cost and Eanoft Rovenuo Roquircmont Calculatons
98
PecrRConp-20l3 IRP UPDATE APPENDIX C_ENERGY ANALYSIS REPoRT
Water Storase Tank Recvcle: At Currant Creek the pumps did not appear to be recycling as
much as at Lakeside. Also, the valves were automatic and not manual. This allows for less
waste than the manual valves.
Boiler Feed Pumps: This system did have a high amount of throttling that wastes energy.
However, the piping system feeds a number of other loads besides the boiler. This means that
the control valve would still need to be used reducing the amount of benefit derived from
installing VFDs.
Hunter Unit 3
The Hunter plant is unique in the fact that only one unit is wholly owned by PacifiCorp. This
removes general systems like the RO water treatment from the list of potential projects. It also
complicates the compressed air system study. The systems inspected at Hunter Unit 3 include the
following:
Lighting
Compressed Air
PA Fans
Pote ntially Cost-Effective Proj ects
Compressed Air: The compressors at Hunter were running inefficiently. As this project only
pertains to Unit 3, only the compressor for that unit is considered. However, there is still
potential for cost-effective energy saving opportunities for this as a stand-alone system.
Liehting Controls: There are opportunities for efficiency improvements through lighting control
upgrades.
Systems Requiring Furlher Reseurch
Condensate Pumps: There is a significant pressure drop across the control valve in the
condensate piping system. However, project costs could prove to be prohibitive. One of the
major impacts to cost would be finding room nearby to house the VFD's.
PA Fans: Up review of this system there appeared to be enough energy wasted to warrant a
deeper look into actual project costs and savings.
Unlikely to be Cost-Effective
FD & ID Fans: The wasted energy does not appear to be great enough for this project to be cost-
effective.
Cooling Tower Fans: The operating procedure of the plant is to keep the water temperature as
low as possible. The installation of VFD"s would not provide much in the way of saved energy.
Lishtine Retrofit: The following table shows the cost-effective calculation for the lighting for
Hunter Unit 3. The cost and energy savings numbers are taken from the Evergreen study
included in the appendix. The columns under "Net" show the cost-effective ratio for the project
based on the depreciation life. Any project with a ratio under I is not cost-effective.
ID & FD Fans
Cooling Towers
Condensate Pumps
2014 IRP Cod Efioc{ive Lighong CoC and Bonofrt Rsvonue Rsquir.ment C.lculatons
99
Lakeside Plant
The systems inspected at Lakeside Plant include the following:
Condensate Pumps Boiler Feed Water Pumps
Water Storage Tank Recirculation Pumps Heat Trace
Lighting Controls
Potentially Cost-Effective Projects
Liehtins Controls: There is an opportunity to save energy with lighting controls. Ensuring
buildings and other general spaces have occupancy sensors and photo-cells in working order
would likely be a cost-effective measure.
Systems Requiring Further Research
Water Storage Tank Recirculation: The water storage tank recirculation pumps were running
during the inspection. There was a manual control valve that was partially closed. Since this
system didn't have inputs to the plant control system, we could not get good data on the amount
of time that it was running and how often the valve was in that position. There is a possibility
that this system could be improved to save energy in a cost-effective way. However, more data
needs to be gathered.
Condensate Pumps: The condensate pumps discharge is heavily regulated at Lakeside Plant.
There is also recirculation in the system that appears to be a source of wasted energy. This
process configuration needs additional research to determine potential energy savings.
Heat Trace: The heat trace does not have thermostatic control in most cases. The circuits are
turned on and off manually. More investigation is needed to determine the energy savings
potential and cost.
Unlilcely to be Cost-Effective
Boiler Feed Water Pumps: This system does not appear to have potential to be cost-effective.
Blundell Plant
Blundell is a geothermal power plant. The systems and processes used in this plant were unique
enough to require a more thorough look to make sure potential savings weren't missed. Systems
investigated during the Blundell site visit include the following:
Aux Cooling Water
Blowdown Pumps
Brine Transfer
Condensate Pumps
Compressed Air
Circulating Water Pumps
Unit2 Feed Pumps
Lighting Controls
P o te nti a I ly C o s t - Effe ct iv e Pr oj e ct s
Liehtine Controls: There is an opportunity to save energy with lighting controls. Ensuring
buildings and other general spaces have occupancy sensors and photo-cells in working order
would likely be a cost-effective measure.
Systems Requiring Further Research
Comnressed Air: The dew point controls at many of our plants are set very aggressively.
Making changes to the dew point controls to eliminate wasted energy is a very inexpensive way
to conserve energy. The drying system at Blundell did not get reviewed, however, so this is one
system that still needs to be reviewed.
100
PACTFICORP - 20 13 IRP UPDATE APPENDIX C _ ENERGY ANALYSIS REPORT
PecrrCoRp - 201 3 IRP Uppars APPENDIX C_ENERGY ANALYSIS REPoRT
Unlikely to be Cost-Effective
The remaining projects studied are unlikely to be cost-effective. The systems listed largely
produce wasted energy related to recirculation. Projects in general with this type of wasted
energy have not been found to have a positive pay-out.
Gadsby Plant
The Gadsby Plant consists of three gas steam units converted from coal and three gas "peaker"
combustion turbine units. The three steam units are part of the old plant and would provide the
most potential for energy savings projects. However, the steam units are intermittently run.
They have a large amount of downtime. This makes the cost-effective test much harder to meet.
The only potentially cost-effective project identified at this point would be lighting controls.
This project will be investigated fuither.
l0l
PACFICoRP _ 2OI3 IRP UPDATE APPENDIX D - ACCELERATED DSM DECREMENTANALYSIS
ApppNDIx D - ACCPTERATEN CIASS 2 DSM
DpcnEMENT Sruoy
This section presents the methodology and results of the energy efficiency, Accelerated Class 2
demand-side management (DSM) decrement study. The same methodology is used for this study
as that presented in Volume II, Appendix N of the 2013 IRP, with one exception. For this
analysis the amount of Class 2 DSM is re-optimized incorporating accelerated ramp rates that
were inputs to Cases C-14, C-15 and C-18 in the 2013 IRP. This portfolio is used as the base
portfolio to calculate the decrement value ("avoided cost") of various types of Class 2 DSM
resources.
To align with the resource costs applied for resource portfolio development using the System
Optimizer (SO) capacity expansion model, cost credits are applied to the Accelerated Class 2
DSM decrement values reflecting (l) a transmission and distribution (T&D) investment defenal
benefit, (2) a generation capacity investment deferral benefit, and (3) a stochastic risk reduction
benefit associated with clean, no-fuel .esou.ces.n
The modeling approach is the same as explained in Appendix N of the 2013 IRP report. For this
sensitivity, the generation capacity investment deferral benefit is recalculated using the portfolio
created with accelerated DSM assumptions. The avoided cost values are calculated for the same
l7 Class 2 DSM measure shapes, each at 100 megawatts (MW) maximum capacity and available
starting in 2013 and for the duration of the 20-year IRP study period. The production cost
differences with and without each of the Class 2 DSM resources are derived using the Planning
and Risk (PaR) model, which are then added to the capacity value calculated by the SO model
and added to the cost credits as outlined above. The PaR decrement values are determined for
one CO2 tax scenario: medium (starting at $16/ton in2022 and escalating to $26lton by 2032).
Generation Resource Capacity Deferral Benefit Methodology
PacifiCorp used the SO model to determine the generation resource capacity deferral benefit. A
single capacity benefit is calculated for an aggregate Class 2 DSM resource. This is
accomplished by running SO with a resource portfolio that excludes 100 MW of zero cost Class
2 DSM resource (Change Case), and then comparing the fixed portfolio costs against the cost of
the portfolio derived by the SO model that includes the Class 2 DSM program at zero cost (Base
Case). The simulation period is 20 years. As a simpliffing assumption, PacifiCorp applies the
East "system" aggregate Class 2 DSM load shape for the generic DSM resource, because the
next deferrable resource is located in the east side of PacifiCorp's system. The aggregate Class 2
DSM load shape has a capacity planning contribution of 94 percent and a capacity factor of 70
percent. The resource deferral fixed cost benefit is comprised of the deferred capital recovery
' Refer to Volume I, page 147 of the 2013 IRP for a summary of the T&D investment defenal and stochastic risk
reduction cost credits applied to the SO energy efficiency resource options.
103
PACIFICoRP _2013 IRP Upnerg APPENDTX D - ACCELERATED DSM DECREMENTANALYSB
and fixed operation and maintenance costs of a "next best alternative" resource-a combined-
cycle combustion turbine (CCCT). The difference in the portfolio fixed cost represents the
resource deferral benefit of the DSM program. Note that the SO model production cost benefits
are not taken into account to avoid double-counting the benefit extracted from stochastic PaR
model results.
Since a 100 MW Class 2 DSM resource is not sufficiently large enough to defer a full-sized
CCCT, the SO model is configured to allow fractional CCCT unit sizes for both the Base Case
and the Change Case. This allows the Class 2 DSM resource to partially displace the CCCT.
Deferral of CCCT capacity may start as early as 2017.t0 Note that Class 2 DSM resources can
also defer front office transactions (a market resource representing a range of forward firm
market purchase products).
The resource capacity deferral benefit is calculated in two steps:
l. Fixed Cost Deferral Benefit Determination
Fixed cost benefits are obtained by calculating the differences in annual fixed and capital
recovery costs (millions of 2012 dollars) between the base portfolio and the portfolio
with the Class 2 DSM program removed. The stream of annual benefits is then converted
into a net present value (NPV) using the 2013 IRP discount rate (6.882 percent).
2. Levelized Value Calculation
The fixed cost resource deferral benefit value obtained from step I is divided by the Class
2 DSM program energy in megawatt-hours (also calculated as a present value) to yield a
value in nominal levelized dollars per megawatt-hour ($AvIWh).
This value, along with the T&D investment deferral credit and stochastic risk reduction credit,
are added to the PaR model decrement values to yield the final adjusted values.
Table D.l reports the nominal levelized avoided costs by DSM resource for 2013 through2032,
along with a breakdown of the three cost credits (capacity deferral, T&D investment deferral,
and stochastic risk reduction) for the Accelerated Class 2 DSM decrement study. Table D.2
reports the differences between Table D.l and Table N.l from Appendix N of the 2013 IRP,
Volume II (Non-Accelerated DSM deuement study). Tables D.3 and D.4 report the nominal
avoided cost by year in $/MWh.
'o When modeling a CCCT as a fractional resource, the timing of that CCCT in the portfolio can change from the
base portfolio developed using full-sized CCCT resource alternatives.
104
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PACTFICoRP - 2OI3 IRP UPDATE APPENDX D - ACCELERATED DSM DECREMENT ANALYSIS
The total avoided costs from the Accelerated Class 2 DSM are less than those reported in the
Non-Accelerated Class 2 DSM decrement study as presented in Appendix N of the 2013 IRP.
The lower avoided cost values are attributed to a lower capacity resource deferral credit
($18.4944Wh for Non-Accelerated DSM, $13.33lIvIWh for Accelerated DSM). The capacity
resource deferral value is determined based on the fixed cost, size and timing of the resources
that are deferred in the Change Case due to removal of the 100 MW of Class 2 DSM at zero cost.
In the Change Case for the Non-Accelerated Class 2 DSM analysis, the fractional CCCT is
selected in2020 and2023, while in the Change Case of the current Accelerated Class 2 DSM
decrement study, the first CCCT is selected in 2024 because more DSM resources are available
due to accelerated ramp rates. As a result the timing of the CCCTs that could be defened by the
100 MW of zero cost Class 2 DSM is different in the two decrement studies. Table D.5 shows
the differences in expansion resource portfolios between the Change Case and the Base Case of
the Non-Accelerated DSM decrement study presented in Appendix N of the 2013 IRP.
Table D.5 - Portfolio Difference - Appendix N (Non-Accelerated DSIVI)
For the Change Case in the Non-Accelerated DSM decrement study, prior to 2020 the only
resources defened are FOTs, which have no fixed costs, and provide no capacity deferral
benefits. Capacity benefits materialize beginning 2020, with the partial displacement of a
fractional CCCT resource. The incremental DSM from the Accelerated DSM case results in
CCCTs being eliminated, reduced and delayed (starting with fractional CCCTs) beginning in
2020, as compared to the Non Accelerated DSM case, which results in reduced capacrty benefits.
Table D.6 shows the differences in expansion resource portfolios between the Change Case and
the Base Case for the Accelerated DSM study. For this Change Case, the deferral resources in
the front years continue to be FOTs, but the partial displacement of CCCTs starts later, in 2024.
]CCTJ 96 8 395 (190 147 u5
,OTMm03 23 93 94 l5 16 14 8 (263 (159 (38 I
,oTcoB 03 63 93 69 (51
,OT tvlidColmbh 03 l3
tOT Mitcotunbh 03 - 2 225 94 3I
109
PACTICoRP - 201 3 IRP Upnare ApprNox D - Accsr-eRATEo DSM DEcREMENT ANALysrs
Table D.6 - Portfolio Difference - Non-Accelerated DSM
Overall, the delay in timing of the defened CCCT reduces the net present value of savings in
fixed costs, which lowers capacrty deferral credits from $l8.49Adwh in Appendix N to
$13.334{Wh in the Accelerated DSM study.
Consistent with the results for the 2013 IP.P, the residential air conditioning decrements produce
the highest value for both the east and west locations. The water heating, plug loads, and system
load shapes provide the lowest avoided costs. Much of their end use shapes reduce loads during a
greater percentage of off-peak hours than the other shapes and during all seasons, not just the
summer.
PaCrICoRp _ 2OI3 IRP UPDATE APPENDIX E - IRP Table A.7 Correction
AppgNDIx E - IRP TAgrg 4.7 COnnpCTIoN
The following table was included as part of PacifiCorp's response to Wyoming Public Service
Commission Staff Data Request 2.5 (Docket No. 20000-424-EA-13). This is the corrected
version of Table A.7 from the 2013 IRP.
Table E.l - Jurisdictional Contribution to Coincident Peak 1997 through 2012
peak's do not include sales for resale or ldaho exchange
llt
PACIFICoRP _ 20 13 IRP Upparr CONFIDENTIAL APPENDIX F - BREAKEvEN ANAIySIS
CoNpIDENTIAL APPENDIX F - BNPATEVEN
ANarvsrs
On November 25, 2013 the Washington Utilities and Transportation Commission (WUTC)
acknowledged PacifiCorp's 2013 IRP. In Docket UE-120416 the WUTC stated the 2013 tRP
"meets the requirements of Revised Code of Washington 19.280.030 and Washington
Administrative Code 480- I 00-23 8."
The WUTC further provided "suggestions and requests for future IRP filings", which included a
request to update PacifiCorp's coal analysis as part of the 2013 IRP Update and include various
price curves for carbon regulation and price curves for natural gas where it would be more
economical to operate a given unit using natural gas as opposed to coal. This Confidential
Appendix is included in the 2013 IRP Update to satisfu the WUTC requested update.
Carbon Regulation
In their memo the WUTC specifically mentioned two carbon related items: (l) The September 20,
2013 EPA proposed regulations on new coal and natural gas-fired generating plants, and (2) the
June 25, 2013 Presidential Memorandum directing the Environmental Protection Agency (EPA)
to propose regulations on existing coal plants by June 2014.
PacifiCorp recognizes there is uncertainty around the potential costs resulting from pending
regulation of COz emissions applicable to existing natural gas and coal resources. Additionally,
despite issuance of the June 2013 Presidential Memorandum, there is tremendous uncertainty
about the regulatory mechanisms that might be used in EPA's pending rule-making process, and
consequently there continues to be uncertainty in the cost for future regulations on COz emissions
from existing sources. This uncertainty is the reason that PacifiCorp evaluated a range of COz
price scenarios in the 2013 IRP and in the financial analyses included within Confidential Volume
III.
PacifiCorp has reviewed the June 2013 Presidential Memorandum in which President Obama
directed the EPA to complete greenhouse gas (GHG) standards for both new and existing power
plants. For existing sources, EPA was directed to issue "standards, regulations, or guidelines, as
appropriate" that address GHG emissions from modified, reconstructed, and existing power
plants.r' The Presidential Memorandum did not explicitly set forth regulations for existing coal
plants. The proposed standards, regulations, or guidelines are to be issued by June l, 2014,
finalized by June 1,2015, with implementation of regulations as proposed in SIPs required by
June 30, 2016. EPA would then review the implementation plan proposed by each state.
Accordingly, even if EPA follows the President's aggressive schedule, the effective compliance
dates for these standards, regulations, or guidelines are a number of years into the future.
I I Presidential Memorandum - Power Sector Carbon Pollution Standards, June 25, 2013 .
113
PACIFICORP -2013 IRP Upnarg CONFIDENTIAL APPENDIX F _ BREAKEVEN ANALYSIS
The June 2013 Presidential Memorandum did not detail how EPA will approach CO2 regulation
or what the resulting standards, regulations, or guidelines will ultimately entail for existing
resources.
Absent any information on how EPA intends to proceed with its rule-making process, and without
any information on how individual states will propose to implement those regulations through a
SIP, there is currently no,means to develop a specific CO2 price assumption that accurately reflect
potential CO2 regulation.'' As such the COz assumptions used in the 2013 IRP remain reasonable.
The IRP assumptions already represent a wide range of policy mechanisms that might be used to
regulate COz emissions in the power sector at some point in the future. The range of assumptions
are based upon independent third- party price projections, with a high scenario that is consistent
with prominent legislative proposals, and with even higher scenarios developed consistent with
stakeholder input during the pre-frling public input process for this IRP. This approach was taken
because, as of today, there are a wide range of potential future policy tools that may be employed
to regulate COz emissions. Because the June 2013 Presidential Memorandum does not direct a
particular type of regulatory approach, it does not make one particular approach more or less
likely and therefore does not change the IRP assumptions. Similarly, because there is no detail on
which to base an analysis, it does not make a particular CO2 price forecast used in the IRP more
or less reasonable.
Given the timeline set forth in the Presidential Memorandum, the Company will have multiple
opportunities to re-evaluate its CO2 price assumptions incorporating new information with
issuance of proposed regulations in June 2014. As assumptions are developed forthe 2015 [RP,
the Company will re-evaluate current market conditions and policy developments along with
current forecasts from external sources in establishing updates, if any, to its CO2 price
assumptions. At this point however there is no reason to believe the assumptions contained in the
2013 IRP are not reasonable.
Natural Gas Prices
The WUTC also pointed to changes in gas prices, and suggested that "...a more detailed analysis
that focuses on the gaps between various projections that the Company used and identifies the
price level at which it would become cost effective to switch an existing coal plant to natural gas
is required to beffer inform the Company's decision making process".l3 Again, the Company
posits that the analysis already provided in Confidential Volume III is sufficient to find breakeven
points.
Figure F.l below includes a shaded area representing the spread between the high and low gas
forecasts used in the 2013 IRP. The two lines on the graph are the September and December 2013
forecasts used in the IRP Update. As shown, the current forecasts are within the range analyzed
for the 2013 IRP. As such, analysis contained within the IRP is applicable to find the breakeven
points as requested.
t2 While some groups have made recommendations to EPA, EPA has provided no indication of how it plans to
proceed through its rulemaking process.
13 PacifiCorp IRP Acknowledgment Letter - Attachment, Washington Utilities and Transportation Commission,
Docket UE-120416 atpage 3,
tt4
PaCrICOnp - 201 3 IRP UPDATE CONFIDENTIAL AppgwoX F - BREAKEVEN AUAI-YSTS
Figure F.l - Natural Gas Price Forecast for 2013 IRP Update
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Confidential Volume III Analysis
As discussed above, PacifiCorp malyzed investnent decisions contained in Confidential Volume
III of the 2013 IRP across a wide range of gas and COz price assumptions. There is not any
additional information to suggest the range tested for the two variables is applicable today as it
was then. Given that, results from PacifiCorp's analysis for Hunter Unit 1, Bridger Units 3 and 4
and Naughton Unit 3 shown in Confidential Volume III can be used to address the requests from
the WIITC. That is, the analysis can be used to estimate valid breakeven points as requested.
Methodology
As discussed in the 2013 IRP, present value revenue requirement differential (PVRR(d)) analyses
are used to quantifr the benefit or cost of completing coal unit environmental investnents by
legally binding compliance deadlines as compared to the next best alternative. The PVRR(d) for
any given environmental investnent is calculated as the difference in system costs between two
System Optimizer simulations. In one System Optimizer simulation, the costs for near-term and
prospective future environmental invesfrnents required for a unit to continue operating as a coal-
fueled facility are included as incremental system costs. In a second System Optimizer
simulation, it is assumed that coal-fueled operations cease at the compliance deadline, allowing
the model to choose the next best compliance alternative where incremental environmental
investnent are avoided. In this second simulation, the System Optimizer model evaluates
115
PACIFICoRP _ 20 13 IRP Upoare CONFIDENTIAL APPENDIX F - BnTaxTwn ANALYSIS
converting a unit to operate as a gas-fueled facility and early retirement as potential alternatives to
the installation of emissions control equipment.'o The second System Optimizer simulation also
considers how cost and performance assumptions are affected when one or more units at a plant
convert to natural gas or retire early.
The PVRR(d) analyses for the resources in questions (Hunter Unit l, Jim Bridger Units 3 and 4,
and Naughton Unit 3) were performed on broad range of different market scenarios pairing
varying levels of natural gas prices and COz costs. These scenarios looked at high, base, and low
gas prices as well as high, low, and base COz costs. One can interpolate breakeven points for
both gas and COz costs using these study results, as shown below.
To find the breakeven point for a single factor, the other factors must be held constant. That is, to
isolate the effects of COz prices for instance, the natural gas price relationship with PVRR(d)
results is shown for the natural gas price scenarios in which the base case COz price assumption is
used. Holding CO2 costs fixed at the base case assumption allows for finding an estimate for the
breakeven natural gas price. Likewise, the COz breakeven points are found using scenarios with
base gas price forecasts.
Hunter Unit I
The Hunter Unit I baghouse and low NOl burner (LNB) breakeven analysis relies on an
PVRR(d) analysis completed to support the appropriations request (APR), which was approved in
May 2012, and summarized in Confidential Volume III of the 2013 IRP. Table F.l shows the
PVRR(d) results among five different scenarios analyzed in support of the APR which can be
used to find the breakeven points for gas and COz prices, as discussed above.
Confidential Table F.l - Hunter I APR Emission Control PYRR(d) Analysis Results, 2026
SCR
Figure F.2 graphically displays the relationship between the nominal levelized natural gas price at
the Opal market hub over the period 2015 through 2030 and the PVRR(d) benefit/cost of the
incremental investments required for continued coal operation of Hunter Units I with the
additional baghouse and SCR. To isolate the effects of COz prices, the natural gas price
relationship with PVRR(d) results is shown for the natural gas price scenarios in which the base
case COz price assumption is used. The result is a predicted breakeven value of f per
MMBtu before gas conversion would be considered.
ra In the case of an early retirement altemative, the System Optimizer model can fill the resource need by selecting
from the full suite of supply side resources used in the IRP portfolio development process. Current new resource
options are summarized in Volume l, Chapter 6 of the 2013 IRP.
ll6
Redacted
PACIFICoRP _ 20 I 3 IRP UPDATE CONFIDENTIAL APPENOIX F _ BREAKEVEU ANELYSIS
Confidential Figure F.2 - Relationship between Gas Prices and the PYRR(d) (Benefit)/Cost
of the Baghouse and LNB Investments at Hunter Unit I
The results of a similar analysis for the breakeven value for COz are shown in Figure F.3. Here, it
is the relationship between the nominal levelized COz cost over the 2015 to 2030 period and the
PVRR(d) of continued coal operation of Hunter Units I with the additional baghouse and LNB
that is shown. In this case, to isolate the effects of gas price changes, base case natural gas prices
assumptions are maintained. As shown, COz cost would have to be at a levelized rutr. if !
per ton or greater to consider gas conversion for this unit.
tt7
Redacted
PecmICOnp - 20 13 IRP UPDATE CONFIDENTIAL APPENDIX F _ BREAKEVEN ANALYSIS
Confidential Figure F.3 - Relationship between COz Prices and the PYRR(d) @enefit/Cost
of the SCR Investments at Hunter Unit I
Jim Bridger 3 and 4
Breakeven analysis for Jim Bridger Units 3 and 4 can be completed relying on the analysis
provided to support two regulatory filings: (l) Application for a Certificate of Public Convenience
and Necessity (CPCN) filed with the Wyoming Public Service Commission on August 7,2012's,
and (2) Voluntary Request for Approval of Resource Decision filed with the Public Service
Commission of Utah on August 24,201216. The Company used the same analysis to support the
Wyoming and Utah filings, and the base case natural gas, power, and COz price assumptions are
the same as the medium price assumptions used in the 2013 IRP.
Table F.2 shows the PVRR(d) results for five of the nine different scenarios analyzed in support
of the Jim Bridger Unit 3 and Unit 4 CPCN analysis (and provided in Confidential Volume III of
the 2013 IRP). These five represent the cases for the base gas, or CO2 price scenarios.
15 See Wyoming Docket No. 20000-418-EA-12. The Wyoming Public Service Commission approved the
Company's CPCN application in a public deliberation on April 10, 2013.
16 See Utah Docket No. 12-035-92.
ll8
PACTICORP -2013 IRP UPDATE CONFIDENTIAL APPENDD( F _ BREAKEVEN ANALYSIS
Confidential Table F.2 - Bridger 3 and 4 CPCN Emission Control PyRR(d) Analysis
Results
These points can be used to perform analysis similar to that shown above for Hunter Unit l.
Figure F.4 shows the relationship benveen gas prices and the PVRR(d) of benefit/cost of the
incremental investments required for continued coal operation of Jim Bridger Units 3 and 4.
Again, to isolate the impact of changes in gas prices, thglq value was held constant at the base
level. As shown in the figure, a breakeven price of I per MMBtu would be needed to
consider gas conversion.
Confidential Figure F.4 - Relationship between Gas Prices and the PyRR(d) @enefit/Cost
of the SCR Investments at Jim Bridger Units 3 & 4
Figure F.5 below shows the relationship between COz prices and the PVRR(d) of benefit/cost of
the incremental investments required for continued coal operation of Jim Bridger Units 3 and 4.
Here the gas prices were held constant at the base level assumed. As shown, the breakeven
levelized Co2 p.ice is I/ton.
Redacted
119
PncrrConp - 2013 IRP Upoare CONFIDENTIAL APPENDX F _ BREAKEVEN ANALYSIS
Confidential Figure F.5 - Relationship between COz Prices and the PVRR(d) @enefit)/Cost
of the SCR Investments at Jim Bridger Units 3 & 4
Redacted
Naughton Unit 3
PacifiCorp completed an Emission Control PVRR(d) analysis in its evaluation of SCR and
baghouse investments required by December 31, 2014 to meet Regional Haze regulations at
Naughton Unit 3. The analysis was completed in support of the Company's Application for a
Certificate of Public Convenience and Necessity (CPCN) filed with the Wyoming Public Service
Commission on September 16, 2OlIr7. Information from this filing is used for the breakeven
analysis requested. Table F.3 shows the PVRR(d) results for five different scenarios analyzed in
support of the Naughton Unit 3 CPCN analysis. These are the scenarios relying on base
assumptions for gas, or COz prices.
Confidential Table F.3 - Naughton 3 CPCN Emission Control PyRR(d) Analysis Results
r7 Wyoming Docket No. 20000-400-EA-l I
t20
Redacted
PacrICOnp _ 20 I 3 IRP UPDATE CONFIDENTIAL AppsNorx F - BnraxrveN ANlr.ysrs
Figure F.6 below shows a very strong linear relationship between the nominal levelized price of
Opal natural gas prices and the PVRR(d) benefit/cost of the incremental environmental
investments required at Naughton Unit 3. Based upon this trend, levelized natural gas prices
would need to increase from $6.00 per mmBtu as was in the base case forward price curve to
I per mmBtu to achieve a breakeven PVRR(d).
Confidential Figure F.6 - Relationship between Gas Prices and the PVRR(d) (Benefit)/Cost
of the SCR and Baghouse Investments at Naughton Unit 3
Higher CO2 price assumptions improve the PVRR(d) in favor of the gas conversion alternative,
and lower CO2 prices erode the benefits of the gas conversion alternative; however, PVRR(d)
results remain favorable to the gas conversion alternative when CO2 prices are zero and paired
with the base case natural gas price assumptions, as shown in Figure F.7. As with the trend
described in the relationship between natural gas prices and the PVRR(d) results, the relationship
between CO2 prices and the PVRR(d) benefit/cost of the incremental environmental investments
at Naughton Unit 3 is intuitive. Because the COz content of coal is nearly double the COz content
of natural gas, higher CO2 prices lowers the cost of emissions for the gas conversion alternative
and lowers the fuel cost ofother natural gas-fueled system resources used to offset any generation
lost from the coal-fueled Naughton Unit 3 asset.
t2l
PACIFICoRP _ 20 I 3 IRP UPDATE CONFIDENTIAL APPENDIX F _ BREAKEVEN A.,{,
Confidential Figure F.7 - Relationship between COz Prices and the PyRR(d) (Benefit)/Cosr
of the SCR and Baghouse Investments at Naughton Unit 3
Redacted
122