20110628Addendum.pdf

~. ROCKY MOUNTAINPOER
A DIVIION OF PAClACRP
RECE\VED
16\\ JUN 28 l\~\ \0: 25 201 South Main, Suite 2300
Salt lake City, Utah 84111
June 28, 201 1
VI OVERNGHT DELIVERY
Idaho Public Utilities Commission
472 West Washigton
Boise, Idaho 83702
Attention:Jean Jewell
Commission Secreta
RE: Case No. PAC-E-ll-10
PacifCorp's 2011 Integrated Resource Plan - Addendum
PacifiCorp (or Company) fied its 2011 Integrted Resoure Plan (2011 IR) with the Idao
Public Utilties Commssion (Commssion) on March 31, 2011. At that time, the Company
indicated that it would be fiing supplementa inormation to the 2011 IR at a later date. To tht
end, please fid enclosed the origina and seven copies of the Addendum to the 2011 IR.
As cited in Chapter 2, page 21 of the 201 1 IR, ths Addendum includes the following additiona
studies:
. Stochasic anysis of the Energy Gateway transmission scenaos documented in Chapter
4 of the 2011 IR;
· Stochatic production cost simulation of revised Energy Gateway and minial Energy
Gateway portolios; the revised portfolios account for tranmission operational
constrnts not captued with the System Optiize capacity expansion model, as well as
an alternate strtegy for representing out-year generation resources;
. An energy effciency (Class 2 demad-side management) avoided cost stdy; and
. An evaluaon of wid capita cost and capacity factors recommendations and associated
supportg data provided by Interwest Energy Alliance.
Copies of the 2011 IRP and ths Addendum are available electronically on PacifiCorp's website,
at ww.pacificorp.com.
Idaho Public Utilties Commission
June 28, 201 1
Page 2
All formal correspondence and data requests regardig ths filig should be addressed as follows:
Bye-mail (preferrd):datareguest(ßpacificorp.com
irp(ßpacificorp.com
ted. weston(ßpacificorp.com
yyonne.hogle(ßpacificorp.com
By reguar mail:Data Request Response Center
PacifiCorp
825 NE Multnomah Strt, Suite 2000
Portland, Oregon, 97232
With copies to:Ted Weston
Idaho Regulatory Affais Manger
Rocky Mountain Power
201 South Mai Street, One Uta Center, Suite 2300
Salt Lae City, Uta 84111
Yvonne R. Hogle
Rocky Mountan Power
201 South Mai Street, One Uta Center, Suite 2300
Salt Lake City, Uta 84111
Informal inquies may be directed to Pete Waren, Manger, Integrated Resource Plang at
[phone] or Ted Weston, Idaho Reguatory Affai Manager, at [phone].
Sincerely,
~~~~::~
Enclosures
cc: Terr Carlock - Idaho Pulic Utilities Commission
Rick Sterling - Idao Public Utilties Commission
Rady Lobb - Idao Public Utilties Commssion
Mark Stokes - Idao Power Company
Nancy Kelly - Western Resource Advocates
Radall Budge - Raine, Olson, Nye, Budge & Bailey
Eric Olson - Racine, Olson, Nye, Budge & Bailey
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For more information,contact:
PacifiCorp
IRP Resource Planning
825 N.E.Multnomah,Suite 600
Portland,Oregon 97232
[phone]
irp(pacificorp.com
http://www.pacificorp.com
Cover Photos (Left to Right):
Wind:McFadden Ridge I
Thermal-Gas:Lake Side Power Plant
Hydroelectric:Lemolo]on North Umpqua River
Transmission:Distribution Transformers
Solar:Salt Palace Convention Center Photovoltaic Solar Project
Wind Turbine:Dunlap I Wind Project
PAdnICoaP —2011 IRP TsLE OF CONTENTS
TABLE OF CONTENTS
TABLE OF CONTENTS I
INDEX OF TABLES II
INDEX OF FIGURES II
ADDENDUM INTRODUCTION III
CHAPTER 1-STOCHASTIC RESULTS FOR ENERGY GATEWAY SCENARIOS 1
Infroduction 1
Stochastic Production Cost Modeling Results 4
Conclusion 5
SuPPLEINTAL LIwuTED ENERGY GATEWAY ScENA1U0 ANALYsIs 5
Introduction 5
Study Approach Details 6
Study Results 7
Conclusion 11
CHAPTER 2-CLASS 2 DSM DECREMENT STUDY 13
MODELING APPR0ACII 13
Generation Resource Capacity Deferral Benefit Methodology 14
CLAss 2 DSM DEcREMENT VALUE RESULTS 14
CHAPTER 3-APPRAISAL OF INTERWEST ENERGY ALLIANCE’S WIND CAPITAL COST AND
CAPACITY FACTOR RECOMMENDATIONS 25
INTRODUCTION 25
CAJITAL CosTs 25
Capacity Factors 27
CoNcLusIoN 28
APPENDIX A -COMMENTS AND DATA SUBMISSION FROM INTERWEST ENERGY ALLIANCE ...29
PACWICORP —2011 IRP ADDENDUM INDEX OF TABLES AND FIGuREs
INDEX OF TABLES
TABLE 1 —STOCHASTIC MEAN PVRR COST COMPARIsON FOR ENERGY GATEwAY ScENARIOs,No CO2 TAx (“GREEN
RESOURCE FuTURE”)4
TABLE 2—SToCsTIC MEAN PVRR COST C0MPA1usON FOR ENERGY GATEwAY SCENARIOS,MEDrur’1 CO2 TAx
SCENARIO (“GREEN RESOURCE FuTuRE”)4
TABLE 3—RESOURCE PORTFOLIO,REVISED FULL ENERGY GATEwAY SCENAJuo (“GREEN RESOURCE FuTuRE”)8
TABLE 4—RESOURCE PORTFOLIO,REVISED ENERGY GATEWAY-LIIvIIThD SCENARIO (“GREEN RESOURCE FuTuRE”).9
TABLE 5—RESOURCE PORTFOLIO DIFFERENCES,REVISED FULL ENERGY GATEWAY SCENARIO LESS ENERGY
GATEwAY-LIMrFED SCENARIO 10
TABLE 6—PORTFOLIO STOCHASTIC AvE1GE PVRR CoMPARISoN,GATEwAY-LIMrrED VS.FULL GATEwAY
SCENARIOS 11
TABLE 7—LEVELIzED CLASS 2 DSM AvoIDED COSTS BY CARBON DIOxIDE TAX ScENARIO,20-YEAR NET PRESENT
VALUE (2011-2030)16
TABLE 8—Ajqr’mAL NOMIL CLASS 2 DSM AvoIDED COSTS,No CO2 Tx SCENARIO,20 11-2030 17
TABLE 9—ANNuAL NOMll’.&L CLASS 2 DSM AVoIDED COSTS,Low TO VERY HIGH CO2 TAX SCENARIo,2011-2030
18
TABLE 10—ANNUAL NOMINAL CLASS 2 DSM AVOIDED COSTS,MEDHJM CO2 TAX SCENARIO,2011-2030 20
INDEX OF FIGuREs
FIGuRE 1—ENERGY GATEWAY SCENARIO 1 (“GATEWAY-LIMITED”)2
FIGURE 2—ENERGY GATEWAY SCENARIO 2 2
FIGuRE 3—ENERGY GATEwAY SCENARIO 3 3
FIGURE 4—ENERGY GATEWAY SCENARIO 4 (“FULL GATEWAY”)3
FIGURE 5—TNSMIsSION SYsTEM MODEL TOPOLOGY 7
FIGURE 6—EAST CLASS 2 DSM NOMINAL AVOIDED COST TRENDs,Low TO VERY HIGH CO2 TAX SCENARIO 22
FIGURE 7—WEST CLASS 2 DSM NOMINAL AvOIDED COST TRENDS,Low TO VERY HIGH CO2 TAX SCENARIO 22
FIGuRE 8—EAST CLASS 2 DSM NOMINAL AVOIDED COST TRENDs,MEDIUivI CO2 TAX SCENARIO 23
FIGuRE 9-WEST CLASS 2 DSM NOMINAL AVOIDED COST TRENDS,MEDIuM CO2 TAX SCARIo 23
FIGuRE 10-EAST CLASS 2 DSM NOMINAL AVOIDED COST TRENDS,No CO2 TAX SCENARIO 24
FIGURE 11 —WEST CLASS 2 DSM NOMINAL AVOIDED COST TRENDS,No CO2 TAX SCENARIO 24
11
PAcwICo1 —2011 IRP ADDENDUM ADDENDUM INTRODUCTION
ADDENDuM INTRODUCTION
This addendum to the 2011 IRP includes the results of additional studies and analysis that could
not be completed in time to include in the original filed IRP document.These studies and
analysis consist of the following:
•Development of stochastic cost results for 16 Energy Gateway scenarios documented in
Chapter 4 of the 2011 IRP.
•Stochastic production cost simulation of revised full Energy Gateway and minimal
Energy Gateway portfolios;the revised portfolios account for transmission operational
constraints not captured with the System Optimizer capacity expansion model,as well as
an alternate strategy for representing out-year generation resources.
•An energy efficiency (Class 2 demand-side management)avoided cost study,referred to
as the DSM decrement analysis.
•An evaluation of wind capital cost and capacity factor recommendations and associated
supporting data provided by Jnterwest Energy Alliance.
111
PAc[FIC0RP —2011 IRP ADDENDUM CHAPTER 1 —STocsTIc RESULTS FOR ENERGY GAmwAY
CHAPTER 1 —STOCHASTIC RESULTS FOR ENERGY
GATEWAY SCENARIoS
Introduction
PacifiCorp conducted stochastic Monte Carlo production cost simulation of the portfolios and
associated transmission assumptions for the “Green Resource Future”Energy Gateway
expansion scenarios described in Chapter 4 of the 2011 IRP.(Refer to the “Transmission
Scenario Analysis”section,beginning on page 66,for background information on these
scenarios and associated resource modeling assumptions.)As noted in the IRP,PacifiCorp
assumes that state and federal energy policies will continue to emphasize strong support for
renewables development.Hence,the Company focused on the “Green Resource Future”set of
scenarios for stochastic modeling.The Company also concluded that the full Energy Gateway
configuration provides a number of strategic benefits.These benefits include insurance for
regulatory uncertainty and risk mitigation associated with increased resource diversity and
operational flexibility.
These production cost simulations,performed with the Planning and Risk (PaR)model,are
consistent with the stochastic simulations conducted for the core portfolio cases1,utilizing two
carbon dioxide (C02)tax scenarios:$0/ton and $19/ton (or “medium”scenario).2 Figures 1
through 4 are maps of the four Energy Gateway expansion scenarios.
‘Refer to the “Monte Carlo Production Cost Simulation”section of Chapter 7,beginning on page 182,for
background on stochastic production cost modeling conducted for the IRP.
2 Refer to page 159 of the 2011 IRP for definition of the CO2 tax scenarios.
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PAcwICo1u —2011 IRP ADDENI)uM CHAPTER 1 —STOCHASTIC RESULTS FOR ENERGY GATEWAY
Figure 3—Energy Gateway Scenario 3
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PACIFICORP —2011 IRP ADDENDUM CHTER 1 —STOCHASTIC RESULTS FOR ERGY GATEWAY
Stochastic Production Cost Modeling Results
Tables 1 and 2 report the stochastic mean Present Value Revenue Requirement (PVRR)for the
two CO2 tax scenarios along with the PVRR cost component details.
Table 1 —Stochastic Mean PVRR Cost Comparison for Energy Gateway Scenarios,No
CO2 Tax (“Green Resource Future”)
Scenario Scenario Scenario Scenario
Cost Component (Million $)1 2 3 4*
Scenario Scenario Scenario Scenario
1 2 3 4*
$18,821 $18,829 $18,827 $18,789 $19,411 $19,412 $19,525 $19,412
$12,067 $11,131 $11,159 $11,201 —$12,128 $11,362 $11,111 $11,336
*Scenario 4 corresponds to Scenario 7 in Table 4.2,page 78,ofthe 2011 IRP.
Table 2 —Stochastic Mean PVRR Cost Comparison for Energy Gateway Scenarios,
Medium CO2 Tax Scenario (“Green Resource Future”)
Scenario Scenario Scenario Scenario
CostComponent (Million$)1 2 3 4*
Scenario Scenario Scenario Scenario
1 2 3 4*
$26,858 $26,830 $26,826 $26,729 $27,368 $27,287 $27,452 $27,237
$12,067 $11,131 $11,159 $11,201 -$12,128 $11,362 $11,111 $11,336
*Scenario 4 corresponds to Scenario 7 in Table 4.2,page 78,ofthe 2011 IRP.
Medium Natural Gas Price Forecast huh Natural Gas Price Forecast
Variable Costs
Fuel &O&M
Emission Cost
FOT’s &Iong TermContracts
Demand Side Management
Renewables
SystemBalancing Sales
SystemBalancing Purchases
Energy Not Served
Dump Power
Reserve Deficiency
Total Variable Costs
Capital and Fixed Costs
Total PVRR
15,295
2
3,857
3,373
699
(6,031)
1,715
44
(133)
0
15,235
2
3,858
3,421
699
(6,008)
1,705
48
(131)
0
15,232
2
3,858
3,421
699
(6,007)
1,705
48
(131)
0
15,184
2
3,858
3,421
699
(6,017)
1,727
47
(132)
0
15,327
2
3,819
4,059
700
(6,084)
1,683
42
(137)
0
15,211
2
3,811
4,137
681
(6,014)
1,673
50
(140)
0
15,288
2
3,800
4,139
681
(5,989)
1,695
50
(140)
0
15,181
2
3,807
4,137
681
(6,011)
1,709
49
(141)
0
$30,888 $29,960 $29,986 $29,990 $31,540 $30,774 $30,636 $30,748
Medium Natural Gas Price Forecast High Natural Gas Price Forecast
Variable Costs
Fuel&O&M 15,231 15,165 15,155 15,048 15,300 15,181 15,263 15,087
Emission Cost 7,409 7,332 7,335 7,230 7,331 7,190 7,238 7,096
FOT’s &Iong Term Contracts 4,063 4,064 4,064 4,064 4,018 4,008 3,994 4,003
Demand Side Management 3,373 3,421 3,421 3,421 4,059 4,137 4,139 4,137
Renewables 693 693 693 693 694 681 681 681
SystemBalancing Sales (6,458)(6,413)(6,413)(6,387)(6,528)(6,422)(6,399)(6,387)
System Balancing Purchases 2,631 2,646 2,647 2,740 2,583 2,597 2,623 2,710
Energy Not Served 44 48 48 47 42 50 49 48
Dump Power (127)(12 (126)(128)(131)(135)(135)(137)
Reserve Deficiency 0 0 0 0 0 0 0 0
Total Variable Costs
______________________________________________________________________
Capital and Fixed Costs
__________________________________________________________________
Total PVRR $38,925 $37,961 $37,985 $37,930 $39,496 $38,650 $38,563 $38,573
4
PAcWICORP —2011 IRP ADDEi.iiurvl CHAPTER 1—STOCHASTIC RESULTS FOR ENERGY GATEWAY
Conclusion
The stochastic modeling results indicate that the full Energy Gateway configuration is cost-
effective when compared to the Limited Gateway configuration in all CO2 taxlnatural gas price
scenarios and outperforms Energy Gateway Scenarios 2 and 3 with medium natural gas prices
and medium CO2 prices.Consistent with the deterministic modeling results using the System
Optimizer model,the stochastic PVRR range for Energy Gateway expansion scenarios 2 through
4 is narrow,suggesting that economics does not drive a clear selection of the alternatives.As
noted in the 2011 IRP,the Company continues to conclude that proceeding with the full Energy
Gateway expansion scenario is the most prudent strategy.
Supplemental Limited Energy Gateway Scenario Analysis
Introduction
The 2011 IRP contemplated seven different scenarios of the Company’s Energy Gateway
transmission expansion program.The “base case”(Scenario 1)is a minimum-build transmission
plan that,while part of the overall Energy Gateway strategy,needs to be constructed regardless
of other Energy Gateway options due to specific load and reliability requirements.This group of
projects—referred to as “Gateway-Limited”for the purpose of this IRP addendum—includes
Populus to Terminal,Mona to Oquirrh and Sigurd to Red Butte.(Refer to Chapter 10 of the 2011
IRP3 for detailed information on each of the planned Energy Gateway segments).To analyze
these transmission planning scenarios,PacifiCorp used its System Optimizer model to select
optimal resource portfolios constrained by the transmission topology defined for each Energy
Gateway scenario.Both the System Optimizer results reported in the 2011 IRP and the stochastic
production cost simulations described in the previous section indicate that the full Energy
Gateway strategy has a lower PVRR than the Gateway-Limited strategy under a range of
alternative natural gas and CO2 price assumptions.These two Energy Gateway scenarios are
shown in Figures 1 and 4 above.
As an extension of this Energy Gateway scenario analysis,the Company wanted to investigate
the extent to which operational limitations of the transmission system under the Gateway-
Limited scenario constrain the location of thermal resources as determined by System Optimizer.
At issue is whether System Optimizer is adequately accounting for the need (and associated cost)
to site thermal resources at alternative locations given such operational constraints.A particular
focus is on growth resources that the model uses to balance capacity in the outer years of the
simulations.Growth resources,which are assigned forward market prices,serve as proxies for
unspecified electricity supply options.They are also made available within load bubbles as
opposed to acquiring them from market hubs.4 Use of growth resources circumvents
transmission constraints as a limiting factor for adding future resources,and thus may not be a
suitable out-year resource modeling strategy when evaluating transmission expansion scenarios.
For this supplemental Energy Gateway scenario analysis,the Company’s goal was thus to
determine the resource selection and cost impact of applying locational resource constraints
PacifiCorp IRP documents are available at www.pacificorp.comles/irp.html
Growth resources are described on page 179 ofthe 2011 IRP.
5
PAcIFICORP —2011 IRP ADDENDUM CHAPTER 1 —STocasTIc RESULTS FOR ENERGY GATEWAY
based on transmission capacity limits,as well as removing growth resources as future resource
options.To this end,PacifiCorp developed revised Full Gateway and Gateway-Limited
portfolios reflecting application of these resource modeling changes,and then simulated them
with the PaR production cost model to provide a PVRR cost comparison.Subsequent sections
provide more details on the revised portfolio development approach and the results of the
scenario analysis.
Study Approach Details
As noted above,the study approach consisted of developing Gateway-Limited and Full Gateway
portfolios using System Optimizer,and then simulating both portfolios using the Planning and
Risk production cost model.The main modeling assumptions for the study are as follows:
•The expected load,natural gas price,wholesale electricity price,CO2 price forecasts from the
2011 IRP (described on pages 175-176),developed in September 2010,were used.
•With the exception of growth resources (previously available beginning in 2021)and
geothermal5,all resource options specified for the 2011 J.RP were available for System
Optimizer selection.Gas-fired combined-cycle combustion turbine plants acquired after 2019
are represented by two technology options:Mitsubishi G/General Electric H class lx 16,and
General Electric F class 2x1,both with duct firing.(System Optimizer is allowed to select a
fractional amount of duct-firing capacity up to the specified megawatt limits.)All east-side
CCCTs beyond 2014 are assumed to be dry-cooled.
•Consistent with the Green Resource Future outlined in Chapter 4 of the 2011 IRP
(“Transmission Planning”),portfolios are required to meet minimum annual renewable
generation requirements based on the Waxman-Markey proposed targets (6 percent by 2012,
9.5 percent by 2014,13 percent by 2016,16.5%by 2018,and 20%by 2020).The model is
allowed to select an optimal amount of wind resources subject to the minimum renewable
generation requirements.
•System Optimizer was allowed to select a variable amount of market purchases (front office
transaction proxy resources)up to the annual market hub limits.
•Consistent with the original minimum-build Energy Gateway scenario,incremental wind
resources in Wyoming were excluded as model options in the Gateway-Limited scenario.
•The base transmission topology for the 2011 IRP was used,which is shown in Figure 5.
To account for operational transmission constraints under the Gateway-Limited scenario,
PacifiCorp first ran System Optimizer based on the above assumptions to create a base Gateway-
Limited portfolio for inspection by the Transmission Department.Based on this inspection,
PacifiCorp conducted a final System Optimizer run that incorporated the following resource
changes needed to account for a 700 MW incremental capacity transfer limit from the “Utah
South”to “Utah North”topology bubbles once the Mona-Oquirrh transmission project is in
place:
Geothermal resources are excluded as resource options due to recovery risk for resource development costs,a
procurement issue identified in the 2011 IRP.Geothermal projects will nevertheless be included as eligible
resources in future Requests for Proposals.
6 The C and H class CCCTs are assumed to have the same capacity and other attributes,and are considered
interchangeable.
6
PAc[FIC0RP -2011 IRP ADDENDUM CHAPTER 1—STocsTIc RESULTS FOR ENERGY GAmwAY
•The model was constrained to locate 300 MW of Utah wind (“Utah South”bubble)to the
west side of the system (Oregon and Washington).
•The 2019 CCCT resource originally selected by the model at Currant Creek (“Utah South”
Bubble)was manually moved to the “Utah North”bubble.
•The 2025 CCCT resource originally selected by the model for the “Utah North”bubble was
moved to the Borah bubble located in Idaho.
Weat E
Q Load
Generation
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4—+ModeiedTransmisdon
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Wind BubbIe Used forseieion Olend resourcesrequiring inc,ementaltranstnisnron intedment.
PacifiCorp simulated the Full Gateway and final Gateway-Limited portfolios using the PaR
model.Transmission investment costs were incorporated in the PVRRs,consistent with the
approach used for the original minimal-build and full Energy Gateway scenarios.
Study Results
Tables 4 and 5 show the revised Full Gateway and Gateway-Limited portfolio resources
respectively after running System Optimizer with the resource modifications described above.
Table 6 provides the resource differences between the two portfolios.The major resource
changes consist of a location shift of a simple-cycle combustion turbine plant and the Wyoming
wind to the west.
Figure 5—Transmission System Model Topology
___________
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Energy Gateway
Sensitivity Topology
January 10,2011
(2Ollto 2030)
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PACIFICORP —2011 IRP ADDENDuM CHApTER 1 —STocHAsTIc RESULTS FOR ENERGY GATEwAY
Table 6 reports the stochastic average PVRR and cost component details for the revised Full
Gateway and Gateway-Limited scenarios under the Green Resource Future scenario assuming
medium CO2 and medium natural gas prices.A comparison of these PVRR results with the
original Full and Gateway-Limited PVRR results is also provided.As indicated,the generation
resource changes,which account for transmission operational constraints,resulted in higher
PVRRs for both scenarios.The table also shows that the PVRR difference between the revised
Full Gateway and Gateway-Limited scenario portfolios increased by $89 million ($1 .084 billion
less $995 million)relative to the difference for the original portfolios.
Table 6 —Portfolio Stochastic Average PVRR Comparison,Gateway-Limited vs.Full
Gateway Scenarios
Difference
Original (Original
Gateway-Original Full Gateway
Limited Gateway Limited less
Cost Component (MillionS)Scenario Scenario Full Gateway)
Variable Costs
Fuel&O&M $15,231 $15,048 $183
Emission Cost 7,409 7,230 179
FOT’s &Long Term Contracts 4,063 4,064 (1)
Demand Side Management 3,373 3,421 (48)
Renewables 693 693 0
System Balancing Sales (6,458)(6,387)(71)
System Balancing Purchases 2,631 2,740 (109)
Energy Not Served 44 47 (3)
Dump Power (127)(127)0
Reserve Deficiency 0 0 0
Total Variable Costs $26,858 $26,729 $129
Capital and Fixed Costs $12,067 $11,201 $866
Total PVRR $38,925 $37,930 $995
Dilfere nce
Revised (Original
Gateway-Revised Full Gateway
Limited Gateway Limited less
Scenario Scenario Full Gateway)
$14,858 $14,586 $272
7,448 7,172 276
4,195 4,195 (0)
3,657 3,639 18
665 665 (0)
(6,529)(6,250)(279)
2,586 2,744 (158)
46 38 8
(125)(124)(1)
0 0 0
$26,802 $26,666 $136
$12,693 $11,745 $948
$39,495 $38,411 $1,084
Conclusion
Based on these results,PacifiCorp concludes that for future Energy Gateway and other
transmission expansion scenarios conducted for the IRP,a review of initial System Optimizer
portfolio results in light of operational transmission constraints—followed by manual resource
adjustments as needed—is a worthwhile modeling refinement.However,the cost impact is
relatively small such that it would not be expected to change relative cost rankings of alternative
transmission expansion scenarios.Excluding growth resources as a resource option has a more
significant impact,raising portfolio costs due to the higher fixed costs associated with generation
plant.The Company will revisit the efficacy of the growth resource approach for the next IRP.
Original Energy Gateway °ortfolios Revised Energy Gateway lortfolios
11
PAcWIC0Ri -2011 IRP ADDENDUM CHmR 2-DSM DEcREMErr ANALYSIS
CHAPTER 2-CLASS 2 DSM DEcREMENT STUDY
This section presents the methodology and results of the energy efficiency (Class 2 demand-side
management)decrement study.For this analysis,the 2011 JRP preferred portfolio was used to
calculate the decrement value (“avoided cost”)of various types of Class 2 DSM resources.
PacifiCorp will use these decrement values when evaluating the cost-effectiveness of current
programs and potential new programs between IRP cycles.
The Class 2 DSM decrement study was enhanced for the 2011 IRP.To align with the resource
costs applied for resource portfolio development using the System Optimizer capacity expansion
model,cost credits were applied to the Class 2 DSM decrement values reflecting (1)a
transmission and distribution (T&D)investment deferral benefit,(2)a generation capacity
investment deferral benefit,and (3)a stochastic risk reduction benefit associated with clean,no-
fuel resources.7 Decrement values for two new energy efficiency load shapes were also
estimated:residential water heating and “plug”loads (i.e.,energy consumed by electronic
devices plugged into sockets.)
Modeling Approach
To determine the Class 2 DSM decrement values,PacifiCorp defined 17 shaped Class 2 DSM
resources,each at 100 megawatts at the time of peak load,and available starting in 2011 and for
the duration of the 20-year IRP study period.In contrast,the valuation study for the 2008 IRP
focused on 13 resources.The added resources consist of residential water heating and plug loads
for both east and west control areas.Adding these new energy efficiency resources to the
analysis is intended to provide a refmed valuation for energy savings and further aid in
developing program initiatives for such applications as showerheads,heat pump water heaters,
and consumer electronics.
Consistent with prior valuation studies,PacifiCorp first determined the system production cost
with and without each Class 2 DSM resources using the PaR production cost model in Monte
Carlo stochastics mode.The difference in production cost (stochastic mean PVRR)for the two
runs indicates the system value attributable to the DSM resource through lower spot market
transaction activity and resource re-optimization with the DSM resource in the portfolio.The
cost credits mentioned above are then added separately outside of the model,thereby increasing
Class 2 DSM decrement values.The resource deferral benefit,as a new step for deriving the
decrement values value,is described below.The PaR decrement values were determined for
three CO2 tax scenarios:zero,medium (starting at $19/ton and escalating to $39/ton by 2030),
and low-to-very high (starting as $12/ton and escalating to $93/ton by 2030).
Refer to Volume 1,page 147 of the 2011 IRP for a summary ofthe T&D investment deferral and stochastic risk
reduction cost credits applied to the System Optimizer energy efficiency resource options.
13
PAcWIC0RP —2011 IRP ADDENDUM CTER 2—DSM DECREMENT ANALYSIS
Generation Resource Capacity Deferral Benefit Methodology
PacifiCorp used the System Optimizer model to determine the generation resource capacity
deferral benefit.The approach is similar to the stochastic production cost difference method,
except that only the fixed cost benefit of adding each 1 00-megawatt Class 2 DSM resource is
calculated.This is accomplished by running System Optimizer with a base resource portfolio that
excludes each 100-megawatt Class 2 DSM program,and then comparing the fixed portfolio costs
against the cost of the same portfolio derived by System Optimizer that includes the DSM
program at zero cost.The simulation period is 20 years.As a simplifying assumption,PacifiCorp
applied the East “system”load shape for the generic DSM program,which has a capacity
planning contribution of 93 percent and a capacity factor of 69 percent.The resource deferral
fixed cost benefit is comprised of the deferred capital recovery and fixed operation and
maintenance costs of a “next best alternative”resource—a combined-cycle combustion turbine
(CCCT).The difference in the portfolio fixed cost represents the resource deferral benefit of the
DSM program.(Note that System Optimizer’s production cost benefits were not taken into
account to avoid double-counting the benefit extracted from stochastic PaR model results.)
Since a 100-megawatt Class 2 DSM is not sufficiently large enough to defer a CCCT,System
Optimizer was configured to allow fractional CCCT unit sizes for both the base portfolio and
each of the 17 Class 2 DSM resource portfolios.Deferral of CCCT capacity can begin starting in
2015,the year after the Lake Side 2 CCCT is planned to be in service.Note that each Class 2
DSM resource can also defer front office transactions (a market resource representing a range of
forward firm market purchase products).
The resource capacity deferral benefit is calculated in two steps:
1.Fixed Cost Deferral Benefit Determination
Fixed cost benefits are obtained by calculating the differences in annual fixed and capital
recovery costs (millions of 2010 dollars)between the base portfolio and the portfolio
with the Class 2 DSM program addition.The stream of annual benefits is then converted
into a net present value (NPV)using the 2011 IRP discount rate (7.17 percent).
2.Levelized Value Calculation
The fixed cost resource deferral benefit value obtained from step 1 is divided by the Class
2 DSM program energy in megawatt-hours (also converted to a NPV)to yield a value in
dollars per megawatt-hour-year ($/MWh-yr).
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.
Class 2 DSM Decrement Value Results
Table 7 reports the NPV levelized avoided costs by DSM resource and CO2 tax scenario for 2011
through 2030,along with a breakdown of the three cost credits (capacity deferral,T&D
investment deferral,and stochastic risk reduction).Tables 8,9,and 10 report the annual nominal
dollar avoided costs,in $/MWh,for each CO2 tax scenario.Figures 6 through 11 graphically
14
PAcWIC0Rp —2011 IRP ADDENDUM CHAPTER 2—DSM DECREMENT ANALYSIS
show the avoided annual cost trends for the three CO2 tax scenarios by east and west location,
along with average annual forward market prices for the relevant location (Palo Verde (PV)for
the east and Mid-Columbia (Mid-C)for the west.)
Consistent with the results for the 2008 JRP,the residential air conditioning decrements produce
the highest value for both the east and west locations.The water heating (new),plug loads (new),
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.
15
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48
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56
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59
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68
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71
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1
Av
o
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EA
S
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PA
C
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3
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WE
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21
PAcWIC0IU —2011 IRP ADDENDUM CHAPTER 2—DSM DEcIMEr ANALYSIS
Figure 6 —East Class 2 DSM Nominal Avoided Cost Trends,Low to Very High CO2 Tax
Scenario
East,Low to Very High C02 Tax Scenario
/
7J/_
/j
-—--1/.v
ut
____________________________________
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
-+—Palo Verde Flat (2011 IRP,Low to Very High C02 Tax)-Residential Cooling
—*Residential Lighting Residential Whole House
-Comrriercial Cooling —Commercial Lighting
t—System Load Shape Water Heating
Plug Loads
Figure 7 —West Class 2 DSM Nominal Avoided Cost Trends,Low to Very High CO2 Tax
Scenario
West Low to Very High C02 Tax Scenario
$200
$190
$180
$170
$160
$150
$140
$130
$120
.$110
$100
In
$90
$80
$70
$60
$50
$40
$30
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Residential Cooling -—---Residential Heating
t Residential Lighting Commercial Cooling
—a---—Residential Whole HoLes —Commercial Lighting
—i—--Syslem Load Shape Mid Colombia Flal(2011 IRP,Lowlo Very High C02 Taut
WaterHealing -Plug Loads
230
220
210
200
190
180
170
160
150
140
130
120
110
100
90
80
70
60
50
40
30
-C
ha
22
PACIFICORP —2011 IRP ADDENDUM CHAPTER 2—DSM DEcREMENT ANALYSIS
Figure 8—East Class 2 DSM Nominal Avoided Cost Trends,Medium CO2 Tax Scenario
East,Medium C02 Tax Scenario
/7
—.---
—---—-
———--,
—--—4
.----
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
---+---PaloVerde FIat (2011 IRP,Medium C02 Tax)——Residential Cooling*ResidentialLighting Residential Whole House
—*——Commercial Cooling ———Commercial Lighting—i—-—System Load Shape Water HeatingPlugLoads
Figure 9—West Class 2 DSM Nominal Avoided Cost Trends,Medium CO2 Tax Scenario
$180
$170
$160
$150
$140
$130
$120
$110
$100
$90
$80
$70
$60
$50
$40
$30
West,Medium C02 Tax Scenario
2011 2012 2013 2014 2019 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
—--—Reoidental Cooling —S——Residental Heating —t——Renidential Lighting
Commercial Coning —--—Residental Whole Home —-—--Commercial Lightemg
—‘—-—SystemLoad Shape -—-Mid Columbia Flat (2011 IRP,MediumC02 Tax)Water Heating
Plug Loads
180
170
160
150
140
130
120
110
100
go
80
70
60
50
40
30
05
----
-—--—-.--——------—------.--—-—------
23
PAcWIC0RP —2011 IRP ADDENDUM CEIAPmR 2—DSM DEciuMEr ANALYSIS
Figure 10 —East Class 2 DSM Nominal Avoided Cost Trends,No CO2 Tax Scenario
East,$0 C02 Tax Scenario
150
140
130
120
110
!E
60 _._--.—
50
---4,--
40
30
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PaloVerde Flat (2011 IRP,$0 C02 Tax)———Residential Cooling —&-——Residential Lighting
Residential Whole House —Commercial Cooling —•—Commercial Lighting
—1—System Load Shape Water Heating Plug Loads
Figure 11 —West Class 2 DSM Nominal Avoided Cost Trends,No CO2 Tax Scenario
West,$0 C02 Tax Scenario
$150
::
__
$120 -
$60
$50 -----—-
$40 -
$30
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
—4-----Residential Cooling —*-----Residential Heating —*——Residential Lighting
CommercialCooling —4——Residential Whole Home —4----CommercialLighting
—SystemLoad Shape Mid CotambeFlai(201I IRP,$0C02tax)Waler Healing
Plug Loads
24
PAcWICORP -2011 IRP ADDENDUM CHAPTER 3-ADDITIONAL WIND ANALYSIS
CHAPTER 3 -APPRAIsAL OF INTERWEST ENERGY
ALLIANCE’S WIND CAPITAL COST AND CAPACITY
FACTOR RECOMMENDATIONS
Introduction
At the 2011 IRP public input meeting held December 15,2010,Wasatch Wind (a wind project
developer headquartered in Utah)and other participants contended that PacifiCorp’s planning
capital cost value for east-side wind projects were too high,while the planning capacity factor
value—35 percent for Wyoming and 29 percent for Utah—were too low.PacifiCorp agreed to
review information supplied by participants and provide its assessment to all IRP public
participants,also noting that it was too late to incorporate such information into the portfolio
development process.8 At the Company’s discretion,a sensitivity analysis on wind selection
impacts of alternative capital cost and capacity factor values may be conducted as warranted
based on its findings.On January 10,2011,PacifiCorp received wind capital cost and net
capacity factor information from Interwest Energy Alliance (TEA).This information is included
as Appendix A.The sections below provide PaciflCorp’s response to both lEA’s capital cost and
capacity factor recommendations.
Capital Costs
The Company has reviewed the TEA’s “ITC Grant Recipient”project cost overview and,while
informative,the information is not viewed as a suitable replacement for PacifiCorp ‘5 own wind
cost information.The reasons are summarized below.
First,The TEA information is generally not representative of projects that would interconnect to
PacifiCorp’s transmission system.None of the example projects are located in Wyoming and
only one is located in Utah.In contrast,PacifiCorp’s wind capital cost estimates are informed by
both actual project costs and regionally-adjusted capital costs used in an independently produced
model (ICF International’s TPM®model).The 1PM model supports development of PacifiCorp’s
forward price curve and,therefore,assumptions within the 1PM model are inherently important
as it relates to the Company’s TRP.
Second,the costs represented by LEA are derived by taking United States Treasury Department’s
ITC Grants stemming from the 2009 Stimulus Bill and dividing by 0.285.The result is shown on
a cost per unit basis ($/MW).lEA represents the divisor as being an adjustment factor to convert
the amount of cost qualifying for the cash grant into “total wind project costs”.Tt is not known if
the “total wind project costs”being promoted by lEA can accurately be compared to the capital
PacifiCorp presented and discussed resource option characteristics,including those for wind,at the August 4,
2010,public input meeting.The subsequent meeting report,provided to IRP participants on October 5,2010 andpostedtoPacifiCorp’s IRP Web site,included the detailed table of resource characteristics.
25
PAcffICoIu -2011 IRP ADDENDuM CH.pTER 3—ADDITIONAL WIND ANALYSIS
cost assumptions used by PacifiCorp in its most recent version of the IRP.PacifiCorp’s cost
estimate is intended to represent all costs to develop,permit,construct,own and operate a
representative wind-powered generation resource using PacifiCorp’s weighted average cost of
capital and with an assumed economic life of 25 years.
lEA’s estimate appears to rely on two key assumptions:(1)that LEA’s view of “total wind
project costs”includes all of the factors included in PacifiCorp’s cost estimate,and (2)lEA has
accurately interpreted Internal Revenue Service (IRS)guidance associated with such grants.It is
uncertain if TEA’s interpretation of IRS guidance as applied to such a limited set of western
project data can,or should,serve as definitive prediction of all costs that will affect the total bus
bar costs of future wind-powered generation resources as seen from the customer’s perspective.
For example,it is uncertain what portion of transmission-related costs the IRS considers as being
“qualifying costs”under the 2009 Stimulus Bill and how transmission-related costs (e.g.,
generation tie line and/or transmission collector system costs)will change as future projects are
brought to fruition.
Third,the lEA’s sample data set data represents projects that were poised and ready to qualify
for a cash grant under the 2009 Stimulus Act.As such,the data set does not account for
significant new and prospective environmental regulatory actions or other policy decisions that
are expected to change development costs for future projects.Examples include (1)Wyoming’s
Greater sage-grouse core breeding area plan,(2)the effect of emerging “Land-Based Wind
Energy Guidelines”by the U.S.Fish and Wildlife Service,and (3)federal,state or local tax
and/or permitting policies.(As noted above,none of the sample projects in the TEA data set
include projects in Wyoming,which are subject to Wyoming’s sales tax and generation excise
tax policies.)
Fourth,even if TEAs estimates include all of the cost elements included in PacifiCorp’s estimate,
because of the factors that led to the 2009 Stimulus Act,it is impossible to ascertain what cost
concessions developers were able to extract from major equipment suppliers and/or construction
contractors during then-current market conditions.Furthermore,because PacifiCorp is planning
for the long-term,any long-run cost improvements can reasonably be expected to be offset to
some degree by supply chain pricing dynamics and/or the effects of domestic and/or
international market demand,depth and liquidity.Finally,it can also reasonably be expected that
market forces will result in the development of increasingly less desirable and/or more costly
sites as the more optimal sites are utilized (i.e.,moving higher up the cost-supply curve).
In summary,PacifiCorp does not see definitive evidence suggesting that the capital cost
estimates in the JRP for wind-powered generation resources are inappropriately high.However,
to get a sense for what TEA’s capital cost recommendation would do in terms of a wind resource
selection impact,we refer to the alternate wind integration cost sensitivity results on page 244 of
the 2011 LRP.The lower wind integration cost used for this sensitivity study,$5.3 8/MWh,
equates to a fixed cost reduction of $195/kW.Using the alternative wind integration cost value
resulted in 81 MW of additional wind.Based on the $346/kW capital cost reduction advocated
by lEA ($2,239/kW from IRP Table 6.5 less $1,893/kW from page 1 of lEA’s materials),the
capacity impact is not likely to exceed 150 MW.
26
PAcIFICORP —2011 IRP ADDENDUM CHAPTER 3—ADDITIONAL WIND ANALYSIS
Capacity Factors
lEA makes multiple generalized assumptions and,using these assumptions as a basis,suggests
that PacifiCorp should use a 43.6%or higher net capacity factor (NCF)for modeling future
Wyoming wind projects.Below is a discussion of these generalized assumptions and their
suitability for characterizing NCFs for use in the IRP context.
lEA assumes that the NCF associated with PacifiCorp owned wind resources in Wyoming
should serve as a base-level assumption for future wind projects.lEA determines the average
NCF for seven selected resources.Using this average NCF,TEA represents that it can “back
into”an annual average wind speed (in meters per second)that should be associated with future
wind projects constructed in Wyoming.lEA concludes that 8.6 meters per second should be
assumed as the annual average wind speed.Using this average wind assumption,lEA further
concludes a theoretical NCF increase of 112 percent can be achieved if a General Electric (GE)
model 1.5 megawatt (MW)“XLE”wind turbine generator (WTG)is used instead of a GE 1.5
MW “SLE”WTG.The GE 1.5 MW XLE WTG has longer blades and a larger rotor diameter
(82.5 meters)than the GE 1.5 MW SLE WTG (77 meter rotor diameter).TEA considers the GE
1.5 XLE to be an “advanced”WTG design.lEA likewise considers the Vestas V90 and Siemens
2.3 MW WTGs,with 90 meter and 101 meter rotor diameters respectively,to be advanced WTG
designs.Applying the 112 percent enhancement to the Dunlap I NCF,lEA represents it has
demonstrated its theory.
In short lEA suggest that PacifiCorp should assume that all future wind projects in Wyoming are
suitable for WTGs with increased rotor diameters.While PacifiCorp agrees that WTG design
evolutions may favorably impact performance for those sites for which they are suitable,the
Company makes the following observations regarding lEA’s NCF recommendation and the
assumptions it is based on.
First,TEA’s NCF recommendation assumes all Wyoming wind developments could utilize
WTGs with increased rotor diameters.In arriving at this conclusion,TEA points toward an
unreferenced GE determination that,depending on final layouts and turbulence intensity,the GE
XLE model is “meteorologically suitable for some wind projects at 7500’altitude with annual
average wind speeds of 8.5 mIs to over 10 mis”.TEA’s representation that WTG suitability for a
site is primarily based on average annual wind speed and turbulence intensity is flawed.The
suitability of a WTG model(s)for any given site can only be determined using a site specific
mechanical loads assessment performed by the turbine manufacturer.TEA has provided no
evidence of such assessments demonstrating that WTGs with rotor diameters as large as 101
meters are broadly suitable for use in Wyoming.Further,TEA fails to adequately discuss that
WTG suitability is often driven by 50-year peak gusts and turbulence intensity at high wind
speeds.Without a sufficient amount of reliable data from the site towers,it is difficult to
conclusively determine if a WTG is suitable for a given site,let alone if specific WTG models
are broadly suitable for use in Wyoming.Indeed,manufacturers may require more site data to be
collected to verify that their WTGs are suitable,and in the event that site conditions are more
extreme than was indicated by the data provided to the manufacturer (e.g.,higher wind gusts or
higher overall average wind speeds),they may not honor warranties in the event of failures
associated with greater than estimated environmental conditions at the site.For these reasons,
PacifiCorp’s IRP does not rely on generalized WTG assumptions.
27
PACWICORP —2011 IRP ADDENDuM CH.pTER 3—ADDITIONAL WIND ANALYSIS
Second,lEA’s assumed NCF improvement (12 percent applied broadly)associated with the GE
XLE WTG over the GE SLE WTG is significantly higher than that indicated by a recent
Company procurement process.In its “2009R”renewable Request for Proposals,PacifiCorp
received two separate bids from the same developer using the same site and based on the GE
SLE WTG versus GE XLE WTG.The capacity factor difference was only 1.8 percentage points
in favor of the GE 1.5 XLE WTG,a difference of 4.6 percent.This is in contrast to the 12
percent capacity factor improvement recommended by lEA.9 Of note is that the bid based on the
GE XLE WTG commanded a price premium relative to the bid based on the GE SLE WTG.
PacifiCorp further notes that LEA’s recommendation to reduce assumed capital costs (discussed
above)relied on information where the model of WTG was not disclosed.
Finally,in selecting the seven wind projects that serve as the source of the average NCF
assumption that,in turn,serves as the starting point for all of lEA’s subsequent assumptions and
resulting adjustments,TEA fails to consider all of PacifiCorp’s owned and contracted wind
resources in Wyoming.lEA dismisses this choice by stating that “We did not average the
capacity factors for projects in western Wyoming as those projects do not reflect the higher
capacity factors experienced in the central Wyoming projects”.PacifiCorp believes there is no
basis to assume that all future Wyoming resources would be restricted to locations in just central
Wyoming.PacifiCorp’s IRP assumption of a 35 percent NCF for planning purposes is informed
by those wind resources that are actually in the current portfolio.The NCF for operating
Wyoming wind resources—both owned and acquired through power purchase contracts—is
34.98 percent based on weighted averaging with each resource’s nameplate capacity.This
weighted average NCF reflects capacity factor updates utilized in the latest Wyoming General
Rate Case.Of note is that Dunlap I has a NCF of 36.4 percent rather than the 38.6 percent NCF
cited by lEA.This is in comparison to TEA’s starting-point assumption of 37.6 percent.
PacifiCorp emphasizes that the NCF assumption in the IRP is not intended to be based on
idealistic or theoretical assumptions of what may find its way into the portfolio.Indeed,NCF is
not what will determine which individual renewable resources will be added to PacifiCorp’s
portfolio in the future.The cost and risk to customers of those case-by-case decisions is what
will be the determining factor.
Conclusion
For the reasons cited above,PacifiCorp does not find TEA’s recommendations to change the IRP
cost or NCF assumptions associated with wind-powered generation resources to be warranted.
PacifiCorp will continue to rely on its procurement practice of making decisions regarding
individual renewable resource additions on a case-by-case basis,and the standard for such
decisions will continue to be established regulatory principals regarding prudence and benefit to
customers.
Mechanical load suitability of the alternate GE XLE WTG is uncertain.
28
PAcWIC0RP —2011 IRP ADDENDUM APPENDIX A—TEA COMMENTS AND DATA
APPENDIX A -COMMENTS AND DATA SuBMIssIoN
FROM INTERWEST ENERGY ALLIANCE
29
1,P%
INTERWEST
ENERGY ALUANCE
10 January2011
Pete Wamken
PacifiCorp IRP Team
[e-mail]
Re:2011 IRP Modeling
Dear Mr.Warnken:
Interwest Energy Alliance appreciates the opportunity to provide input to promote accurate
cost analysis of wmd and solar energy in the public process related to development of
PacifiCorp’s 2011 IRP.We ask you to consider some of the enclosed materials related to
wind development costs and net capacity factors as you develop modeling inputs and
consider the results.Several questions raised at the public meeting held on December 15,
2010,by Wasatch Wind and others,which require further response and consideration.We
want to provide any support you may require to inform the resource planning process
related to these issues.
First,wind costs are lower than PacifiCorp assumes in its modeling,due to decreases in
turbine prices and related costs.See attached Schedule 1 “Recent Turbines Using the ITC
Grant Proxy”,and “ITC Grant Recipients —CAPEX For U.S.Wind Farms”attached
thereto.
Second,please consider the information related to net capacity factors attached as Schedule
2,with Appendix A “Wind Turbine Brochure Information”and Appendix B “Summary of
Utah WREZ Prospects”attached thereto.Your modeling should reflect the increased net
capacity factors available from this new equipment available to the market.
We appreciate the opportunity to provide this input.
Best regards.
Sincerely,
Craig Cox
Executive Director
P.O.Box 261311,Denver,Colorado 80226 •303-679-9331 •www.interwest.org
I
Recent Turbine Prices using the ITC Grant Proxy
Under the 2009 Stimulus bill,wind projects became eligible to receive a cash grant (the “ITC Grant”)from the
US Treasury Department equal to 30%of the “qualified costs”of a wind project within 60 days after the wind
project achieved commercial operations.Qualified costs include approximately 95%of total wind project costs.
The US Treasury Department published the recipient,date,and amount of the ITC Grant.Based on the recipient
information,we were able to identify the location of the wind project (and the related MW).Based on the
amount of the ITC Grant,we were able to approximate the cost of the wind project.This cost approximation
assumes that since the ITC Grant represents 30%of 95%of the wind project costs,then by simply taking the
ITC Grant amount and dividing it by the product of 30%and 95%(or 28.5%)the total wind project costs are
calculated.For example,assume that the ITC Grant was $100 million.Based on the above assumptions,the
wind project cost would be approximated at $350.9 million ($100 million 1(30%x 95%)).
Using this data from Appendix A we plotted below a polynomial 2’’order trend line to determine the cost per
MW for each region of the US.The dataset may reflect higher prices than market as of Dec 2010 due to
l)Developers with frame agreements prior to 2009 when turbine prices were higher placing those turbines on
projects in 2009 and 2010 2)A perverse ITC incentive that encourages an increase in capex by requiring turbine
suppliers to bundle O/M contracts with the turbine supply.
Looking at the Western US installed cost per MW graph below the trend line indicates turbine prices decreasing
beginning in 2Q2010 and ending at $1,893,430 per MW on July 30,2010
$1500000
$1,000,000
y =-9.4161x +757835x -2E+10
R2=0.1501
$3,000,000
$2,500,000
Western US Wind Project Installed Cost/MW
$2,000,000
.
••,
$500,000
7(612009 8(2512009 10/1412009 121312009 112212010 3/13/2010 5/212010 6/21/2010 8/10/2010 9/2912010
Other regions are below as reference:
Texas Wind Project Installed Cost/MW
$2,500,000
.
$2,000,000
$1,500,000
y =0.3298x2 -26431x +5E+Q8
$1,000,000 R2=0.0037
$500,000
71612009 812512009 10/14/2009 1213/2009 1122/2010 3/1312010 5/2/2010 6/21/2010 8/10/2010 9/2912010
Midwest US Wind Project Installed Cost/MW
$3,000,000
$2500000
.,4
$2,000,000 ••
$1,500,000
$t000 000 y =-1 .058x2 +84948x -2Ei-09
R2 0.0291
$500,000
$0
7/6/2009 8/25/2009 10/14/2009 12/3/2009 1122)2010 3/13/2010 512)2010 6/21/2010 8Il012010 9/29/2010 11/18/2010 1/7/2011
Eastern US Wind Project Installed Cost/MW
$3,000,000 —-_____
_________________
$2,500,000
$2,000,000 -*
$1,500,000
y=-3.1227x2 +251766x-5E÷09
$1,000,000 -R2=0.2847
$500,000
l
7(6/2009 8/25/2009 10114/2009 12/3/2009 1/22/2010 3/13/2010 5/2/2010 6/21/2010 8/10/2010 9/29/2010 11/18/2010
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Wyoming Capacity Factor Recommendations
For IRP modeling,we recommend that Paciflcorp use a 43.6 percent or higher net
capacity factor (NCF)for future Wyoming wind projects.One method Paciflcorp
should consider is the average of the predicted capacity factors and adjusted costs ofthe
already built projects using more recent,next generation turbine performance and cost
data.
GE 1.5 MW sle turbines where installed on all Pacificorp built sites from 2008 through
2010.The following chart illustrates the p50 capacity factor predicted for each of the
sites according to various testimony in PUC dockets in Utah (10-035-23,10-035-89)and
in Oregon (UE200,210).
Wind Projects Built by Pacificorp (2008 through 2010)
j Facility Name MW COD NCF TurbineType
Glenrock Wind I 99 2008 37.40%65 x 1.5MW x 77m rotor,GE SLE
Seen Mile Hill Wind 99 2008 41.00%66 x 1.5MW x 77m rotor,GE SLE
Seen Mile Hill Wind Il 19.5 2008 40.30%66 x 1.5MW x 77m rotor,GE SLE
Glenrock Wind III 39 2009 36.4%13x 1.5MWx 77m rotor,GE SLE
Rolling Hills Wind 99 2009 33.80%66 x 1.5MW x 77m rotor,GE SLE
High Plains 99 2009 35.30%66 x 1.5MW x 77m rotor,GE SLE
McFadden Ridge 28.5 2009 34.50%19x 1.5MWx 77n1 rotor,GE SLE
•Dunlap 111 2010 38.60%74 xl.5MW x 77m rotor,GE SLE
AvgNCFwithRollingHills 37.2%
lAvg NCF without Rolling Hills 376%
Table 1:NCFs of Wyoming Pacificorp Projects
We averaged the NCF with and without the Rolling Hills project to reflect the Oregon
PUC disallowance of certain capital costs due to a lower than expected capacity factor.
We did not average the capacity factors for projects in western Wyoming as those
projects do not reflect the higher capacity factors experienced in the central Wyoming
projects.Using the average NCF for existing Paciflcorp projects is arguably a reasonable
proxy for capacity factors if the GE SLE turbine were the most appropriate turbine going
forward.However,this turbine has lower NCF than newer turbines now on the market
(cost analyis is covered later).These advanced turbines with longer,more efficient
blades for a given nameplate capacity came on the market in 2009 and are being supplied
in commercial quantities to projects by established,credible suppliers.Therefore,we
recommend the NCF be adjusted upward to reflect these advances as follows.
We selected the turbines in the below table for general wind suitability in Wyoming.To
determine turbine potential improvements,in the below table we compared the NCF of
three ofthe most prevalent “advanced”turbines with three “workhorse”turbines that
have been supplied in the United States for several years.The advanced turbines have
been erroniously classified by some as “low wind speed”turbines leading to inaccurate
conclusions that they are not suitable in high wind speed areas.This generally is true at
sea level but not at high altitude.In our experience,most sites above 7000 feet are
suitable for these turbines as long as the average annual wind speeds do not exceed 9.3
m/s*.Increasing the 8.5 mIs sea level limit for Class 2 turbines is governed by the
altitude derate ie.(alt density/sealevel density)’\33.We have found that many Wyoming
sites also exhibit low turbulence and on a case by case basis the wind speed average
upper limit can be even higher depending on turbine spacing and the wind rose.
Competitive wind speeds in Wyoming generally average 8.5 to 9.5 mIs and while not
definitive for the use of advanced turbine at all Wyoming sites,these turbines are
suitable at most sites and should be modeled in the IRP.Ofnote,as further argument,
GE has determined depending on final layouts and turbulence intensity that the xle model
is meterologically suitable for some wind projects at 7500’altitiude with annual average
wind speeds of 8.5 mIs to over 10 m/s.
ReIati Annual Energy Yield
Turbine Nameplate Rotor Rotor Area/for indicated a WS (7000’alt)
.Class Size MW Dia (rn)MW size 9 m/s 8 rn/s 7 mIs —
GE 1.5 sle 2 1.5 77 3104 100%100%100%
Workhorse Suzion S88 2 2.1 88 2896 97%96%95%
Clipper C96 2 -2.5 96 2895 97%—96%95%
GE 1.Sxle 2b 1.5 82.5 3564 111%114%116.4%
Advanced Vestas V90 2b 1.8 90 3534 110%114%115%—
•Siemens 2.3 2b 2.3 101 3483 109%112%114%
aFor normal turbulence,the advanced turbines are generally suitable for sea leval sites with less than an annual a wind speed
limit of 8.5 mIs and somewhat higher for the workhorse turbines.At 7000 feet altitude,the limit can be_increased to approximately
9.3 rn/s and somewhat higher for lower turbulence intensity sites.
Table 2:Increase in Energy Yield using Advanced Turbines
Using the GE sle and xle power curves,we determined the increase in annual energy
yield of the GE xle compared to the GE sle for a typical Wyoming wind distribution
(Wiebull K=2)for three wind speeds.The capacity factor increase ranges from 111%to
116%.We ran Wk sensitivities of 1.8 to 2.2,which are the ranges of wind distributions
in the NREL Western Wind and Solar Integration study for our random selection of
commercially viable wind areas.The NCF increase for the advanced turbines across the
expected Wk’s and wind speeds was 111%to 118%(see table below).
Advanced Turbine Annual Energy Yield Increase
120.0%
118.0%-
116.0%..—
-1.8OWk
110.0%-—2,00Wk
‘‘2.20Wk
108.0%-
106.0%-,.-r-------——r—,---,—r-,
7.0 7.1 7.2 73 7.4 7.5 7.6 7.7 7.8 7.9 8.0 8.1 8.2 2.3 8.4 8.5 8.6 8.7 $2 6.9 9.0
Annual Average Wind Speed rn/s
Chart 1:Energy Yield Improvement using Advanced Turbines
Back caiculating from the average NCF at the Pacificorp projects,with a 15%gross to
net energy loss,reveals annual wind speeds of 8.2 to 9.2 mIs.For this wind speed range
and 1.8 to 2.2 Wk the range of NCF increases ranged from 111%to 114%.We
recommend that a 8.6 mIs wind speed represents the average wind speed for the
Pacificorp projects thus by selecting 112%and an expected minimum Wk of 1.8 from
Chart 1 gives a minimum capacity factor for Wyoming as follows:
Using 3 7.6%NCF as the average from table 1
AdjustedNCF37.6%x 112%42.1%
Next,we wanted to determine the NCF improvement of other advanced turbines
compared to the GE xle results.We compared the rotor arealmw size “rotor ratio”for
each turbine and made scaling adjustments to match the power curves.Generally,the
capacity factor change is directly proportional to the change in rotor ratio.Using this
method,the Vêstas V90-1.8 and the Siemens 2.3 improved the NCF by 109%to 115%
greater than the GE sle and slightly lower than the GE xle.As expected,all three
advanced turbines are in the same general range ofperformance improvement as all three
turbines compete directly in the same markets.Therefore,for simplicity,we
recommend using 112%NCF improvement for all three turbines over the older
technology workhorse turbines.In summary,the evidence indicates a 42.1%NCF for
Wyoming IRP modeling.
Also it could be argued that the capacity factor to model should be from the latest RFP
benchmark (Dunlap)as this process reflects the most recent robust competitive
environment.Consider the Testimony of Stefan A Bird,PacifiCorp,in Utah Public
Service Commission Docket No.10-035-89,Exhibit E,p.11,lines 232-235 (citing
Benchmark memo at p.11-12):“Finally,the IE found that the estimated Benchmark
capacity factor was within the range of capacity factors from proposals associated with
potential resources in the nearby vicinity.”Since the estimated capacity factor for
Dunlap is 38.6%the adjusted NCF with the bctter turbines is:
Adjusted NCF =38.6%x 112%=43.2%
Utah Capacity Factor Recommendations
For IRP modeling,we recommend that Pacificorp use a 34 percent or higher net capacity
factor (NCF)for future Utah wind projects up to 1,000 MW’s.See Exhibit 13.The was
determined by using the same rationale as used above.
Appendix A
1.5 MW Wind Turbine Brochure;
http://www.gepower.corn/prod serv/products/wind turbines/en/i 5mw/index.htm
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.
0
%
—--
—
—
-
--
-
-
‘
10
.
0
%
--
-
-
-
-
-
-
-
-
-
-
—
---
--
-
-
—-
-
-
-
-
-
-
—
—-
0.0
%
i
--
-
-
‘
S
0
20
0
0
40
0
0
60
0
0
80
0
0
10
0
0
0
-
Cu
m
u
l
a
t
i
v
e
MW