2013

Integrated Resource PlanIRP Modeling Schedule Update

Utility-scale Renewable Resource Options Update

Wind Integration Study Update

WECC Planning Reserve Margin “Building Block” Results

Portfolio Development Case Fact Sheets

October 24, 2012

1

Agenda

• IRP modeling schedule update

• Utility-scale resource option updates

• Wind integration study update

• Planning reserve margin development

using the WECC building block approach

• Lunch: 11:30am PT / 12:30pm MT

• Portfolio development case fact sheets

2

IRP MODELING SCHEDULE UPDATE

3

Modeling Schedule

• Start of core portfolio development with System Optimizer delayed to November 1, 2012

• Reasons for delay:

– Encountered performance problems with pre-simulation data processing for the upgraded IRP models, and bugs discovered during our testing

• Ventyx provided multiple software patches over two-month span

• Worked with Ventyx to streamline input set-ups and investigate/implement IT infrastructure improvements

– Ventyx delay in completing the planning reserve margin study

4

Modeling Schedule, cont.

• Current Activities

– Continue testing with full slate of IRP resource

options

– Develop reporting templates for

• Capacity load and resource balance

• Portfolio resources and cost/operational details

– Develop updated initial capacity L&R balance

with new planning reserve margin target

5

UTILITY-SCALE SUPPLY-SIDE RESOURCE

OPTION UPDATES

6

Supply Side Resource Table Updates

• Added a generic geothermal PPA-based resource, reflecting recent responses to the 2016 RFP; assumed similar performance characteristics as other geothermal resources

• Small Utility Scale Solar (2 MWac)– Will apply a 20-year declining cost “glide path” (using

the 1 MW solar resource in the February 2012 NREL Cost Report)

– Sensitivity cases: up to ~26% to be applied to existing costs

• Large Utility Scale Solar (50 MWac)– Fixed and single axis technologies

– Located in Southwest Utah (Washington & Beaver Counties)

7

Supply Side Resource Table Updates, cont.

• Added another Wyoming based wind

resource (40% capacity factor, slightly

higher capital cost)

• Adjusted Wyoming-based wind resource

O&M costs to capture the Wyoming state

production tax

• Modified cost structure of some of the

battery storage resources (Lithium, NaS,

Vanadium Redox)

8

WIND INTEGRATION STUDY UPDATE

9

Agenda

• Updated Load Data, and the Impact

• Revised Results of Sensitivity Scenarios

• Production Cost Modeling

10

Updated Load Data and the Impact

• Corrected load data for the east balancing authority area– Reduces East BAA requirement by 21 aMW

• Impact of the update – Regulating margin requirement at 99.7% tolerance level, net of the

system L10, is slightly lower due to lower load component reserve

requirements

– Contribution to regulating margin requirement due to wind generation

11

Regulation Regulation

West East Ramp Total

Draft Original 65 112 9 186

Corrected 65 125 9 200

Regulation Regulation

West East Ramp Total

Draft Original 166 309 132 608

Corrected 166 293 128 587

Revised Results of Sensitivity Scenarios

• Historical Total Regulating Margin

• Incremental Reserves due to Wind

12

Regulation

West

Regulation

East Ramp Total

Average Wind

Capacity, MW

2007 185 194 134 512 606

2008 176 193 122 491 787

2009 150 211 121 482 1364

2010 158 261 122 541 1810

2011 166 293 128 587 2126

Regulation

West

Regulation

East Ramp Total

Average Wind

Capacity, MW

2007 16 11 2 29 606

2008 26 14 3 42 787

2009 35 45 4 84 1364

2010 44 78 6 129 1810

2011 65 125 9 200 2126

Revised Results of Sensitivity Scenarios,

cont.

• 30-minute Balancing Sensitivity Scenario

– Scheduling interval assumption reduced from hourly to

half-hourly

– Self-supply of ramp reserves is assumed

– Following reserves are half-hour interval rather than hourly

– Wind Following forecast taken at ten minutes into

scheduling interval

– Assumes liquid market at 30-minute intervals

13

Regulation Regulation

West East Ramp Total

Scenario 109 233 128 470

Default 166 293 128 587

Revised Results of Sensitivity Scenarios,

cont.

• Combine East and West BAAs– Ignores real transmission constraints

– East and West load deviations netted concurrently, as well as the

respective wind deviations

– 459 MW represents the sum of East and West requirements in the

default case

• Concurrent Load and Wind– Net wind and load following errors concurrently, as well as wind and

load regulation errors

14

Regulation Ramp Total

Scenario 398 121 520

2012 Study 459 128 587

Regulation Regulation

West East Ramp Total

Scenario 154 284 128 566

2012 Study 166 293 128 587

Production Cost Modeling

• Production costs of integrating wind are determined by the following steps:

• The Regulating Margin costs are determined by Steps 1 and 2. The incremental

reserve added between steps 1 and 2 isolates the impact of the hourly and intra-hour

reserves.

• The System Balancing costs are determined by Steps 3-5, using historical data.

15

1 2013 2013 Load Forecast P50 Profiles No None

2 2013 2013 Load Forecast P50 Profiles Yes None

3 2013 2011 Day-ahead Forecast 2011 Day-ahead Forecast Yes None

4 2013 2011 Actual 2011 Day-ahead Forecast Yes For Load

5 2013 2011 Actual 2011 Actual Yes For Load and Wind

Regulation Margin Cost = System Cost from PaR Simulation 2 less System Cost from PaR Simulation 1

Regulation Reserve Cost Runs

System Balancing Cost Runs

Wind System Balancing Cost = System Cost from PaR simulation 5 (which uses the unit commitment from Simulation 4) less system cost from

PaR simulation 4

PaR Model

SimulationForward Term Load Wind Profile

Incremental

Reserve

Day-ahead Forecast

Error

Production Cost Modeling, cont.

• Differences between the 2012 and 2010 Studies are

driven by:– Substantial reduction in power and gas prices

• 2010 Study – PV HLH $51.42, LLH $35.70 and Opal gas $5.38

• 2012 Study – PV HLH $37.06, LLH $25.75 and Opal gas $3.43

– Different wind regulating reserve modeling

– Removal of the load component of day-ahead balancing

• The total wind integration costs are estimated to be

$1.89/MWh in 2013

16

PLANNING RESERVE MARGIN DEVELOPMENT

USING THE WECC BUILDING BLOCK APPROACH

17

Agenda

• Overview

• Planning Reserve Margin Building Blocks

• Study Method

• Inputs to the Study

• Study Results

• Conclusion

18

Overview

• Purpose of the study: support the Company’s selection

of a planning reserve margin for IRP portfolio

development

• The study uses actual data from 2008 to 2011 and

calculates the building block elements as a percentage

of load

• During the four year historical period, the building block

approach yields a planning margin of approximately 19%

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Planning Reserve Building Blocks

• As defined in WECC’s “2011 Power Supply Assessment” report, the building blocks of planning reserves are– Contingency reserves

• Defined by WECC Standard BAL-STD-002-0 as an amount of spinning reserve and non-spinning reserve held by a balancing authority that is sufficient to meet the North American Electric Reliability Corporate (NERC) Disturbance Control Standard BAL-002-0

– Regulating reserves• An amount of spinning reserves, in addition to contingency reserves,

responsive to automatic generation control sufficient to meet NERC's Control Performance Criteria described in BAL-001-0

– Additional forced outages• An amount of reserves in addition to contingency reserves to cover

additional forced outages after the contingency reserves

– Temperature adders• An amount of reserves to cover the impact of extreme increases in load,

which is defined as an amount that actual load would have one-in-ten probability to exceed (ten percent exceedence)

20

Study Method

• Study period: 2008 – 2011

• Time of the system coincidental peak

• Planning reserve margins are calculated for

– Time of the system peak

– 100 high-load hours

– 10 high-load hours

• Results are presented by year, and as an average over

the study period

21

Inputs to the Study

• Actual hourly system load– Hourly actual load and temperature normalization adjustments

• Generation– Hourly generation from the Company’s thermal, hydro and wind

generating facilities

– Information is used to determine the contingency reserves during the study period

• Regulating margin– Hourly regulation reserves and ramp reserves from the

Company’s 2012 Wind Integration Study

• Forced outages– Actual thermal generation capacity lost due to forced outages

• Temperature adders– Additional load approximating the one-in-ten temperature events

and assumed to be 3.27 percent of one-in-two load

22

Inputs to the Study, cont.

23

2011

2010

2009

2008

Inputs to the Study, cont.

24

Inputs to the Study, cont.

25

2011

2010

2009

2008

Inputs to the Study, cont.

26

Inputs to the Study, cont.

27

2011

2010

2009

2008

Inputs to the Study, cont.

28

Inputs to the Study, cont.

29

2011

2010

2009

2008

Study Results

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• At the time of system coincidental peak

• Average of 100 high-load hours

2008 2009 2010 2011 Average

East West Total East West Total East West Total East West Total

System Coincidental Peak Load 6,079 3,422 9,501 5,898 3,522 9,420 6,073 3,345 9,418 6,392 3,039 9,431

1-in-2 Temperature Adjustment (237) 108 (128) 54 (195) (141) (7) (2) (9) (0) (91) (91)

1-in-10 Temperature Adjustment 191 115 306 195 109 303 198 109 308 209 96 305

Reserve Components, at the time of the system coincidental Peak

Forced Outages 338 43 381 333 85 418 353 19 372 106 197 303

Contingency Reserves 389 171 560 388 189 578 374 176 550 408 160 569

Regulating Margin 252 70 322 358 207 565 273 173 446 376 212 588

Reserve Components as % of 1-in-2 Load

Forced Outages 4.07% 4.50% 3.95% 3.25%

Contingency Reserves 5.97% 6.23% 5.84% 6.09%

Regulating Margin 3.44% 6.09% 4.74% 6.30%

1-in-10 Temperature Adjustment 3.27% 3.27% 3.27% 3.27%

Total 16.75% 20.08% 17.80% 18.91%

2008 2009 2010 2011 Average

East West Total East West Total East West Total East West Total

System Coincidental Peak Load 6,079 3,422 9,501 5,898 3,522 9,420 6,073 3,345 9,418 6,392 3,039 9,431

1-in-2 Temperature Adjustment (237) 108 (128) 54 (195) (141) (7) (2) (9) (0) (91) (91)

1-in-10 Temperature Adjustment 191 115 306 195 109 303 198 109 308 209 96 305

Reserve Components, 100 high-load hours

Forced Outages 225 82 307 368 100 469 592 115 707 331 102 432

Contingency Reserves 388 166 554 373 182 555 351 175 526 377 161 539

Regulating Margin 236 144 380 322 165 487 357 195 552 368 169 537

Reserve Components as % of 1-in-2 Load

Forced Outages 3.27% 5.05% 7.51% 4.63%

Contingency Reserves 5.91% 5.98% 5.59% 5.77%

Regulating Margin 4.06% 5.24% 5.86% 5.75%

1-in-10 Temperature Adjustment 3.27% 3.27% 3.27% 3.27%

Total 16.51% 19.55% 22.23% 19.41%

Study Results, cont.

31

• Average of 10 high-load hours

Study Results, cont.

32

• Building blocks in 2011

• Building blocks, four-year average forced outages and

contingency reserves

2011

Coincidental

Peak Hour

Average of

Top 100-Hour

Average of

Top 10-Hour

Forced Outages 3.25% 4.63% 2.33%

Contingency Reserves 6.09% 5.77% 6.02%

Regulating Margin 6.30% 5.75% 5.50%

1-in-10 Temperature Adjustment 3.27% 3.27% 3.27%

Planning Reserves 18.91% 19.41% 17.12%

2008-2011

Average Generation

Coincidental

Peak Hour

Average of

Top 100-Hour

Average of

Top 10-Hour

Forced Outages 3.94% 5.12% 4.83%

Contingency Reserves 6.04% 5.82% 5.90%

Regulating Margin 6.30% 5.75% 5.50%

1-in-10 Temperature Adjustment 3.27% 3.27% 3.27%

Planning Reserves 19.55% 19.96% 19.49%

Study Results, cont.

33

• Graphical representation of building blocks, four-year

average forced outages and contingency reserves

Study Results, cont.

34

• Building blocks, four-year average of all elements

• Comparison with WECC study result, based on

PacifiCorp’s 2011 data

2008-2011

Average All Elements

Coincidental

Peak Hour

Average of

Top 100-Hour

Average of

Top 10-Hour

Forced Outages 3.94% 5.12% 4.82%

Contingency Reserves 6.03% 5.81% 5.89%

Regulating Margin 5.14% 5.23% 4.97%

1-in-10 Temperature Adjustment 3.27% 3.27% 3.27%

Planning Reserves 18.38% 19.43% 18.95%

PacifiCorp (2011)

WECC Coincidental

Peak Hour

Average of

Top 100-Hour

Average of Top

10-Hour

Forced Outages 2.00% 3.25% 4.63% 2.33%

Contingency Reserves 6.00% 6.09% 5.77% 6.02%

Regulating Margin 2.00% 6.30% 5.75% 5.50%

1-in-10 Temperature Adjustment 3.10% 3.27% 3.27% 3.27%

Planning Reserves 13.10% 18.91% 19.41% 17.12%

Conclusion

35

• The resulting planning reserve margin is higher than

WECC’s estimates

– Higher contribution from regulating margin

• The sum of building blocks defined by WECC during

the four historical period is estimated to be

approximately 19% of load

FACT SHEETS FOR PORTFOLIO

DEVELOPMENT CASES

36

Fact Sheet Hand-out

• Two-page fact sheets document the key

input assumptions for each case

• Core cases included in the hand-out; fact

sheets for the sensitivity cases to be

provided once developed

37