2006 Integrated Resource Plan

Portfolio Analysis Update

October 31, 2006

2

Introduction– Purpose of today’s meeting is to provide final modeling results

and observationsCEM results updateDerivation of candidate portfolios for risk analysisDetailed stochastic simulation results

– Not presented todayCO2 adder scenario results ($0, $10, $25, $40 per ton)Customer rate impact analysisThe preferred portfolioThe action planClass 2 DSM decrement results

– Planning on another public meeting in mid-to-late November to cover these topics

3

Agenda

– Candidate Portfolio Development– Detailed Simulation Results and Conclusions

Stochastic Cost/Risk Trade-off Analysis ResultsReliability Analysis ResultsCO2 emissions for $8/ton CO2 adder case

– Quantec DSM Proxy Supply Curve Study– Feedback on Capacity Expansion Module Results– IRP Document Overview– Next Steps

4

2006 IRP Analytical Process Overview

1. Review planning environment

2. Update inputs and assumptions

3. Develop load and resource balance to identify annual capacity/energy positions

4. Define candidate resource list, including transmission projects

5. Develop planning scenarios; use the capacity expansion optimization tool (CEM)to determine the optimal portfolio for each scenario that eliminates annual capacitydeficits according to capacity reserve margin requirements

“Alternative future” scenarios Input sensitivity studies

7.Create candidate portfolios based on alternative risk management strategies that can be differentiated through stochastic (Monte Carlo) simulation

8. Model candidate portfolios using stochastic simulations

9. Select a Preferred Portfolio using evaluation criteria:Cost/risk trade-off, system reliability, ratepayer impact, CO2 emissions

6. Use planning scenario results to help determine a diversified resource mix that is robust across the range of alternative futures

Covered in today’s meeting

Mid-November

January 13January 24February 10

April 4May 10

June 7August 23

2006 Public Meetings

5

Candidate Portfolio Development

– General Approach: Use Capacity Expansion Module to help select candidate portfoliosCEM constrained to select fixed additions for wind, load control/demand-side management, and distributed generation

• Ensures resource diversity among candidate portfolios—resource amounts selected reflect the totality of CEM alternative future scenario results

Develop alternative portfolios distinguished by resource strategies whose risk impacts can be differentiated by stochastic simulation

6

Candidate Portfolio Resource Additions

Nine candidate portfolios were developed that are distinguished by planning margin level and the quantity of wind, front office transactions, coal, and IGCC

– 2012 resourcesSmall pulverized coal resource selected in every portfolio except one (where pulverized coal is excluded as an option)East-side single-cycle combustion turbine frame selected in 7 of 9 portfoliosEast-side combined cycle combustion turbine selected in 5 of 9 portfoliosWest-side single-cycle combustion turbine frame selected in 6 of 9 portfoliosWest-side combined cycle combustion turbine selected in 4 of 9 portfolios

– 2013 and 2014 resourcesPulverized coal resource selected in 6 of 9 candidate portfolios (replaced by IGCC in one and not allowed in another)Only one gas resource selected for 2013; all others selected for 2012

– For all candidate portfoliosAt least 1,000 MW of renewables added to bring total nameplate to at least 1,400 MW (cumulative 217 MW capacity contribution from wind by 2015)

• Some candidate portfolios include an additional 600 MW of renewablesOver 1,000 MW of load control/DSM and distributed generation added

7

Diversity in Resource Capacity Additions

Load Control

front office transactions

Pulverized Coal

2016 Resource Capacity Additions Example: Candidate Portfolio 1

(Nameplate Megawatts)

1,000

1,086

332200

1,090

336

308

399

Pulverized Coal

Front OfficeTransactions

DSM

Load Control

DGRenew ables(217 MW PeakCapacity Contribution)

GasIGCC

8

Risk Analysis Conclusions

– Stochastic cost versus risk trade-offPortfolios with front office transactions are the least-cost portfolios, but have additional fuel and market price riskA portfolio resulting from constraining the CEM to build coal early was the most effective at balancing costs and fuel/market price risks

– ReliabilityRelying on a combination of 12% planning reserve margin and front office transactions significantly reduces system reliabilityPortfolios without front office transactions generally makes the system surplus and more reliable

• There is a trade-off between reliability and system cost

9

Portfolio Development Strategies to Manage Risk– Reduce electricity market risk: minimize electricity market price risk

exposure by eliminating long-term reliance on front office transactions after 2012

– Reduce fuel and CO2 cost risks: acquire additional wind resources above the fixed amounts described above—with and without front office transactions included after 2012

– Reduce over-build risk: plan to a 12 percent planning reserve margin with and without reliance on front office transactions after 2012

– Reduce natural gas and electricity price escalation and volatility risks: Acquire baseload coal resources early to take advantage of lower and less volatile variable operating costs

– Reduce CO2 cost risk through technology avoidance: remove pulverized coal plants as a resource option, and rely on gas resources and front office transactions as a bridge until commercially proven IGCC can be acquired

– Reduce CO2 cost risk by relying on IGCC: become an early IGCC adopter

10

Candidate PortfoliosID Description Selection Rationale CP1 Medium alternative future study with wind,

DSM, and CHP at fixed levels and front office transactions capped at quantities assumed for the 2004 IRP

Determines the optimal resource selections given a medium view of the future and constrained with fixed build patterns for wind, DSM, and CHP. The constrained build patterns are broadly representative of CEM resource selection across the alternative future scenarios.

CP2 CP1 with front office transactions removed as a resource option from 2012 onward (long-term asset-based portfolio)

Tests the strategy of eliminating the use of short-term market purchases (front office transactions) to meet long-term resource needs, and thereby reduce exposure to electricity market price risk.

CP3 CP1 with an additional 600 MW of wind added into the portfolio

Tests the strategy of using incremental amounts of wind to reduce CO2, fuel, and market price risks.

CP4 CP2 with 12% planning reserve margin and front office transactions removed as a resource option from 2012 onward (long-term asset-based portfolio)

Represents a variant of the “long-term asset-based” portfolio (CP2), but with the lower planning reserve margin to determine the associated cost/risk tradeoff.

CP5 CP2 with the model constrained to select a second Utah pulverized coal plant in 2013 and an east-side IGCC in 2014. Front office transactions are removed as a resource option from 2012 onward (long-term asset-based portfolio)

Tests the relative economics and risk of building coal early as a hedge against gas and electricity market price risk; the IGCC plant replaces an east-side gas plant.

CP6 CP1 with pulverized coal removed as a resource option

Tests the strategy of minimizing CO2 cost risks, as well as testing the risk impact of relying on higher variable cost, shorter lead-time resources until IGCC is commercially ready (i.e., gas-fired generation and market purchases).

CP7 CP2 with 600 MW of additional wind as in CP3 and front office transactions removed as a resource option from 2012 onward (long-term asset-based portfolio)

Tests additional wind in combination with the construction pattern resulting from limiting front office transactions.

CP8 CP1 with a 12% planning reserve margin Tests the medium alternative future portfolio (CP1) with the lower 12% planning reserve margin.

CP9 CP8 with the model constrained to select Wyoming IGCC plants in 2013 and 2016

Tests an IGCC-intensive portfolio at the lower planning reserve margin level, assuming that the technology is commercially mature enough to acquire by 2013.

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Portfolios Grouped by Risk Management Strategies

15% 12%

Market ReliancePlanning Reserve Margin CO2 Risk Mitigation

CP1CP2CP3CP5CP6CP7

CP4CP8CP9

CP2CP4CP5CP7

Long TermAssets Mixed*

CP1CP3CP6CP8CP9

IGCC-Intensive Wind-Intensive

CP5CP6CP9

CP3CP7

* Portfolios that include front office transactions after 2011

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DSM, CHP and Renewables Cumulative Additions in Alternative Future Scenarios through 2016 – Chart below shows megawatt resource additions for each of the 16

alternative future scenarios forDSM - Class 1 and Class 3Combined Heat and Power (CHP)Renewables (capacity contribution for wind)

0

100

200

300

400

500

600

Meg

awat

ts

DSMCHPRenewables

DSM 51 150 0 150 19 99 46 26 73 64 81 190 150 41 145 194 92

CHP 125 25 25 125 125 125 125 100 75 75 100 125 50 0 25 125 84

Renewables 82 196 60 277 259 215 354 514 0 514 85 148 95 222 99 410 221

CAF00

CAF01

CAF02

CAF03

CAF04

CAF05

CAF06

CAF07

CAF08

CAF09

CAF10

CAF11

CAF12

CAF13

CAF14

CAF15

Ave.

CAF00 CAF01 CAF02 CAF03 CAF04 CAF05 CAF06 CAF07 CAF08 CAF09 CAF10 CAF11 CAF12 CAF13 CAF14 CAF15Wind Nameplate Capacity MW 300 1,000 400 1,400 1,400 1,400 2,200 3,100 - 3,100 400 700 400 900 400 2,300

On-Peak Capacity

Contribution

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Fixed Resource Additions Detail: Load Control, DSM, and Distributed Generation– 644 MW of Load Control and Demand-Side Management Programs

Class 1 DSM: 95 MW• Summer direct load control in the east control area beginning in 2011 and ramping

to 48 MW by 2013• Scheduled irrigation control in the east control area beginning in 2010 and ramping

to 15 MW by 2012• Scheduled irrigation control in the west control area in 2010 and ramping to 32 MW

by 2012Class 2 DSM: 241 MW of peak load reduction by 2016Interruptible Load: 308 MW, reflecting extension of all system contingency reserve products that expire during the IRP study period

– 399 MW of Distributed GenerationCombined Heat & Power (CHP): 100 MW

• Three 25-MW CHP facilities in the west control area in 2012• One 25-MW CHP facility in the east control area in 2012

Qualifying Facilities: 299 MW• 238 MW of firm capacity (included in the load & resource balance), reflecting

extension of QF contracts that expire during the IRP study period• 61 MW of nonfirm capacity (not included in the load & resource balance),

reflecting extension of QF contracts that expire during the IRP study period

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Fossil Fuel Resource Frequencies in Alternative Future Scenariosfor 2012 through 2016

0

2

4

6

8

10

12

14

16

Larg

e P

ulve

rized

Coa

lW

Y #

1

Sm

all P

ulve

rized

Coa

lU

T

Larg

e P

ulve

rized

Coa

lU

T

CC

CT

F 2x

1 W

est

IGC

C W

est #

1

CC

CT

F 2x

1 U

tah

Larg

e P

ulve

rized

Coa

lW

Y #

2

SC

CT

Fram

e W

est

CC

CT

G 1

x1 W

est

SC

CT

Fram

e U

tah

IGC

C W

Y

IGC

C W

est #

2

IGC

C U

tah

Coal Coal Coal Gas Coal Gas Coal Gas Gas Gas Coal Coal Coal

Fossil Fuel Resources

Freq

uenc

y (N

= 1

6)

15

Generation and Market Purchase Resource Additions for Candidate Portfolios

Resource CP1 CP2 CP3 CP4 CP5 CP6 CP7 CP8 CP9Small Pulverized UT (340MW) 2012 2012 2012 2012 2012 - 2012 2012 2012Large Pulverized UT (600MW) 2017 2018 2018 2018 2013 - 2018 2017 2018Pulverized WY 1 (750MW) 2013 2013 2015 2013 2013 - 2014 2014 2017Pulverized WY 2 (750MW) 2018 2018 2018 2018 2018 - 2018 2018 -IGCC West (200MW) 2016 2017 2017 2016 2018 2016 2017 2018 2018IGCC West (300MW) 2018 2017 2018 2017 2018 2018 2017 2018 2018IGCC 1 WY (497MW) - - - - 2014 2016 - - 2013IGCC 2 WY (497MW) - - - - - 2017 - - 2016IGCC UT (497MW) - - - - - 2018 (x2) - - -

West SCCT Frame (332MW) 2012 2012 2012 2012 2012 2013 2012 - -West CCCT F 2x1 w/DF (602MW) - 2012 - - 2012 - 2012 - -West CCCT G 1x1 w/DF (392MW) - - - 2012 - - - - -East SCCT Frame (302MW) - 2012 2012 2012 2012 2012 2012 2012 -East CCCT F 2x1 w/DF (548MW) - 2012 - - 2012 2012 2012 - -East CCCT G 1x1 w/DF (357MW) - - - 2012 - - - - -

Front Office TransactionsAve Annual MW, 2012-2016 1,063 - 1,005 - - 1,024 - 1,000 1,115

Planning Reserve Margin 15% 15% 15% 12% 15% 15% 15% 12% 12%CO2 Risk Mitigation: Wind/IGCC - - Wind - IGCC IGCC Wind - IGCC

Coal

Gas

16

Transmission Resource Options

Utah SouthUtah South

Path C (N)Path C (S)

APS trans

Brady

Goshen

WyomingWyoming

MontanaMontana

Bridger WestBridger West

ColoradoColorado

BPABPA

Palo VerdePalo Verde

YakimaYakima

West MainWest Main

Arizona Arizona

Borah

Walla WallaWalla Walla

MonaMona

Utah NorthUtah North

ChollaCholla

COBCOB

Mid-CMid-C

4 Corners4 Corners

8. Wyoming to Bridger

4. Bridger to Ben Lomond 6. Additional Path C Upgrade

5. Mona to Utah North

1. Walla Walla to Yakima A3. Walla Walla to Yakima B

7. Yellowtail to Bridger2. W

est Main to Walla Walla

9. Utah North to West Main Bridger EastBridger East

Load

Generation

Purchase/Sale Markets

Contracts/Exchanges

PacifiCorp Merchant Transmission Rights

West East

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Transmission Additions for Candidate Portfolios

Transmission Project CP1 CP2 CP3 CP4 CP5 CP6 CP7 CP8 CP9

West Main-Walla Walla 2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

2012 @ 630 MW

Walla Walla-Yakima B 2012 @ 400 MW

2012 @ 400 MW

2012 @ 400 MW

2012 @ 400 MW

2012 @ 400 MW

2012 @ 400 MW

2012 @ 400 MW

2012 @ 400 MW

2013 @ 400 MW

Mona-Utah North 2012 @ 500 MW

2018 @ 500 MW

2012 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2012 @ 500 MW

Jim Bridger-Ben Lomond 2015 @ 1000 MW

2016 @ 1000 MW

2016 @ 1000 MW

2016 @ 1000 MW

2014 @ 1000 MW

2017 @ 500 MW

2014 @ 1000 MW

2016 @ 1000 MW

2015 @ 1000 MW

Utah North-West Main 2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2014 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

2017 @ 500 MW

Wyoming-Bridger 2018 @ 500 MW

2018 @ 500 MW

2018 @ 500 MW

Path-C Upgrade B 2018 @ 600 MW

18

Stochastic Cost Results

– Portfolios 1 and 8 appear as the least cost, unadjusted for risk

Stochastic Mean PVRR

20.7

21.0 20.9 20.9

21.821.7

21.1

20.7

21.1

20.0

20.5

21.0

21.5

22.0

CP1 CP2 CP3 CP4 CP5 CP6 CP7 CP8 CP9

Portfolio

PVR

R

($ b

illio

n)

$8 CO2

19

Stochastic Cost/Risk Trade-off Analysis Results

– Portfolios 1 and 8 appear as the least cost, unadjusted for risk– Portfolio 5 has the lowest tail risk

Cost vs Risk Tradeoff

CP1

CP2

CP3

CP4

CP5

CP6

CP7

CP8

CP9

28.0

30.0

32.0

34.0

36.0

38.0

40.0

20.5 20.6 20.7 20.8 20.9 21.0 21.1 21.2 21.3 21.4 21.5 21.6 21.7 21.8 21.9PVRR

($ billions)

Ris

k ($

bill

ions

)

Risk Measure: Upper Tail less Stoc Avg $8 CO2 Case

20

Stochastic Cost/Risk Trade-off Analysis Results

– Portfolios 1 and 8 appear to be the least cost, unadjusted for risk

CEM found portfolio 8 less costly than portfolio 1, but the savings were offset in PaR by additional costs associated with energy not served and operating reserve violations The cost of energy not served reflects imbalance energy priced at $400/MWh

– Portfolio 5 achieves the most cost-effective risk reduction: tail risk can be reduced by one dollar with the expenditure of about 33 cents of expected PVRR

Risk Measure: Upper Tail less Stoc AvgRisk Tolerant $8 CO2 Case Risk Averse

CP1 CP5

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75 0.80 1.00 1.50 2.00 3.00

Risk Weighting($ PVRR / $ Risk Measure)

21

Reliability Analysis Results

Energy Not Served, Stochastic Average Average Gigawatt Hours per Year for 2007 through 2026

($8/Ton CO2 Adder Case)

020406080

100120140160180200220240

CP1 CP2 CP3 CP4 (12% PRM)

CP5 CP6 CP7 CP8 (12% PRM)

CP9 (12% PRM)

aGW

h-ye

ar

West East

163

135

150161

110

170

132

195

218

22

Carbon Dioxide Emissions– Relative emission reductions in Portfolios 3 and 7 are due to additional

wind on the system– Reduction in Portfolio 6 is due to elimination of pulverized coal from

resource mix– Range of variation across all portfolios is 2.1 million tons per year

Average Annual CO2 Emissions(2007 through 2026)

Deltas from CP1

-2.50

-2.00

-1.50

-1.00

-0.50

0.00CP1* CP2 CP3* CP4 CP5 CP6* CP7 CP8* CP9

CO

2 (m

illio

ns o

f ton

s/yr

)

$8 CO2

Purchased Power assumed at 0.57 tons CO2 /MWh

23

CEM Modeling Results Update

– An information packet was distributed to public participants on October 4, 2006► CEM updated results paper

• Preliminary results distributed and discussed at August 23 public meeting• Latest CEM runs incorporated

» August 31 forward price curves» Front office transactions cap (1,200 MW)» Modified annual low/high load growth values to reduce year-to-year

variability► Scenario and Assumptions background paper

• Added an altered “favorable wind environment” scenario, reflecting a permanent expiration of renewables production tax credit beginning in 2008. Purpose is to check the necessity of the PTC under otherwise favorable conditions

• Added sensitivity studies for business-as-usual and cost bookend cases► Quantec demand-side management proxy supply curve report

24

IRP Document Overview

– IRP will be produced in two volumesVolume 1 – Main documentVolume 2 - Appendices

– Soliciting feedback from IRP public participants on both volumes prior to filing

Intend to distribute volumes for review in NovemberProvide a three-week review period

– Feedback should be focused on compliance with Standards & Guidelines

Limit the additional analysis to what is required to comply with the Standards & Guidelines

25

IRP Document– Volume 1 Chapters

Chapter 1: Executive SummaryChapter 2: IRP Components, Planning Principles, Objectives and ApproachChapter 3: The Planning EnvironmentChapter 4: Resource Needs AssessmentChapter 5: Resource OptionsChapter 6: Modeling and Risk Analysis ApproachChapter 7: Modeling and Portfolio Selection ResultsChapter 8: Action Plan

– Document organizational improvementsConsolidated presentation of data; for example, all load and resource balance information is now in Volume 1More concisely written to focus on details pertinent to the planning process and outcome

26

IRP Document– Appendices

Base Assumptions• General, load forecast, commodity prices, emission costs, renewable

assumptions, existing resourcesDemand-side Management Proxy Supply Curve and Program Valuation StudyDetailed capacity expansion optimization Screening ResultsDetailed Simulation Modeling ResultsStochastic Risk Assessment MethodologyPublic Input ProcessAction Plan StatusAnalysis of CHP Potential to Defer Distribution System InvestmentIRP Standards and Guidelines and Acknowledgement Order ComplianceWind Resource Methodology

• Wind integration costs, determination of cost-effective wind resources, and wind capacity planning contribution

Ten-Year Renewable Action Plan

27

Next Steps

– Determine date for public meeting in November– Distribute IRP document draft