Discussion ofDiscussion ofResource PlansResource Plans

Michael Schilmoellerfor the

Northwest Power and Conservation Council

Wednesday, June 10, 2009

2

OverviewOverview Interpreting the resource strategy

Key assumptions Resource build out Decision milestones

Comparison of least risk and least cost plans

Similarities Differences in

Power cost and rate volatility Changes in costs within futures Wholesale power market exposure

Choosing a plan

3

Base Case AssumptionsBase Case Assumptions

RPS renewables are acquired Scenario uncertainty for carbon costs, range

from $0 to $100, grow over the planning period and reach average of $50 per ton by 2030

Scenario uncertainty for construction costs, load requirements, natural gas price, electricity price, forced outage rates, aluminum price, production tax credits, value of renewable energy credits (RECs)

Variation for hydrogeneration and forced outage based on historical patterns

4

Resources Available forResources Available forSelection by the ModelSelection by the Model

Conservation Discretionary conservation limited to 160

average megawatts per year, phased in to 85% penetration maximum

CCCT (415 MW) available 2011-2012 SCCT (85 MW Frame GT) available 2012 Wind generation (100 MW blocks), 4800 MW

available by end of study, no REC credit if RPS are assumed in force, includes any production tax credit (PTC) and transmission, integration, and firming costs

Geothermal (14 MW blocks) available 2011, 424 MW (382 MWa) by end of study

5

Resources Available forResources Available forSelection by the ModelSelection by the Model

Woody Biomass (25 MW), available 2014, 830 MW by end of study

Advanced Nuclear (1100 MW), available 2023, 4400 MW by end of study

Supercritical pulverized coal-fired power plants (400 MW), available 2016

IGCC (518 MW) available 2023, with carbon capture and sequestration

Wind imported from Montana, with new transmission, available 2011, 1500 MW by end of study

Five classes of demand response, 2000MW available by end of study, 1300 MW of this limited to 100 hours per year of operation

6

Least-Cost Plan (A)Least-Cost Plan (A)

Source: Schedules for plan resources 090609.xls

Least Cost Plan (A)

10 Lost opportunity conservation cost-effectiveness threshold, premium over market ($2006/MWh)2941 Lost opportunity conservation by end of study (MWa)*

10 Discretionary conservation cost-effectiveness threshold, premium over market ($2006/MWh)2585 Discretionary conservation by end of study (MWa) assuming 160MWa/year limit

5527 Total conservation (MWa)

7

Least-Risk Plan (D)Least-Risk Plan (D)

Least Risk Plan (D)50 Lost opportunity conservation cost-effectiveness threshold over market ($2006/MWh)

3253 Lost opportunity conservation by end of study (MWa)*10 Discretionary conservation cost-effectiveness threshold over market ($2006/MWh)

2573 Discretionary conservation by end of study (MWa) assuming 160MWa/year limit

5827 Total conservation (MWa)

Cumulative MW, by earliest date to begin construction

Dec-15 Dec-17 Dec-19 Dec-23 Dec-25CCCT 0 415 830 830 830SCCT 170 170 170 170 170

Geothermal 0 52 104 156 169Wind 1200 1200 3000 3000 3000

Source: Schedules for plan resources 090609.xls

8

RPS DevelopmentRPS DevelopmentExpected RPS requirement by end of study is 1800 MWa, but it can vary from 1400 MWa to 2500 MWa. Non-wind renewables (purple) would play a significant role

Contribution from Plan wind will be a small portion of total RPS wind.

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

MW

a R

PS

Wind Energy Other Energy Least-Risk Plan Wind

Source: RPS plus wind buildout.xls

9

Build Out of ResourcesBuild Out of ResourcesWindWind

Source: workbook “L811x2_LR3.xls”

Least-risk plan wind has about 50 percent likelihood of completion

Average energy is about half of maximum possible.

Wind (No RECs) On-Line Capability

0

200

400

600

800

1,000

1,200

Sep

-09

Sep

-11

Sep

-13

Sep

-15

Sep

-17

Sep

-19

Sep

-21

Sep

-23

Sep

-25

Sep

-27

MW

a en

erg

y

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

Mean

10

Build Out of ResourcesBuild Out of ResourcesGeothermalGeothermal

Source: workbook “L811 LR plan buildout 080604.xls”

Geothermal On-Line MW Capability

0

20

40

60

80

100

120

140

160

Sep

-09

Sep

-11

Sep

-13

Sep

-15

Sep

-17

Sep

-19

Sep

-21

Sep

-23

Sep

-25

Sep

-27

MW

a

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

average

Least-risk plan geothermal has about 80 percent likelihood of completion

11

Build Out of ResourcesBuild Out of Resources Combined-Cycle Combustion Turbine Combined-Cycle Combustion Turbine

Least-risk plan CCCTs have about 30 percent likelihood of completion

CCCT MWa On-Line Capability

0100200300400500600700800

Se

p-0

9

Se

p-1

1

Se

p-1

3

Se

p-1

5

Se

p-1

7

Se

p-1

9

Se

p-2

1

Se

p-2

3

Se

p-2

5

Se

p-2

7

MW

a e

ne

rgy

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

Mean

Source: workbook “L811x2_LR3.xls”

12

Build Out of ResourcesBuild Out of ResourcesSimple-Cycle Combustion TurbineSimple-Cycle Combustion Turbine

Source: workbook “L811 LR plan buildout 080604.xls”

SCCT On-Line MW Capability

0.0020.0040.0060.0080.00

100.00120.00140.00160.00180.00

Sep

-09

Sep

-11

Sep

-13

Sep

-15

Sep

-17

Sep

-19

Sep

-21

Sep

-23

Sep

-25

Sep

-27

MW

a

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

average

Least-risk plan SCCTs have about 20 percent likelihood of completion

13

Schedule of DecisionSchedule of DecisionLeast-Risk PlanLeast-Risk Plan

Action Plan

Source: Schedules for plan resources 090609.xls

Siting, licensing, and permitting associated with the least-risk plan falls after the Action Plan time period. Regional planning costs for the first four resources is about $72 M.

14

OverviewOverview Interpreting the resource strategy

Key assumptions Resource build out Decision milestones

Comparison of least risk and least cost plans

Similarities Differences in

Power cost and rate volatility Changes in costs within futures Wholesale power market exposure

Choosing a plan

15

Filtering Out PlansFiltering Out Plans

Efficient Frontier Finding the best plans Discovering the successful and less

unsuccessful strategies Represent entire distributions

Distributions of cost Show NPV costs Hide year-to-year excursions that hold

much of what we typically think of as risk

16

Examining Annual Examining Annual DifferencesDifferences

Cost and rate variation, across time and futures

Changes in costs within futures Market exposure, across time and

futures

17

Cost And Rate VariationCost And Rate Variation

Trying to understand how much a plan protects regional ratepayers from overall cost and rate variation, especially annual rate increases (“rate shock”)

Uses real levelized costs for all investments, including conservation

18

Cost And Rate Variation Cost And Rate Variation FindingsFindings

Relative to the least-cost plan, the least-risk plan has higher likelihood of smaller rate variation, both increases and decreases

Because the plans are so similar in most years, however, the likelihood of significant differences between the plans is small

19

Changes in System CostChanges in System Costwithin Futureswithin Futures

Trying to understand how the least risk plan might protect regional ratepayers from cost excursions within a future, relative to the least cost plan

We get to live in only one future (but we can not know which one)

Within a future, how long do savings last? How frequently do costs and savings occur?

20

Differences in NPV CostsDifferences in NPV CostsLeast-risk plan less Least-cost planLeast-risk plan less Least-cost plan

-15,000

-10,000

-5,000

0

5,000

10,000

15,000

20,000

25,000

750 futures

Dif

fere

nc

e in

co

st

(M $

20

06

)

Source: LR&LC_distributions.xls, worksheet “LR less LC”

Least-risk plan costs more than least-cost plan in most futures

Least-risk plan reduces cost primarily in the futures that would have been the most expensive under the least-cost plan (not shown).

21

Findings for System CostFindings for System Costwithin Futureswithin Futures

Fixed costs are higher for least-risk plans than least-cost plans due to siting, licensing, and construction costs. Variable costs are lower.

Differences occur in a variety of patterns, but often involve higher cost for least-risk plans earlier followed a small number of large savings.

Because most of the plants come into service late in the study, so do the savings.

22

Market ExposureMarket Exposure

Trying to understand how much a plan protects regional ratepayers from wholesale electricity market price variation, especially during periods of energy import

Look at energy and cost associated with imports and exports from outside the region, including from regional IPPs

23

Market Exposure FindingsMarket Exposure Findings The variation in imports and exports is

significant Relative to the least cost plan, the least

risk plan would provide some economic advantage 20 to 30 percent

of the time that the region imports expected annual import cost savings that

grows to $250 million by the end of the study protection exceeding $400 million in 4

percent of hydro quarters by the end of the study

24

The ChoiceThe Choice A plan with more resources reduces

dependence on the power market and increases power price and rate stability

A plan with resources provides guidance to the region regarding the resources that promote an efficient and reliable system

Very little difference exists between least-cost and least-risk plans in the five-year Action Plan time period.

The least-risk plan preserves decision milestones

EndEnd

26

Difference in Cost Difference in Cost DistributionsDistributions

Source: LR&LC_distributions.xls, worksheet “LR less LC”

Least Risk less Least Cost by FutureSorted by the NPV Study Cost Difference

-15000

-10000

-5000

0

5000

10000

15000

20000

25000

1 44 87 130173216259302345388431474517560603646689732

M $

2006

Dif

fere

nce

in

co

st

0

50000

100000

150000

200000

250000

M $

2006

lea

st-c

ost

pla

n c

ost

Diff LR-LC corresponding LC plan cost Linear (corresponding LC plan cost)