Draft Avoided Cost Forecast and Marginal CO 2 Offset Value of Conservation Regional Technical Forum Maury Galbraith Northwest Power and Conservation Council

Draft Avoided Cost Forecast and Marginal CO2 Offset Value of

Conservation

Regional Technical Forum

Maury Galbraith

Northwest Power and Conservation Council

April 29, 2008

NorthwestPower andConservation

Council


Council2April 29, 2008

Agenda• Interim Wholesale Power Price Forecast

– Revised AURORAxmp Inputs– Capacity Expansion Results– Base and Sensitivity Case Price Forecasts– Thoughts on Avoided Cost

– Avoided Resources– RPS Mandate– Blended Avoided Costs

• Marginal CO2 Offset Value of Conservation– WECC and PNW Annual CO2 Production Forecasts– Selecting the Region’s Marginal Resource– Average Marginal CO2 Production Rates


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Interim Wholesale Power Price Forecast


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Council4April 29, 2008 4

Revised AURORAxmp Inputs:

1. Converted CO2 Footprint paper setup to 2006 dollars

2. Revised coal and natural gas prices

3. Revised CO2 emission prices

4. Revised new resource capital costs

5. Added IGCC with CO2 sequestration as a resource option

6. Restricted addition of coal-fired resources without CO2 sequestration

7. Added resources to achieve current state RPS targets

8. Implemented capacity reserve margin modeling


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Revised Natural Gas PricesPNW West

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

2007 2012 2017 2022

2006

$/M

MB

tu

Interim Forecast --High Case

Interim Forecast --Base Case

5th Power Plan --Medium


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Revised CO2 Emission Prices

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

2007 2012 2017 2022

2006

$/to

n o

f C

O2

Interim Forecast -High Case

Interim Forecast -Base Case

5th Power Plan -Mean Values


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Summary of RPS ModelingSummary of Standard Assumed allocation of new

acquisitions (Energy basis)

AZ IOU sales: Annual increments to 15% by 202530% min distributed resources.

31% load-side; 7% biomass; 27% solar; 34% wind

BC Renewables will continue to account for 90% of generation

20% biomass; 40% hydro; 40% wind

CA IOU sales: 1% min/yr to 20% by 2011COUs: “recognize legislative intent”

10% biomass; 15% geothermal; 25% solar; 50% wind

CO IOU sales: Scheduled increments to 20% by 2020COU sales: Scheduled increments to 10% by 2020

5% solar; 95% wind

MT IOU sales: Scheduled increments to 15% by 2015 25% biomass; 75% wind

NM IOU sales: Scheduled increments to 20% by 2020COU sales: Scheduled increments to 10% by 2020


NV IOU sales: Scheduled increments to 20% by 20155% min solar; 105% credit for conservation to limit

27% conservation; 36% geothermal; 18% solar; 18% wind

OR Large utility sales: Scheduled increments to 25% by 2025. (Medium utilities 10%; small 5% by 2025)


WA Sales of large utilities (17/~ 84% load): Scheduled increments to 20% by 2020.

20% biomass; 5% hydro; 75% wind


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Interim Base CaseWECC Resource Expansion 2007-26

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

20072011

20152019

2023

Dis

pat

ched

En

erg

y (M

Wa)

AURORA NG SCCT

AURORA Solar

AURORA IGCC w\ Seq

AURORA IGCC wo\ Seq

AURORA Steam Coal

AURORA NG CCCT

AURORA Wind

RPS


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Interim Base Case PNW Resource Expansion 2007-26

0

400

800

1,200

1,600

2,000

2,400

20072011

20152019

2023

Dis

pat

ched

En

erg

y (M

Wa) RPS Hydro

RPS Solar

RPS Geothermal

RPS Biomass

RPS Wind


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Interim High Capital Cost CaseWECC Resource Expansion 2007-26

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

20072011

20152019

2023

Dis

pat

ched

En

erg

y (M

Wa) AURORA NG SCCT

AURORA IGCC wo\ Seq

AURORA NG CCCT

AURORA Wind

RPS


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Interim High Capital Cost Case PNW Resource Expansion 2007-26 (No change!)

0

400

800

1,200

1,600

2,000

2,400

20072011

20152019

2023

Dis

pat

ched

En

erg

y (M

Wa) RPS Hydro

RPS Solar

RPS Geothermal

RPS Biomass

RPS Wind


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Interim High Capital Cost CaseWECC Resource Mix 2007-26

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

20072011

20152019

2023

Dis

pat

ched

En

erg

y (M

Wa)

Other

Geothermal

Wind

Biogas

Biomass

Uranium

Water

Coal

Natural Gas


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Interim High Capital Cost CasePNW Resource Mix 2007-26

0

5,000

10,000

15,000

20,000

25,000

30,000

20072011

20152019

2023

Dis

pat

ched

En

erg

y (M

Wa)

Other

Geothermal

Wind

Biogas

Biomass

Uranium

Water

Coal

Natural Gas


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Base Case Price ComparisonsMid-C Annual Average Prices

$30

$35

$40

$45

$50

$55

$60

$65

2007 2012 2017 2022

2006

$/M

Wh

5th Plan Final

Biennial Assessment

Draft Interim Base Case

Final Interim Base Case

Interim High Capital CostCase


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Sensitivity Case Price ComparisonsMid-C Annual Average Prices

$30

$35

$40

$45

$50

$55

$60

$65

2007 2012 2017 2022

2006

$/M

Wh

Interim Base Case


Interim High CO2 PriceCase

High Capital Cost/HighCO2 Price Case

Interim High Fuel PriceCase

Interim No IncrementalRPS Case


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Interim High Capital Cost CaseAnnual Average Prices by Load Segment

$15

$20

$25

$30

$35

$40

$45

$50

$55

$60

2007 2012 2017 2022

2006

$/M

Wh

Average

Segment 1

Segment 2

Segment 3

Segment 4

Seg 1: M-F Hr 9 - 18

Seg 2: M-F Hr 5 - 8; 19 - 22; Sa & Su 5 - 22

Seg 3: M-F Hrs 1 -4; 23 & 24

Seg 4: Sa & Su Hrs 1 - 4; 23 & 24


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Interim High Capital Cost CaseAnnual Average Prices by Load Segment

$0

$10

$20

$30

$40

$50

All Hours Segment 1 Segment 2 Segment 3 Segment 4

Le

ve

lize

d 2

00

6$

/MW

h

Seg 1: M-F Hr 9 - 18

Seg 2: M-F Hr 5 - 8; 19 - 22; Sa & Su 5 - 22

Seg 3: M-F Hrs 1 -4; 23 & 24

Seg 4: Sa & Su Hrs 1 - 4; 23 & 24


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Thoughts on Avoided Costs

• Avoided costs are associated with avoidable (or planned) resources:

• Logically come after a resource plan

• Guide resource decisions between plans

• Long-term concept

• Depend on load-resource balance

• If “short” resources then plan to acquire resources

• If “long” resources then plan for wholesale sales


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More Thoughts on Avoided Costs• Are RPS Resources Avoidable?

1) RPSMWh = RPS Target% * SalesMWh

2) RPSMWh = RPS Target% * (SalesMWh – EEMWh)

3) RPSMWh = (RPS Target% * SalesMWh)

– (RPS Target% * EEMWh)

• In general, every MWh of EE avoids a fraction of a utility’s required RPS resource development; even though EE is typically a zero GHG emission resource.


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Blended Avoided Cost Methodology

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

Lev

eliz

ed 2

006$

/MW

h

Wholesale PowerPrices

Annual Levelized Costof Wind in 2020

Region's AvoidedCost

Seg 1: M-F Hr 9 - 18

Seg 2: M-F Hr 5 - 8; 19 - 22; Sa & Su 5 - 22

Seg 3: M-F Hrs 1 -4; 23 & 24

Seg 4: Sa & Su Hrs 1 - 4; 23 & 24


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Upcoming AURORAxmp Input Revisions• Demand forecast for Pacific Northwest

• Demand forecasts for other WECC areas

• Revised hydro inputs (i.e., use 70 years of stream flow)

• Revised wind modeling (i.e., improved hourly shape)

• AURORA Version 9.1 (i.e., improved capacity reserve margin logic)

• + Others yet to be identified


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Marginal CO2 Offset Value of Conservation


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Sensitivity Case CO2 ProductionWECC Annual Emissions

300

350

400

450

500

550

600

2007 2012 2017 2022

Mil

lio

n T

on

s

Interim Base Case

Interim High Fuel PriceCase

Interim High CO2 PriceCase

Interim No IncrementalRPS Case



5th Plan Portfolio


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Sensitivity Case CO2 ProductionNW Annual Emissions

30

35

40

45

50

55

60

65

70

2007 2012 2017 2022

Mil

lio

n T

on

s

Interim Base Case

Interim High CapitalCost Case


Est. 1990 Level


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Marginal CO2 Production Rates

• The CO2 emissions rate of the last resource (or marginal resource) brought on-line to supply power during a given hour.

• Measured in pounds of CO2 per kilowatt-hour (lbs. per kWh).

• Power system results are averages of the CO2 production rate of the marginal resources in each hour of the period (e.g., 8,760 marginal resources per year).


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Use AURORAxmp Hourly Output to Identify the Marginal Resource in Each Hour(e.g., Interim Base Case: Jan. 15, 2020 HE 7:00 P.M.)

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

Cumulative Capability (MW)

Dis

pa

tch

Co

st

(no

min

al $

/MW

h)

Hydro

Nuclear

Wind

Coal/Biomass

NG CCCT/Biogas

NG SCCT/Fuel Oil/Demand Response

Demand


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Interim High Capital Cost CasePNW Marginal Resource Mix

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2015 2020 2025

Per

cen

t o

f A

nn

ual

Ho

urs

Demand ResponseNatural GasBiomassCoal


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Interim High Capital Cost CaseMarginal CO2 Rates Greater Than Average CO2

Rates

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

2010 2015 2020 2025

lbs.

of

CO

2 p

er k

Wh

Marginal RateAverage Rate


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Interim High Capital Cost CaseMarginal CO2 Production Rates by Load Segment

0.0

0.2

0.4

0.6

0.8

1.0

1.2

2010 2015 2020 2025

lbs.

of

CO

2 p

er k

Wh

Segment 1

Segment 2

Segment 3

Segment 4

All hours

Seg 1: M-F Hr 9 - 18

Seg 2: M-F Hr 5 - 8; 19 - 22; Sa & Su 5 - 22

Seg 3: M-F Hrs 1 -4; 23 & 24

Seg 4: Sa & Su Hrs 1 - 4; 23 & 24


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Use AURORAxmp Hourly Output to Identify the Marginal Resource in Each Hour(e.g., Interim High Capital Cost Case: Jan. 15, 2020 HE 7:00 P.M.)

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

Cumulative Capability (MW)

Dis

pa

tch

Co

st

(no

min

al

$/M

Wh

)

Hydro

Nuclear

Wind

Biomass/Biogas

Coal/NG CCCT

Coal/NG SCCT/Fuel Oil/Demand Response

Demand


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High Capital Cost/High CO2 Price CasePNW Marginal Resource Mix

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2015 2020 2025

Per

cen

t o

f A

nn

ual

Ho

urs

Demand Response

Natural Gas

Biomass

Coal


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High Capital Cost/High CO2 Price CaseHigher Marginal CO2 Production Rates

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2010 2015 2020 2025

lbs.

of

CO

2 p

er k

Wh

Interim High CapitalCost Case



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High Capital Cost/High CO2 Price CaseHigher Marginal CO2 Rates But Lower Annual CO2 Emissions

• Higher CO2 emissions prices increase the dispatch costs of coal-fired (and to a lesser extent natural gas-fired) resources.

• Results in coal-fired resources being the marginal resource during more hours of the year. This increases marginal CO2 emission rates.

• Also results in less overall reliance on coal-fired resources (and more reliance on natural gas). This reduces annual CO2 emissions.


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Final Thoughts on CO2 Offset Value

• Under Interim High Capital Cost Case assumptions, the average marginal CO2 production rate of the Northwest power system is expected to range between 0.7 -- 0.8 lbs. of CO2 per kWh.

• Marginal CO2 production rates vary significantly by hourly load segment (-9% to +33% of all hour average).

• The CO2 offset value of (flat output) conservation ranges between $0 and $5 per MWh under base case CO2 emission price assumptions (in constant 2006 dollars).


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Documents

Draft Avoided Cost Forecast and Marginal CO 2 Offset Value of Conservation Regional Technical Forum Maury Galbraith Northwest Power and Conservation Council