2011 irp public input meeting december 15, 2010 · east side resources 8 supply side resources...

Pacific Power | Rocky Mountain Power | PacifiCorp Energy

2011 IRP Public Input Meeting

December 15, 2010

Agenda

• 2011 IRP schedule update and next steps

– Resource portfolio development status

• Supply Side Resources update

• Final capacity/energy load & resource balances

• Capacity expansion model set-up

• Stochastic model parameter update

• Proposed preferred portfolio selection approach

2


IRP Schedule Update and Next Steps

3

Pete Warnken

Recent Milestones

• Distributed Loss of Load Study on November 18, 2010

– PacifiCorp selected a 13% planning reserve margin for portfolio

development

• Distributed October 5 IRP public input meeting report and

dispersed generation resource attribute workbook

• Distributed updated Portfolio Development Case List on

November 18, 2010

• Completed analysis of sustained hydro peaking capability

– will distribute associated report in December 2010

4

Remaining 2011 IRP Schedule

5

IRP Public Meetings*

General Public Meetings 15 X X

Wind integration study follow-up

Model tutorial

Status report/issue resolution conference calls

* Specific meeting dates will be determined after considering state regulatory calendars, participant availability, and meeting preparation requirements.

IRP Development Schedule

Hydro capacity accounting methodology assessment X

Stochastic parameter update (loads, CO2 price) X

System Optimizer portfolio development, sensitivity cases

PaR stochastic simulations and results reporting

Preferred portfolio analysis and selection

Action Plan development/contingency planning

Market reliance and hedging analysis

Stochastic analysis of illiquid market scenario

Western market assessment

Hedging

IRP report preparation, 1st draft

Public review of draft IRP report (30 days)

IRP report preparation, final draft

Commission filing, 3/31/2010 X

To Be Determined

2010 2011

Dec Jan Feb March

To Be Determined

To Be Determined

Next Steps…

• Next public meeting, to be scheduled for mid-

January 2011, will focus on:

– Portfolio development and stochastic results

– Preferred portfolio selection

– Portfolio sensitivity cases

– Status update on market reliance and hedging

analysis

• Model tutorial – February 2011?

– Presentation development activities starting in

January 2010

– Working with Ventyx on non-disclosure agreement

6


Supply Side Resource Update

7

Jim Lacey

East Side Resources

8

Supply Side Resources

DRAFT (IRP PIM December 15, 2010)

Description

Installation

Location

Earliest In-

Service

Date

Average

Capacity

MW

Design

Plant Life

in Years

Annual

Average

Heat Rate

HHV

(BTU/kWh)

Maint.

Outage

Rate

Equivalent

Forced

Outage

Rate

(EFOR)

Low

Estimate

Capital

Cost

($/kW)

High

Estimate

Capital Cost

($/kW )

Var.

O&M

($/MWh)

Fixed

O&M

($/kW-yr)

Utah PC without Carbon Capture & Sequestration Utah 2020 600 40 9,106 4.6% 4.0% $2,923 $3,692 $0.96 $38.80

Utah PC with Carbon Capture & Sequestration Utah 2025 526 40 13,087 5.0% 5.0% $5,285 $6,676 $6.71 $66.07

Utah IGCC with Carbon Capture & Sequestration Utah 2025 466 40 10,823 7.0% 8.0% $5,117 $6,463 $11.28 $53.24

Wyoming PC without Carbon Capture & Sequestration Wyoming 2020 790 40 9,214 4.6% 4.0% $3,310 $4,181 $1.27 $36.00

Wyoming PC with Carbon Capture & Sequestration Wyoming 2025 692 40 13,242 5.0% 5.0% $5,985 $7,559 $7.26 $61.37

Wyoming IGCC with Carbon Capture & Sequestration Wyoming 2025 456 40 11,047 7.0% 8.0% $5,794 $7,318 $13.52 $58.00

Existing PC with Carbon Capture & Sequestration (500 MW) Utah/Wyo 2025 (139) 20 14,372 5.0% 5.0% $1,314 $1,660 $6.71 $66.07

Utility Cogeneration Utah 2014 10 20 4,974 10.0% 8.0% $4,449 $5,619 $23.29 $1.86

Fuel Cell - Large Utah 2013 5 30 7,262 2.0% 3.0% $1,668 $2,106 $0.03 $8.40

SCCT Aero Utah 2014 118 30 9,773 3.8% 2.6% $1,047 $1,322 $5.63 $9.95

Intercooled Aero SCCT Utah 2014 279 30 9,379 3.8% 2.9% $1,229 $1,553 $3.93 $7.01

Internal Combustion Engines Utah 2014 301 30 8,806 5.0% 1.0% $1,204 $1,521 $5.50 $6.49

SCCT Frame (2 Frame "F") Utah 2014 362 35 10,446 3.8% 2.7% $1,037 $1,310 $7.16 $5.41

CCCT (Wet "F" 1x1) Utah 2015 263 40 7,302 3.8% 2.7% $1,253 $1,583 $2.94 $13.04

CCCT Duct Firing (Wet "F" 1x1) Utah 2015 42 40 8,869 3.8% 2.7% $511 $646 $0.39 $0.00

CCCT (Wet "F" 2x1) Utah 2014 539 40 6,885 3.8% 2.7% $1,014 $1,280 $2.98 $8.19

CCCT Duct Firing (Wet "F" 2x1) Utah 2014 86 40 8,681 3.8% 2.7% $511 $646 $0.55 $0.00

CCCT (Dry "F" 2x1) Utah 2015 512 40 6,963 3.8% 2.7% $1,134 $1,433 $3.35 $9.69

CCCT Duct Firing (Dry "F" 2x1) Utah 2015 85 40 8,934 3.8% 2.7% $571 $721 $0.11 $0.00

CCCT (Wet "G" 1x1) Utah 2015 333 40 6,777 3.8% 2.7% $1,185 $1,497 $4.56 $6.75

CCCT Duct Firing (Wet "G" 1x1) Utah 2015 72 40 9,021 3.8% 2.7% $502 $634 $0.36 $0.00

CCCT Advanced (Wet) Utah 2018 400 40 6,651 3.8% 2.7% $1,308 $1,653 $4.56 $6.75

CCCT Advanced Duct Firing (Wet) Utah 2018 75 40 9,021 3.8% 2.7% $642 $811 $0.36 $0.00

Wyoming Wind (35% CF) Wyoming 2012 100 25 n/a n/a n/a $2,015 $2,686 $0.00 $31.43

Utah Wind (30% CF) Utah 2012 100 25 n/a n/a n/a $2,015 $2,686 $0.00 $31.43

East Side Geothermal Utah 2015 35 40 n/a 5.0% 5.0% $4,063 $5,132 $5.94 $110.85

Greenfield Geothermal Utah / Idaho 2017 35 40 n/a 5.0% 5.0% $5,826 $7,359 $5.94 $209.40

Battery Storage All 2015 5 30 11,000 1.9% 5.0% $1,924 $2,431 $10.00 $1.00

Pumped Storage Nevada 2020 250 50 12,500 5.0% 5.0% $1,636 $2,067 $4.30 $4.30

Compressed Air Energy Storage (CAES) Wyoming 2015 350 30 11,980 3.8% 2.7% $1,241 $1,568 $5.50 $3.80

Nuclear Utah 2030 1,600 40 10,710 7.3% 7.7% $5,041 $6,368 $1.63 $146.70

Solar (PV) - 19% CF Utah 2012 5 25 n/a n/a n/a $3,982 $5,030 $0.00 $59.50

Solar Concentrating (natural gas backup) - 25% solar Utah 2014 250 30 n/a n/a n/a $3,831 $4,839 $0.00 $120.99

Solar Concentrating (thermal storage) - 30% solar Utah 2014 250 30 n/a n/a n/a $4,293 $5,423 $0.00 $135.56

Coal

Natural Gas (4500 feet)

Other - Renewables

EAST SIDE RESOURCE OPTIONS

Location / Timing Plant Details Outage Information Costs

West Side Resources

9

Supply Side Resources

DRAFT (IRP PIM December 15, 2010)

Description

Installation

Location

Earliest In-

Service

Date

Average

Capacity

MW

Design

Plant Life

in Years

Annual

Average

Heat Rate

HHV

(BTU/kWh)

Maint.

Outage

Rate

Equivalent

Forced

Outage

Rate

(EFOR)

Low

Estimate

Capital

Cost

($/kW)

High

Estimate

Capital Cost

($/kW )

Var.

O&M

($/MWh)

Fixed

O&M

($/kW-yr)

Utility Cogeneration Northwest 2014 0 20 4,974 10.00% 8.00% $4,044 $5,109 $21.17 $1.69

SCCT Aero Northwest 2014 130 30 9,773 3.85% 2.60% $952 $1,202 $5.12 $9.04

Intercooled Aero SCCT Northwest 2014 307 30 9,379 3.85% 2.90% $1,117 $1,412 $3.57 $6.37

Internal Combustion Engines Northwest 2014 331 30 8,806 5.00% 1.00% $1,094 $1,383 $5.50 $6.49

SCCT Frame (2 Frame "F") Northwest 2014 405 35 10,446 3.85% 2.70% $943 $1,191 $6.51 $4.92

CCCT (Wet "F" 1x1) Northwest 2015 289 40 7,302 3.85% 2.70% $1,139 $1,439 $2.67 $11.86

CCCT Duct Firing (Wet "F" 1x1) Northwest 2015 46 40 8,869 3.85% 2.70% $465 $587 $0.36 $0.00



CCCT (Wet "G" 1x1) Northwest 2015 367 40 6,777 3.85% 2.70% $1,077 $1,361 $4.14 $6.13

CCCT Duct Firing (Wet "G" 1x1) Northwest 2015 80 40 9,021 3.85% 2.70% $456 $576 $0.33 $0.00

CCCT Advanced (Wet) Northwest 2018 440 40 6,651 3.85% 2.70% $1,189 $1,503 $4.14 $6.13

CCCT Advanced Duct Firing (Wet) Northwest 2018 83 40 9,021 3.85% 2.70% $584 $737 $0.33 $0.00

Oregon / Washington Wind (35% CF) Northwest 2012 50 25 n/a n/a 5.00% $2,145 $2,860 $0.00 $31.43

Greenfield Geothermal Northwest 2015 35 40 n/a 5.00% 5.00% $5,826 $7,359 $5.94 $209.40

Solar (PV) - 19% CF Northwest 2012 5 25 n/a n/a n/a $3,982 $5,030 0 $59.50

Utility Cogeneration Northwest 2014 0 20 4,974 10.00% 8.00% $3,868 $4,886 $21.17 $1.69

SCCT Aero Northwest 2014 135 30 9,773 2.00% 2.60% $910 $1,150 $4.89 $8.65

Intercooled Aero SCCT Northwest 2014 321 30 9,379 3.85% 2.90% $1,069 $1,350 $3.42 $6.10

Internal Combustion Engines Northwest 2014 346 30 8,806 3.85% 1.00% $1,047 $1,322 $5.50 $6.49

SCCT Frame (2 Frame "F") Northwest 2014 423 35 10,446 5.00% 2.70% $902 $1,139 $6.23 $4.70



CCCT (Wet "F" 2x1) Northwest 2015 604 40 6,911 3.85% 2.70% $984 $1,243 $2.56 $6.89


CCCT (Wet "G" 1x1) Northwest 2015 383 40 6,777 3.85% 2.70% $1,030 $1,302 $3.96 $5.87

CCCT Duct Firing (Wet "G" 1x1) Northwest 2015 83 40 9,021 3.85% 2.70% $436 $551 $0.31 $0.00

CCCT Advanced (Wet) Northwest 2018 460 40 6,651 3.85% 2.70% $1,138 $1,437 $3.96 $5.87

CCCT Advanced Duct Firing (Wet) Northwest 2018 86 40 9,021 3.85% 2.70% $558 $705 $0.31 $0.00

Oregon / Washington Wind (28% CF) Northwest 2012 100 25 n/a n/a 5.00% $2,145 $2,860 $0.00 $31.43

Biomass Northwest 2015 50 30 10,979 4.60% 4.00% $3,334 $4,211 $0.96 $38.80

Nuclear Northwest 2025 1,600 40 10,710 7.30% 7.70% $5,041 $6,368 $1.63 $146.70

Hydrokinetic (Wave) - 21% CF Northwest 2020 100 20 n/a n/a n/a $5,539 $6,997 $0.00 174.92

Solar (PV) - 19% CF Northwest 2012 5 25 n/a n/a n/a $3,982 $5,030 $0.00 $56.91

Other - Renewables

West Side Options at ISO Conditions (Sea Level)

Natural Gas

Other - Renewables

WEST SIDE RESOURCE OPTIONS

West Side Options (1500 feet)

Natural Gas

Location / Timing Plant Details Outage Information Costs


Final Load and Resource Balances

10

Brian Osborn

Load and Resource Balance Changes

• Load and resource balance development based on a

13% planning reserve margin (Loss of Load study

conclusion)

• Change to Idaho irrigation dispatchable load control:

peak contribution reduced by 139 MW for all years

– Reflects revised expectation of load reductions available at the

time of dispatch

– Acknowledges system stability issues at certain substations

arising from growth in the irrigator network

• Incorporates updated hydro energy forecast

• Incorporates new east-side wind PURPA Qualifying

Facilities

– Pioneer wind I / II, and Power County Wind Park North / South

11

Initial Capacity Load and Resource Balance (Final)

12

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Me

gaw

att

s

Obligation + 13% Planning Reserves

System Obligation

West Existing Resources

East Existing Resources

2012 Resource Gap:1,601 MW

Planning Reserves

2020 Resource Gap:3,852 MW

Initial Capacity L&R Balance (Final),

Line Item Details

13

Calendar Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

East

Thermal 6,019 6,026 6,028 6,028 6,028 6,046 6,046 6,046 6,046 6,046

Hydro 133 133 133 133 133 129 129 129 129 129

Class 1 DSM 324 329 329 329 329 329 329 329 329 329

Renewable 179 179 179 178 176 176 176 176 176 176

Purchase 655 705 604 304 304 283 283 283 283 283

Qualifying Facilities 152 187 206 206 207 206 207 207 206 206

Interruptible 281 281 281 281 281 281 281 281 281 281

Transfers 810 451 414 456 311 499 547 299 361 328

East Existing Resources 8,553 8,290 8,174 7,916 7,768 7,949 7,997 7,749 7,811 7,778

Load 7,112 7,344 7,566 7,805 8,009 8,201 8,377 8,544 8,712 8,896

Sale 758 997 1,045 745 745 745 659 659 659 659

East Obligation 7,870 8,341 8,611 8,550 8,754 8,946 9,036 9,203 9,371 9,555

East Reserves 930 984 1,032 1,063 1,090 1,117 1,129 1,151 1,173 1,196

East Obligation + Reserves 8,799 9,324 9,643 9,613 9,844 10,063 10,165 10,354 10,544 10,752

East Position (247) (1,034) (1,469) (1,698) (2,076) (2,114) (2,168) (2,605) (2,732) (2,974)

East Reserve Margin 10% 1% (4%) (7%) (11%) (11%) (11%) (15%) (16%) (18%)

West

Thermal 2,552 2,552 2,556 2,556 2,556 2,556 2,541 2,550 2,550 2,550

Hydro 1,103 958 958 957 958 959 958 958 902 745

Class 1 DSM - - - - - - - - - -

Renewable 77 71 71 71 71 71 71 71 71 71

Purchase 856 247 331 226 221 225 255 269 285 242

Qualifying Facilities 136 136 136 136 136 136 136 136 136 136

Transfers (809) (452) (416) (457) (311) (499) (547) (300) (360) (330)

West Existing Resources 3,915 3,512 3,636 3,489 3,631 3,447 3,415 3,684 3,584 3,414

Load 3,266 3,374 3,395 3,448 3,491 3,541 3,584 3,650 3,666 3,713

Sale 290 258 258 258 158 108 108 108 108 108

West Obligation 3,556 3,632 3,653 3,706 3,649 3,649 3,692 3,758 3,774 3,821

Planning reserves 351 440 432 452 446 445 447 454 454 465

Non-owned reserves 7 7 7 7 7 7 7 7 7 7

West Reserves 357 447 438 459 452 452 453 460 460 472

West Obligation + Reserves 3,913 4,079 4,092 4,165 4,101 4,100 4,145 4,218 4,234 4,293

West Position 2 (567) (456) (676) (470) (653) (730) (534) (650) (879)

West Reserve Margin 13% (3%) 1% (5%) 0% (5%) (7%) (1%) (4%) (10%)

System

Total Resources 12,468 11,802 11,810 11,404 11,399 11,397 11,412 11,433 11,395 11,192

System Obligation 11,425 11,973 12,264 12,256 12,403 12,595 12,728 12,961 13,145 13,376

Reserves 1,287 1,430 1,470 1,522 1,542 1,569 1,582 1,611 1,633 1,668

Obligation + 13% Planning Reserves 12,712 13,403 13,735 13,778 13,945 14,164 14,310 14,572 14,777 15,044

System Position (244) (1,601) (1,925) (2,373) (2,546) (2,767) (2,898) (3,139) (3,383) (3,852)

Reserve Margin 11% (0%) (3%) (6%) (8%) (9%) (10%) (11%) (13%) (16%)

Initial L&R Balance: Line Item Differences,

Final less October 5th Presentation

14

Calendar Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

East

Thermal - - - - (1) (1) (1) (1) (1) (1)

Hydro 1 1 1 1 1 (3) (3) (3) (3) (3)

Class 1 DSM (139) (139) (139) (139) (139) (139) (139) (139) (139) (139)

Renewable - - - - - - - - - -

Purchase - - - - - - - - - -

Qualifying Facilities - 34 54 54 54 54 54 54 54 54

Interruptible - - - - - - - - - -

Transfers (59) 47 (30) 147 (200) (45) 278 (285) 31 (256)

East Existing Resources (197) (57) (114) 63 (285) (134) 189 (374) (58) (345)

Load 1 1 1 - - 1 (1) - - 1

Sale - - - - - - - - - -

East Obligation 1 1 1 - - 1 (1) - - 1


Non-owned reserves - - - - - - - - - -

East Reserves 83 87 91 93 95 97 98 100 101 103

East Obligation + Reserves 84 88 92 93 95 98 97 100 101 104

East Position (281) (145) (206) (30) (380) (232) 92 (474) (159) (449)

East Reserve Margin (3%) (1%) (1%) 1% (3%) (2%) 2% (4%) (1%) (4%)

West

Thermal - - 4 4 4 (8) (20) (20) (32) (32)

Hydro (32) (19) (18) (19) (23) (23) (23) (20) (23) (25)

Class 1 DSM - - - - - - - - - -

Renewable - - - - - - - - - -

Purchase - - - - - - - - - -

Qualifying Facilities - - - - - - - - - -

Transfers 61 (48) 27 (150) 201 46 (278) 284 (31) 254

West Existing Resources 29 (67) 12 (165) 181 15 (321) 243 (86) 197

Load (1) 1 1 1 (1) 1 1 - - 1

Sale - - - - - - - - - -

West Obligation (1) 1 1 1 (1) 1 1 - - 1


Non-owned reserves - - - - - - - - - -

West Reserves 27 34 33 35 34 34 34 35 35 36

West Obligation + Reserves 26 35 34 36 33 35 35 35 35 37

West Position 3 (102) (22) (201) 148 (21) (357) 208 (121) 160

West Reserve Margin 1% (2%) 0% (4%) 5% 0% (9%) 7% (2%) 5%

System

Total Resources (168) (124) (102) (102) (104) (119) (132) (130) (144) (148)

System Obligation - 2 2 1 (1) 2 - - - 2

Reserves 110 121 124 128 129 132 132 135 136 139

Obligation + Planning Reserves 110 123 126 129 128 134 132 135 136 141

System Position (278) (247) (228) (231) (232) (253) (265) (265) (280) (289)

Reserve Margin (1%) (1%) (1%) (1%) (1%) (1%) (1%) (1%) (1%) (1%)

(2,500)

(2,000)

(1,500)

(1,000)

(500)

0

500

1,000

1,500

2,000

2,500

3,000

MW

a

System Off-Peak

System On-Peak

System Energy Position – On Peak / Off Peak

15

System On-Peak / Off-Peak hours


System Optimizer Model Settings

16

Topology Changes

• West side: Added four new bubbles and

associated links to capture constraints relieved by

Hemingway – Boardman – Bethel (“Cascade

Crossing”) transmission project option

• Wind generation bubbles: Added to Oregon,

Utah, and Wyoming to enable assignment of

applicable incremental transmission investment

costs to wind selected by the model

17

2011 IRP Topology Changes – More Detailed West

18

BPA

Yakima

West Main

Borah

Walla Walla

Hermisto

n

Chehalis

Mid-C

$

COB

$

BPA

Yakima

Borah

Walla WallaMid-C

$

Hermiston

Chehalis

Portland / N. Coast

Willamette Valley /

Central Coast

South-Central OR /

N. California

COB

$

Bethel

Wind

2008 IRP Update

2011 IRP – West only

Wind Bubbles: Used for selection of wind resources requiring incremental transmission

investment beyond the base Energy Gateway footprint.

Front Office Transaction Limits

19

Market Hub / Proxy FOT Product 2011 IRP 2008 IRP Update

West Main / 3rd Quarter 6x16 50 MW 50 MW

Mid-Columbia / Flat 7x24 and 3rd Quarter 6x16400 MW + 375 MW with 10% price premium

400 MW

COB / Flat 7x24 and 3rd Quarter 6x16 400 MW 400 MW

• East-side FOT limits are still under review; PacifiCorp will distribute a table that includes the east-side limits subsequent to this meeting. The table below covers only the west-side

• For market hubs where both flat 7x24 and 3rd quarter 6x16 products are available, only one product type can be selected in a given year

Wind Resource Representation

New “cost step” approach to modeling wind resources

• Geographic zones based on Western Renewable Energy

Zones (WREZ) initiative Phase 1

• Capital costs based on a third party model have three

“cost steps” that vary by wind resource quality

• Incremental transmission costs are the full portion of the

Energy Gateway component necessary for the resource

– Three new wind-only bubbles:

• West, linked to BPA bubble (“Washington South”, ”Oregon Northeast” WREZ

zones)

• Utah, linked to Utah South bubble (“Utah West” WREZ zone)

• Wyoming, linked to Aeolus bubble (Wyoming “East Central”, “East”, “South”

WREZ zones)

– Walla Walla and Yakima each able to accommodate 100 MW of

new wind without new incremental transmission20

Wind Resource Representation (continued)

• System Optimizer annual constraints

– 200 MW annual wind resource limit except for hard cap cases

– 500 MW annual limit for hard cap core cases

• Available dates

– 2012: Washington South (100 MW in Yakima without new

transmission) and Oregon Northeast (100 MW in Yakima without new

transmission)

– 2016: Idaho East, Oregon (Northeast, West), Utah West, Washington

South

– 2018: Wyoming (East, East-central, South, North)

• Other considerations

– Existing wind energy shapes were used

– Resources modeled in 100 MW blocks; System Optimizer model can

pick partial amounts

– Resources modeled with and without production tax credit (PTC)

– No update to capacity contribution

21

WREZ Initiative Hub Map

22WREZ Map is found on page 5-5, figure 5-2 of the October 2009 Phase 1 report at

http://www.nrel.gov/docs/fy10osti/46877.pdf

http://www.nrel.gov/docs/fy10osti/46877.pdf

Out-year Resource Representation

• All resource types, subject to “earliest in-service

year” constraints, are available throughout the 20-

year simulation period

• In addition, growth resources are available after

2020 for additional system capacity balancing

flexibility

– Similar to front office transactions, except that they are

not transacted at market hubs

– System Optimizer can select a flat or third-quarter

heavy load hour energy pattern priced at forward

market prices appropriate for each load area

23


Stochastic Modeling Parameter Update

Connie Clonch

24


• Only the load stochastic parameters have been

updated for the 2011 IRP

– Load stochastics

• Short-term load parameters updated in PaR

– Seasonal volatilities

– Mean reversions

– Seasonal correlations

• Long-term load volatilities set to zero to avoid highly unlikely

load excursions in the out years

• Load Stochastics estimated by Transmission Area to Match

PaR load topology. Prior IRP load stochastics were

estimated by state

• Volatilities follow prior IRP estimates with Washington / West

Main the most volatile and Wyoming the least

25

.


• Capturing CO2 Price Uncertainty In the PaR

model

– Three CO2 price scenarios per portfolio

• No CO2 price

• Medium: $19/ton* in 2015, exceeding $51/ton by 2036

• Low-High: $12/ton* in 2015, exceeding $136/ton by 2036

– CO2 / natural gas price relationship enforced

• Using IPM®, scenario-specific natural gas curves are

produced as a function of CO2 price

• Resultant gas curves are then coupled with corresponding

CO2 price curves in PaR

26

* Nominal Dollars

IPM® is a North American production simulation model that optimizes electricity production costs under a given environmental paradigm.


Potential Future Enhancements to Investigate

– Explore Incorporating CO2 stochastics directly into

PaR

• Lack of observable US market data limits ability to estimate

CO2 parameters

• European market data for CO2 are available but have limited

relevancy

• Test CO2 parameters have been calculated using European

and IPM® - generated price movements. However,

parameters need to be further refined

– Expand Stochastic Correlations to Include CO2 / Coal

Prices

27


Proposed Preferred Portfolio Selection

Approach

Pete Warnken

28

Preferred Portfolio Selection Approach

• Step 1 – Initial Screening

– Use stochastic average PVRR vs. stochastic upper-

tail PVRR scatter-plot diagrams for the three CO2

price scenarios to identify efficient frontier portfolios;

limit selection to no more than seven portfolios for

further screening

29

39

40

41

42

43

44

45

46

47

48

49

21 22 23 24 25 26 27

Up

pe

r-ta

il M

ean

PV

RR

, Bil

lio

n $

Stochastic Mean PVRR, Billion $

Sample Scatter Plot - 15 Portfolios

Portfolio 14

Portfolio 9

Portfolio 8

Portfolio 7

Portfolio 6

Portfolio 11

Portfolio 15

Portfolio 2

Portfolio 4

Portfolio 1

Portfolio 3

Portfolio 5

Portfolio 10

Portfolio 12

Portfolio 13


• Step 2 – Final Screening

– Evaluate relative performance of efficient frontier

portfolios based on the following measures, listed in

the order of importance

• Risk-adjusted PVRR – Stochastic mean PVRR plus the

expected value of the 95th percentile PVRR

• 10-year customer rate impact – Year by year and cumulative

percentage rate change by 2020, relative to 2011 revenue

requirement forecast

• Supply reliability – average annual Energy Not Served (ENS)

• Carbon dioxide emissions (generator plus net market

transaction contribution)

30


– Other portfolio performance measures will also be

reported

• Ave. annual probability of ENS events for July exceeding 25

GWh

• Production cost standard deviation (alternate cost risk

measure)

• Upper-tail ENS

– Scenario risk assessment using System Optimizer

• Determine range of deterministic PVRRs resulting from fixing

portfolios in System Optimizer under varying gas/electricity

and CO2 price assumptions

– PacifiCorp will explain its preferred portfolio selection

on the basis of the above measures and analysis, but

does not intend to use numerical weights for portfolio

ranking purposes31

2011 irp public input meeting december 15, 2010 · east side resources 8 supply side resources...

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