Resource Adequacy Steering Committee Meeting

October 4, 2011

Key Assumptions

Adequacy Assessment Assumptions

2008 Standard Current Assumptions

In-region Market Supply   Summer 1,000 MW1 1,000 MW3

  Winter Full Capability2 Full Capability4

Out-of-region Market Supply   Summer 0 MW 0 MW3

  Winter 3,000 MW 3,000 MW4

Purchase Ahead Resources – 0 MW5

Borrowed Hydro ~2,500 MW-months6 1,000 MW-months1 June through September2 October through May3 May through September4 October through April5 Under development6 1,800 GW-hours per month

Assumptions (cont.)2008 Standard Current Assumptions

Non-modeled Resources   Summero Capacity 3,000 MW –

   Demand-side Management – 120 MW8

   Small Miscellaneous Resources7 – 602 MW8

o Energy 28,800 MW-hours –   Demand-side Management – –   Small Miscellaneous Resources7 – 83,000 MW-hours8,9

  Wintero Capacity 3,000 MW –

   Demand-side Management – 60 MW8

   Small Miscellaneous Resources7 – 602 MW8

o Energy 28,800 MW-hours –   Demand-side Management – –   Small Miscellaneous Resources7 – 83,000 MW-hours8,9

7 Utility contractual rights for load curtailment and emergency generation8 Only includes net additions since 2010 because these resources were previously included in loads9 Cumulative energy limit excluding Banks Lake resource

Out of Region Market Supply

Out of Region Market Supply

The 2008 Adequacy Standard has seasonal assessments of resource adequacy: summer and winter (3 months each)

The winter assessment assumes that 3,000 MW of out of region market is available on any hour (not the dispatch – just the capability)

The summer assessment assumes 0 Proposed new adequacy standard will be an annual assessment Need to update out of region market assumptions for not just

winter and summer, but also for the shoulder months Update the assessment by analyzing:

The California PUC Resource Adequacy Assessment to determine “surplus”

The rolling 5 year actual Intertie (A.C. and D.C. South to North) to determine the minimum transfer capability

CPUC RA Assessment (April 2011)

Assessment includes all IOUs and Community Choice Aggregators

Purpose of RA is mandatory LSE acquisition of capacity to meet load and reserve requirements

Results include unit-contingent, import contracts, DWR contracts, physical resources, and RMR capacity

Only net qualifying capacity is considered based on historical performance and other factors – designed to get the expected value of capacity (GADs data)

CPUC RA Assessment (April 2011)

Normal demand (1:2) plus a 15 percent adequacy requirement is the load that has to be met

Modified the analysis by: Assume that demand response programs (1,000 to 2,300

MW) are not available for ‘export’ The CPUC RA looks backward (2010); the PNW RA

looks forward (2015) – so include gas-fired plants that are not in the CPUC RA, but are under construction (4,767 MW)

Removed California imports as resources for exports

Gas-Fired Plants Under Construction

The CPUC RA assessment does not include these plants in their analysis

Plant MW Percent CompleteHumbolt Bay 163 On-LineColusa 660 On-LineRiverside 96 On-LineCanyon 200 93%Tracy 145 40%Lodi 255 69%Almond 174 45%Los Esteros 140 10%Walnut Creek 500 1%Marsh Landing 760 5%Sentinel Peaker 850 1%Mariposa 200 10%Oakley 624 10%

4,767

New Gas Fired Plants (Started Construction or On-Line)

Modified RA Assessment + Transfer Capability

A B C D E F G

2010Demand

1:2

Adequacy Requirement

(AR)

Total Resources Reported

New Gas-Fired Plants

(2015)Import

Assumption* "Surplus" Average Min

B=D*1.15 (D+E) - (C+F)

Jan 29,930 34,420 34,845 4,767 - 5,193 4761 3764

Feb 29,053 33,411 33,858 4,767 - 5,214 4732 3304

Mar 28,648 32,945 33,105 4,767 - 4,927 4213 3310

Apr 30,094 34,608 34,571 4,767 - 4,730 4101 3466

May 34,623 39,816 39,668 4,767 2,662 1,957 4213 3605

Jun 38,236 43,971 43,455 4,767 3,718 533 4551 3471

Jul 41,872 48,153 47,184 4,767 5,717 (1,919) 5078 3885

Aug 45,105 51,871 50,438 4,767 7,719 (4,385) 5073 4311

Sep 40,200 46,230 45,210 4,767 5,513 (1,766) 4019 2912

Oct 33,407 38,418 38,790 4,767 - 5,139 3402 2885

Nov 29,893 34,377 35,411 4,767 - 5,801 4136 3243

Dec 31,406 36,117 36,538 4,767 - 5,188 4565 3998

* No Import Assumptions given for other months

2010 - California PUC Adequacy Report (April 2011) S. to N. Transfer (AC + DC)(2006 to 2010)

SW Imports

(6,000)

(4,000)

(2,000)

-

2,000

4,000

6,000

8,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

MW

Surplus Transfer Capability PNW RA Assumption

Conclusion:

In 2015, there is enough surplus in the state of California and enough transfer capability to support 3,000 MW of imports October to April

From May to September, California relies heavily on imports to support their resource adequacy efforts and therefore no import capability should be assumed

Demand-Side Management and Small Miscellaneous Resources (non-modeled resources)

2008 Adequacy Standard

The 2008 Adequacy Standard included 3,000 MW (capacity) and 28,800 MWhrs (energy) as a proxy for emergency generation and/or demand response that are not modeled in Genesys

These thresholds are applied post processing to games that have events; those that exceed these thresholds are counted as “Loss-of-Load”

Proposal for new standard is to count specific resources that are available to utilities and are not modeled in Genesys

Emergency generators not owned or under contract with utilities are not considered (they number in the thousands of megawatts)

Demand-Side Management

Demand-side management (DSM) for irrigation pumps, A/C, and flexible load control (programs for use every year) Most of these resources are on AGC or prescheduled by utilities DSM geared towards summer peaking utilities By 2010, Idaho and PacifiCorp have developed over 600 MW of

DSM However, the Genesys load forecast for 2015 incorporates these

programs in the demand forecast Only incremental demand response programs beyond 2010 can be

included (to avoid double counting)

DSMDSM - Summer

2010 MW 2015 MW Delta MWIdaho Power(Flex Peak, Irrigation, A/C)* 336 351 15PacificorpIrrigation Programs Idaho* 275 275 0Westside Load Control 0 45 45PGE - Bi Seasonal DR 0 60 60

Summer DSM 120*2010 MW Included in Genesys load forecast

DSM - Winter2015 MW

PGE - Bi Seasonal DR 60Winter DSM 60

Small Miscellaneous Resources

Includes resources and load management actions utilities have rights to

Not generally used on an annual basis, but rather used only during periods of stress

Small Miscellaneous Resources

Small Miscellaneous ResourcesSummer or Winter

2015 MW 2015 MWhrsBPA - Banks Lake 300PAC - Monsanto Curtailment 182 35,000 PGE - Dispatch. Standby Gen* 120 48,000

602 83,000

*Limit 400 hrs per year or 200 hours per season

Appendix

Appendix - Power Plant Development in California 2001 - 2010

During the past 11 years there as been substantial resource development within the state of California – most of it gas-fired

Charts includes all resources built in state regardless of owner

Bar Chart “net addition” includes the impact of plant retirements in the state (but also including Mohave)

Source: Ventyx

California Power Plant Development 2000 - 2010

90%

6%

Misc. Geothermal Biogases Natural Gas Wind Biomass Hydro PV

Wind

Natural Gas

  MW

Natural Gas 21567

Wind 1378

Geothermal 211

Biogases 219

Hydro 275

PV 157

Biomass 87

Misc. 21

Net Additions = cumulative additions – cumulative retirements

California Cummulative and Net Resource Additions 2000 - 2010

0

5000

10000

15000

20000

25000

30000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

MW

Cummulative Additions Net Addition

California Cumulative and Net Resource Additions