How Markets Fared this Summerand

What to Expect in 2007IEP 25th Annual Meeting

October 9, 2006

Steve McClaryMRW & Associates, Inc.

Oakland, Californiamrw@mrwassoc.com

2

Overview

1. Heat Storm 20062. How Demand Was Met3. Looking Ahead to 20074. Conclusions

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Heat Storm 2006

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July 2006 California Heat StormCAISO Area Weighted Average Summer Temperatures

Normal summer (1-in-2) is 89° Extreme summer (1-in-10) is 102° July 2006 was 106°-110°

Definitions:Summer is the period June 15-September 15.Weighted average temperatures are from a set of representative weather stations.

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Heat Storm was Long and Intense Extraordinary minimum and average temperatures in July

Minimum temperatures significantly above normal in some areas Livermore: 24° above normal; Fresno: 23° above normal

Hottest overnight lows ever recorded at about half of the NOAA recording stations

Fresno: 90°; Stockton: 82°; San Jose: 74° For June 15-July 27: actual temperatures 3 standard deviations above weighted

maximum average temperatures in the CAISO control area Duration of high temperatures contributed to heat storm

Valley heat wave persisted for 36 days Sacramento recorded 11 consecutive days of 100+ temperatures

Humidity was a factor SDG&E estimates humidity combined with high temperatures added

4%-6% additional load during July 22-24

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Historical Heat Waves: 1949-2006Top Eight Heat Waves in PG&E Service Area

Source: PG&E Presentation, “July 2006 Heat Wave (Heat Storm) PG&E Area”

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Temperatures & Peak Loads: July 17-27

Source: California Energy Commission, July 2006 Heat Storm Workshop, August 29, 2006; http://www.energy.ca.gov/2006_summer_outlook/documents/index.html

July 24 peak: 50,270 MW

Tem

pera

ture

s in

IOUs

’ Are

as Peak Load in CAISO Area

Mission Viejo soccer tournament

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Peak: Temperature + Load Growth CAISO 2006 peak almost 5,000 MW higher

than 2005 Total CAISO load year to date is 5% higher

than 2005 Adjusted to account for MID and TID departure

Load continues to grow Higher energy use per customer Significant growth in air conditioning use Heat caused loss of A/C load diversity

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Customer and Infrastructure Impacts 138 deaths attributed to heat storm conditions Distribution transformers failed

Extreme conditions meant loss of A/C cycling diversity; high load factors on distribution system

Ambient temperatures were critical contributing factor to transformer failures Age of transformers only a minor factor in failure

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Market Price ImpactsSP-15 Electricity Prices (Jan. 1 - Sep. 30 '06)

$0

$50

$100

$150

$200

$250

$300

$350

$400

1-Jan 31-Jan 2-Mar 1-Apr 1-May 31-May 30-Jun 30-Jul 29-Aug 28-Sep

Date

$/M

Wh

CAISO Hourly Real-Time

Day-Ahead Average

Source: CAISO and MW Daily

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1-A

pr-9

9

2-M

ay-9

9

2-Ju

n-99

3-Ju

l-99

3-A

ug-9

9

3-S

ep-9

9

4-O

ct-9

9

4-N

ov-9

9

5-D

ec-9

9

5-Ja

n-00

5-Fe

b-00

7-M

ar-0

0

7-A

pr-0

0

8-M

ay-0

0

9-Ju

n-00

10-J

ul-0

0

10-A

ug-0

0

10-S

ep-0

0

1

8

15

220

75

150

225

300

375

450

525

600

675

750

$/MWh

Date

Hour

CalPX Day Ahead Unconstrained Market Clearing Price(4/1/99 - 9/30/00)

0-75 75-150 150-225 225-300 300-375 375-450 450-525 525-600 600-675 675-750

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Demand Forecast Performance

43

46

49

52

CAISO - April CEC - April CEC - June 29

Thou

sand

Meg

awat

ts

1 in 2 1 in 10

CAISO Peak50,270 MW

1,500 MW

Demand forecasts for CAISO control area

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How DemandWas Met

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Customers Cut Their Own DemandState government led by example

25% reduction in state buildings

Strong public response to conservation requests Flex Your Power: “Flex Alerts” issued only when

high temperatures were expected Utilities’ customer outreach efforts

PG&E estimated 500 MW reduction in its territory

Interruptible and demand response customers provided 850 MW

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CAISO July 24 Demand: Forecast vs. Actual

25000

35000

45000

55000

0 4 8 12 16 20 24

Forecast Actual

Stage 1

Stage 2

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Coordination by Market Participants Water districts

Reduced peak pumping load Returned load gradually at PG&E request

Generators Maintenance schedules were optimized

Coordination on imports Exceeded normal transmission limits from Northwest;

“sharpened the pencils” BPA sent water down river on Sunday to maximize

Monday generation Modified generator maintenance schedules

CAISO summer preparedness training for transmission system operators

Firefighters protected grid from wildfires

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High Generator Availability Less than 1,000 MW of uncommitted capacity

during peak hours in late July Scheduled and forced outages less than 2,500

MW on July 24 Below 3,000 MW for most of July

Resource adequacy requirements were instrumental 95% of overall peak scheduled day-ahead; 99%

scheduled hour-ahead SDG&E reported mixed performance for peakers

in its territory

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Additional Factors

Imports provided 9,600 MW Hydro resources were abundant Blown transformers reduced load by about

200 MW Transmission line availability was high Transmission congestion was not an issue

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Looking Ahead to

2007

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Electricity Demand Continues to Grow… CEC’s 2007 forecast: 1-2% growth

CAISO expects weather-adjusted increase of about 1,000 MW per year

Under expected conditions (1-in-2), CEC forecasts an operating reserve margin of 21% Reserve margin drops to 5.5% for 1-in-10 Reserve margin under Heat Storm 2007?

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…But New Infrastructure Several Years Out High probability generation additions

2007: 190 MW1

2008: 752 MW CAISO has interconnection requests for 29,150

MW covering next five years; expects less than 50% to reach commercial operation

New major transmission lines SCE’s Devers-Palo Verde 2 planned for late

2009 SDG&E’s Sunrise Powerlink planned for 2010

1 Source: WECC Proposed Generation Database, posted on the CEC website. This number does not include the peaking capacity the IOUs have proposed in response to CPUC Pres. Peevey’s ruling.

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Fast-Track Measures for 2007 IOUs seek to add new peaking capacity

SCE: utility-built 250 MW PG&E: utility-built 200 MW + San Francisco

peakers + power purchases SDG&E: 250 MW in-basin through power

purchases Expanded demand response programs

IOUs proposing extra 679 MW for 2007 A/C cycling, demand bidding, AutoDR

Requested expedited regulatory approval

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Regulatory and Planning Issues Resource adequacy requirements

Should 15% planning margin be based on 1-in-2 demand? 1-in-10?

Consideration of IOU-specific circumstances Hydroelectric capacity Large single contingency relative to system (e.g., SDG&E)

Potential for multi-year adequacy requirements Need 3-10 year forecast of requirements for development

Forecasting CEC needs data from IOUs sooner to provide forecasts

earlier Include humidity factors in forecasts

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Conclusions

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Lucky or Well-Prepared? Well-prepared

Coordination among key market players High generator availability: additional

resources would not have prevented outages; transformers were the weak link

Strong customer response Lucky

Excellent hydro conditions No wildfires threatening grid Transmission congestion not an issue

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Implications for Future Planning Summer 2006 was (or should be) wake-up call for state planners and SCE

Climate change could be a wildcard in future energy forecasts

The CEC identified resource needs in the 2005 IEPR (not additive) Total Procurement Need for 2009

SCE: 8,724 MW PG&E: 5,001 MW SDG&E: 305 MW

Additional Renewables by 2010 SCE: 1,183 MW PG&E: 790 MW SDG&E: 428 MW

Aging Plant Replacement by 2012 SCE: 8,088 MW PG&E: 4,900 MW SDG&E: 1,619 MW