How Markets Fared this Summer and What to Expect in 2007
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Transcript of How Markets Fared this Summer and What to Expect in 2007
How Markets Fared this Summerand
What to Expect in 2007IEP 25th Annual Meeting
October 9, 2006
Steve McClaryMRW & Associates, Inc.
Oakland, [email protected]
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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
$/M
Wh
CAISO Hourly Real-Time
Day-Ahead Average
Source: CAISO and MW Daily
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1-A
pr-9
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2-M
ay-9
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2-Ju
n-99
3-Ju
l-99
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ug-9
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3-S
ep-9
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4-O
ct-9
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4-N
ov-9
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5-D
ec-9
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5-Ja
n-00
5-Fe
b-00
7-M
ar-0
0
7-A
pr-0
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ay-0
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9-Ju
n-00
10-J
ul-0
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1
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15
220
75
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375
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525
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675
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$/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
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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