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Electricity Shortage in California: Issues for Petroleum and Natural Gas Supply |
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2. Electricity Reliability Issues in California
A. SummaryFor the summer of 2001 in California, reliability assessments of the electricity supply and demand conditions likely to prevail have been made by industry reliability organizations, the California Energy Commission, and the California Independent System Operator. These sources agree that electricity demand will exceed supply capability within California this summer and rotating electrical outages will be required. The estimates of electricity outages in California during the summer 2001 (June 1 through September 30) range from a low of 55 hours to a high of 700 hours. The estimates of involuntary peak demand reduction during electrical outages range from 1,825 megawatts (MW) to as high as 5,500 MW. One of the significant uncertainties in these projections of electricity outages is the amount of electricity demand reduction that is either voluntary or motivated by high electricity prices. |
The State of California and 10 other Western States make up the United States portion of the Western Power Grid (Figure 2-1).[1] The electric power industry's Western System Coordinating Council (WSCC) oversees its operations and planning and it is a member of the North American Electric Reliability Council (NERC) (Figure 2-2). These industry organizations are responsible for reliability standards (adequacy of supply, security and system operational practices). The electric utilities (investor-owned, municipal, cooperative, and Federal) all adhere to the operational and planning standards established by WSCC and NERC. Oversight and review of planning done by the electric utilities operating in California are handled by the California Public Utilities Commission (CPUC), the California Energy Commission (CEC), and by various municipal governments.[2]
Figure 2-1. Map of the Western Power Grid
(http://www.wscc.com/files/WSCC Transmission System Map.pdf)
Figure 2-2. NERC Regional Council Map
(http://www.nerc.com/regional/)
As a result of restructuring in California, operational authority for most of the state's transmission system was given over to the California Independent System Operator (CAISO), which also adheres to the WSCC and NERC reliability standards (Figure 2-3).[3] Some electric utilities, like the Los Angeles Department of Water and Power (LADWP), were exempted from joining the CAISO (Figure 2-4).[4] They are responsible for meeting their own supply obligations, but they do coordinate purchases, sales, and other operational actions with the CAISO. They are, however, not currently subject to CAISO's curtailment criteria.
Figure 2-3. Map of the CAISO Operating Area
(http://www1.caiso.com/aboutus/infokit/map/)
Figure 2-4. California's Electric Utility Service Areas.
(http://www.energy.ca.gov/maps/utility_service.html)
Restructuring also impacted the ownership of generating powerplants by investor-owned electric utilities.[5] They were required to divest their fossil-fueled powerplants as part of the stranded cost recovery process. As a result, the percentage of investor-owned utility ownership in the State of California dropped from 55 percent to 15 percent.[6] These assets were acquired by nonutilities and their share of generating assets has increased from 19 percent to 54 percent in California.[7]
Reliability is defined as the adequacy of supply and security of operations. For this summer in California, reliability assessments have been made by industry reliability organizations, the California Energy Commission, and the California Independent System Operator.[8] All reports agree that electricity demand will exceed supply capability within California this summer and that rotating electrical outages will be required. However, the reports differ in their estimates of the magnitude of the problem.
In the 2001 Summer Assessment released on May 15, 2001, NERC made an assessment of the operational conditions and sources of expected problems that could affect the interconnected power grids covering all of Canada and the contiguous United States.[9] This reliability assessment indicated that there would be higher customer demand and constrained electrical supply in the Western Power Grid, with rotating electricity blackouts likely to occur in California.
NERC identifies several potential sources for these problems.[10] They include:
With the exception of California, generating resource availability in the Western Power Grid is expected to be tight, but adequate to meet electrical usage and required operating reserve capacity. However, NERC believes that the ability of other utilities to provide power supplies to California is limited this summer.
Utilities in the Pacific Northwest will not be able to make sustained export sales to anyone outside their region. However, they may be able to offer some electricity for sale during the peak demand hours in California. Power suppliers in Arizona, New Mexico, and Nevada (the Southwest area of WSCC) will have limited ability to export electricity under normal summer temperature conditions. When temperatures are much warmer than normal these power supplies are not expected to be able to export electricity.
For California, NERC believes "that resource deficiencies and transmission constraints are likely to result in the curtailment of interruptible and firm customer demand both during peak periods and at other times due to energy limitations during the 2001 summer within the CAISO operating area unless conservation or assistance from other areas is greater than projected."[12] Conservation is expected to shave peak demand in California and the Western Power Grid. However, the magnitude of the potential savings from conservation is difficult to measure and is not expected to eliminate the need for rotating electricity outages. The municipal and cooperative utilities within California that are not part of the CAISO are projected to have sufficient electricity supply to meet their own demand.
Assessments of California electricity demand and generating capacity available this summer (June through September) have been published by WSCC [13], CEC [14], CAISO [15], and NERC [16]. All sources reached the same conclusion that there is inadequate supply available to meet expected demand in California this summer.
The California Energy Commission (CEC) projected a peak demand for California during the summer of 2001 of 47,703 MW. With a desired 7 percent operating reserve, a total generating capacity of 50,303 MW would be required. The CEC also developed forecasts that examined temperature sensitivity. They found that a warmer summer would raise the demand for electricity leading to higher generating capacity requirements. For the CEC, the 50,303 MW baseline generating capacity requirement represents a 1 in 2 chance of occurring, while the 1 in 5 chance of warmer weather raises the generating capacity requirement to 51,882 MW, and the 1 in 10 chance of very warm weather raises the generating capacity requirement to 53,104 MW.
The CAISO and NERC reports start from the same peak load baseline of 47,703 MW and reach the estimated 50,303 MW capacity requirement by adding 2,600 MW of desired operating reserves. However, the CAISO and NERC assessments of generating capacity differ in two important areas (Table 2-1):
| Table 2-1. CAISO and NERC Summer Peak Projections | ||||||||||||||||
| CAISO operating area peak demand in megawatts (MW) | ||||||||||||||||
| CAISO Projections | NERC Projections | |||||||||||||||
| Jun. | Jul. | Aug. | Sep. | Jun. | Jul. | Aug. | Sep. | |||||||||
| 1 | Forecast summer season peak load | 47,703 | 47,703 | 47,703 | 47,703 | 47,703 | 47,703 | 47,703 | 47,703 | |||||||
| 2 | Operating reserve requirements | 2,600 | 2,600 | 2,600 | 2,600 | 2,600 | 2,600 | 2,600 | 2,600 | |||||||
| 3 | Estimated total capacity requirement | 50,303 | 50,303 | 50,303 | 50,303 | 50,303 | 50,303 | 50,303 | 50,303 | |||||||
| Control Area Generating Resources | ||||||||||||||||
| 4 | Maximum net dependable generating capacity (as of Feb. 2001) | 42,113 | 42,113 | 42,113 | 42,113 | 42,113 | 42,113 | 42,113 | 42,113 | |||||||
| 5 | Dynamic schedules into CAISO | 1,857 | 1,857 | 1,857 | 1,857 | 1,857 | 1,857 | 1,857 | 1,857 | |||||||
| 6 | Expected new generation (cumulative totals) | 390 | 2,593 | 2,789 | 3,371 | 0 | 500 | 1,000 | 1,500 | |||||||
| 7 | Scheduled outages | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||
| 7a | Emission related outages | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||
| 7b | Unavailability due to financial concerns | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||
| 8 | Estimated forced outages/capacity limitations | (2,500) | (2,500) | (2,500) | (2,500) | (4,525) | (4,525) | (4,525) | (4,525) | |||||||
| 9 | Estimated hydro capacity limitations | (1,000) | (1,000) | (1,000) | (1,000) | (1,200) | (1,800) | (2,400) | (2,800) | |||||||
| 10 | Total resource capacity (at peak) | 40,860 | 43,063 | 43,259 | 43,841 | 37,165 | 37,065 | 38,045 | 38,145 | |||||||
| Generation Imports | ||||||||||||||||
| 11 | Required net imports (line 3 - line 10) | 9,443 | 7,240 | 7,044 | 6,462 | 13,138 | 13,238 | 12,258 | 12,158 | |||||||
| 12 | Forecast net imports at peak | 3,500 | 3,500 | 3,500 | 3,500 | 2,500 | 2,500 | 2,500 | 2,500 | |||||||
| 13 | Estimated resource deficiency before mitigation measures (line 11 - line 12) |
5,943 | 3,740 | 3,544 | 2,962 | 10,638 | 10,738 | 9,758 | 9,658 | |||||||
| Definitive Mitigation Measures | ||||||||||||||||
| 14 | UDC interruptible load curtailments | 400 | 400 | 400 | 400 | 700 | 700 | 700 | 700 | |||||||
| 15 | Demand relief programs and conservation | 596 | 596 | 596 | 596 | 1,250 | 1,250 | 1,250 | 1,250 | |||||||
| 15a | Response to rate increase | 0 | 0 | 0 | 0 | 1,950 | 1,950 | 1,950 | 1,950 | |||||||
| 16 | Conversion of non-spinning reserve to energy | 1,300 | 1,300 | 1,300 | 1,300 | 1,300 | 1,300 | 1,300 | 1,300 | |||||||
| 17 | Estimated resource deficiency after mitigation measures |
3,647 | 1,444 | 1,248 | 666 | 5,438 | 5,535 | 4,558 | 4,458 | |||||||
| Source: North American Electric Reliability Council, 2001 Summer Special Assessment, (Princeton, NJ, May 2001), pg. 12 | ||||||||||||||||
The summer 2001 monthly estimates for generating capacity available to meet peak demand in the CAISO operating area (line 10 in Table 2-1) range from 41,000 to 44,000 MW in the CAISO study, but are lower in the NERC study (from 37,000 MW in June to 38,000 MW in September). The resulting estimated resource deficiency [18] highlights the difference in the interpretation of the magnitude of impact. The CAISO analysis shows the deficiency in generating capacity before definitive mitigation measures (line 13 in Table 2-1) dropping from 6,000 MW in June to 3,000 MW in September. NERC projects a deficiency range starting at 10,600 MW in June, rising slightly to 10,700 MW in July, then declining to 9,700 MW in September. When the uncertain conservation and demand mitigation measures are included, the estimated generating capacity deficiencies reported by the two organizations decline but still remain significantly different (line 17 in Table 2-1). The deficiency margin at peak declines from 3,600 MW in June to 700 MW in September for CAISO, but NERC sees it starting at 5,400 MW and shifts downward by about 1,000 MW to 4,500 MW over the same period.[19]
For NERC, the projected outages or expected hours of unserved energy requirements for California range from a low of 9 percent to 24 percent of the total hours (that is, from 260 to 700 hours out of 2,928 total hours covering the period June 1 through September 30).[20] The average high outage is expected to reach 3,150 MW (with no demand mitigation measures being taken). The low is projected to be an average outage of 2,160 MW, which includes customers responding to tariff rate increases and other demand mitigation measures.[21] CAISO estimates a lower level of 55 outage hours with an average outage of 1,825 MW.[22] NERC also expects that "CAISO may be short as much as 5,500 MW during peak periods."[23]
CAISO will provide notice about unusual system conditions or emergencies to the electric utility distribution companies it oversees, market participants, and reliability and regulatory agencies. These include alerts (covering day ahead markets), then warnings (usually for one hour ahead markets), and finally 3 stages of emergency status notices describing worsening minimum operating reliability reserve support.[24] For the emergency status, when operating reserves fall to the 7 percent reserves mark, all available power is purchased. When operating reserves go below 5 percent, conservation measures are implemented, interruptible customers are curtailed and emergency assistance requests are made. When operating reserves drop below 1.5 percent or there is a significant emergency event, involuntary load curtailments are initiated.
The geographical location or type of electrical event affecting CAISO operations and causing issuances of emergency notice will initiate different types of actions to address it. The source can be external (e.g., transmission line outages coming from other parts of WSCC or loss of committed generation supply), from a single event (e.g., individual distribution system, loss of a high voltage transmission line or large generating powerplant), and/or a system wide event (e.g., time of day transfer constraints for peak or off-peak, high customer demand for electricity).
Upon identifying the part of California being affected, the electrical distribution systems under oversight of CAISO will be directed to shed a pro-rated share of firm customer load.[25] For 2001, the statewide ratios are: Pacific Gas and Electric (PG&E) at 49.6 percent, Southern California Edison (SCE) at 42 percent, San Diego Gas and Electric (SDG&E) at 7.4 percent, and the Cities of Pasadena and Vernon at 0.6 and 0.4 percent, respectively. In addition, both PG&E and SCE further allocate their share to cover special municipal allocations within their operational area.[26]
Unlike other commodities, electricity, at the levels used by customers, cannot be stored. Operators of the electrical system must rely on real-time generation matched to their customers' electricity demand. Operators need to keep the whole electrical system operationally viable and under constant control.[27] In order to do this, firm customer load has to be dropped on occasions. This particular event is considered to be a 1-day in a 10-year situation by the electric power industry.[28]
Specific substation and high voltage transmission line problems affect defined customer groups and are addressed by repair crews once the source of the problem is identified. However, customers that are not under interruptible rate tariffs, that suffer usage interruptions initiated by their electrical system operators, are in this blackout condition because it is a last resort action taken by their electric utility. Besides these sources of concern, extreme weather conditions are often the lead or major cause of distribution system disruptions of service. They usually have local area impacts.
Keeping the electrical system protected is a key operational concern because losing control and suffering a blackout results in a much longer period of outage that affects everyone. When an electrical system operates with these problems as on-going concerns, it affects contingency planning and operational practices of all other interconnected electrical systems.
The normal oversight of the electrical system operators includes:
These operational actions done by the electrical system operators are usually in the background and almost never noticed by the customer. In California this summer, the problems will be evident, but acknowledging calls for conservation will have a beneficial impact on mitigating the disruptions.
The California Public Utility Commission (CPUC) describes rotating outages as planned load reductions in which customer power is shut off following predetermined plans. Various customers on distribution feeder lines are grouped together and each takes their turn in being shut off; which provides the "rotating outages" terminology.[29] Each distribution utility system does this in a different way. For example, PG&E uses 750 MW blocks of customers that cover their whole distribution system. SCE uses different terminology and subdivides its service territory into 100 MW groupings of customers. In all cases, the customers impacted (for each of the individual group or block classifications) are spread throughout the individual electrical systems.
To provide assistance to their customers in coping with the abrupt loss of electrical supply resulting from a blackout, the electric distribution companies are placing the rotational code on the customer's billing documents. This tells each customer that they must pay attention to anticipated emergency problems when announcements are made by CAISO or the State of California 48 hours in advance of expected blackouts. These customer codes are also important because those codes that are prescheduled to be affected by an anticipated blackout will be announced 24 hours in advance. Later, another announcement will be made, 1 hour before the actual start of a blackout.[30]
Exemptions from rotating outages are granted by the CPUC. The CPUC defines essential use customers as those generally providing public health, safety, and security services. They include: hospitals, fire and police stations, prisons, national defense facilities, communication utilities, and air traffic control and sea traffic control, but not water utilities. Other customers will indirectly gain the benefits of avoiding rotating outages if they are served on a common distribution feeder that also covers one or more essential use customers.
The CPUC is concerned that the determination to designate a customer as an essential customer can significantly affect the amount of load available to be shut off and the frequency of outages other customers must face.[31] The CPUC is also concerned about equity issues and the impact on demand-side reduction programs because of reduced incentives to voluntarily participate.[32] [33]
If the CAISO or utility has to take quick action by isolating a transmission line or removing a major substation terminal from service to remove load, all customers will be dropped whether they are in an exempted category or not.
Electrical system peak demand normally occurs in the late afternoon to early evening hours of business weekdays. Monthly, yearly, or all-time record usage comes during periods when extreme temperatures affect customers during a prolonged cold spell or when high temperatures and humidity encompass a large geographical area for several continuous days.[34] The response to these types of temperature extremes is a high customer usage of electricity.
For California, the temperature pattern across the State usually breaks into two parts (northern and southern) and this diversity does assist CAISO in its operations.[35] However, when the two parts of the State have a joint coincident peak, that is, the highest usage comes at the same time for all major utilities in the State, then the operation of the overall electrical system is impacted in the strongest manner.[36] During these same periods, the California Energy Commission (CEC) has found that the "climatic conditions that cause high temperatures across California are also likely to have a similar effect on temperatures in the Pacific Northwest and Desert Southwest."[37] This concurrent impact of high temperatures raises the demand for electricity in the West and reduces the availability of power for export at the same time.
The expectations for the timing of the rolling blackouts in California are for these same extreme temperature-induced usage periods. Other outages will come from sudden losses of powerplants or transmission lines that happen when generating reserves are near the system operational constraint limitations.
CEC staff also noted in their report that in California, the statewide peak demand is very sensitive to small changes in average high temperatures. The average high temperature in a 1-in-40 year scenario (i.e., similar to temperature conditions that occurred in the summer of 1998) was only 5-degrees hotter than the average high temperature under expected "normal" weather conditions.[38] Weather will be one of the key factors that will influence the level of customer load that will have to be matched to available power supplies.
[1] The States include: Washington, Oregon, California, Idaho, Montana, Wyoming, Nevada, Utah, Colorado, Arizona, and New Mexico. In addition, the western tip of Texas and portions of South Dakota and Nebraska are part the WSCC reliability council and Western Power Grid. However, the eastern edge of Montana and New Mexico are part of the Eastern Power Grid. The Provinces of British Columbia and Alberta and portions of the Mexican State of Baja California are also part of the WSCC.
[2] The State of California also oversees the Department of Water Resources and several transmission and public power agencies.
[3] The CAISO map depicts their coverage and it should be noted that the northern edge of California is physically overseen by utilities operating in Oregon.
[4] Public utilities - mostly municipals and cooperatives - were not required under California Assembly Bill 1890 to join the CAISO.
[5] The three investor-owned electric utilities are: Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric.
[6] The associated percentages did not change much for public utilities and qualifying facilities. California Utilities Emergency Association and Department of Energy, Office of Critical Infrastructure Protection, RED HEAT Interdependencies Workshop - Summary of Discussion and Key Issues (Sacramento, CA, May 18, 2001), p. 4.
[7] Energy Information Administration calculated from data collected on the Form EIA-860 and EIA-860A.
[8] These reports include:
• California Energy Commission, Summer of 2001 Forecasted Electricity Demand and Supply, (Sacramento, CA, November 2000) ( http://www.energy.ca.gov/reports/2000-11-20_300-00-006.PDF);
• California Independent System Operator, California 2001 Summer Assessment, (Folsom, CA, March 22, 2001) ( http://www.caiso.com/docs/09003a6080/0c/af/09003a60800cafcd.pdf);
• Western System Coordinating Council, Assessment of the 2001 Summer Operating Period, (Salt Lake City, UT, Issued April 6, 2001, Revised April 13, 2001) ( http://www.wscc.com/files/wisrrptg.pdf);
• North American Electric Reliability Council, 2001 Summer Assessment, (May 2001, Princeton, NJ) ( ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/summer2001.pdf);
• North American Electric Reliability Council, 2001 Summer Special Assessment. (May 2001, Princeton, NJ). ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/summer2001-special.pdf
[9] North American Electric Reliability Council, 2001 Summer Assessment, (May 2001, Princeton, NJ). This evaluation included a review of available generating resources, determination of what electrical energy would be available from other members of the power grid to provide support for each other, and an examination of the rapid growth in electrical demand experienced in the Western States.
[10] North American Electric Reliability Council, 2001 Summer Assessment, (May 2001, Princeton, NJ), p. 29.
[11] Air quality restrictions were expected to be relaxed in California but not the other Western States. For example, on June 12, 2001, California Governor Gray Davis signed an Executive Order to allow natural gas-fired power plants to operate in excess of their hourly, daily, quarterly and/or annual emission limitations if the additional power is sold to the California Department of Water Resources; serves a local load; or is sold to another California-based utility. The gas-fired plants must pay a mitigation fee to the local air districts of $7.50 per pound of oxides of nitrogen (NOx) and $1.10 per pound of carbon monoxide emitted. These mitigation fees will be used to clean-up or retire other sources of pollution in the same air basin. California Office of the Governor Press Release, "Governor Davis Signs Order Allowing Gas-Fired Power Plants to Operate at Maximum Levels" (Sacramento, CA., June 8, 2001).
[12] North American Electric Reliability Council, 2001 Summer Assessment, (May 2001, Princeton, NJ), p. 29.
[13] Western System Coordinating Council, Assessment of the 2001 Summer Operating Period, (Salt Lake City, UT, Issued April 6, 2001, Revised April 13, 2001).
[14] California Energy Commission, Summer of 2001 Forecasted Electricity Demand and Supplies, (Sacramento, CA, November 2000).
[15] California Independent System Operator, California 2001 Summer Assessment, (Folsom, CA, March 22, 2001).
[16] North American Electric Reliability Council, 2001 Summer Special Assessment. (May 2001, Princeton, NJ). The NERC report was released later than the CAISO report, so additional information was available for consideration in development of the findings.
[17] Ibid, p. 9.
[18] This is calculated after addressing net import assumptions, but before taking into account mitigating measures (interruptible load curtailments, demand relief programs, and conversion of non-spinning reserves to energy).
[19]Refer to the California ISO (http://www.caiso.com/SystemStatus.html) and Lawrence Berkeley National Lab (http://energycrisis.lbl.gov/) for current information on hourly electricity loads and other relevant data pertaining to California.
[20] The summer covers June through September or 2,928 hours.
[21] Ibid, p.13.
[221] Ibid, p.11.
[23] North American Electric Reliability Council, NERC 2001 Summer Outlook for Electricity Reliability Briefing, (Princeton, NJ, May 15, 2001) presented on May 14, 2001 in Washington, DC.
[24] Rapid changes in operating conditions will cause the CAISO to use the appropriate notice first. Minimum operating reliability criteria covers the sum of regulation and contingency reserves plus reserves covering interruptible imports and on-demand obligations to other entities or control areas.
[25] The pro-rated shares are based on the electrical distribution system respective ratios of: demand to total control area, demand at the time of control area annual peak, and demand for the previous year.
[26] If a statewide reduction was ordered, then 49.6 percent would be allocated to PG&E. PG&E itself would take responsibility for 79.2 percent of this share with the remaining being assigned in the following manner to: Sacramento Municipal Utility District-9.4 percent, Modesto Irrigation District-2 percent, SNCL-2 percent, Northern California Power Agency-3.8 percent, Turlock Irrigation District-1.4 percent, CCSF-0.8 percent, and the Western Area Power Administration-1.5 percent. For this same statewide reduction, the SCE portion is 42 percent. Then SCE would take responsibility for 93.9 percent of this share and the rest would be allocated to the Cities of Anaheim-2.6 percent, Riverside-2.4 percent, Colton-0.4 percent, Azusa-0.3 percent, Banning-0.2 percent, and to the Southern California Water Agency-0.2 percent. SDG&E and the Cities of Pasadena and Vernon, as noted above, would be assigned their 2001 ratio percentage. California Utilities Emergency Association and Department of Energy, Office of Critical Infrastructure Protection, RED HEAT Interdependencies Workshop, (Sacramento, CA, April 24, 2001), CAISO presentation.
[27] U.S. Department of Energy, "Report of the U.S. Department of Energy's Power Outage Study Team: Findings and Recommendations to Enhance Reliability from the Summer of 1999" (Washington, DC, March 2000); and U.S. Department of Energy, "Report to the President: Electric Power Outages in the Western United State, July 2-3, 1996" (Washington, DC, August 1996).
[28] This criteria of 1-day in 10-years will not be practical in California this summer and is effectively suspended.
[29] California Public Utilities Commission, Energy Division Report on Interruptible Programs and Rotating Outages, (San Francisco, CA, February 8, 2001), p.63.
[30] The CAISO will issue a 48-hour forecast for blackouts, then the electric distribution utilities will announce 24 hours in advance the areas that will be affected. One hour before the start of a blackout, the individual utilities will provide notification about the exact time and location of the blackout to its customers. This is part of the 3-tiered alert system that was implemented under the orders of Governor Davis of California. American Public Power Association, Public Power Daily, (Washington, DC May 25, 2001), p. 1.
[31] Ibid, pp.70-71.
[32] California Public Utilities Commission, Energy Division Report on Interruptible Programs and Rotating Outages, (San Francisco, CA, February 8, 2001), p. 72.
[33] The hours available for use in the interruptible program for Northern California were exhausted on May 31, 2001. For Southern California, there is only a limited amount of contracted load reduction that is expected to be available from Southern California Edison and San Diego Gas and Electric customers. California Independent System Operator, CAISO 2001 Summer Assessment, (Folsom, CA, March 22, 2001), p. 10.
[34] California Energy Commission, High Temperatures and Electricity Demand - An assessment of Supply Adequacy in California, (Sacramento, CA, July 1999), p. 10. The Commission report indicates "staff have found a strong correlation between peak electricity demand and a buildup of high temperatures over several days."
[35] Ibid, p.11.
[36] Ibid.
[37] Ibid, p.18.
[38] Ibid, p.2.
File last modified: June 12, 2001.
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