Introduction page 1
Updated Load Forecasts page 6
Accounting for DSM/DG page 7
Power Flow Studies page 8
Operational Requirements page 10
Interpreting Results page 12
Findings page 13
Closure of the Hunters Point Power Plant has been an important community objective for decades, and part of City policy since 1998. However, until recently, the owner of the plant, PG&E, had taken little tangible action to shut it down.
In April 2002, with the involvement of community groups and non-profit organizations working in the Bayview-Hunters Point community and the City and County of San Francisco, the California Independent System Operator (ISO) agreed to work with the City and County of San Francisco and community stakeholders to identify the conditions under which the Plant could be closed. A Load Forecasting and Power Flow Analysis (LFPFA) working group was formed to conduct the necessary analyses to determine these conditions and assess locally developed alternatives.[1] As part of this process, several community stakeholders expressed their intent that the Hunter Point Plant be closed without replacing it with a new large fossil fuel power plant.[2]
After years of public pressure PG&E has agreed to a shutdown “as soon as the facility is no longer needed to sustain electric reliability in San Francisco and the surrounding area and the FERC authorizes PG&E to terminate the Reliability Must Run (RMR) agreement for the facility.”[3] Likewise, as the result of LFPFA discussions, the primary organization responsible for RMR contracts, the California Independent System Operator (Cal-ISO), has agreed to release the plant from its contract after certain conditions, including the development of new fossil fuel sources in San Francisco, are met.
In May 2001 the San Francisco Board of Supervisors directed the San Francisco Public Utilities Commission and the Department of the Environment to develop an Energy Resource Plan (ERP) to implement all practical transmission, conservation, efficiency and renewable alternatives to fossil fuel generation in the City and County of San Francisco.[4] The ERP was adopted unanimously by the Board of Supervisors in December 2002.[5]
The LFPFA has reviewed and discussed many documents and presentations that provide the underlying support for this statement. Some of the key documents include:
Community Energy Plan – Community Energy Coalition, May 2002.
The Electricity Resource Plan: Choosing San Francisco’s Energy Future, Revised December 2002.
San Francisco Peninsula Load Serving Capability Study – California ISO, December 17, 2003.
San Francisco Internal Transmission System After AP-1 Technical Study, PG&E, August 6, 2003.
California Energy Demand 2003-2013 Forecast, California Energy Commission, February 2003.
PG&E (2002) 2003-2012 1-in-10-load forecast for San Francisco and Peninsula.
Overview of California Energy Commission Demand Forecast Methods, Lynn Marshall, Demand Analysis Office, CEC, Presented to LFPFA – October 6, 2003.
Terry Winter, President and CEO, CA ISO, Letter to Kevin Dasso and Theresa Mueller, April 18, 2003.
Terry Winter, President and CEO, CA ISO, Letter to Supervisor Sophie Maxwell, October 22, 2003.
California’s electricity system is composed of supply sources (generation) and means to convey electricity, sometimes across great distances (transmission). This interlocking network needs to be “balanced” to enable power to be supplied cost-effectively and reliably. Power plants, connected at different points to the transmission system, can send differing amounts of electricity depending on what other plants are operating. In this sense the grid is like a highway – congestion, particularly at certain points, can change the value of generation in different locations.
Because of transmission constraints, a portion of San Francisco’s electricity demand has to be met with in-City generation. There are two gas fired boiler-steam turbine power plants in San Francisco, the 46 year old, 170-megawatt Hunters Point Power Plant Unit 4, owned by PG&E; and the 39 year old, 210-megawatt Potrero Power Plant Unit 3, owned by Mirant Potrero LLC. There are also four 50-megawatt diesel-fired peaking turbines, Hunters Point Unit 1 and Potrero units 4, 5 and 6 in the City.
None of the existing diesel-fired turbines have modern emission control technology, and under air quality rules are limited to operating 877 hours per year. The steam turbine power plants at Hunters Point and Potrero must meet lowered limits on emission of nitrogen oxides (NOx) under Bay Area Air Quality Management District requirements. To allow Potrero 3 to continue to operate in compliance with BAAQMD regulations, Mirant, with approval from Cal-ISO, plans to install selective catalytic reduction equipment on Potrero 3. Mirant expects to complete this project by early 2005. While this retrofit will result in a reduction in NOx emissions, particulate matter emissions will remain the same. In the near term, PG&E expects to use interchangeable emission reduction credits (IERCs) to operate Hunters Point 4 in compliance with emission limits.
Environmental health and justice concerns were key considerations driving the policy adopted in Ordinance 124-01 to seek all practical alternatives to power plants.
Power plants are the largest stationary sources of criteria air pollutants in San Francisco.[6] These plants – and a disproportionate number of the City’s other pollution sources – are located in Southeast San Francisco. The Hunters Point and Potrero communities consist of a high proportion of lower-income, predominantly non-white residents. These communities share a common concern for public health, especially that of children and the elderly, who are hospitalized for asthma and other diseases at higher rates than reported statewide. Air pollution is a contributing factor to these health problems.[7]
Reliable electricity supplies are critical to the economic and public health of San Francisco. Ensuring reliability is of high importance to state policymakers, particularly in the wake of California’s failed experiment in industry restructuring.
There are a number of ways to help insure that electricity is available when it is needed. These include demand-side management, in which consumers are encouraged, through a variety of means, to lower or change their use patterns; the development of small scale generation, such as solar and combined heat power systems; and the construction of conventional fossil fuel generating stations. Historically, utility planners have preferred to rely on this latter source, because of its economic implications, and the ability to dispatch generation “with the flick of the switch.”
Cal-ISO is responsible for ensuring electric supply reliability. The Agency uses a variety of methods to meet this goal, chief among them being “reliability-must-run” contracts, under which specific power plants are compelled to remain operationally available. Both of San Francisco’s large power plants operate under RMR contracts.
The LFPFA did not come to a consensus on the issue of reliability and that topic remains of central concern to most of the parties. As a result, by and large this analysis reflects Cal-ISO’s reliability criteria, without necessarily endorsing these criteria.
Existing Bay Area Transmission System
The existing transmission system through the peninsula and into San Francisco is insufficient to provide enough electricity to meet demand during all hours of the year (i.e., when demand is particularly high) without some in-area generation. There are four major constraints to the delivery of electricity to San Francisco from other areas of the State: 1) power flowing into the Greater Bay Area, 2) power flowing from the East Bay to the Peninsula, 3) power flowing up the Peninsula into San Francisco and 4) power flowing from the Martin substation on San Francisco’s border into points in San Francisco. Improvements to the transmission system at each of these bottlenecks can improve the import of electricity into San Francisco and lessen the need for in-city generation.
Key constraints that impact the need to operate the Hunters Point and Potrero Power Plants are those that exist north of the San Mateo substation. To prevent overloading the transmission lines serving the upper peninsula and San Francisco, under current conditions generation must be operating at Hunters Point or Potrero Power plants at certain load levels. Constraints within the 115kV underground transmission system within San Francisco north of the Martin substation also currently require the operation of generation at Hunters Point or Potrero. These “in-City” constraints limit the effectiveness of new transmission projects outside of San Francisco, such as the Jefferson-Martin line, to improve load-serving capability in the City.
Because of the intricate nature of the electric grid, and its sensitivity to different operating system conditions, it is necessary to carry out complex power flow studies using various assumptions to determine the ability of the system to reliably serve load. As with any complex system, there will always be some uncertainty regarding the results of such analysis.
ERP Action Plan
The Electricity Resource Plan (ERP) acknowledged that the City must take aggressive steps to achieve the closure of the Hunters Point Power Plant while assuring reliable electric service.
In addition, the City has an interest in facilitating the closure of the power plants located at the Potrero Power Station as soon as possible without jeopardizing reliability. The ERP’s short-term action plan envisioned the possibility of facilitating the retirement of Potrero Unit 3 before costly upgrades were made that would extend the operation of this aging power plant.
The ERP’s short-term action plan called for:
· Maximum investments in energy efficiency measures particularly peak reducing measures.
· Development of new highly efficient and operationally flexible generation at appropriate sites.[8]
· Aggressive efforts to promote and facilitate installation of distributed generation using renewable technologies and clean natural gas-based technologies.
· Development of a plan between the City and Mirant to allow for the environmental dispatch of new generation owned by the City and Potrero Unit 3 to meet BAAQMD requirements under the State Implementation Plan for the Clean Air Act and ISO requirements for reliability.[9]
The ERP also put forward a medium term action plan that covered the period of 2006 through 2012. The ERP recognized the key challenges during this period of time was to close all power generation at Potrero and to meet the City’s commitment to reduce greenhouse gases. The key components of the mid-term action plan included
· Completion of the Jefferson to Martin transmission line
· Accelerated development of solar electric generation in San Francisco with the objective of having 50 megawatts installed by 2012
· Development of additional renewable energy, cost-effective co-generation, and clean distributed generation technologies in San Francisco
· Maximizing investments in energy efficiency and demand reduction with a goal of maintaining San Francisco peak demand at a level no higher than 909 megawatts
· Development of at least 150 megawatts of new wind or other renewable generation that can be imported into San Francisco
The following table shows the contribution that each resource would make towards meeting the projected peak demand for electricity in San Francisco from 2002 through 2012. The projection of peak demand used in the ERP was that produced by PG&E for their 2001 Electric Transmission Grid Expansion Plan.[10] The targets for energy efficiency, solar and distributed generation were assumed to be met through a combination of investments by San Francisco, PG&E and private investors.[11]
Table 1. San Francisco Electricity Resource Plan targets, in MW at peak demand.
|
|
2002 |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
|
Hunters Point |
215 |
215 |
215 |
52 |
0 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Potrero |
363 |
363 |
363 |
203 |
156 |
156 |
156 |
156 |
156 |
156 |
156 |
|
New
Cogeneration |
0 |
0 |
0 |
50 |
100 |
100 |
100 |
100 |
100 |
100 |
100 |
|
Energy
Efficiency |
1 |
10 |
16 |
23 |
32 |
43 |
55 |
68 |
81 |
94 |
107 |
|
New
Combustion Turbines |
0 |
0 |
150 |
150 |
150 |
150 |
150 |
150 |
150 |
150 |
150 |
|
Solar |
1 |
2 |
4 |
7 |
10 |
13 |
16 |
19 |
23 |
27 |
31 |
|
Distributed
Generation |
3 |
6 |
10 |
17 |
24 |
31 |
38 |
45 |
54 |
63 |
72 |
|
Imported
Power |
363 |
384 |
277 |
559 |
601 |
592 |
582 |
571 |
557 |
543 |
529 |
|
Totals |
946 |
980 |
1,035 |
1,061 |
1,073 |
1,085 |
1,097 |
1,109 |
1,121 |
1,133 |
1,145 |
The California Energy Commission (CEC) annually completes a 10-year forecast of electricity and natural gas consumption and peak electricity demand. The latest forecast was developed for the 2003 Integrated Energy Policy Report. The forecast is contained within The California Energy Demand 2003-2013 Forecast.[12]
The CEC forecasts use models that require extensive data about: 1) consumer characteristics such as building characteristics, demographic makeup, and end-use appliance saturations, 2) historic electricity and natural gas consumption, 3) economic and demographic projections and 4) impacts from building and appliance standards and energy efficiency programs.
CEC forecasting attempts to account for the influence of conservation and energy efficiency that is “reasonably expected to occur.” The impacts from demand side management programs sponsored by utilities, state government, local government and other organizations are estimated directly with the CEC models.[13]
PG&E annually conducts a 10-year forecast of peak electricity demand to determine the need for additional transmission projects. These forecasts are published in PG&E’s Electric Transmission Grid Expansion Plan. PG&E has noted the wide variation between its 2000 load forecast and subsequent load forecasts. PG&E observed that the 2000 forecasts were not realized because “the numerous rotating outages during the fall/winter of 2000-2001 and the subsequent increase in electricity price have spurred significant conservation efforts.”[14]
The following table compares the PG&E 2000 and 2002 forecasts for San Francisco with the California Energy Commission’s most recent forecast for the period 2003-2012.
Table 2.
Recent forecasts of San Francisco peak load by PG&E and the CEC, in MW.a
|
|
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
|
PG&E
2000 Forecast |
980 |
1035 |
1061 |
1073 |
1085 |
1097 |
1109 |
1121 |
1133 |
1145 |
|
PG&E
2002 Forecast |
900 |
915 |
927 |
942 |
955 |
968 |
978 |
989 |
998 |
1008 |
|
CEC 2003
Forecast |
927 |
979 |
1004 |
1015 |
1034 |
1057 |
1074 |
1094 |
1112 |
1129 |
NOTES: a) The forecasts are for weather conditions that have a probability of occurring once in ten years.
PG&E’s forecast is notably lower than CEC’s forecast. For example, the CEC forecasts a greater demand growth projected in 2004 and 2005. This is in part due to the CEC’s assumption that in 2004 the City will return to a level of demand greater than was observed in the year 2000, when economic activity in San Francisco was robust.[15] After 2005 PG&E shows an average increase in peak demand of 1.2 percent while the CEC projects an increase of 1.7 percent.
The observed peak demand on March 4, 2004 during an early heat wave in San Francisco was 863 megawatts. The temperature on that date was 84 degrees, which is 13 degrees below the one-in-ten year conditions, which PG&E uses in planning for the reliability of the electric system. Adjusting to the one-in-ten year conditions would result in peak demand for 2004 being approximately 915 megawatts.[16] Based on this observation the LFPFA concludes that the CEC forecast, which projects peak demand at 979 megawatts in 2004, is very likely to overestimate peak demand while the PG&E forecast is likely to be more accurate.
The LFPFA acknowledges that vacancy rates in commercial buildings are at historically high rates and that an economic rebound for the Bay Area could result in a higher growth rate in peak demand for a one or two year period than is included in the PG&E forecast. Based on historical data an increase of peak demand by 50 megawatts from one year to the next can occur during periods of economic recovery. However, subsequent to this rebound, growth in electric demand has tended to be flat. Based on these observations the LFPFA concludes that the PG&E forecast could be increased by as much as 977 megawatts in 2006 rather than the 942 megawatts predicted. However, longer term the LFPFA believes that projecting growth in peak demand of 1.2 percent per year is likely to be more accurate than the 1.7 percent postulated by the CEC.
The load forecasts discussed above do not account for all of the new solar, efficiency, and distributed generation projected to be put in place in San Francisco under the ERP. Such new demand-side management and distributed generation (DSM/DG) will reduce future electric loads on the transmission system that is modeled by the power flow studies discussed below. Therefore, the LFPFA agreed on a method of accounting for these new resources by subtracting their projected capacity at peak load from the load forecast. The table below shows this analysis of projected peak load:
Table 3.
Peak load forecast for San Francisco and the Peninsula with new DSM/DG, in MW.
|
|
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
|
PG&E
2002 Load Forecasta |
1915 |
1949 |
1978 |
2005 |
2027 |
2050 |
2070 |
2092 |
|
New
DSM/DG in ERPb |
29 |
48 |
69 |
91 |
114 |
140 |
166 |
192 |
|
Adjusted
peak load forecast |
1886 |
1901 |
1909 |
1914 |
1913 |
1910 |
1904 |
1900 |
NOTES: a) PG&E forecast of peak load with historical trend of DSM/DG programs. Note that the discussion above and Table 2 present the portion of this forecast applicable to San Francisco alone, while this table presents the forecast for San Francisco and the Peninsula north of Ravenswood Substation. Peninsula load peaks in summer (May-October).
b) Projected capacity at peak load of new energy efficiency, solar and other distributed generation resources in San Francisco as presented by the SFPUC and SFE at the 10/6/03 LFPFA meeting. Note that this 2003 projection is more conservative than the targets shown in Table 1 for these resources.
Two factors affect the accuracy of the resource adjustment to the load forecast. First, although PG&E’s forecast does not account for all of San Francisco’s projected new DSM/DG, it does account for some projected growth in these resources. Second, the projected DSM/DG resources may not be put in place in the amounts projected. Table 3 is based on a revised projection that is smaller than the targets for these resources in Table 1, however; the revised projection does not fully address these uncertainties.
The Load Forecasting and Power Flow Analysis work group was presented with the results of two power flow studies. One was conducted by ISO Operations Engineering and Grid Planning for the San Francisco Peninsula electrical system, defined as the area bounded by the Ravenswood substation near Palo Alto on the south, and including all of San Francisco and almost all of San Mateo County. The other was conducted by PG&E for the internal San Francisco 115 kv system assuming the installation of the Jefferson-Martin project and other transmission improvements.
The purpose of the ISO study was to improve the understanding of what mix of transmission and generation is needed to reliably serve the San Francisco Peninsula in the future. The ISO study presented its results in the form of “Load Serving Capability” (LSC). LSC is defined as the amount of electrical demand that can be served by the electrical transmission systems and available generation without violating a set of system performance standards. The ISO study examined 37 different cases, using different assumptions about the availability of specific transmission and generation resources.
Key conclusions of the ISO Power Flow Study are as follows:
1) The ability of the Jefferson-Martin 230 kv transmission project to contribute to the LSC of the San Francisco is limited by constraints south of the San Mateo substation and on the 115 kv underground cable system within the City of San Francisco.
2) Utilization of the Jefferson Martin project with a reduction in existing generation within San Francisco would require reinforcement of both the transmission system south of San Mateo and the 115kv cable system within San Francisco.
3) The San Francisco Peninsula Area LSC can be increased by completing each or some combination of the following:
a. Re-rating of existing transmission facilities through replacement of limiting components or assumption of higher wind speeds across specific transmission lines which would allow higher load of the lines.
b. Reinforcement of the transmission system through either reconductoring of existing lines, rearrangement of existing lines or cables, and/or building new lines or cables.
c. Proposed new generation capacity within the San Francisco Peninsula area.
The differences in load serving capability for various combinations of transmission and generation are summarized in Table 4 below.
Table 4.
Load serving capability for 36 combinations of transmission and generation, in
MW.a
|
SF
Generation Modeled On-Lineb |
0 |
100 |
150 |
200 |
230 |
280 |
320 |
|
Pre-base
Case Transmission system |
|
1591 |
|
|
|
|
1876 |
|
Base Case
Transmission system |
1316 |
1596 |
|
1850 |
1880 |
1921 |
1971 |
|
Base Case
& South of San Mateo Re-rates |
|
|
1731 |
1850 |
1880 |
|
|
|
Base Case,
SM re-rates & New S.F. cables |
|
|
1811 |
1860 |
1890 |
|
|
|
Jefferson-Martin
Project |
1271 |
1376 |
|
|
|
1561 |
1601 |
|
Jefferson-Martin
& New SF cables |
1266 |
1376 |
|
|
|
1556 |
1596 |
|
Jefferson-Martin
& SM Re-rates |
1271 |
1536 |
1666 |
1770 |
1850 |
1996 |
2081 |
|
Jefferson-Martin,
SM Re-rates & New SF cables |
1976 |
2101 |
2106 |
2208 |
2213 |
2271c |
2291d |
NOTES: a) Results from modeling of 36 cases reported by the CAISO in the San Francisco Peninsula Load Serving Capability Study and ISO staff’s 9/8/03, 12/3/03 and 2/17/04 reports to the Load Forecasting and Power Flow Analysis Group. Results shown are for the Peninsula electrical system north of Ravenswood Substation (near Palo Alto).
b) Generation modeled on line is generation interconnected at the Hunters Point and Potrero substations assuming that the largest available unit and one 50 MW combustion turbine are off line pursuant to ISO grid reliability planning criteria. For example, if only Potrero power plant units 3-6 are available (360 MW is available after Hunters Point plant shutdown), Potrero Unit 3 and one CT are modeled off line, and 100 MW is modeled on line. Similarly, if Potrero 3-6 and Hunters Point units 1 and 4 are available (580 MW available), Potrero 3 and one CT are modeled off line, and 320 MW is modeled on line. ISO states that available generation should be taken into account for meeting additional operational requirements.
c) This
result assumes that an in-city limitation will be addressed by emergency
ratings or by additional in-city transmission reinforcement. If this limitation
is not addressed the load serving capability is 2,136 MW.
d) This result
assumes that an in-city limitation will be addressed by emergency ratings or by
additional in-city transmission reinforcement. If this limitation is not
addressed the load serving capability is 2,121 MW.
It is noteworthy that the Jefferson-Martin project, by itself, decreases load-serving capability on the San Francisco Peninsula. Even with the south of San Mateo re-rates; LSC is degraded, in the cases with less than 230 megawatts of generation on line. To realize the benefit of Jefferson-Martin it is also necessary to complete additions to the 115 kV transmission system within San Francisco.
In response to this finding that the Jefferson-Martin project could worsen load-serving capability on the San Francisco peninsula, PG&E conducted its own power flow study.[17]
That study examined the 13 cables that constitute the internal 115 kv transmission system in San Francisco. The study assumed that in 2006 the Jefferson-Martin project would be completed and that six additional transmission enhancements would also be finished.[18] The study stated that PG&E had investigated the feasibility of using higher emergency ratings for its 115 kv cables in San Francisco and found it to be feasible. The City and County of San Francisco has questioned this finding and expressed its concern to PG&E and the ISO that these re-rates in older cables could jeopardize reliability of electric service in San Francisco.[19]
The PG&E study examined four potential new additions to the 115 kv transmission system in San Francisco separately and in combination.[20] The study found that the Martin to Hunters Point cable and the Martin to Mission cable increased LSC in San Francisco by the greatest amount after the retirement of the Hunters Point Power Plant. PG&E has proposed building the Martin to Hunters Point cable, but still needs to prepare environmental analysis and go through a permitting process before construction, suggesting that this project might not be completed before 2007 or 2008.
The power flow analysis discussed above examines the capability of the electric transmission and generation system to serve load during normal conditions.[21] To assure reliability it is also necessary to examine specific “abnormal” conditions when transmission lines or substations are taken out of service for maintenance, repair or upgrade. ISO operations staff routinely turns on generation in San Francisco when maintenance or repair is needed on transmission lines or at substations within San Francisco or on the Peninsula north of the San Mateo substation. Typically, sufficient generation is turned on during each of these conditions to prevent shedding of load if other transmission resources are forced out of service.
The ISO expects that 400 megawatts of generation will need to be available north of San Mateo in 2006 after the completion of the Jefferson-Martin transmission line to allow for typical San Mateo Substation wash conditions.[22]
The operational analysis used to determine the need for power generation during planned maintenance, repair and upgrade differs from the power flow analysis during normal conditions in three important ways. First, the power flow analysis discussed above assumes the outage of one power line during normal conditions. In contrast, operational analysis examines the loss of more than one power line during “abnormal” conditions (such as one line going out unexpectedly while another is out of service for maintenance).
Second, operational analysis assumes that generation will be available and turned on during planned outages of transmission equipment. The power flow analyses during normal conditions assume some generation is unavailable because of forced outages.
This means that in addition to looking at how much generation is left on line after assumed outages during normal conditions, it is also necessary to look at how much total generation is available to address operational constraints.
Third, the LFPFA has not yet completed its analysis of operational issues. For example, the work group has not completed analysis of the following questions that have been raised by some group members:
What are the critical system components that, when out of service for maintenance or repair, require generation to be turned on?
When these critical components are out of service, what are the potential transmission outages that additional generation is needed to protect against, and what is the probability that these next contingencies will occur?
What technically feasible alternatives, such as scheduling line washes during periods of lower expected load, or equipment changes, could reduce the need for generation during the times when these components are out of service?
What are the costs of these alternatives?
What are the environmental and environmental justice implications of the alternatives?
Some work group members believe that it may be feasible to reduce the operational need for in-city generation to a level substantially smaller than 400 megawatts.
Operational constraints could impact the renewal of reliability-must-run contracts for existing power plants such as Potrero Unit 3. ISO planning staff indicates that ISO’s operations staff has input on the analysis of RMR designations and schedules. Operational issues may become increasingly important to determining when the closure of Potrero Unit 3 can occur.
Table 5 gives examples of how the results can be used to assess power system options.
Table 5.
Examples of reliability analysis for San Francisco and the Peninsula using the
resource scenarios, peak load forecast and power flow results reported above,
in MW.
|
1. Load
Forecast: |
2005 |
2006 |
2008 |
2010 |
2012 |
|
PG&E
2002 Load Forecast for San Francisco and the Peninsula |
1915 |
1949 |
2005 |
2050 |
2092 |
|
New
efficiency, solar and other DG (DSM/DG) projected in SF |
29 |
48 |
91 |
140 |
192 |
|
Adjusted
peak load forecast for San Francisco and the Peninsula |
1886 |
1901 |
1914 |
1910 |
1900 |
|
2. Add
City-sponsored CTs; close Hunters Point plant |
|
|
|
|
|
|
Load
serving capability assuming only the City-sponsored CTs are added and Hunters
Point units 1 and 4 are shut down |
1920 |
1920 |
1920 |
1920 |
1920 |
|
Projected
reliability margin for contingencies in normal conditions |
+35 |
+20 |
+7 |
+11 |
+21 |
|
In-city
generation available to address operational constraints |
540 |
540 |
540 |
540 |
540 |
|
3. Add
City CTs & all transmission; close Hunters Pt & Potrero 3-5 |
|
|
|
|
|
|
Load
serving capability assuming the City-sponsored CTs, Jefferson-Martin, SM
Re-rates & New SF cables are added & that Hunters Pt. 1 & 4 and
Potrero units 3-5 are shut down |
NA |
NA |
2100 |
2100 |
2100 |
|
Projected
reliability margin for contingencies in normal conditions |
|
|
+187 |
+191 |
+201 |
|
In-city
generation available to address operational constraints |
|
|
230 |
230 |
230 |
|
4. Add all
transmission; close Hunters Pt; no City-sponsored CTs |
|
|
|
|
|
|
Load
serving capability assuming only the Jefferson-Martin, SM Re-rates & New
SF cables added & Hunters Pt. 1 & 4 shut down |
NA |
NA |
2100 |
2100 |
2100 |
|
Projected
reliability margin for contingencies in normal conditions |
|
|
+187 |
+191 |
+201 |
|
In-city
generation available to address operational constraints |
|
|
360 |
360 |
360 |
NOTES: Based on Potrero Unit 3 capacity of 210MW and Hunters Point 4 (170 MW), Hunters Pt 1 and Potrero 4-6 (50 MW each), and 4 City-sponsored CTs (45 MW each). DSM/DG, load forecast and load serving capability projections are from tables 3 and 4. Load serving and generation results rounded to reflect accuracy.
Part 1 of Table 5 shows the effect of projected new DSM/DG on the peak load forecast. Parts 2, 3 and 4 compare power flow results from three of the 36 cases in Table 4 with this forecast, and show the total amount of generation that could be available to address operational needs for each particular combination of DSM/DG, transmission and generation. These three cases are presented as examples of the range of resource combinations that can be assessed using the results in tables 3 and 4, and the limitations of these assessments given the uncertainties discussed above.
Part 2 of Table 5 assumes that all Hunters Point generation is shut down, the additional DSM/DG projected in Table 3 is put in place (and is not already counted in PG&E’s forecast), and the only addition to the Base Case power system is the City-sponsored combustion turbines. The results in Table 5 suggest that with these assumptions, the system meets reliability criteria during normal conditions through 2012, and more than 400 megawatts of generation is available for operational needs. However, the reliability margin during normal conditions is small, given the load forecast’s uncertainty due to possible near-term load growth, especially if the projected DSM/DG is not put in place.
Part 3 assumes the City-sponsored CTs, Jefferson-Martin, SM Re-rate and New SF Cable projects are added to the system and all existing Hunters Point and Potrero generation is shut down except for one existing Potrero CT. With these assumptions the system meets reliability criteria during normal conditions by a wider margin than the uncertainty in the load forecast. However, the generation available is less than the 400 megawatts ISO asserts is needed for operational reliability of the system, and the New SF Cables may not be in place before 2007 or 2008.
Part 4 of Table 5 assumes the Jefferson-Martin, SM Re-rate and New SF Cable projects are added to the system, all existing Hunters Point generation is shut down, and no new power plants are added north of San Mateo. With these assumptions the system meets reliability criteria during normal conditions by a wider margin than the uncertainty in the load forecast, but available generation is less than 400 MW, and the SF Cables may not be in place before 2007-2008.
Barry R. Flynn, Flynn RCI; (925) 634-7500; Brflynn@flynnrci.com.
Francisco DaCosta, EJA; (415) 822-9602; Frandacosta@att.net.
Don Smith, CPUC/ORA; Dsh@cpuc.ca.gov.
Julie Gill, ISO; (916) 351-2221; Jgill@caiso.com.
Andrew Bozeman, SESCDC; (415) 822-2522; Andrew@heavensglade.com.
Larry Tobias, ISO; (916) 608-5763; Ltobias@caiso.com.
Manho Yeung, PG&E; (415) 973-7649; Mxy6@pge.com
Meeting convened by co-chairs Greg Karras (CBE; 510-302-0430 x206; Gkarras@cbecal.org) and Ed Smeloff (SFPUC; 415-554-0763; Esmeloff@sfwater.org).
[1] The LFPFA is a technical working group that includes representatives from community-based groups, the San Francisco Public Utilities Commission (SFPUC), PG&E, ISO, and other local and state agencies. The LFPFA has held 12 meetings since it was convened. An attendance list for the January 27, 2004 LFPFA meeting is attached.
[2] At the time Mirant Potrero LLC was proposing to build a 540 megawatt combined cycle power plant at the existing Potrero Power Station.
[3] Agreement between the City and County of San Francisco and Pacific Gas and Electric Company to Close Hunters Point Power Plant, July 9, 1998.
[4] Ordinance 124-01
[5] Resolution 827-02
[6] 2003 Emission Inventory, California Air Resources Board (www.arb.ca.gov).
[7] Electricity Resource Plan, City and County of San Francisco. Page 3.
[8] The ERP envisioned the siting of new efficient and flexible generation by the summer of 2004 that would allow for the closure of Hunters Point Unit 4 by the end of 2004. Currently new generation could be completed, under favorable circumstances, by the end of 2005 or early 2006.
[9] Mirant and the ISO have reached an agreement that would allow the retrofit of Potrero Unit 3 with selective catalytic reduction equipment to reduce emissions of nitrogen oxides and allow for the recovery of the cost of this equipment over five years.
[10] The forecast for the 2001 Transmission Expansion Plan was produced by PG&E in December, 2000. Load growth for each geographical division in the PG&E service area is developed by PG&E distribution planning and is determined by allocating total system load growth to each division based on non-simultaneous transmission bus levels.
[11] The ERP assumed the following: 50 percent of the solar installations would be funded by CCSF and 50 percent by private investors (e.g. homeowners, commercial property owners); 30 percent of distributed generation would be funded by CCSF and 70 percent by private investors; 25 percent of commercial energy efficiency measures would be funded by PG&E and 75 percent by commercial property owners, 25 percent of residential energy efficiency measures would be funded by PG&E, 25 percent by CCSF and 50 percent by residential property owners.
[12] These reports can be found at www.energy.ca.gov/energypolicy/documents/index.html.
[13] Communication from Lynn Marshall, Demand Flow Analysis Office, CEC to the Power Flow and Load Forecasting Working Group, October 6, 2003
[14] Appendix 4 to the 2002 PG&E [NOTE INCOMPLETE CITATION]
[15] Peak demand for electricity in 2000 for San Francisco was 950 megawatts. Subsequently, there has been a substantial increase in vacancies in commercial office and retail space in San Francisco.
[16] The load temperature sensitivity factor used by PG&E in load forecasting for San Francisco is 0.4 percent per degree Fahrenheit.
[17] San Francisco Internal Transmission System After AP-1 Technical Study, August 6, 2003.
[18] Newark-Ravenswood rerate, Ravenswood-San Mateo rerate, Tesla-Newark upgrade, Ravenswood 230/115 kv transformer, San Mateo-Martin No. 4 Line 60kv to 115kv conversion, Potrero-Hunters Point Underground cable.
[19] Correspondence from Barry Flynn representing CCSF to PG&E, July 21, 2003
[20] Potrero to Mission Number 2 Cable, Martin to Mission Cable, Potrero to Martin Cable and Martin to Hunters Point Cable.
[21] In planning for electric system reliability it is assumed the system will be robust enough to withstand specified contingencies. In the case of the San Francisco Bay Area the assumption is that reliability of electric service can be maintained when the largest transmission lines fails and the largest generator in the City is off line and one of the old diesel-fired peaking plants fails to start.
[22] Based on the assumption that San Mateo washes occur during weekends when San Francisco load could be as high as 750 megawatts. See letter of October 22, 2003 from Terry Winter to Sophie Maxwell.