Comments on Draft Decision
The draft decision of the ALJ in this matter was mailed to the parties in accordance with Section (311(g)(1) of the Public Utilities Code and Rule 77.7 of the Rules of Practice and Procedure. Comments were filed on March 1, 2001 by the City and County of San Francisco, ISO, ORA, PG&E, Ridgetop, SCE and SDG&E. Based on those comments, we have made several editorial changes, clarifications and minor corrections to staff'' report (Attachment 1). However, we do not make substantive changes to the recommendations contained in the staff report, with two exceptions. In light of comments by the ISO and SCE, it appears that the Victerville-Lugo upgrade (Project #31 in the draft decision) cannot be built by summer 2001, and may involve additional costs to the Los Angeles Department of Water and Power. In Addition, the Cortina-Colusa upgrade (Project #25 in the draft decision) will not be completed until 2002. As a result, we have removed them from the list of Phase 1 upgrades, but may consider them further during Phase 2. We also clarify that utilities are to file Advice Letters to increase their distribution revenue requirements, without modifying current rates, to reflect the costs of the upgrades authorized today, consistent with the language of AB 970.
The staff recommendations for transmission upgrades presented in Attachment 1, as summarized in Table 2, are reasonable and necessary improvements to the utilities' transmission systems.
1. The transmission projects listed in Table 2 are high priority candidates for relieving transmission constraints on the electric system by summer, 2001. The utilities should proceed expeditiously with their implementation.
2. The utilities should continue submitting monthly status reports on these transmission projects as well as interconnections with new generation facilities.
3. In order to proceed with needed transmission upgrades as expeditiously as possible, this order should be effective today.
INTERIM ORDER
IT IS ORDERED that:
1. Pacific Gas and Electric Company, San Diego Gas & Electric Company and Southern California Edison Company, collectively referred to as "the utilities" shall develop the transmission projects recommended by staff and listed in Table 2.
2. The utilities shall file monthly status report on the transmission upgrade projects included in their filings and in Table 2. For each project, the report shall include information on the status of the notice of construction, if applicable, and the status of construction. The report shall also include information on whether a completed transmission upgrade project has resolved the transmission constraint it was intended to address. In addition, as discussed in this decision, the utilities shall report progress on remedial action schemes taken to improve transmission access and the system's ability to meet electricity demands. With regard to the generation projects that are underway in response to the Independent System Operator's solicitation, the monthly reports shall also include status information regarding the completion of interconnection studies and whether the projects involve utility-constructed facilities that would need to come before the California Public Utilities Commission (Commission). The reports shall be filed with the Commission's Docket Office on the first of each month, and be served on all appearances and the state service list in this proceeding. The utilities shall continue this monthly reporting until December 31, 2001, unless otherwise directed by the Assigned Commissioner or Administrative Law Judge.
3. As discussed in this decision, the utilities shall increase their distribution revenue requirements, without modifying current rates, to reflect the costs of the upgrades authorized today by filing Advice Letters for this purpose. The Advice Letters shall be filed within 30 days of the effective date of today's decision, and copies shall be served on all appearances and the state service list in this proceeding.
This order is effective today.
Dated , at San Francisco, California.
Attachment 1
RELIEVING TRANSMISSION CONSTRAINTS
An Overview in Response to AB 970
Energy Division
California Public Utilities Commission
March 12, 2001
CONTENTS
Executive Summary
Background
Short-Term Transmission System Constraints and Projects
Long-Term System Constraints and Projects
Tables and Maps
Appendix A How the Transmission / Distribution System Operates
Appendix B Methodology /Limitations of this Report
Appendix C Constraint Summaries
Appendix D Project Summaries
Appendix E Electrical Glossary EXECUTIVE SUMMARY
AB 970 requires the California Public Utilities Commission to identify constraints in California's transmission and distribution system and to take actions to remove them.
This report identifies constraints, and utility projects underway or planned to mitigate them either by 2001 or between 2002-2005.*
This report identifies 51 constraints on California's transmission and distribution system that either exist now, or will exist by summer 2001. This report also identifies an additional 107 constraints that will affect the system's reliability from 2002 to 2005.
This report recommends that in year 2001, utilities should complete 31 projects, costing $120 million, to address 38 of the 51 constraints. Twenty-seven of these projects should be completed by summer 2001. (The other four have later completion dates.) These projects increase system capacity to allow more energy to flow to consumers, improve system reliability by making the system more stable, and/or allow access to a wider range of generation sources, some of which may supply cheaper power.
These projects increase capacity by more than 3,000 megawatts (MW). Benefits are not strictly additive, however, because most of the projects affect a specific local area rather than the system as a whole and relieving one constraint can shift power flows to other parts of the system that may become new constraints. On the other hand, many projects provide benefits, such as a reduced chance of outages or an improvement in local voltage, that are not measurable in megawatts. The benefits of individual projects, including capacity increases where relevant, are discussed in more detail in two sections of this report, Short-Term Transmission System Constraints and Projects and Long-Term System Constraints and Projects, and in Appendix D.
Most projects are on PG&E's transmission system. The extent to which the projects improve transmission system reliability will depend in part on demand for electricity, weather, and the amount of new generation added in California before summer 2001.
Currently, the state has no process for conducting comprehensive analysis of California's transmission and distribution system that considers costs and benefits of various options to improve reliability. Accordingly, this report recommends the Commission initiate a process for such analysis and recommends further study of several specific issues that will affect the state's transmission system in the longer term:
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* This report was originally released on February 13, 2001, and revised in response to comments.
· Whether relieving the congestion on lines that move power up and down the state is cost-effective. Current high prices and generation shortage appear to justify adding a third line on Path 15, the state's largest transmission corridor. However, by the time the line is completed, new generation is expected to be in place easing supply shortages. The Commission should analyze the costs and benefits of constructing a new line.
· Whether and how current transmission constraints on moving power to California customers should be alleviated to reduce the need for local generation, improve reliability, and/or improve competition statewide.
· How to assure that distribution substations can accommodate projected peak load growth from 2002-2005.
· Whether and when it is cost-effective to build the system to withstand unlikely equipment, and what options are available, considering reliability criteria issued by the ISO and the Western States Coordinating Council (WSCC)
· How increased regionalization of the transmission system in the western part of the United States, and changes in federal regulation, may affect the reliability and cost of operating California's transmission system.
BACKGROUND
Section 7 of AB 970 directs the California Public Utilities Commission (Commission) to identify and undertake actions necessary to reduce or remove constraints on the state's electrical transmission and distribution system:
399.15. Notwithstanding any other provision of law, within 180 days of the effective date of
this section, the commission, in consultation with the Independent System Operator, shall take all of the following actions, and shall include the reasonable costs involved in taking those actions in the distribution revenue requirements of utilities regulated by the commission, as appropriate:
(a)(1) Identify and undertake those actions necessary to reduce or remove constraints
on the state's existing electrical transmission and distribution system, including, but not limited to, reconductoring of transmission lines, the addition of capacitors to increase voltage, the reinforcement of existing transmission capacity, and the installation of new transformer banks. The commission shall, in consultation with the Independent System Operator, give first priority to those geographical regions where congestion reduces or impedes electrical transmission and supply.
(2) Consistent with the existing statutory authority of the commission, the commission
shall afford electrical corporations a reasonable opportunity to fully recover costs it determines are reasonable and prudent to plan, finance, construct, operate, and maintain any facilities under its jurisdiction required by this section...
In addition, Section 4 of AB 970 allows air pollution control districts to issue expedited permits for power plants if: the power plant will be interconnected to the grid in a manner that the Public Utilities Commission, in consultation with the Electricity Oversight Board, has determined will allow the power plant to provide service to a geographical area of the state that is urgently in need of generation in order to provide reliable electric service.
To comply with AB 970, this report:
· identifies constraints on California's transmission system that exist now or will appear by 2005.
· evaluates specific transmission projects that can relieve those constraints for summer 2001.
· identifies projects designed to relieve constraints planned for completion 2002-2005.
This report relies primarily on existing utility and Independent System Operator reports.
It is a first step toward an integrated approach to analyzing transmission system constraints, and ways to relieve them. This type of analysis is critical as the transmission and distribution system age, electricity demand increases, and responsibility for system planning and integrity has become less clear due to changes in regulation and law.
Data collection and analysis of long-term projects will continue over the next few months.
SHORT TERM TRANSMISSION SYSTEM
CONSTRAINTS AND PROJECTS
Table 1 shows the 51 constraints that will appear on California's transmission and distribution system by summer 2001.
To relieve system constraints by summer 2001, this report recommends that utilities complete 27 of the 31 projects (Table 2) recommended for 2001, most of which are already underway to address 38 constraints. Three of the remaining 4 projects are targeted to address winter peaks, while the last one is targeted for an early 2002 in-service date, but may be pushed up to late 2001.
The constraints identified in this report are based on studies and data from the ISO and the utilities. These studies estimate likely power flows during peak hours, and identify which parts of the system will overload or cause instability in the case of contingencies. Table 1 describes constraints for 2001. These constraints fall into five categories: bulk power constraints, RMR constraints, stability constraints, normal overloads, and contingency overloads, and are described in more detail in the following section Long Term System Constraints, Projects, and Recommendations.2
Short Term Constraints
PG&E Territory
All but 5 of the 31 recommended projects are to reduce or remove the normal overload, stability, RMR, contingency, and economic transmission system constraints in PG&E's territory. Unlike SCE and SDG&E, PG&E's capital investment strategy has been to build local generation rather than transmission. PG&E cut back its infrastructure investments during the l990s and made limited investments in redundant distribution-related facilities. Therefore, many of PG&E's current projects were discussed internally years ago, but not built. PG&E has over the last three years doubled its transmission investment.
The ISO has identified several projects that will increase the redundancy of PG&E's system. While greater redundancy should improve system reliability, this report does not assess the cost-effectiveness of these projects or whether the investments would be better spent on other transmission projects or on distribution. This is an important issue for subsequent study.
SCE Territory
SCE spent more than PG&E on transmission, relied less on local generation, and more made investments on redundant system components to relieve stability and contingency constraints.
SDG&E Territory
SDG&E followed an intermediate strategy, depending on local generation, but making more investments in redundant system components to relieve contingency overload, and bulk power constraints.
Projects to be Completed by Summer 2001
There are 31 projects planned for 2001. The 27 projects planned for summer 2001 were either planned or under construction when this study began. Of the remaining 4 projects, all of which are PG&E projects, 3 are planned to meet the winter 2001 peak, and one is projected to be in-service in early 2002 but may be in-service by late 2001. Utilities cannot begin construction of additional projects now and complete them by summer 2001 because project construction requires 9-12 month lead times for equipment purchases and acquisition of rights-of-way; therefore, this report recommends only one addition to the projects proposed by the utilities and the ISO.3
Martin Substation
PG&E is planning to add a new bank of capacitors (Project 17 on Table 2), to the Martin Substation, through which power to San Francisco flows to relieve stability constraints.
Recommendation
As part of this work, PG&E should upgrade existing capacitors to increase capacity by 50%,4 allowing for both additional voltage support on transmission lines and increased power deliveries.
Path 15
Three constraints contributed to major reliability problems in the past year and are likely to continue to cause problems in 2001. Most important is Path 15 (see Map 1), the northern half of the link between Northern and Southern California,5 and the most congested of all major California transmission paths.6 While transmission north and south of this path consists of three parallel 500 KV lines, they connect with Path 15 which has only two 500 KV lines.
During December 2000 and January 2001, congestion repeatedly blocked transmission of critically needed power from southern California --which had extra power-- to Northern California --which needed power. Path 15 constraints were a major cause of the rolling blackouts in Northern California during this period.
The ISO recently increased Path 15 capacity by 300 MW by changing operating procedures. The ISO recently approved PG&E's initiation of environmental studies and permit acquisition work that could lead to construction of a third 500kV transmission line between Los Banos and Gates Substation.
Recommendation
A new experimental monitoring technology (Project 26 - Table 2) now being tested by PG&E may also reduce this bulk power constraint. Transmission line capacity is calculated assuming poor conditions, for example, surrounding air is still and surrounding air temperatures are high.7 This new technology measures line tension (which reflects air temperature, line current, and wind speed) along the transmission path, and may allow increased power flows on all days except those that are exceptionally hot and still.
Bay Area
Constraints on imports into the Bay Area contributed to the rolling blackouts there on June 14, 2000, when voltage dropped precipitously at a major Bay Area substation. Ten projects for 2001,8 including new and upgraded transmission lines, transformers, and capacitors and other equipment, will improve service to and within the Bay Area, and partly relieve the constraints in the Bay Area.
In addition, two new generating plants are scheduled to begin operation in the Bay Area during the summer, adding a total of 545 MW.9
South San Jose
PG&E proposes a project for solving longer term distribution normal overload constraints. The Coyote Valley Project for south San Jose is to service additional load growth, primarily from Cisco Systems' campus. It was originally targeted for completion by June 2001, then pushed out to December 2001, and now targeted for February 2002. A quicker resolution of issues causing the delays could bring this project back into year 2001.
Recommendation
PG&E should have the substation ready as the load materializes.
Lodi/Stockton / Humboldt / San Diego
In addition to these transmission improvements in the Bay Area, other projects for 2001 will relieve RMR constraints in the Lodi/Stockton, Humboldt, and San Diego RMR areas.
Fresno Area
PG&E's Pinedale project would serve growth northeast of Fresno. The current load is served from an area distribution substation that has reached its maximum capacity. Target date for completion is June 2001.
Recommendation
PG&E should complete this substation.
Path 26
Path 26 completes the link between Northern and Southern California. Power flows from the north to the south were blocked during the summer of 2000 causing many emergency alerts, but no rolling blackouts. One small project on Path 26 will increase transmission capacity from 2800 MW to 3000 MW.10
Recommendation: SCE should complete this project.
LONG TERM CONSTRAINTS AND PROJECTS
Table 3 shows 107 system problems that will affect the transmission and distribution system between 2002 and 2005.
From 2002-2005, utilities are considering 90 projects (Table 4) to address 99 of the 2002-2005 constraints. As part of ongoing Investigation 00-11-001, the Commission will review these projects and other solutions to these constraints.
Bulk power constraints
There are bulk power constraints on eight high-voltage, congested transmission paths that tie regions of California to each other or to other states. Congestion results in California utilities losing access to cheaper sources of power, and increases their operating costs (see Project Summaries Appendix). Further, when available capacity from other paths or from local generation is unavailable, these constraints can threaten the ISO's ability to maintain or access operating reserves.11 This forces the ISO to order rotating outages for firm customers. Table 5 shows the percentage of time and how many hours various paths were congested last year.
Recommendation - Examine Feasibility of a third AC Line on Path 15
The ISO has stated that the costs of congestion and rotating outages in December 2000 and January 2001 suggest that it is now cost effective to remove the bottleneck on Path 15 by construction of a new AC line to supplement the two existing lines.12 PG&E estimates the new line would cost $200 million. CPUC Energy staff supports the ISO study of feasibility of this new line.
Construction of new transmission lines is costly and may have environmental consequences. In addition, what is constructed in California could have adverse impacts on transmission in other states because of the interconnection of the system. For these reasons, decision-makers need to approach system planning by considering the impact of new generation resources on the cost-effectiveness of transmission system upgrades.
There are 25 new power plants are in various stages of planning and construction California (Map 2). To the extent new generation reduces wholesale market prices, the cost effectiveness of relieving bulk power constraints will decrease. The recent volatility of wholesale electricity markets, however, suggests that relieving constraints on major transmission paths is an economic insurance policy.
Recommendation
Energy conservation efforts may also relieve market uncertainty and be more cost-effective than major new transmission projects. This matter deserves further, more detailed study.
Reliability Must Run (RMR) Constraints
While the impact of RMR constraints is limited to smaller areas than Bulk Power constraints, RMR constraints may cause cascading outages.
There are ten groups of congested high or medium voltage transmission paths, each serving an RMR load center (see Map 3). The ISO signs contracts with generators in these areas to assure the availability of local generation at a specified price.13 The impacts of RMR constraints are similar to those of bulk power constraints, though smaller areas are affected.14 For example, on June 14, a combination of high demand caused by record high temperatures and plant outages in the Bay Area (an RMR area), forced the ISO to order PG&E to drop firm electricity customers.
All three utilities plan at least one project to reduce RMR constraints from 2002-2005.
SCE proposes one to eliminate its only RMR constraint. SDG&E plans the following RMR improvements during 2002-2005: the new Valley Rainbow transmission line, the new Miguel-Mission Line, and new transformers at the Sycamore Canyon substation.
PG&E classified 5 projects as RMR Projects. The ISO approved 2 of them as RMR (Lodi-City of Lodi Area Reinforcement, and Eight-Mile Road). The ISO classified the other 3 projects (Metcalf 500kV Shunt Capacitors, Bridgeville-Cottonwood, and Janes Creek Modification) as stability (reliability) projects.
The most severe RMR constraints are in PG&E's territory because it has historically relied heavily on local generation, rather than on strong transmission links. PG&E has plans to further reduce RMR constraints and have incorporated these plans into its annual electric grid expansion plan.
Recommendation
Upgrading California's transmission system so that it can move power to and from any part of the state may improve the operational efficiency and reliability of the system, reducing reliance on local and regional generation resources. Since neither the utilities nor the CPUC have analyzed the capital costs of such a strategy, this is a matter for additional study.
Stability Constraints
The ISO and utility studies identify a number of stability constraints in California. In general, they must be fixed according to WSCC criteria. Six projects15 address six constraints by summer 2001 (two of these projects also help mitigate the Bay Area's RMR constraint), and the utilities have identified six additional projects to address another six constraints during 2002-2005.
From 2002-2005, studies identify another 62 constraints. Of these 55 are addressed by projects.
Recommendation
The cost-effectiveness of investing in transmission upgrades to relieve these constraints or whether the ISO and utilities should seek exemptions from reliability criteria or institute other solutions merits further study.
Normal Overloads
Normal overloads generally do not threaten system stability, but can result in outages at particular distribution substations16 during peak periods when equipment reaches its thermal limits. Such overloads usually result from additional customer demand and are likely to occur even if all related equipment is operating normally. In some cases, these projects are the first phase of multi-phase distribution improvements. Considering the potential for repeated outages and the utility's obligation to serve customers, these projects are high priority and should be built.
Recommendation
Energy Division recommends that the utilities build 20 projects to relieve 21 expected overloads in summer, 2001.17 We have no recommendation on six projects for which PG&E submitted insufficient information. Studies show 30 additional overloads and projects to address them from 2002-2005, which should be examined in Phase II of I.00-11-001.
Contingency Overloads
Contingency overloads occur when nearby equipment fails during peak periods. Some contingency overloads threaten system stability. Such equipment failures can cut power supplies directly (if the only transformer serving a substation shuts down) or cause power to re-route itself and overload other equipment still in service (as when one of two transmission lines into a substation fail). Since equipment is in service most of the time, such overloads are much less likely than normal overloads, but can occasionally interrupt service to customers.
Transmission studies have identified three areas where overloads or frequency problems are expected in year 2001 if outage contingencies occur during peak periods. PG&E has proposed three projects18 to address these previously unsolved problems at a cost of about $19 million. The ISO has approved all three projects, and they are expected to be completed by summer 2001.
Recommendation
Looking forward, the Commission should consider whether contingency overloads should be lower priority than the other kinds of constraints identified. There are 49 additional overloads and projects to address them, in all three utility service territories, from 2002-2005. The Commission should consider whether these improvements are fully cost effective, as well as what alternatives are feasible, considering that the projects are driven by reliability criteria.
- (we call these bulk power constraints) and 10 RMR constraints, without defining those terms. (PG&E, SDG&E, and Edison did not provide a list of constraints as such.)
However, we found many more constraints implicit in Planning Assessment studies prepared by the utilities in the ISO's transmission planning process. We define constraints as those parts of the system that 1) will overload or cause instability according to planning studies or 2) were listed as economic constraints by the ISO.
- Canyon power projects) to the rest of PG&E's system. It consists of two high voltage transmission lines. Path 26 connects Path 15 to Southern California Edison's system (and the rest of Southern California.)
- In December, Path 15 was congested more than a third of the time.
- power transmission, in effect, minimizing power flows.
- MW, is scheduled to open July 1, 2000. United Golden Gate in San Mateo county, generating 45 MW, is scheduled to open in August 2000.
- essential communications equipment (wavetraps) if other transmission lines were to fail suddenly. Project 28 will install new, higher capacity wavetraps. In anticipation of this project, the ISO has already started operating the lines at 3000 MW. See the detailed project description in Appendix D for more details.
- power but which are on standby to meet increasing loads or to substitute for the failure of other generators or transmission lines.
- transmission system serving each of these areas can only meet a portion of the area's peak load. Therefore, to maintain voltage and frequency in the area, the ISO and PG&E must supply remaining load from local generation. Second, the generation market in the area is uncompetitive because there are too few generators (or owners). In response, the ISO signs "RMR contracts" with enough generators in the area to meet system loads. These contracts require owners to comply with ISO orders to supply capacity at a specified price.
- as it did for RMR areas. The ISO considered dependence on local generation to be a reliability problem. The ISO did not consider statewide capacity issues to be a reliability problem, perhaps because statewide supplies were supposed to be competitive. Further, signing enough contracts to meet peak needs (essentially most of the generators in the state) would have tied up nearly all available supplies and prevented that competition.
15 # 7, Oakhurst Area Reinforcement (Exchequer Powerhouse); # 20,Janes Creek-Humboldt
Modification Project; #17,Martin 115 kV Capacitor Project (which also improves the Bay Area's RMR constraint), and # 23,Tesla-Newark Transmission Reinforcement Project (which also improves the Bay Area's RMR constraint).
- distribution circuits that serve most consumers. They consist of banks of transformers and circuit breakers, along with other types of equipment.
17 Fulton 60 kV Line reinforcement Project; Coyote Valley Distribution Substation Project;
Moss Landing Circuit Breaker Upgrade; Kifer-Trimble (Nortech) Line Project; Paradise Area reinforcement Project; Newark 230/115 kV Bank TCAP Project; Ravenswood 230 kV Loop and Transformer Increase; Pittsburg-Tassajara 230 kV Reconductoring Project; Moss Landing 500/230 kV Transformer Increase Project; Woodward 21 kV Capacity Increase; Mountain View-Whisman 115 kV Loop; Brighton 230/115 kV Transformer Re-rate; Jefferson 230/60 kV Transformer Re-rate; Tesla Newark Reinforcement; Lakewood 115KV; Lockeford-Lodi 60 KV 8-Mile Loop; Tesla 500/230 KV transformer; Alamitos-Barre; and Rancho Santa Fe.
18 Grant-East Shore 115 kV Breaker Project; Lakewood Area Transmission Reinforcement
Project; and Metcalf-Monta Vista 230 kV Line Project.
