SOLUTIONS

· The new Escondido 230/69kV transformer project (BP99117) will increase SDG&E's import capability about 200MW, therefore solves the import shortage for 2001. This project also solves local reliability problem in the area Escondido Substation serves.

· The identified local constraint to serve Rancho Santa Fe Substation will be addressed by the reconductoring project (BP98187).

· There are two known generation developments in SDG&E's service territory. The 50MW Chula Vista Project is planned to be in-service by summer 2001. The 558MW Otay Mesa Project is currently pending a license from CEC and could be in-service by summer 2003. Other generation developments are at very preliminary stages, so they should not be counted at this time.

SDG&E transmission system will be able to import enough power to adequately serve its forecasted 2001 load if the import capability enhancement project is built on time. However, uncertainty exists on the availability of surplus generation resources outside SDG&E territory, which SDG&E has little control.

Section 4 - ECONOMIC CONSTRAINTS UNDER THE CONTROL OF THE CALIFORNIA ISO

The California ISO has identifies a few transmission line sections, or paths, which are economically constrained. In other words, there is congestion (power flow is limited) for these paths and there is economical consequence (cost) associated with the congestion. The power flows through these paths are limited due to either stability concern or thermal concerns of the transmission lines under either Normal conditions or Emergency contingencies.

Limited studies, if any, have been conducted to analyze in detail each of the paths identified here by either the California ISO or the utilities. Based on the limited information provided to the CPUC stuff, recommendation for possible solutions to correct congestion for each path was made whenever it is possible.

4.1 California-Oregon Intertie (COI_BG)

PROBLEM

Voltage Stability Problem following Palo Verde G-2, PDCI, or N-2 AC line outage contingency.

SOLUTION:

· Install 350 MVARs Capacitor Banks at Metcalf 500 kV Bus. (Project T-519) This project will eliminate the RMR contract and improve the congestion problem. Unfortunately, the ISO is currently unable to quantify the transmission capacity increase from this project.

· Completion of Klamath Falls 500 MW New Generation Project. This project is scheduled to be completed by July 2001. This generation facility is closer to the California border and will help to reduce the congestion problem of the California-Oregon Intertie. However, the ISO is currently unable to quantify the potential benefits of this new generation facility.

RECOMMENDATION

Completion of the Metcalf 500 kV Capacitor Banks Project (T-519).

4.2 Eldorado_BG

PROBLEM

The thermal limit of the Moenkopi-Eldorado 500 kV line is reached during the summer peaks. The capacity for this line is about 1550MW.

This section is part of the East of River or WSCC Path 49.

SOLUTION

· Need a new transmission line in order to reduce the congestion problem. This is a major project since a new line needs to be built. It probably will take 3 to 5 years to build another transmission line.

RECOMMENDATION

None.

4.3 Palo Verde_BG

PROBLEM

The Palo Verde-North Gila 500 kV line typically reaches its thermal limit between 5000MW to 6000 MW during the Summer peaking hours.

There are two lines: Palo Verde to North Gila and Palo Verde to Devers. These are part of the East of River Path (WSCC Path 49). For some unknown reason, the thermal limit of the Palo Verde to North Gila is always reached before that of Palo Verde to Devers.

SOLUTION

· Re-conductor the section between Palo Verde to North Gila. It probably will take 2 years to complete this re-conductor project.

· Use FACTS (Flexible AC Transmission Systems) to control the power flows between those two lines: Palo Verde to North Gila and Palo Verde to Devers. FACTS is a relative new technology. It relies upon power electronics devices to control the power flow between two substations. It is a viable option. The lead time for procuring the needed power electronics systems is about 2 to 3 years.

RECOMMENDATION

None.

4.4 Path 15_BG

PROBLEM

Congestion is caused by reactive margin in the PG&E and Idaho Power Systems following a South of Los Banos N-2 contingency.

This path is south of Los Banos, and is comprised of two 500 kV, four 230 kV, and several 70 kV lines.

SOLUTION

· The ISO is working with PG&E to find out the true reason for this congestion, possible solutions, cost of the congestion, and justification for implementing solution at this moment. They are not sure whether by installing capacitor bank the congestion problem can be solved or not.

RECOMMENDATION

None.

4.5 Path 26

PROBLEM

The thermal limit (3000 MW) of the Midway to Vincent No. 3 line will be reached during N-2 contingency (The outage of the other two lines: Midway-Vincent No. 1 and No. 2 lines).

There are three transmission lines: Midway Vincent Lines Nos. 1, 2, and 3. This path is WSCC Path 26.

SOLUTION

· Replace the Wavetrap installed at Vincent Substation No. 3 line with another Wavetrap which has a higher power rating to allow more power to flow through the Midway to Vincent Line No. 3.

RECOMMENDATION

The SCE should replace the wavetrap for line No. 3 at the Vincent substation to increase its rating to 3000 MW immediately.

4.6 Silver Peak, Summit, and IID-SCE

PROBLEM

The thermal limit of 40 miles PG&E's 115 kV transmission line west of Donner Summit will be reached if the Hydro unit in the Donner Summit area is producing power.

SOLUTION

· Re-conductor approximately 40 miles of 115 kV transmission line. This project, however, probably is not justifiable economically based on initial rough cost and congestion cost estimates.

RECOMMENDATION

None.

4.7 Sylmar-AC_BG

PROBLEM

The SCE's 220 kV system and LADWP's 230 kV system are joined together at the Sylmar substation. A 220 kV/230 kV transformer is used to connect two systems with slight different voltages together. The thermal limit of the 220 kV/230 kV transformer is causing the congestion at Sylmar substation.

SOLUTION

· Install a larger transformer

· Take the transformer out. Study conducted by ISO indicates that the system will be fine even without the transformer.

RECOMMENDATION

The SCE to replace the existing transformer with a larger transformer. This is a preferred option because there is always some concern about voltage increase from 220 kV to 230 kV in the SCE system, if the option of taking the transformer out is adopted. More engineering analyses need to be done before SCE is going to agree to the option of no transformer. Therefore, CPUC recommends to install a bigger transformer. The transformer used here could be autotransformer type, which is much cheaper than conventional transformers.

4.8 Mead_BG

PROBLEM

The actual power flow through Mead to Eldorado #1 and #2 230 kV lines and Mead to Camino E&W 230 kV lines does not equal to the scheduled values. The capacities of these 230 kV lines are not being utilized fully. This is because there is a 500 kV transmission line running parallel to these 230 kV lines. Power is flowing through the 500 kV line instead of 230 kV lines. Since no one can control where the power should flow among all possible lines without active control systems, there is no solution for this problem.

SOLUTION

None.

RECOMMENDATION

None.

Appendix D

PROJECT SUMMARIES

1. NORTECH (KIFER-TRIMBLE) (T010)

Recommendation:

Not enough information received from PG&E to determine course of action at this time.

Project Description (Scope):

Construct 115 kV line from Nortech toKifer substation including the addition of a 115 kV circuit breaker at Kifer. This part of the North San Jose Capacity Project.

The Problem:

The Kifer-Nortech line mitigates normal overload for outages. (No other details were provided by PG&E)

Cost and Benefits:

Cost: Under $1 million

¬ Part of the over $30 Million North San Jose Capacity Increase Project which has a December 2000 operational date.

Benefits:

Mitigates line thermal overload .

Environmental Impacts & Other Policy Issues (relation to other projects):

Unknown at this time

Alternatives Considered:

None

Technical Issues:

This project was held up by the City of Santa Clara as they negotiated relief on their transmission rates. This was part of the North San Jose Capacity Relief Project which has a December 2000 operational date. Now that Santa Clara has agreed to support this project, a new engineering and construction schedule has to be developed.

2. EIGHT MILE ROAD SUBSTATION 230VK LOOP PROJECT (T091)

Recommendation:

Order completion of the project, which would increase transmission import capacity to serve projected electric demand increase and cost effectively reduce reliance on RMR contracts affecting 20,000 customers or 50MW of load in the Stockton area for between $1 million and $10 million.

Project Description (Scope):

The 8 Mile Road Substation 230kV Loop Project provides the 8 Mile substation a loop line of the Lodi STIG-Stagg 230kV circuit, 3 new circuit breakers and protective relays. The project relieves low voltage condition and reduce reliance on RMR contracts with completion in June 15, 2001. This is a part of the proposed Stagg Area Voltage Support Project, referenced in PG&E ETSA Year 2001-05, dated 9/19/00, Attach3 p2 Diagram. Utility has not provided a Project Justification.

The Problem:

The CAISO in its 2001-03 RMR report identified reliability constraints primarily as low voltage in the Stagg 230kV circuit caused by a Stagg-Telsa 230kV line outage. In 1998, PG&E installed an under-voltage load shedding scheme of 50MW at Stagg substation to alleviate the low voltage problem. The ISO concluded that even with the load shedding scheme the Lodi STIG generating unit is still required for voltage support at Stagg substation.

Cost and Benefits:

Cost: between $1,000,000 to $10,000,000 which includes the following:

¬ Installs a loop circuit into 8 Mile Road substation

¬ Install 3 new 230kV circuit breakers, convert the bus from a loop to ring bus configuration

¬ Install protective relays

Benefits:

This project improves low voltage condition, eliminates reliance on the Lodi STIG to provide voltage support as well as eliminate the existing under-voltage load shedding scheme that could drop as many as 50MW load or about 20,000 customers until condition is relieved. No RMR cost benefit provided by Utility for this project.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal impact is anticipated. Utility did not provide any environmental impat studies for this project.

Alternatives Considered:

Status Quo, if not built, does not improve the low voltages in the area and the RMR current reliance continues on Lodi STIG generating unit to provide the voltage support even with the current load shedding scheme at Stagg substation.

Add more generation and add new T&D lines, this is an uncertain alternative and cannot rely on in the short term.

Technical Issues:

None provided by the utility.

3. PARADISE AREA REINFORCEMENT (T228)

Recommendation:

PG&E received a Permit-To-Construct (PTC) from the CPUC.

Project Description (Scope):

Paradise Area reinforcement with a June 2001 operation. (No other project detail from PG&E)

The Problem:

(No details were provided by PG&E)

Cost and Benefits:

Cost: No costs were submitted by PG&E, because they already have a PTC.

Benefits:

(No justification submitted by PG&E)

Environmental Impacts & Other Policy Issues (relation to other projects):

Alternatives Considered:

Technical Issues:

4. NEWARK 230/115KV BANK TCAP PROJECT (T239)

Recommendation:

Not enough information has been provided by the utility to recommend a course of action. This appears to be a study at this time and should most likely be done.

Project Description (Scope):

The Newark 230/115kV Bank TCAP re-rates banks 7, 9 and 11 for higher ratings to be done in June 2001. For each Transformer Bank will install SCADA for monitoring bank temperature and will replace fans, pumps and temperature devices. The objective is to increase the normal rating for Bank 7 and 9 and increase the emergency 1 hour rating for Bank 11. No project detail or justification was provided from Utility.

The Problem:

The Newark 230/115kV Transformer Bank Re-rate mitigates normal and emergency overload from outages. The increase or re-rating of banks is usually done to mitigate specific thermal overload concerns. No other details were provided by Utility.

Cost and Benefits:

Cost: estimated to be under $1 million

¬ Increases bank rating

Benefits:

Mitigates bank thermal overload preventing further outages and equipment degradation from heat.

Environmental Impacts & Other Policy Issues (relation to other projects):

Unknown at this time, no details provided by the utility.

Alternatives Considered:

Alternatives will be considered if re-rate project is not feasible other detail are unknown at this time.

Technical Issues:

Unknown

5. Jefferson 230/60 kV Bank Re-rate and SCADA Project (T-240)

Recommendation: Order PG&E to complete this project, which will re-rate the 230 kV/60 kV transformer bank at Jefferson Substation from 134 MVA to 160 MVA.

Project Description:

Install load and temperature monitoring equipment on Jefferson 230/60 kV Bank No. 1 to allow more power flow (from 134 MVA to 160 MVA) and upgrade other related protective equipment for the increased power flow to correct existing Normal overload during the peak load hours.

The Problem:

This problem is for transformer overload under the Normal condition during the peak load period.

The 230/60 kV transformer at Jefferson Substation is expected to overload by 5% (equivalent to 6.7 MW) during peak periods, even when all equipment is operating normally. This transformer is currently the only existing unit in the Jefferson Substation. Therefore, during peak periods it may be necessary to drop a minimum of 6.7 MW of load to avoid permanent damage of the transformer, which could result in extended blackout in the Peninsula area.

The rating of the Jefferson transformer bank can be re-rated by installing load and temperature monitoring system. Because there is no operator stationed at the Jefferson Substation, the proposed Supervisory Control and Data Acquisition (SCADA) allows operator stationed at the San Mateo Substation to monitor and control the Jefferson transformer on the real time basis to ensure the maximum reliability.

Costs and Benefits:

· Cost:

The project is estimated to cost under $1 million

· Benefit: over $3 million

By increasing the rating of transformer bank No. 1, it can avoid a minimum of 6.7 MW of load being dropped for a total 25.37 hours per year, based on 1999 Bay Area load duration curve. The probability of overload is 100% since transformer is overloaded during peak load period under the Normal system operating condition. Based on PG&E's Peninsula Value of Service ($/MWhr), the benefit of this proposed project is over $3 million in the first year. Thus this project is clearly cost effective.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. The proposed project has no adverse environmental impacts or EMF effects on customers.

Alternatives:

· Install another transformer bank at Jefferson substation. This alternative will cost over $5 million and it is not considered as economically attractive as the proposed rating increase of the existing transformer bank. However, PG&E is evaluating the need for a second bank to address reliability concerns should the existing transformer become unavailable.

Status:

· Engineering Works was finished on 10-13-2000.

· Long Lead Time Materials Procurement was finished on 10-1-2000.

· Substation Relay work started on 11-14-2000.

· Test & Energize New Equipment started on 11-14-2000 and will be completed by 1-13-2001.

· Estimated In Service Date: 01-13-2001

Technical Issues:

The 230/60 kV transformer bank in Jefferson substation experiences a 5% overload during the Normal peak loading period. If the problem is not corrected by either increasing transformer's rating or installing another transformer bank, PG&E has to drop loads during the peak load period to prevent permanent transformer damage.

· Existing transformer bank was installed in 1963 and has a nameplate rating of 134.4 MVA. There is no operator stationed in this substation.

· Power Flow studies of the forecast peak load indicates that Jefferson Transformer bank No. 1 will be overloaded by 5% under the Normal peak loading period.

· Since there is no operator on site at the Jefferson Substation, when overload happens, alarm signal will be sent to operators in San Mateo substation. No real time data is available to operators to check how critical the overload is without travelling to Jefferson Substation to assess the situation. The reaction time might be as long as several hours.

· Rating increase is feasible through installation of SCADA load and temperature monitoring on Jefferson transformer bank No. 1. SCADA system will allow operators to obtain real time load and temperature information during normal, overload, and emergency conditions so they can conduct load dropping switching scheme to protect transformer from being damaged.

· Some current transformers used with the load side circuit breakers are also overloaded during the Normal peak loading period right now, upgrade on those overloaded current transformer is also necessary in order to make sure the rating increase of Jefferson transformer bank can be realized.

6. Woodward 21 kV Area Capacity Increase (T-351)

Recommendation: Order completion of the project, which adds an additional 19.8 MW of electric capacity into the Woodward Planning Area to serve existing and future loads until the summer of 2002.

Project Description (Scope):

· Build a new Pinedale Substation.

· Install a 45 MVA, 115/21 kV transformer at Pinedale Substation Bank #1.

· Install a distribution feeder at new Pinedale Substation Bank #1.

· Install a 115 kV tapline to serve the new Pinedale Substation.

· Install automatic load dropping scheme at Bullard.

The Problem:

The Woodward Distribution Planning Area (DPA) has an annual growth rate of 11.22 MW. Based on this growth rate, the Woodward area load is projected to exceed the available capacity of 255.4 MW by 10.9 MW (4.3%) in the summer of 2001.

Specifically:

· The Bullard Substation Bank #1 is projected to be loaded to 102% of normal capacity during the 2001 summer peak load period.

· The Woodward Substation Bank #1 is projected to be loaded to 103% of its normal capacity during the summer peak load period.

· The Woodward Substation Bank #2 is projected to be loaded to 101% of its normal capacity during the 2001 summer peak load period.

· From past history, over 26,000 customers would be affected by outages on these lines.

Costs and Benefits:

· Benefit - Adds 19.8 MW of normal capacity in 2001 to the Woodward DPA. It will provide sufficient normal capacity to serve existing and future loads in the DPA through the summer of 2002. Also, in the event of the failure of the Clovis Substation Bank #3 during the 2001 summer peak load period, the proposed installation will reduce the 34.7 MW emergency deficiency to 13.5 MW.

· Cost -Total cost of this project is expected to be under $5 million.

Alternatives:

· Status Quo - Not acceptable since it would overload equipment, reduce its service life and increase the chances of customer outages.

· Alternative #1 -

o Install a 45 MVA 115/21 kV transformer at the existing Bullard Substation.

o Install a distribution feeder at Bullard Substation Bank #4.

o Install automatic load dropping scheme at Bullard Substation.

Alternative #1 was not chosen because the net present value of cash flow for this alternative is under $500,000. The net present value of cash flow for the project proposed is over $1 million.

Environmental Impacts & Other Policy Issues (relation to other projects):

· The Notice of Construction (NOC) has been filed and accepted by the CPUC (approved mid year 2000).

· An environmental assessment of the site was completed.

· Electric and magnetic fields (EMF) concerns are not expected to be an issue in this area. A plan will be developed to inform nearby business of the project and address any concerns that they my have. In addition, the potential EMF effects will be considered in accordance to the Substation EMF Design Guidelines.

Status:

· PG&E has approved the project, including job estimates.

· Grading and foundation work is underway and will be complete in 2000.

· Project is expected to be complete by May 1, 2001.

Technical Issues:

This project proposes to install an automatic load dropping scheme to relieve the emergency thermal overload after the loss of either one of the Herndon #1 and #2 115 kV lines. The current plan is to transfer loads to the neighboring Woodward, Figarden and Clovis substations after the single transmission line outage. The existing distribution feeders at Bullard and Pinedale have the capacity to transfer about 46.5 MW of load. It would take about 5-1/2 hours to perform distribution switching. From past history of outages on these lines, 26,240 customers would be affected. The PG&E benefits-to-cost ratio analysis concluded that the transmission system should be reinforced by 2005 to mitigate the emergency deficiency. The benefit-to-cost ratio exceeds 1.0 in 2005 when the transmission system is to be reinforced.

7. Oakhurst Area Reinforcement (T362)

Recommendation: Order completion of the project in time for Winter 2001, which separates an existing circuit into two circuits in 2001. The second phase of the project, which reconductors two 115kV lines in 2003, should be revisited at a later date to see if the anticipated overloads would still pose a problem.

Project Description (Scope):

· Located in PG&E's Yosemite Division.

· This project upgrades the 115kV facilities near the Kerckhoff II Powerhouse.

· Phase I - By November 2001, separate the Kerckhoff I-Kerckhoff II 115kV line into two separate circuits, and install circuit breakers at each.

· Phase II - By June 2003, reconductor the Kerckhoff I-Kerckhoff II 115 kV lines (1.5 miles) and reconductor the Oakhurst Junction-Kerckhoff II 115kV line (7 miles).

The Problem:

· The two 115kV circuits between Kerckhoff I and Kerckhoff II powerhouses are operated as a single unit. An outage of either circuit would cause both circuits to be unavailable. Such a simultaneous outage of the Kerckhoff I-Kerckhoff II line (such as those caused by winter conditions in this area) could result in major voltage deficiencies (stability problems).

· The Kerckhoff I-Kerckhoff II and Oakhurst Junction-Kerckhoff II lines are projected to experience normal overloads by 2003.

· An outage of Exchequer Powerhouse would result in 16% overloads by 2003 on the Kerckhoff I-Kerckhoff II and Oakhurst Junction-Kerckhoff II lines.

Costs and Benefits:

· Cost - The total cost for both phases of this project is expected to be between $3 million and $5 million.

· Benefit - Separating the Kerckhoff I-Kerckhoff II 115kV line into 2 different circuits reduces the risk of an outage caused by a single incident, that could lead to stability problems (major voltage deficiencies). PG&E indicates that reconductoring the Kerckhoff I-Kerckhoff II and Oakhurst Junction-Kerckhoff II 115kV lines relieve projected normal and emergency overload conditions.

Alternatives:

· Alternative #1: Status Quo. Not acceptable since existing and future demand in the Yosemite Division cannot be met without potential damage to transmission facilities and degradation of service reliability.

· Alternative #2: Re-rate circuit for higher emergency ratings. PG&E rejected this alternative because it claims the alternative does not solve the potential problem of losing both lines due to a single incident, and does not resolve potential voltage deficiencies or thermal overloads.

· Alternative #3: Reduce generation at Kerckhoff II Powerhouse. PG&E rejected this alternative due to supply needs in the Yosemite and Fresno areas during summer conditions. This alternative could lead to low voltages (stability problems) in the Yosemite and Fresno transmission systems.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. The proposed facilities would be installed within existing PG&E property. This project is exempted from the noticing and permitting requirements of General Order 131-D.

Status:

PG&E indicates that this project is in engineering. Construction work is forecast to begin in May 2001.

Technical Issues:

· The Kerckhoff I-Kerckhoff II and the Oakhurst Junction-Kerckhoff II lines would be reconductored with 715 AAL conductors.

· The LeGrand, Coarsegold, and Oakhurst distribution substations are located in the southern portion of the Yosemite Division. PG&E indicates that those substations have a total peak demand of about 160MW. They serve electric power from a 115kV transmission system with connections to Wilson, Sanger, and Panoche.

· There are two generation facilities in the area-Exchequer Powerhouse (75MW) and Kerckhoff II Powerhouse (150MW).

8. Brighton 230/115kV Transformer (T-449)

Recommendation: Order completion of the project, which re-rates the Brighton 230/115 kV Transformer Bank to higher Normal and Emergency ratings

Project Description (Scope):

By 2001, re-rate the Brighton 230/115 kV Transformer Bank to higher Normal and Emergency ratings. This is done by analyzing the oil in the transformer and performing various other tests. By 2005, install a 2^nd Brighton 230/115 kV transformer bank.

The Problem:

Continued increase in electric demand will cause the Brighton Transformer to go into a Normal overload condition starting in 2001, continuing to 16% Normal overload in 2005.

Costs and Benefits:

· Benefit - Removes the Normal overload condition at the transformer

· Cost - Cost of testing and re-rating the transformer bank in 2001 should be under $1 million. The cost of adding the additional transformer bank in 2005 will be between $5 and $10 million.

Alternatives:

· Status Quo - Not acceptable since it would overload equipment, reduce its service life and increase the chances of customer outages.

· No other practical alternatives.

Environmental Impacts & Other Policy Issues (relation to other projects):

There should be no issues until the new transformer bank is installed in 2005.

Status: Rerate the transformer bank in 2001. Add additional transformer bank in 2005. The utility gave us no other status information.

9. Fulton #1 60 kV Line Reinforcement Project (T-490, T491, T575)

Recommendation: Order PG&E to complete this project, which will re-conductor two sections of 60 kV transmission line in the Fulton area in order to correct Normal and Emergency overload conditions.

Project Description (Scope):

· To re-conductor the entire section (about 10.7 miles) of the Fulton #1 60 kV line between Fulton Substation and Healdsburg # 2 60 kV line tap point.

· To re-conductor about 0.86 miles of Fitch Mountain #1 60 kV Tap point.

The Problem:

It is estimated based on PG&E studies that under the Normal conditions during the summer 2001 peak conditions, the Fulton-Healdsburgh section of the Fulton No. 1 60 kV line will be overloaded by 14% or 2.4 MW.

In the event of an outage of the Fulton-Hopland 60 kV line during summer 2001 peak conditions, the Fulton No. 1 60 kV line is projected to be overloaded by 70% or 12 MW.

Costs: between $5 million and $10 million

Benefit: over $6 million

By re-conductoring two sections of Fulton #1 60 kV line, a projected 14% (2.4 MW) Normal overload between Fulton and Healdsburgh and 70% (12 MW) Emergency overload between Fulton and Hopland during 2001 summer peak period can be avoided.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. A notice of Construction (NOC) is needed per CPUC G.O. 131D. The proposed work should not require any additional permitting or environmental filings, since the work is an upgrade of an existing transmission line.

A biologist is needed to be present during construction due to identified endangered species habitat issues. The biologist would be on site to monitor construction activities and make recommendations as required.

Alternatives:

· Design an operating procedure to cope with the overload conditions. This alternative is deemed to be unrealistic because it is inadequate to eliminate the expected Emergency overloads and would cause extended outages to electric transmission customers in this area.

· Re-rate conductors of the Fulton #1 60 kV line and Fulton-Hopland 60 kV line. This alternative is not realistic either because the higher wind speed which is needed to re-rate the conductor is not supported by the historical weather data.

Status:

· Notice of Construction was sent to CPUC and was available for construction on 04-17-2000.

· Test & Energize New Equipment will be completed by 06-01-2001.

Technical Issues:

Geyserville Substation (9.6 MW), Fitch Mountain Substation (18.5 MW) and the city of Healdsburgh (17.5 MW) are served from Fulton Substation and Hopland Junction by two 60 kV transmission lines: Fulton #1 60 kV line and Fulton-Hopland 60 kV line. The load growth of this area is estimated to be roughly 2.7 MW/year or 5.9% per year.

Fitch Mountain Substation is normally served from the Fulton-Hopland 60 kV line. The City of Healdsburgh and Geyserville Substation are normally served from the Fulton #1 60 kV line. The City of Healdsburgh and Fitch Mountain Substation loads are transferred automatically to the other line in the event of the outage of their respective primary source.

· Under Normal conditions during the summer 2001 peak conditions, the Fulton-Healdsburgh section of the Fulton #1 60 kV line is projected to overload by 14%.

· In the event of an outage of the Fulton-Hopland 60 kV line during summer 2001 peak conditions (N-1 contingency), the Fulton #1 60 kV line is projected to overload by 70% because it automatically picks up the load of Fitch Mountain area which was served by the Fulton-Hopland 60 kV line.

· In the event of an outage of the Fulton #1 60 kV line during summer 2001 peak conditions (N-1 contingency), the Fitch Mountain #1 60 kV line section of the Fulton-Hopland 60 kV line is projected to overload by 19%. This emergency overload is due to the automatic tansfer of the City of Healdsburgh to the Fulton-Hopland line.

· A section of Fulton #1 60 kV line to Healdsburgh tap point is located on the same poles as the Monte Rio-Fulton 60 kV line. Both of these line sections shall be re-conductored at the same time to save cost.

· All the transmission facilities at Fulton Substation and on the line sections to be re-conductored should be evaluated to remove any limitation which might limit the full rating of the 477 kcmil ACSS conductor to be used in the re-conductor project.

· A significant portion of the Fulton #1 60 kV line parallels the Northwestern Pacific Railroad line and traverses private vineyards, residential backyards, as well as the Russian River, the rail line, and Highway 101. Access to the Fulton #1 60 kV line from River Road to Highway 101 crossing could be difficult in specific locations if the ground is wet. Inclement weather could delay the project, due to the concerns about property damage and costly repairs.

10. RAVENSWOOD 230KV LOOP (T498) AND 230/115KV TRANSFORMER CAPACITY INCREASE (T476) PROJECTS

Recommendation:

Order completion of the projects, which would provide reliable electric transmission service to 100,000 customers in the San Mateo County for between $1 million and $5 million.

Project Description (Scope):

The Ravenswood 230kV Loop Project (T498) installs the Loop circuit and Ravenswood 230/115/kV Transformer capacity increase Project (T476) are to be completed in June 2001. Looping the Newark-San Mateo 230kV circuit into Ravenswood Substation provides a second 230 kV source and prevents such an outage concern. See attached Service Area Map. No Project justification has been provided by the utility.

The Problem:

Planning analysis concluded that an outage of the Telsa-Ravenswood 230kV circuit is the worst outage for the San Mateo area. Also of concern is an outage of the Ravenswood 230/115kV bank which will overload the Ravenswood-San Mateo 230kV circuit to 107% of its emergency rating. This is addressed by re-rate of the 230kV circuit to 4ft/sec.

An increase in capacity for the Ravenswood Substation requires an increase in the Ravenswood 230/115kV transformer capacity (rating) to mitigate any thermal overloads. Project T476 addresses this transformer capacity increase problem, but details have not been provided by the Utility.

Cost and Benefits:

Cost: between $5 million and $10 million (PM Forecast) includes the following:

¬ Installs a loop circuit Ravenswood-San Mateo 230kV No. 1 & 2 into Ravenswood Substation.

¬ Increase the Ravenswood 230/115kV transformer capacity. (Cost needed)

Benefits:

Ravenswood 230kV Loop and the associated transformer capacity increase is needed to increase transmission import capacity to serve projected electric demand increase and reduce electric service interruption to 100,000 customers or more by minimizing the worst case outage for the area.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal impact is anticipated. Land issues are currently under review. Permits may be required from Bay Conservation Development Commission and County/City. PG&E biologists have determined that the proposed projects will not impact sensitive habitats or species, since most work is confined to substation property.

Alternatives Considered:

Status Quo, if not built, does not address the worst case outage for the Central Peninsula area, which would affect cities of Palo Alto, San Mateo and Belmont.

Technical Issues:

None provided by the utility.

11. Metcalf 500 kV Shunt Capacitors Project (T-519)

Recommendation: Order completion of this project, which will install a total of 350 MVARs capacitor banks at Metcalf Substation.

Project Description:

Install a total of 350 MVAR shunt capacitors on the Metcalf Substation for June 15, 2001 operation to eliminate a Reliability Must Run (RMR) unit at Moss Landing power plant and to maintain adequate voltage levels.

The Problem:

The ISO maintains a contract with Moss Landing units 6 and 7, at a cost of $25 million per year to preserve system stability during summer peaks, especially considering the possibility that local generation may be out of service due to forced outage or maintenance.

· The projected 200 MW (or 2.3%) demand growth, based on 1999 peak Bay Area demand of 8,700 MW, requires PG&E to conduct major electric system upgrade before 2001 to avoid potential localized firm load dropping.

Cost and Benefit:

Costs: under $15 million

Benefit: $25 million

Installation of 350 MVAR capacitors banks at Metcalf Substation will eliminate the need of RMR contract for Moss Landing Unit No. 6. The immediate savings for 2001 is about $25 million. Depending on other proposed generation plant in the Bay Area such as Calpine's Los Medanos power plant, the RMR contract for Moss Landing Unit No. 7 can be eliminated too, to save an additional $25 million.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. The proposed capacitor facility would be installed within existing PG&E property at Metcalf Substation. The project has no adverse environmental impacts or EMF effects. This work is exempted from the noticing and permitting requirements of General Order 131-D with the CPUC. Certain local building permits are still needed for site preparation and minor modification work.

Alternatives:

· RMR contract with Moss Landing Unit 6 and Unit 7.

Status:

· Engineering Works started on 9-7-2000 as planned.

· Long Lead Time Materials Procurement started on 9-28-2000 as planned.

· Civil Construction started on 10-2-2000 as planned.

· Outdoor and Indoor construction will start on 3-29-2001 and 4-12-2001 respectively.

· Test & Energize New Equipment will start on 5-4-2001 and will be completed by 6-1-2001.

· Estimated In Service Date: 06-01-2001.

Technical Issues:

· Peak demand and high projected demand growth of the Bay Area requires sufficient voltage and reactive margin to maintain system stability and reliability.

· Currently, the RMR contracts with Moss Landing Unit 6 and Unit 7 are used to provide voltage and reactive margin for reliability and stability concerns.

· The Metcalf 500 kV shunt capacitors project is one of many projects proposed by PG&E to upgrade PG&E's electrical system, especially in the Bay Area. Metcalf 500 kV shunt capacitors project can provide both voltage and reactive margin support. This project will eliminate the RMR contract with Moss Landing Unit No. 6, a saving of $25 million and possibly Moss Landing Unit No. 7, saving of another $25 million, if an additional power plant will be built in the Bay Area such as Calpone's Los Medanos power plant.

12. LAKEWOOD AREA TRANSMISSION REINFORCEMENT PROJECT (T-546)

Recommendation:

Order completion of the project, which would provide reliable electric transmission service to 100,000 customers in the Clayton, Concord and Walnut Creek areas of Contra Costa County for between $5 million and $10 million.

Project Description (Scope):

The Lakewood Area Transmission Reinforcement Project installs the Pittsburg-Clayton No. 4 circuit and reconductors the Clayton-Lakewood Nos. 1 & 2 115kV circuits to be completed in June 2001.

The Problem:

Lakewood Substation has a non-standard design which separates the station into two sections which are electrically disconnected and is served by two separate transmission lines. A single transmission line outage would affect 15,000 to 20,000 customers for 15 minutes, the time an operator takes to manually switch circuit breakers to restore service. This design has satisfactorily served the area in the past. However, the design cannot support continued and future growth in the area for electric demand without adversely impacting operations and maintenance because of its complexity. The PG&E standard design specifies redundant transmission supply system.

From a capacity standpoint, planning analysis concluded that the Pittsburg-Clayton No. 3 115kV line and the Clayton-Lakewood 115kV line would be overloaded if another transmission line in the vicinity becomes unavailable during the summer peak hours. Furthermore, the Sobrante-Moraga-Lakewood 115kV line would be subjected to normal and emergency overloads during summer partial peak hours in year 2001.

From an operations standpoint, the non-standard design creates additional burden and pressure on daily operations. These operations complexity could lead to operator errors and customer exposure to longer outage minutes. For example, on August 3, 1998, a troubleman noticed the Pittsburg-Clayton No. 3 115kV circuit sagged close to a tree and because of fire concerns, Pittsburg-Clayton No. 1, 2 & 3 115kV circuits were manually tripped. This interrupted electric service to 84,000 customers for 90 minutes. This was the time it took troublemen to assess the problem, take action which was to manually trip the line, also tripped the other 2 bundled lines, fix the problem (cut the tree down) and restore power. This was an N-2 situation with no contigency.

Constraints addressed:

Distribution constraint is addressed by increased transmission capacity and upgrading of substation.

Cost and Benefits:

Cost: between $5 million and $10 million, which includes the following:

¬ Installs new Pittsburg-Clayton No. 4 115kVcircuit from Pittsburg Power Plant switchyard to Clayton Substation and associated circuit breakers at Pittsburg and Clayton Substations.

¬ Untie Clayton-Lakewood Nos. 1 & 2 115kV circuits into individual circuits and reconductor both circuits. Install new circuit breakers at Clayton and Lakewood Substation to terminate the Clayton-Lakewood No. 2 115kV circuit.

¬ Reconductor existing double bus, replace one overloaded circuit breaker at Clayton Substaion and replace bus differential protection.

¬ Replace line relays for Pittsburg-Clayton Nos. 1 & 2, Pittsburg-Clayton No. 3 and Clayton-Lakewood No. 1 115kV circuits.

Benefits:

The one new circuit and two reconductored circuits (18.9 miles total) would have an increase of 252MW in load capacity by summer 2001, preventing normal and emergency line overload and eventual load shedding of customers. An updated substation would enhance the reliability in operations to the service area.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal impact is anticipated. Electromagnetic fields (EMF) are expected to increase slightly due to increased line loading. An EMF mitigation plan conforming to CPUC standards (Decision # 93-11-013) would be needed. A point of contention could be "should calculation of EMF be done before or after project installation?".

Alternatives Considered:

Status Quo, if not built, does not improve reliability because it continues the complex operations and potential customer service interruptions due to the non-standard design at Lakewood Substation. In addition, it does not provide additional transmission to eliminate forecast normal and emergency overloads.

Another alternative is to install a new circuit from Contra Costa to Lakewood Substation. However this alternative is not a good economical choice due to its high cost.

Technical Issues:

Completing the proposed project will enable Lakewood Substation to be supplied with a loop transmission system arrangement consistent with other Bay Area substations of the 200MW size.

13. PITTSBURG-TASSAJARA 230KV RECONDUCTORING PROJECT (T-552)

Recommendation:

Order completion of Phase I of the project, which would eliminate a projected normal overload of the Pittsburg-Tassajara 230kV circuit in 2001 for between $1 million to $5 million.

Project Description (Scope):

Phase I reconductors 5.4 miles of the Pittsburg-Tassajara 230kV circuit by June 2001. Phase II (T665) reconductors the remaining 11.6 miles in 2003. See attached Area Transmission Facilities Map.

The Problem:

Power flow studies indicate a normal overload of 3% on the 5.4 mile circuit during the year 2001 summer peak demand. The overload is due to the significant load increase in the Walnut Creek and San Ramon Distribution Planning Area with a forecast load growth of 11.5 MW per year and 17.4 MW per year, respectively.

Cost and Benefits:

Cost: between $1 million to $5 million for Phase I and Phase II.

The costs include line work, and reconductoring work which includes raising six towers to achieve adequate ground clearances, installing one intercept tower and installing shooflies at three locations. Costs also include upgrading the Pittsburg Power Plant Switchyard for the connectors and overhead conductors upgrade.

Benefits:

Reconductoring the circuit would increase load capacity by summer 2001, preventing line overload and eventual load shedding of 20,000 customers, which is equivalent to about 50MW.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal impact is anticipated. Electromagnetic fields (EMF) are expected to increase slightly due to increased line loading. An EMF mitigation plan conforming to CPUC standards (Decision # 93-11-013) would be needed. A point of contention might be should the EMF calculation be done before or after line installation.

Alternatives Considered:

Status Quo does not address the additional transmission capacity to eliminate the forecast normal overload. To mitigate the overload, loads at the Tassajara and Research Substations would need to be curtailed.

Another alternative is to transfer the Research Substation from Pittsburg-Tassajara circuit to Contra Costa-San Mateo 230kV circuit. However, power flow studies indicate that is will not prevent a normal overload to Pittsburg- Tassajara circuit in case Potrero PP Unit 3 is out of service, nor prevent an emergency overload due to Newark-Tesla circuit outage while Potrero Power Plant Unit 3 is out.

Technical Issues:

Phase II reconductoring 11.6 miles of Pittsburg-Tassajara 230kV line is scheduled for 2003. This could be affected by the following factors:

New Generation:

There is an addition of 4000MW of new generation proposed to interconnect to the Bay Area. The size and location of the new generation may accelerate or postpone the Phase II schedule.

Tri-Valley 2002 Capacity Increase Project:

The Tri-Valley Project was approved by CAISO and is currently in CPUC CPCN process. If the project is delayed beyond 2002, Tassajara Substation could be utilized to pick up some of the loads served by the project. This situation could increase the loading on the Pittsburg-Tassajara circuit and accelerate the Phase II schedule to 2002.

14. Tesla 500/230kV Transformer Project (T-558, T-669)

Recommendation: Order completion of the project, adding an additional 500/230kV transformer at the Tesla Substation, which provides Normal overload relief at the Tracy 500/230 kV transformer bank and provides an extra 800 MW of import capability into the Bay Area.

Project Description (Scope): The Tesla Substation, located near the Altamont Pass, takes 500kV electric from the Northwest Intertie and steps it down to 230kV for transmission to the Bay Area and other areas in Northern California.

· Phase I - Install and energize a new 1122MVA 500/230kV transformer by June 2001 utilizing a minimal system connection (T-558).

· Phase II - Install dedicated breakers and equipment allowing full integration of the transformer into the system by June 2002 (T-669).

The Problem: During 1999, with all facilities in service, the peak load on the Tracy 500/230 kV transformer exceeded its normal rating of 850 MVA by 2.6% (872 MVA on July 12, 1999). In addition, in 2000, the CAISO ordered the interruption of as much as 800 MW of load in Northern California to prevent overloads on the Tracy transformer bank. Also, electric demand in the Bay Area is expected to increase by 300 MW (3.3%) per year, making it important to increase import capabilities into the Bay Area.

Costs and Benefits:

· Benefit - Provides approximately 100 MW of Tracy transformer relief under Normal conditions. Relieves the Normal overload condition on the Tesla 500/230 kV transformer bank #2. Provides up to 800 MW of import capability into the Bay Area.

· Cost- Total project cost, upon completion in June 2002, is estimated to be more than $10 million.

Alternatives:

· Status Quo - Not recommended due to decreasing availability of Bay Area power plants and continued high economic growth.

· No other feasible alternatives cited by PG&E.

Environmental Impacts & Other Policy Issues (relation to other projects): Involves adding equipment at the existing Tesla substation. This work is exempted from the noticing and permitting requirements of General order 131-D with the CPUC. Start of construction is being held up however, pending finalization by State and Federal agencies of PG&E's mitigation plan for protected species on the site.

Status:

· Mitsubishi transformers ordered in August of 2001. They are scheduled to be shipped from the factory on 3/15/01, to be delivered April 2001.

· Engineering work started on 10/2/00, 3 days behind schedule.

· Long lead time material procurement started on 7/15/00, approximately 45 days ahead of schedule.

· Transformer bank procurement started on 8/01/00, approximately 13 days behind schedule.

· Construction is expected to start in mid January, pending finalization by State and Federal agencies of PG&E's mitigation plan for protected species on the site. This is two months behind schedule.

Technical Issues:

· System Reliability Risk - This project will be done in two phases. Phase I, to be completed in June 2001, will install the new 500/230kV transformer. Because of the tight schedule to energize the transformer by June 2001, it is not possible to purchase and install all of the related equipment (e.g. protection devices such as circuit breakers) necessary to fully integrate it into the system. This will be done in Phase II to be completed by June 2002.

· Until Phase II is completed there will be a slightly higher possibility of losing five 230 kV lines if there is a fault (short circuit) at the new transformer or its related busses (lines or tubes carrying electric to and from the transformer). An unknown number of customers could lose power. If this happens, the 230kV lines will have to be manually switched to another bus at the substation. This could take several hours. If the transformer is not energized by June 2001 however, the risks of power outages could be greater due to lack of capacity in the system.

· This transformer project is physically interrelated to the addition of the 500/230kV transformer at Tracy in 2002. Without the new transformer at Tesla, the new transformer at Tracy will increase the short circuit duty problems at the existing Tesla facility. In addition, both transformers will be needed to meet the growing electric demands by as early as 2002.

· There is also Project T-670, scheduled to be on-line by June 2001, which will build a second 230kV line from the Tesla Substation to the Newark Substation near Fremont. This line will physically carry additional electric imported from the Northwest Intertie into the Bay Area. Project T-558 and Project T-670 are not necessarily dependent on one another, however.

15. Metcalf Distribution Substation (Coyote Valley) Transmission Connection (T579)

Recommendation: Currently cannot recommend ordering completion of the project for Summer 2001, which builds a new distribution substation to serve the Coyote Valley Development (new Cisco campus). The timing of this project is impacted by litigation and the EIR process, which could delay the in-service date into 2002. Nevertheless, this project should still appear in Tables 1 and 2 because a faster resolution of issues causing delays could bring this project back into year 2001.

Project Description (Scope):

· Located in PG&E's San Jose Division.

· Build a new distribution substation and connect it with a loop arrangement to the Metcalf-Hicks 230kV line.

· Revised estimated in-service date from June 2001 to December 2001 (delays by customer in siting and construction), pending results of Cisco's litigation and EIR. Latest information from PG&E is that the in-service date has been pushed out to February 2002.

The Problem:

· The Edenvale and Morgan Hill substations serve electric customers at the southern end of Silicon Valley, including the North Coyote Valley area. Developers are planning to build office, research and development, and light manufacturing complexes in the North Coyote Valley.

· Electric demand is expected to start initially in 2001 and grow at a rate of 13MW per year until it reaches its maximum of 190MW by 2015. Existing PG&E facilities cannot accommodate this load growth.

Costs and Benefits:

· Cost - This project is expected to cost between $5 million and $10 million.

· Benefit - Building the new substation will allow PG&E to serve the new load in the Coyote Valley Development, without overloading existing circuits and equipment. PG&E did not provide a benefit cost calculation for this project. PG&E will initially install one 45MVA transformer and add more as the load growth increases in the future.

Alternatives:

· Alternative #1: Status Quo. Not recommended since existing distribution circuits and equipment are projected to overload, thereby increasing the likelihood of additional equipment failure.

· Alternative #2: Install distribution capacity at Edenvale. This alternative would replace Edenvale Transformer #2 with a 45MVA transformer, increasing distribution capacity in the area by 17MW. However, PG&E believes it is inadequate in the long-term to serve the long-term projected 190MW demand in 2015.

· Alternative #3: Install a new substation at the north or south end of the proposed Coyote Valley Development. This option would install a new substation and be designed for three 45MVA transformers. However, PG&E rejected this alternative due to its long implementation time.

Environmental Impacts & Other Policy Issues (relation to other projects):

Since the new distribution substation is being built by PG&E, the project may be subject to CEQA.

Status:

PG&E indicates that this project is in final engineering. Construction work could begin as early as in May 2001.

Technical Issues:

· PG&E ultimately envisions a 230/21kV distribution substation with three 45MVA distribution transformers.

16. Lockeford - City of Lodi Area Reinforcement Project (T-602 and T-605)

Recommendation: Order completion of the project, which brings an additional electrical capacity of 23 MW into the City of Lodi.

Project Description (Scope):

· Re-conductor, by June 2001, the 4/0 aluminum conductor section (approximately 2.1 miles) of the Lockeford-Lodi No. 3 60 kV line, with 1113 aluminum conductor.

· Re-conductor, by June 2001, the 2/0 copper conductor section (approximately 2.5 miles) of the Lockeford-Lodi No. 3 60 kV line, with 715 aluminum conductor.

· Rerated (complete) in June 2000, the 4.5 mile section of 397 aluminum conductor, of the Lockeford-Lodi No. 3 60 kV lines, to a higher rating with 4 feet per second wind speed assumption.

· Rerate, by June 2001, the Lockeford-Industrial and Lockeford-Lodi No. 2 60 kV lines to a higher rating, with 4 feet per second wind speed assumption. Circuit breakers at Lockeford would need to be replaced.

The Problem:

· Forecast peak demand at Lodi is 120.7 MW for 2000 and 122.4 MW for 2001. In August 1998, the City of Lodi reached a peak load of 116.9 MW. PG&E's Normal Delivery Capability is only 112.0 MW. Lodi is a member of the Northern California Power Agency (NCPA). Due to the Normal overload condition, PG&E is in violation of Section 6.2.5 c of the Interconnection Agreement with NCPA.

· System analysis shows that the Lockeford-Lodi line No. 3 60kV line is projected to overload by 1.4% above its normal rating of 29 MVA under normal conditions in 2001.

· System analysis shows that after a loss of Lockeford-Industrial 60 kV line, the Lockeford-Lodi No. 3 60 kV line would exceed its summer emergency rating of 34 MVA by 62% in 2001.

Costs and Benefits:

· Benefit - Currently, CAISO has an RMR contract with a combustion turbine in Lodi. The turbine has the capability of reducing the Emergency overload from 62% to 20%. The RMR contract costs in the range of $1 million per year. If this project is completed, the RMR contract can be eliminated. In addition, Lodi has automatic load shedding which drops load until the Emergency overload is eliminated. If this project is completed, customers will not have to be dropped.

· Cost - between $1 million and $5 million to complete the project.

Alternatives:

· Status Quo - The status quo is unacceptable. There is a normal overload condition and PG&E is in violation of its contractual agreements with NCPA.

· No other feasible alternatives cited by PG&E.

Environmental Impacts & Other Policy Issues (relation to other projects): Resolution E-3719, dated 11/16/2000, orders that PG&E's Advice Letter No. 2025-E is approved. AL 2025-E claimed that this project was exempt from General Order 131-D permitting requirements. The proposed work involves upgrades to existing transmission facilities and should not require any additional permitting or environmental filings.

Status:

Scheduled for completion in June, 2001.

Key Issue: PG&E, NCPA and the City of Lodi have been aware of the transmission problems in this area for several years. In 1998, Lodi recommended to PG&E to hold off any transmission reinforcements on the PG&E system as Lodi investigated a proposal to switch about 60 MW (50%) of its load to the Western Area Power (WAPA) system. In 1999, Lodi determined that the potential interconnection to the WAPA system was unattractive. Subsequently, Lodi and NCPA advised PG&E that 100% of the City of Lodi loads would remain connected to the PG&E system for the next five to seven years. The implementation of this project would allow PG&E to meet the current contractual obligation.

Technical Issues: In order to provide reliable transmission service to Lodi on a long- term basis, PG&E needs to continue transmission reinforcements on the 60 kV system in the Lockeford-Lodi area subsequent to the year 2001. Additional transmission projects are likely to be needed to provide the transmission capacity of 143 MW at the Industrial Substation to meet Lodi's projected 2.2 MW/year load growth up to year 2010.

17. Martin 115 kV Capacitors Project (T-636)

Recommendation: Order completion of this project, which will install 100 MVARs capacitor banks at Martin Substation.

Similar to PG&E, CPUC staff recommends a further upgrade of the existing two 25-MVARs capacitor banks to 50 MVARs each.

Project Description (Scope):

Install a total of 100 MVAR NEW shunt capacitor bank and upgrade two existing capacitor banks from 25 MVARs each to 50 MVARs each at the Martin Substation for a May 15, 2001, In Service Date.

The Problem:

The problem is Reliability related under Emergency situations.

Studies conducted by PG&E indicated that, unless sufficient voltage and reactive margin is available, (by installing capacitor banks, for example) during a simultaneous outage of Potreno Unit No. 3 and San Mateo to Martin underground cable (G-1/N-1 emergency), the voltage at the San Francisco area will be dangerously low. This low voltage might result in wide spread blackouts in the Bay Area.

Cost and Benefit:

Costs: between $1 million and $5 million, and includes

· adding 100 MVARs (in 2 steps) in Martin Substation

· connecting the Martin Capacitors to 115 kV Bus

· upgrading two 25-MVARs capacitor banks to 50-MVARs each

(a) Benefit: $Unknown

MW of firm load dropped at stage 3: Unknown MW

Value of Service ($/MWHr): approximately $20,000

Hours of outage (hours/yr): unknown hours/yr

By installing the capacitor bank at the Martin substation would provide needed voltage and reactive margin support to the Bay Area so the wide spread outage and voltage collapse under Emergency contingency conditions can be avoided.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. The proposed capacitor facility would be installed within existing PG&E property at Martin Substation. The project has no adverse environmental impacts or EMF effects. This work is exempted from the noticing and permitting requirements of General Order 131-D with the CPUC. Certain local building permits are still needed for site preparation and minor modification work.

Alternatives:

· Convert Hunters Point Unit 2 and Unit 3 to synchronous condenser. This could be more expensive, plus there is also a great uncertainty of this alternative because the ISO needs to approve including the conversion cost into the existing Hunters Point reliability-must-run contract.

Status:

· Engineering/Land Rights Works started on 9-1-2000 as planned.

· Long Lead Time Materials Procurement started on 9-8-2000, one week later than planned starting date.

· Civil Construction started on 10-30-2000 as planned.

· Outdoor and Indoor construction will start on 1-9-2001 and 3-1-2001 respectively.

· Test & Energize New Equipment will start on 5-1-2001 and will be completed by 6-1-2001.

· Estimated In Service Date is 6-1-2001.

Technical Issues:

Electric load in San Francisco is supplied by transmission lines and local generation. System power is transmitted to Martin Substation (located just south of the city's border) by one underground cable and six overhead circuits from San Mateo substation. A small 60 kV transmission tie also exists along I-280 connecting Martin Substation and Jefferson Substation (near Palo Alto).

Generation located within San Francisco consists of two power plants: Hunters Point (427 MW) and Potrero (357 MW) for a total of 784 MW whereas a typical summer peak demand of the San Francisco and the Northern Peninsula area is about 1,240 MW.

· The projected demand growth in the San Francisco area is 3% a year due to large developments such as Mission Bay, PacBell ball park, BART extension and San Francisco International Airport.

· Hunters Point Power Plant units 2 and 3 are currently out of service pending the results of an assessment to ensure they can be operated safely and reliably.

· Study results indicated that for outage scenario involving Potrero Unit 3 and the San Mateo-Martin 230 kV underground cable, a G-1/L-1 contingency, the voltage at 230 kV and 115 kV stations will be dropped to 214 kV and 106 kV due to lack of voltage and reactive margin support. Voltage this low might cause wide spread cascading outages.

· Adding capacitors to Martin 115 kV Bus No. 1 is one of the eight projects identified by ISO and PG&E to provide additional thermal and reactive system capability to serve electric customers in the Bay Area after the June 14,2000 electric emergency where firm load had to be dropped.

· A total of 100 MVARs reactive capacity, two capacitor banks with 50 MVARs each, was proposed in the project. Switching scheme will be used to switch 100 MVARs to the Martin 115 kV Bus No. 1 in two steps, 50 MVARs at a time.

· There are two existing 25 MVARs capacitor banks which can be switched in 25 MVARs steps. For a cost of $200,000 or less, these two existing 25 MVARs banks can be upgraded to 50 MVARs each. This will bring a total of 200 MVARs capacity at Martin substation instead of 150 MVARs. PG&E has indicated that this approach is feasible technically. This additional capacity increase is recommended by CPUC staff.

18. Metcalf to Monta Vista 230 kV Line Project (T-647)

Recommendation: Order PG&E to complete this project, which separate two parallel 230 kV transmission lines: Metcalf to Monta Vista Lines Nos.3 and 4 into two individual lines.

Project Description (Scope):

Conduct necessary work at Metcalf and Monta Vista Substations to establish Metcalf to Monta Vista 230 kV lines No. 3 and No. 4 into two separate circuits to avoid the dropping of 79 MW firm load (approximately 79,000 customers) in the De Anza area under the transmission line outage contingency.

The Problem:

This problem is an overload of the Metcalf to Hicks 230 kV line under the contingency of simultaneous outage of both Metcalf to Monta Vista 230 kV lines Nos. 3 and 4. Because Metcalf to Monta Vista 230 kV lines Nos. 3 and 4 are operated in parallel as one line, the simultaneous outage of these two lines due to a single incident is likely. Under this contingency, 79 MW firm load dropping is necessary because of the overloading of Metcalf to Hicks 230 kV line.

Costs: between $5 million and $10 million

Benefit: over $3 million per year

By separating the Metcalf to Monta Vista 230 kV lines Nos. 3 and 4 into two independent circuits, the probability of losing both of these lines can be reduced significantly. Therefore, the likelihood of load dropping (79 MW of firm load) on the Metcalf to Hicks 230 kV line can be reduced considerably.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. The proposed circuit breaker facilities would be installed within existing PG&E property at the Metcalf and Monta Vista Substations. The work is exempted from the noticing and permitting requirements of General Order 131-D with the CPUC and has no adverse environmental impacts or EMF effects. Certain local building permits are still needed for preparation and minor modification work.

Alternatives:

· There is no other alternative.

Status:

· Engineering Works was started on 07-14-2000.

· Long Lead Time Materials Procurement was started on 08-07-2000.

· Substation Relay work will start on 01-02-2001.

· Test & Energize New Equipment will start on 04-23-2001 and will be completed by 04-27-2001.

· In Service Date: 04-27-2001.

Technical Issues:

The transmission service to customers in De Anza Division and Hicks Substation in San Jose Division is provided mainly by three 230 kV lines: Metcalf to Hicks, Metcalf to Vasona, and Metcalf to Monta Vista No. 3 and No. 4 lines. The Metcalf to Monta Vista No. 3 and No. 4 lines are currently operated in parallel as one line. Therefore, there is a greater chance that both of these two lines could be out of service due to a single incident. This potential problem could be mitigated by separating those two 230 kV lines connecting Metcalf and Monta Vista Substations.

· The load forecast for a 1-in-10 year adverse weather condition in 2000 is approximately 890 MW in De Anza Division and its yearly demand growth is estimated to be 16 MW (2%) per year

· Power Flow studies indicated that during the peak load condition of year 2001, when Mecalf to Monta Vista 230 kV lines (operating in parallel) were out, the Metcalf to Hicks 230 kV line would be loaded 112% of conductor's emergency 4 feet per second rating.

· Approximately 79 MW of load at Hicks Substation would have to be dropped during the aforementioned outage in order to avoid transmission line damage and wide spread outages.

· By installing circuit breakers, protective equipment, and extending the 230 kV bus at Metcalf and Monta Vista substations, these two parallel 230 kV lines can be separated in order to reduce the probability of simultaneous outage for both Metcalf to Monta Vista 230 kV lines. If only one line is out of service, overload of Metcalf to Hicks 230 kV line will not happen and dropping of 79 MW firm load can be avoided.

19. BRIDGEVILLE-COTTONWOOD UPGRADE PROJECT (T652)

Recommendation:

Not enough information received from the utility to recommend this project at this time.

Project Description (Scope):

The Bridgeville-Cottonwood Upgrade Project upgrades protection equipment and scheme with completion in October 2001. No Project justification has been received from Utility.

The Problem:

There is a need to increase import capacity into Humboldt area or an RMR reliance concern.

Cost and Benefits:

Cost: less than $1,000,000 from PG&E meeting on 11/27/00, no other details or back up documents provided by the utility.

¬ Installs and upgrades protection equipment

Benefits:

Not enough information provided by Utility.

Environmental Impacts & Other Policy Issues (relation to other projects):

Unknown at this time

Alternatives Considered:

For T652 details are unknown at this time.

Long term solution includes Project T658 which adds a new line to increase import capacity for over $2 million in 2004.

Technical Issues:

Unknown

20. JANES CREEK AND HUMBOLDT MODIFICATION PROJECT (T664)

Recommendation:

Order completion of the project, which would modify the Janes Creek substation automatic switching scheme to eliminate the risk of cascading outages due to low voltage problem which potentially could affect 2,000 customers in the Humboldt area for under $1 million. No Project Justification was provided by the utility.

Project Description (Scope):

The Janes Creek Substation Modification Project adds protection equipment, substation automatics and SCADA equipment so the automatic switching procedure of Janes Creek Substation under G-1 and N-1 emergency contingency can be modified to avoid low voltage and cascading blackouts under emergency condition.

The Problem:

At high Humboldt area loads (winter), a single line outage of the Humboldt-Arcata-Janes Creek 60kV circuit causes low voltage in northern Humboldt, especially at the circuit's end at Orick. The voltages are even worst with an overlapping generation/line outage of the Fairhaven generation unit and the Humboldt-Arcata-Janes Creek circuit. This is due to existing switching procedure at Janes Creek substation, which is set to switch the load at Janes Creek substation to Essex Junction-Acrata-Fairhaven 60kV circuit automatically regardless whether the Essex Junction-Acrata-Fairhaven 60kV circuit can handle the load or not. Under this contingency, all power to Janes Creek/Essex area must flow from Humboldt area to Fairheaven, back to Arcate, then to Janes Creek junction. This causes the voltage at circuit's end to be much lower than it should be (15% lower than the nominal value).

Cost and Benefits:

Cost: less than $1 million, and includes the following:

¬ Installs Protection equipment at Janes Creek substation

¬ Install substation automatics

¬ Install SCADA equipment

Benefits:

This is a short term project solution which will basically installs a timer to allow load transfer to another circuit only during specific time periods, when the load transfer can be done to appropriate circuit without overloading the circuit and is able to maintain the voltage. This project improves low voltage condition or outages to about 2000 customers during the cold winter months.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal impact is anticipated, since all work is at the substation.

Alternatives Considered:

Status Quo, if not built, does not improve the low voltages in the area during a line (L-1) and generator (G-1) outage condition.

Install shunt capacitors in the Janes Creek Area, not preferred because it will not eliminate future equipment thermal overload problems for over $1 million.

Add a new 60kV circuit from Humboldt to Arcata Project (T658) for a long term solution that would cost over $2 million and be completed by October 2004.

Convert to 115kV Operation is not preferred due to the cost of over $20 million.

Technical Issues:

If the load transfer at Janes Creek is successful and voltage becomes a concern again, then two Janes Creek distribution feeders will be dropped. A voltage-sensing device would do the automatic drop of the two distribution feeders. Load will be restored manually when facilities are back in service.

21. Grant-East Shore 115kV Breakers Project (T667)

Recommendation: Order completion of the project, which disconnects the Grant substation from the Moraga transmission system, and separates a single circuit into two circuits by adding new circuit breakers at two substations.

Project Description (Scope):

· Located in PG&E's Mission Division, to be completed by June 2001.

· Disconnect the Grant distribution substation from the Moraga transmission system, and separate the two Eastshore-Grant 115kV circuits.

· Install new 115kV circuit breakers at the Grant and Eastshore substations.

· Open the 115kV Switch #197 at Owens Brockway, near Oakland's "J" substation.

The Problem:

· The San Leandro, Station J, Edes, and Grant distribution substations serve the cities of Oakland, San Leandro, and Piedmont. According to PG&E, electric demand in this area is expected to grow at 4.5MW per year with total demand reaching 232MW by Summer 2001.

· With this forecasted load growth, several 115kV circuits in the area are projected to be overloaded under normal and emergency conditions by Summer 2001.

Costs and Benefits:

· Cost - This project is expected to cost between $1 million and $5 million.

· Benefit - Disconnecting the Grant substation from the Moraga transmission system would reduce the amount of load through the Moraga system, thereby relieving the overloads by sectionalizing the interconnected 115kV system. Separating the two Eastshore-Grant 115kV circuits (currently operating as one) by installing circuit breakers, to create two independent circuits would reduce the risk of more widespread outages due to a single incident, hence reducing the risk that 60MW of customers could be interrupted during periods of peak demand.

Alternatives:

· Alternative #1: Status Quo. Not acceptable since 60MW of electric customers may need to be interrupted to keep loading on the 115kV system below its ratings during peak demand periods.

· Alternative #2: Reconductor various 115kV circuits to increase transmission capacity. This option would cost between $10 million to $15 million and was rejected by PG&E because it was not as cost-effective as the proposed project.

· Alternative #3: Establish a new Edes-Eastshore 115kV circuit. This option would cost between $5 million to $10 million and was rejected by PG&E because it was not as cost-effective as the proposed project and because it would create equipment overloading on the Eastshore transmission network.

Environmental Impacts & Other Policy Issues (relation to other projects):

Minimal. The proposed facilities would be installed within existing PG&E property. This work is exempted from the noticing and permitting requirements of General Order 131-D.

Status:

PG&E indicates that construction work is in progress.

Technical Issues:

· PG&E asserts that the San Leandro-Domtar-Edes circuit will be 6% overloaded under normal conditions by Summer 2001.

· PG&E asserts that the Moraga-San Leandro 115kV circuits will be 13% overloaded during emergency conditions by Summer 2001.

· PG&E asserts that the Moraga-Station J circuit will be 36% overloaded during emergency conditions by Summer 2001.

22. Moss Landing Circuit Breaker #570 Upgrade (T668)

Recommendation: Order completion of the project, which replaces the existing 2000 Amp Moss Landing #570 circuit breaker with a new 3000 Amp breaker.

Project Description (Scope):

· Located in PG&E's Central Coast Division, at the Moss Landing Substation.

· Replace existing 2000 Amp circuit breaker with a 3000 Amp breaker.

· Replace the 115kV disconnect switches for circuit breaker #570.

· This project has a targeted June 2001 in-service date.

The Problem:

The Moss Landing 230/115kV Bank #8 is currently thermally limited by a 115kV circuit breaker, #570, which is rated at 2000 Amps. An outage of Moss Landing 230kV Bus #2 will result in a 19% thermal overload on circuit breaker #570 used in Bank #8. A sustained circuit breaker overload would cause it to malfunction under normal or emergency conditions. If this were to occur, there could be serious damage to the transmission facility and could result in extended outages.

Costs and Benefits:

· Cost - This project is expected to cost under $1 million.

· Benefit - PG&E indicates that replacing circuit breaker #570 is expected to eliminate all normal and emergency overloads for Moss Landing 230/115kV Bank #8 until year 2010 or beyond. The higher rated breaker adds an equivalent of about 115MW of capacity. It is also supposed to provide operating flexibility (by being able to re-route power for faster load restoration) if a bus outage were to occur.

Alternatives:

· Status Quo - Not acceptable since a bus fault at the Moss Landing substation could damage Breaker #570.

Environmental Impacts & Other Policy Issues (relation to other projects):

No negative environmental impacts identified. This project involves replacing equipment at an existing substation. This work is exempted from the noticing and permitting requirements of General Order 131-D.

Status:

· A project kickoff meeting was held on September 6, 2000.

· Decision quality costs have already been provided to the Transmission Planning group, which will incorporate them into the project justification.

Technical Issues:

· PG&E management has approved this project on a conceptual basis. Final approval is pending the completion of a detailed project cost estimate, which is expected to be completed before the end of year 2000.

· The existing Circuit Breaker #570 is rated at 2000 Amps, which is 65MVA less than Bank #8's four-hour emergency rating; it is also 100MVA less than the one-hour emergency rating. By upgrading this circuit breaker to 3000A, the Bank #8 rating can be increased by 200MVA.

· PG&E also needs to upgrade the disconnect switches, bypass switch, bus selector switches, conductor, and bus tubing to 3000A.

· PG&E asserts that the current circuit breaker limitation does not provide Bank #8 with sufficient 1-hour emergency capacity; for bus outage conditions, this 1-hour emergency rating allows time to implement any necessary switching for load restoration.

23. Tesla-Newark Transmission Reinforcement Project (T-670)

Recommendation: Order completion of the project, which will help to stabilize voltage in the Bay Area and increase import capacity into the Bay Area.

Project Description (Scope):

· The Tesla-Newark Transmission Reinforcement Project will install a third 230 kV transmission circuit from Tesla, to carry power from the 500 kV Northwest Intertie, to the Newark Substation near Fremont. There will be five towers removed and twelve towers installed along the alignment. 162 existing towers will also be used. In addition, modifications will be made at both substations (see Technical Issues section).

The Problem: The proposed Tesla-Newark Transmission Project is needed by Summer 2001 to improve transmission voltages and increase import capability into the Bay Area. If the project is not built by Summer 2001, PG&E and the CAISO may have to limit the overall electric demand in the Bay Area to below 8,800 MW.

Costs and Benefits:

· Benefit - Stabilize voltage and increase transmission import capability into the Bay Area, by about 600 MW to serve projected electric demand increase. Reduces risk of electric service interruption to customers. This project affects approximately 100,000 customers.

· Cost - between $10 million and $20 million.

Alternatives:

· Status Quo - Unacceptable, due to increasing demand and decreasing capacity factors at aging Bay Area power plants.

· No other practical alternatives.

Environmental Impacts & Other Policy Issues (relation to other projects):

· The project is exempt from CPUC permitting requirements under GO 131-D and, as such, no Environmental Impact Report or other CEQA document will be prepared for this project.

· PG&E conducted an environmental assessment to confirm that there will be no significant impacts to protected species. The wildlife assessment was issued on November 10, 2000. The botanical assessment was issued November 8, 2000.

· No comments were filed with the CPUC during the Notice of Construction (NOC) protest period, which ended October 17, 2000. The CPUC is reviewing the NOC after the close of the protest period for compliance with GO-131D. The CPUC has told PG&E that it plans to make the NOC Advice Letter effective thus allowing construction to proceed and will provide a letter so advising. As of 11/30, PG&E had not yet received the letter. PG&E states that construction must be underway by December 1, 2000, in order to complete this critical project by Summer, 2001.

Environmental Impacts & Other Policy Issues (cont'd):

· All pull sites and access roads have been reviewed and impacts determined. PG&E Building and Land will be notifying property owners about the use of their property for construction activity and will be negotiating installation of construction access, material storage and ingress/egress.

· Acquisition of the Caltrans crossing permits is under way. PG&E and the ISO are working together to try to accelerate the permitting process.

Status:

· Engineering / Land Rights started on 8/1/00, on time.

· Long Lead Time Material Procurement started on 10/1/00, on time.

· Construction scheduled to begin on 12/4/00 pending project approval.

· Project is scheduled to be completed on 5/1/01.

Technical Issues:

· At Newark Substation, circuit breakers 810, 850, and 860 will be replaced and the protection scheme upgraded to meet the needs of the substation bus. The air switches at each of the circuit breakers will be replaced with 3000 amp switches.

· At the Tesla substation and ADCC Tap substation, new three terminal protection schemes and transfer trip will be installed.

· In addition, thirteen clearances will be required to complete this work during the time frame of 12/4/00 thru 5/1/01.

24. MountainView / Whisman 115 kV Loop (T-671)

Recommendation: Order completion of the project, which corrects a Normal and Emergency overload.

Project Description (Scope):

· Whisman Substation CB 152 (Ames-Whisman 115 kV Line): Remove and replace the back up line relays. Add alarms from each new relay to the station annunciator. Run fiber optic cable from last transmission tower to the control building.

· Mt. View Substation CB 122 (Ames-Mt. View 115 kV Line): Install new primary relays with fiber optic communication to Whisman CB 152. Remove and replace the back up line relays. Add alarms from each new relay to the station annunciator. Connect new relays to existing communication processor.

· Ames Substation: Install 115 kV jumpers between Ames-Mt. View 115 kV line and Ames-Whisman 115 kV line outside the substation fence. Provide a conduit from jumper structure for a fiber optic cable to the control building.

The Problem:

· Normal and Emergency Overload. The utility has supplied no other information.

Costs and Benefits: The utility has not supplied this information, but we believe the project would cost less than $1 million to complete.

Environmental Impacts & Other Policy Issues (relation to other projects):

The utility has not supplied this information.

Status:

Engineering / Land Rights started on 9/13/00, on time.

Long Lead Time Mat'l Procurement started on 9/22/00, on time.

Install Jumper, scheduled to start on 12/15/00.

Install Telecom Equipment, scheduled to start on 11/17/00.

Substation Relay Work, scheduled to start on 11/27/00.

Project completion scheduled for 12/15/00

25. MOSS LANDING 500/230KV TRANSFORMER RATING INCREASE PROJECT (T674)

Recommendation:

Not enough information received from PG&E to recommend a course of action, transformer re-rates are typically economical.

Project Description (Scope):

The Moss Landing 500/230kV Transformer Bank 9 Rating Increase is to be done in Jun 2001. No Project detail or justification was provided by the utility.

The Problem:

The Moss Landing Transformer Bank 9 will experience an emergency overload from line outages. The increase or re-rating of transformers is usually done to mitigate specific thermal overload concerns. No other details were provided by the utility.

Cost and Benefits:

Cost: We estimate the cost to be under $1 million.

¬ Increases transformer rating

Benefits:

Mitigates transformer thermal overload preventing further outages and equipment degradation from heat. From the Transformer Re-rate table we have the following information provided:

Existing Rating Re-Rating (RR) % Loading % Loading

(Normal/Emergency) (Normal/Emergency) Before RR After RR

1120/1120 1344/1613 122 83

Environmental Impacts & Other Policy Issues (relation to other projects):

Unknown, no information provided by Utility.

Alternatives Considered:

Alternatives will be considered if re-rate project/study is not feasible, other details are unknown and none provided by the utility.

Technical Issues:

Unknown and clearances may be necessary if equipment upgrades are required.

26. Install CAT-1 Monitoring Technology to Path 15

Recommendation: Calibrate, and utilize CAT-1 technology for all thermally limited 230 kV transmission lines on Path 15. CEC funds have already installed CAT-1 systems for all four 230 kV lines on Path 15. The costs and how long does it takes to incorporate this technology into the operation and planning of Path 15 are unknown.

Project Description (Scope): CAT-1 monitoring technology measures the tension of the transmission line to determine its real time power transfer thermal rating. It requires 30 days of recorded data to calibrate the system in order to yield accurate real time thermal rating of the transmission line. This calibration process is underway for Path 15, and must be completed. Following calibration and testing, the CAT-1 system should be used by the system planner and operator to maximize the safe and reliable utilization of the 230 kV transmission lines of the Path 15.

The Problem: Path 15 is the vital transmission lines that link the southern portion of PG&E's service territory to the rest of its system. Path 15 is made up of six transmission lines: two 500 kV lines and four 230 kV lines. There are specific power transfer ratings, called Static Ratings, for each of these six lines. These Static Ratings are determined either by thermal limitations of the transmission line itself or stability concerns of the whole PG&E or WSCC transmission grid. The System Operator does not allow Path 15 to exceed its rated capacity because of its critical nature to the PG&E and WSCC network. During periods of extreme demand or unforeseen generation outage, this vital transmission link is subject to congestion, i.e., the amount of power flow through Path 15 is limited. Congestion of the 230 kV lines of Path 15 is caused by thermal limitation of the line and stability concerns limits the power transfer capability of 500 kV lines of Path 15. By monitoring the thermal rating of 230 kV lines of Path 15 on the real time basis using CAT-1 technology, the power transfer capability of 230 kV lines of Path 15 could be increased beyond its Static Rating under favorable weather conditions (high wind conditions, which cool the lines).

Costs and Benefits: The CAT-1 system uses real time monitoring to predict the actual capacity of the transmission line based upon variables that impact the conductor's capacity, such as ambient temperature and wind speed. The CAT-1 system provides operators on a real time basis with the actual thermal rating of the transmission line. Real time thermal ratings could be higher than thermal Static Ratings if weather conditions are favorable. The CAT-1 system also provides how much time before clearance violations occur if the current loading of the line continues. This information allows operators to operate or manage the transmission grid more reliably and intelligently.

The CAT-1 system can also operate in a predictive mode. The system uses the past 7 to 10 day's recorded data to provide three capability curves⁴² for the next 24 hours. These curves can be used by operators and planners to create operating plans for the next day with varying degrees of confidence. The use of the CAT-1 system would allow for the safe and reliable operation of this transmission link at capacities above its thermal rated limit if weather condition is favorable. The costs for incorporating this technology into the operation and planning of the transmission system are unknown. The cost of installing the CAT-1 technology on Path 15 has already been paid by the CEC.

Environmental Impacts & Other Policy Issues (relation to other projects): CAT-1 has already been installed. Utilizing the technology would not have any additional environmental impact. The use of CAT-1 technology would give the System Operator the sufficient information to reliably and safely exceed the thermal Static Rating of Path 15, improving the reliability of service to customers in PG&E's service territory. Exceeding the previously established Static Rating would be a departure from previous Operator Policy designed to ensure the integrity of Path 15 in a conservative way.

Alternatives: Discontinue calibration of the newly purchased and installed technology, and potentially diminish reliability for customers served by Path 15 in periods of high system stress. The installation and use of CAT-1 on Path 15 (or any other congested transmission line) does not eliminate the need for upgrade of that transmission segment in the future.

Technical Issues: The use of the CAT-1 monitoring technology would not increase power transfer capacity on Path 15 under all circumstances. Only when specific conditions exist (high wind) would the data provided by the CAT-1 technology allow the System Operator to safely exceed Path 15's thermal Static Rating. In addition, CAT-1 would be ineffective in increasing capacity if other components along the transmission line (such as transformers) were already operating at their thermal capacity.

Experiences from other utilities in U.S.A. and other countries indicate that 15 to 30% capacity increase is feasible and achievable. Weather condition is the most important factor that will decide how much capacity increase is available, if any. Since high wind usually occurs during the peak demand period in California (in the afternoon during summer months), the CAT-1 system provides a quick temporary solution for congestion problem of transmission line caused by thermal limitation. The cost to install the CAT-1 system is less than $200,000 for one line. The enhancement on reliability and safety of transmission line resulting from CAT-1 system should justify its cost easily, although no study has been done to quantify this yet.

The CAT-1 system can be extremely useful to the operators during emergency outage situations. By knowing the real time thermal rating of a transmission line and how much time an operator has before clearance violations occur if current loading continues, the operator can react to any emergency line outage and contingency intelligently so affected area of system can be minimized. This consideration alone should justify installation of CAT-1 system on all thermally limited transmission lines controlled by the ISO or IOUs.

27. Antelope-Bailey 66kV System Rearrangement

Recommendation: Order completion of the project, which rearranges the Antelope-Bailey 66kV System for under $1 million.

Project Description (Scope):

· Swap the existing Antelope-Monolith-Windfarm and Cal Cement-Rosamond 66kV lines outside the Cal Cement Substation forming the new Monolith-Rosamond-Windfarm and Antelope-Cal Cement 66kV lines.

· Construct new 500' section of 954 ACSR 66kV line and tap the newly created Monolith-Rosamond-Windfarm 66kV line into Cal Cement forming the new Cal Cement-Monolith-Rosamond-Windfarm 66kV line

· Construct new 0.5 mile 954 ACSR 66kV line from pole-switch 27 on the Cal Cement-Monolith-Windpark 66kV line to the Cal Cement-Goldtown 66kV line.

· Remove tap at pole-switch 27 from the Cal Cement-Monolith-Windpark 66kV line and connect to the newly constructed half-mile section of 66kV line.

· Tap new half-mile section of 66kV line to the Cal Cement-Goldtown 66kV line forming new Cal Cement-Goldtown-Midwind-Monolith-Morwind 66kV line.

· Close pole-switch 32 on the Monolith-PS 32 66kV line forming the new Cal Cement-Monolith-Northwind-Oakwind-Southwind-Zondwind 66kV line.

The Problem: The Antelope-Bailey 66-kV system is located in the Northern Los Angeles County. This area is forecasted to have a total coincident load of 538 MW in 2001 and 569 MW in 2005. It has large amount of wind generation totaling 310 MW. It also has 24 MW of hydro generation. The most critical system conditions occur with maximum wind generation and minimum load because of the large reactive loads of the induction generators, the large reactive losses due to heavily loaded lines, minimal reactive margins, and low short circuit duties. Voltage dips that average approximately 15 seconds from start to finish have occurred.

Costs and Benefits: Significantly increase the voltage, short-circuit duties, and reactive reserve margins for the area, reduce the chance of wind generation backdown. Cost: less than $1 million.

Environmental Impacts & Other Policy Issues (relation to other projects): Minimal, the whole project does not require a GO 131-D filing.

Alternative: A new source line from Antelope would better reduce the loading, increase the duties and provide additional reactive reserve margin to help mitigate the voltage problems then the rearrangement. Because of the long lead-time required to build a new 66kV line as well as the lack of total understanding of the problem, the rearrangement is a good short-term solution to gain some time for a long-term fix.

Technical Issues: The voltage problem in the area has not been thoroughly understood by SCE. Load flow modeling was unable to simulate the phenomenon. A consultant was hired but so far has been unable to provide answer. More testing and study are needed to understand the problem and find a long-term solution.

28. Replace Wavetraps on the Midway-Vincent #3 500kV line (SCE and PG&E Joint Project)

Recommendation: Order completion of the project, which adds 200 MW of transmission capacity on congested lines between Northern and Southern California for under $1 million.

Project Description (Scope): Replace 3,000Amps wavetraps with 4,000 Amps ones at the Midway (PG&E) and Vincent (SCE) substations.

The Problem: Congestion happens often on Path 26, which is the interface between PG&E and Edison's transmission systems. The congestion reduces market efficiency by restrict the free flow electricity.

· Existing wavetraps limit routine flows to 2800 MW (see technical discussion).

· Demand for Path 26 often exceeds that capacity.

· The ISO allocates available capacity by imposing congestion charges based on the difference in power prices between northern and southern California.

· Another way to look at this is that cheaper generation goes unused in one region, while more expensive generation must be used in the other

· Total power costs statewide therefore increase due to congestion (though the region in surplus may benefit temporarily)

· The ISO started running Path 26 at 3000 MW since later last summer on expectation that wavetraps will be replaced.

Costs and Benefits: Replacing wavetraps will increase capacity by 200 MW, reducing congestion charges by estimated $5 million per year.

· The Wavetraps on line #3 are the current limiting factor on Path 26 (see technical details, below), since they could be damaged if contingencies occur when power flows exceed the 2800 MW rating.

· Replacing the wavetraps will cost less than $1 million, and allow routine power flows at 3000 MW, reducing congestion charges by $5 million per year.

Environmental Impacts & Other Policy Issues (relation to other projects): Minimal, involving replacing equipment at two substations.

Technical Issues:

· Path 26 consists of three 500 kV lines between Midway and Vincent substations.

· Each line has a wavetrap at each substation, which detects high frequency communications signals transmitted along with power flows.

· The signals help assure that both ends of the line disconnect simultaneously in response to faults (electrical shorts); this is crucial to preventing damage to the line.

· The wavetraps are able to handle normal current flows.

· However, lines #1 and #2 share a right-of-way, so a simultaneous failure is considered credible, and utilities must plan for it under WSCC and ISO reliability criteria. (Line #3 runs in a separate right of way).

· Simultaneous failure when power flows exceed 2800 MW would send a much larger than normal power flow across line #3, pushing its wavetraps above their emergency ratings, and shortening their life.

· Because of the low cost and high benefits, the ISO has assumed that these wavetraps will be replaced.

· Further, while a simultaneous outage is credible, it's not very likely; and wavetraps would probably continue to function for a while.

· Therefore, late this summer, the ISO allowed Path 26 flows to reach 3000 MW at times.

29. Replace Wavetraps on the Alamitos-Barre #2 230kV Line

Recommendation: Order completion of the project, which eliminates a potential overload on the Alamitos-Barre #2 230kV line for under $1 million.

Project Description (Scope): Replace 2,000Amps wavetraps on the Alamitos-Barre #2 230kV line with 3000Amps wavetraps.

The Problem: The 2,000 Amps wavetraps on the Alamitos-Barre #2 230kV line have an emergency rating of 2,140 Amps. A generator (SONGS unit) outage in combination with a transmission line (Alamitos-Barre #1 230kV line) outage loads the wave trap on the Alamitos-Barre #2 line to 2,270 Amps in 2001, and 2,310 Amps in 2005. This violates WSCC and ISO planning criteria requirement that all equipment stays within its emergency rating on overlapping contingencies of one generator and one transmission element.

Costs and Benefits: Replacing wavetraps will eliminate the potential overload on the Alamitos-Barre #2 230kV line for less than $1 million.

Environmental Impacts & Other Policy Issues (relation to other projects): Minimal, involving replacing equipment at two substations.

Technical Issues: Wavetraps are communication devices. Their function can also be achieved by other means, like fiber optics, which could be more cost effective in some cases. SCE's study concludes that higher rating wavetraps is the most economic alternative.

30. Reconductor Rancho Santa Fe Tap-Bernardo Tap 69kV (BP98187)

Recommendation: Order completion of the project, which reconductors Rancho Santa Fe Tap-Bernardo Tap 69kV for between $1 to $5 million.

Project Description (Scope): Reconductor 6.8 miles of 69kV line to 1033ACSR, replace two 69kV oil circuit breakers to 1200A, and replace bus to twin 500kcmil CU.

The Problem: Rancho Santa Fe Substation is located in the northern part of San Diego County. It has two supply sources coming from Rancho Santa Fe Tap and Bernardo Tap. In certain normal conditions, there is enough flow though power that the lines are overloaded. One of the line has to be opened to eliminate the overload. This leaves the Rancho Santa Fe Substation with only one power source. This violates the planning criteria requirement which calls for two transmission feeds for substation with more than 15MW of load. For 2001, the forecasted peak load is 24.1MW for Rancho Santa Fe Substation. The lines also have 20% overload on contingencies of Poway-Pomerado TL 6913 line and 12% overload on contingency of Encina-Penasquito TL2301 line, respectively.

Costs and Benefits: Reconductoring will increase the transmission lines capacity from 27MVA to 136.8MVA. This capacity increase will enable Rancho Santa Fe Substation to have two power sources at all time. Cost: between $1 million and $5 million.

Environmental Impacts & Other Policy Issues (relation to other projects): The transmission lines go across 2-5 acre lots. Most of the lots and homes have been in this area since the 1930's with no problems due to this transmission arrangement. Since this project will increase reliability in the area, minimal opposition is expected.

Alternatives: The cheaper alternative to reconductoring the line is to establish an emergency rating for the line. However, the establishment of emergency rating is infeasible due to the 12kV underbuild.

Technical Issues: The WSCC and ISO planning criteria require Rancho Santa Fe Substation to normally have two power sources. Starting in year 2000, the changing load flow pattern cause one power source be removed to prevent overloading on the line in certain periods of time. This reduces Rancho Santa Fe Substation's reliability and violates planning criteria. Completion of this project will address the reliability problem for Rancho Santa Fe Substation.

31. New 224MVA 230/69kv Transformer at Escondido Substation (BP99117)

Recommendation: Order completion of the project, which install a new 224MVA 230/69kV transformer at the Escondido Substation for between $5 to $10 million.

Project Description (Scope): Install a new 224MVA 230/69kV transformer at Escondido Substation.

The Problem: Escondido Substation locals at northern part of San Diego County. It supplies power to several 69kV substations in surrounding area. There are two existing 230/69kV transformers, Bank 70 and Bank 71. Bank 71 has a Normal Rating of 224 MVA. By 2001, if there is an outage of 230/69kV Bank 70, it will cause an overload on the remaining 230/69kV Bank 71. The overload during this outage would be 5% above the Maximum Allowable Rating of 261 MVA for Bank 71. Thus, could result firm load dropping of about 11MW.

Also, San Diego's import capability for 2001 is short of 29MW on contingencies of overlapping outages of one generator and one transmission element (G-1/N-1). Firm load will have to be dropped during peak hours when such contingencies happen.

Costs and Benefits: Enhance reliability for the area Escondido Substation serves by eliminating the potential overload on Bank 71 and about 11MW of firm load dropping the overload results. This project also increases San Diego import capability by 200MW, which enhance reliability for the entire San Diego area as well as reduce future RMR cost for the area. The lifetime RMR cost saving is estimated at $29 million. Cost: between $5 million and $10 million.

Environmental Impacts & Other Policy Issues (relation to other projects): Minimal, involving installing equipment at one substation.

Technical Issues: WSCC and ISO planning criteria require all equipment within emergency limit, no load were dropped in N-1 (including G-1/N-1) contingency. Starting 2001, outage of Bank 70 will cause Bank 71's loading over its emergency limit. The situation will get worse in years after as load in the area continue to grow. Completion of this project will address the reliability problem in the area as well as San Diego's import capability shortage.

PROJECT LIST RECONCILIATION