8.5 System Operation

The proposed project, as part of SFPP’s regional pipeline system, will be remotely operated from SFPP’s central control facility at its Headquarters office in Orange, with back-up monitoring at the Watson and Colton stations. A staff of 16 people are currently employed at the central facility and are responsible for system control and operation 24 hours per day.

System Control, Operation, and Safety Features

The computerized system of pipeline communications and system control is referred to as the Supervisory Control and Data Acquisition (SCADA) system. The function of this system is to send instructions to and receive information from Programmable Logic Controllers (PLCs) located at remote stations and other stations along the pipeline.

SFPP’s safety system is based on a SCADA system, gathering and analyzing data from many sources throughout the system. The pumps are equipped with various safety devices such as pressure sensing devices, electrical current and temperature measuring devices to assure reliable and safe operation of the pumps. The pipeline is protected by pressure control valves as well as pressure measuring devices. The computerized SCADA system constantly gathers operational data from the critical sources throughout the system and automatically adjusts the pressure and flow rate of the pipeline to provide for safe operation of the system.

8.6 System Maintenance

A maintenance staff of 15 people currently works in the field carrying out routine inspection and maintenance as well as responding to possible system upset and/or failure emergencies. No additional positions will be added to SFPP’s existing staff as a result of this project.

Inspections

The pipeline route will be visually inspected at least bi-weekly by line rider patrol in accordance with U.S. Department of Transportation (DOT) requirements (49 CFR Part 195) to spot third-party construction or other factors that might threaten the integrity of the pipeline. Additionally, inspection of highway, utility, and pipeline crossing locations will be conducted in accordance with state and federal regulations. Pipe protection level will be inspected annually at all test locations, quarterly at control points and more than quarterly at cathodic protection systems to ensure corrosion control.

Pigging

SFPP will "smart pig" the line in accordance with DOT standards. Pigs or scrapers are devices inserted into the pipeline at launching points and retrieved at receiving points called scraper traps. Pigs are used to clean and/or inspect the pipeline. "Smart" pigs are devices used to inspect and record the condition of the pipe. Smart pigs detect where corrosion or other damage has affected the wall thickness or shape.

Hydrostatic Testing

SFPP will perform hydrostatic testing as required by DOT at certain intervals during pipeline operation to determine whether the pipe, fittings, and weld sections can maintain mechanical integrity without failure or leak under pressure. The test involves filling the pipeline with fresh water or other fluid and increasing the pressure by means of a pump equivalent to 125 percent of the maximum operating pressure (MOP) for a period of at least four hours. Following the four hour test the pressure will be reduced to 110 percent of MOP and held for at least four additional hours. After testing, the used water will be discharged into an existing sewer system or used in dust abatement. Discharge to any surface waters will only occur with approval and a permit from the Regional Water Quality Control Board.

Valves

SFPP will cycle and inspect block valves twice annually, at intervals not to exceed every 7 months, to ensure proper operation (per 49 CFR 195.420).

8.7 Emergency Response

SFPP has prepared an Oil Spill Response Plan (OSRP) for review and approval of appropriate federal, state, and local agencies (including Department of Fish and Game, Office of Spill Prevention and Response). The OSRP is required under state and federal regulations (SB 2040 and 40 CFR 300, the Hazardous Substances Pollution Contingency Plan). The OSRP provides a finalized list of emergency service providers. SFPP has also prepared an Emergency Response Plan to specify measure to be taken in emergency scenarios. These documents identify the responsible parties for the incident command and the supporting organizations/agencies. Normally, the fire department commanders remain the incident commander until relieved by other authorities legally required to assume responsibility for the incident.

SFPP’s terminal and pump stations have fire fighting and other emergency equipment. Fire fighting equipment includes carbon dioxide and/or halon fire extinguishers inside the control rooms for electrical fires around panels and switch gear. Dry powder fire extinguishers are located in the station yard for hydrocarbon fires. Fire suppressant foaming agents (ATC concentrate) and related foam generation equipment is also onsite or readily available. Also, emergency call lists are posted at all stations, in case of accident, fire, or explosion.

SFPP has a contractual agreement with a regional spill response cooperative that will serve as the emergency response contractor with primary responsibility for containment, cleanup, and health and safety. The OSRP lists third-party contractors providing manpower and equipment such as vacuum trucks, boats, oil skimmers, absorbent and skirted booms, dump trucks, portable tanks, absorbent materials, dispersants, steam cleaners, hydroblasters, cranes, and forklifts. These include contractors located in the Los Angeles Harbor area. In addition, SFPP operations personnel are trained in the Incident Command System and oil spill containment and cleanup procedures. In the event of an pipeline spill or fire, local emergency response providers will be notified to assist in traffic control, evacuations of homes or businesses, crowd control, ambulance and hospital services, and backup fire protection services.

8.8 Abandonment and Decommissioning

The expected operational life of the pipeline is at least 50 years. At the end of the pipeline’s life, SFPP will begin the decommissioning process, subject to appropriate local, state, and federal regulations enforced at the time of abandonment. As required by Federal and State laws, SFPP is liable for cleaning up and remediation of any potential contamination that could have resulted from the operation of the pipeline.

In the decommissioning process, SFPP will clean and inspect the drained pipeline. Valves at all delivery points, receiving stations and pump stations will be sealed and all block valves closed; check valves will be left intact. The purged, sealed pipeline will be filled with pressurized inert nitrogen gas and abandoned in place.

The abandoned pipeline could possibly be used for other purposes, for example as a wastewater conveyance or as a conduit for underground electrical utilities, cable TV, fiber-optic lines, telephone or data circuits. The inert gas pressure in the abandoned pipeline will be annually monitored. Any loss of pressure in a pipeline segment would indicate a leak that will be located and repaired in a timely manner.

8.9 Determination of Impact Significance and Applicant Proposed Impact Reduction Measures

It should be noted that the proposed project as described in the Proponent’s Environmental Assessment (PEA) includes measures that SFPP proposes to utilize to reduce identified impacts in many issue areas. In some cases these measures are presented as "mitigation measures" and labeled, for example as Mitigation Measure T-1. In other cases (e.g., in Section 3.1.2.4, Public Health, Safety and System Reliability), the PEA references pipeline design measures or construction practices that would minimize the impacts of the proposed project. In both cases, this Initial Study is prepared with the assumption that these "Applicant Proposed Measures" (APMs) would be implemented.

To clarify terminology, "mitigation measures" are generally imposed by a reviewing agency and not included in project design. As a result, in the impact analysis for the environmental checklist that follows, these APMs are considered to be part of the proposed project itself, and not considered as mitigation. The determination of impact significance is made based on the assumption that these APMs will be implemented as stated by SFPP during project construction and operation.

9. Surrounding Land Uses and Setting: As described above, the proposed pipeline traverses a variety of urban land uses. Those uses are summarized in the Table 2 on the following page.

10. Other public agencies whose approval is required. Table 3 on the following page lists agencies that have responsibility for approving or permitting some aspect of the proposed project, and the type of permit they would issue.

Table 2. Summary of Land Uses

Table 3. Approvals/Permits Required

ENVIRONMENTAL FACTORS POTENTIALLY AFFECTED:

The environmental factors checked below would be potentially affected by this project, involving at least one impact that is a "Potentially Significant Impact" as indicated by the checklist on the following pages.

	Land Use and Planning		Biological Resources		Public Services
	Population and Housing		Energy & Mineral Resources		Utilities & Service Systems
	Geological Problems		Hazards		Aesthetics
	Water		Noise		Cultural Resources
	Air Quality		Mandatory Findings of Significance		Recreation
	Transportation/Circulation

DETERMINATION (To be completed by the Lead Agency)

On the basis of this initial evaluation:

I find that the proposed project COULD NOT have a significant effect on the environment, and a NEGATIVE DECLARATION will be prepared.

I find that although the proposed project could have a significant effect on the environment, there will not be a significant effect in this case because the mitigation measures described on an attached sheet have been added to the project. A NEGATIVE DECLARATION will be prepared.

I find that the proposed project MAY have a significant effect on the environment, and an ENVIRONMENTAL IMPACT REPORT is required.

I find that the proposed project MAY have a significant effect(s) on the environment, but at least one effect 1) has been adequately analyzed in an earlier document pursuant to applicable legal standards, and 2) has been addressed by mitigation measures based on the earlier analysis as described on attached sheets, if the effect is a "potentially significant impact" or "potentially significant unless mitigated." An ENVIRONMENTAL IMPACT REPORT is required, but it must analyze only the effects that remain to be addressed.

I find that although the proposed project could have a significant effect on the environment, there WILL NOT be a significant effect in this case because all potentially significant effects (a) have been analyzed adequately in an earlier EIR pursuant to applicable standards and (b) have been avoided or mitigated pursuant to that earlier EIR, including revisions or mitigation measures that are imposed upon the proposed project.

________________________________ Douglas M. Long, Manager Decision-Making Support Branch Energy Division California Public Utilities Commission

_____________________________ Date

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