SoCalGas - Annual Report of System Reliability Issues
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Annual Report of System Reliability Issues

Date of Issue: November 4, 2010


Beginning in 2010 SoCalGas is required to post an annual report (Report) of system reliability issues on its website ( at least two weeks prior to each annual SoCalGas Customer Forum (Forum) in compliance with Section E.4 of Rule No. 33.

This Report is being submitted in advance of the Forum scheduled for Thursday November 18, 2010.

This Report:

(1) Identifies the need for any new minimum flow requirements beyond those on the Southern System;

(2) Identifies potential tools and infrastructure improvements to mitigate reliability problems;

(3) Provides information on the following items. 

  1. Operational Flow Order (OFO) event triggers including timing, method, formulas and formula inputs;
  2. Requests made to Operational Hub for additional supplies to meet minimum flow requirements;
  3. Review of Operational Hub transactions to meet past years minimum flow requirements and plans for the coming year.  Information is provided on a transaction-specific level that includes price, volume, date, point of delivery and any special terms.


(4)  Provides hourly linepack data for 2009 and 2010.

Section 1 - New Minimum Flow Requirements

No new minimum flow requirements are needed beyond those currently required for the Southern System at this time on the SoCalGas system to maintain capacity in a safe and reliable manner.

Section 2 – Potential Tools and Infrastructure Improvements

Potential Tools

No new potential tools have been identified to mitigate the Southern System minimum flowing requirement.

Infrastructure Improvements

a. Line 6916

Late in 2008 SoCalGas acquired the California portion of the Questar Southern Trails pipeline between Essex and Twenty-nine Palms. Together with a previously acquired section of that pipeline between Twenty-nine Palms and Cabazon, SoCalGas began conversion of this line into an interconnection linking SoCalGas’ Northern Transmission Zone with the Southern Transmission Zone. This new transmission facility, called Line 6916, consists of 115 miles of 16-inch diameter pipeline capable of transporting up to 80 MMcfd between the two systems when needed operationally, reducing the flowing supply requirement at Blythe on a 1:1 basis.

Final permits were received from the BLM in July 2010 to perform construction required to make Line 6916 operational. SoCalGas expects to have Line 6916 in service during the 1st quarter of 2011.

b. Vidal Valley Link

In order to more fully integrate the SoCalGas Northern and Southern Transmission Zones and partially mitigates the need for flowing gas supply requirements on the Southern Transmission Zone SoCalGas would have to construct a 100 mile long 36-inch diameter pipeline interconnect west of the California-Arizona Border between Needles and Blythe. In conjunction with the new pipeline SoCalGas would also have to rework the Newberry Compressor Station to enable the compression of gas transported in an easterly direction back to Needles and into the new link to flow south to Blythe and the Southern Transmission Zone.

The fully-loaded cost of this system upgrade is estimated to be $ 325 million and would take approximately 5 years to complete. This preliminary cost estimate is based on historical project data.  SoCalGas has not performed a detailed specific site or route evaluation for this project in the development of this estimate. Additionally, costs associated with permitting, paving, right-of-way, environmental, gas quality, measurement, regulatory, and land acquisition/development issues; and any unusual construction costs or facility requirements (e.g. freeway, river, or channel crossings) are explicitly excluded from this preliminary cost estimate. At this time, SoCalGas has no plans to immediately pursue this project.

Section 3 – Informational Items

a. Operational Flow Orders

The SoCalGas/SDG&E Gas Control department has the sole responsibility to determine the need for and declaring an OFO. An OFO may be issued only if the level of scheduled quantities specified from Rule No. 41 in the table below for each transportation nomination cycle exceeds the forecasted system capacity.


Quantity Used for OFO Calculation

1) Timely

Prior Flow Day – Evening Cycle Scheduled Quantity

2) Evening

Current Flow Day – Timely Cycle Scheduled Quantity

3) Intraday 1

Current Flow Day – Evening Cycle Scheduled Quantity

4) Intraday 2

Current Flow Day – Intraday 1 Cycle Scheduled Quantity

Forecasted system capacity is the sum of forecasted sendout, physical storage injection capacity and available off-system nominations. 

Gas Control develops the send out forecast by using public weather data for estimating core demand (wholesale and retail) and market information and historical data for noncore customer demand. Gas Control also makes use of demand forecast data provided directly from the California Independent System Operator (CAISO) which accounts for approximately 80% of the electric generation demand on the SoCalGas/SDG&E system.

A total of 85 OFO events were called from October 1, 2008 to October 31, 2010. Attachment 1 provides a detailed calculation for each OFO event including calculation of forecasted system capacity in comparison to scheduled quantities.

The normal trigger for OFO events are nominations in excess of system capacity. This typically occurs during weekends and holidays when forecast sendout is lower.

On August 27, 2010 the Commission approved Advice Letter No. 4139 (AL 4139). AL 4139 required SoCalGas to give priority to prior cycle scheduled quantities over new or unscheduled nominations for equivalent priority capacity when allocating capacity for Cycle 3 on an OFO day. Prior to the approval of AL 4139 capacity was allocated in Cycle 3 based on customer confirmed nominations which often led to higher nominations after an OFO event was announced.

Since AL 4139 was approved only two OFO events (October 9 and 16) have been called. No Cycle 3 capacity cuts were made on the October 16 event. More importantly, it appears that five OFO events avoided since AL 4139 was approved. Exhibit 2 provides the OFO Calculation for these specific dates where OFOs were avoided.

b. Requests to the Operational Hub for additional supplies to meet minimum flow requirements

On September 30, 2010 SoCalGas submitted Advice No. 4153 (AL 4153) containing the Annual Compliance Report on Utility System Operator’s Southern System Reliability Purchases and Sales (ACR). AL 4153 including the ACR is included in this Report as Attachment 3. No protests were made to AL 4153.

Requests to the Operational Hub for additional supplies to meet minimum flow requirements (Requests) from April 1, 2009 through August 31, 2010 can be found in Attachment C of AL 4153. No additional Requests were received between August 31 and October 1, 2010.

c. Operational Hub Transactions to Meet Minimum Flow Requirements

The ACR provides transaction level detail for Operational Hub transactions to meet minimum flow requirements from April 1, 2009 through August 31, 2010. These transactions can be found in Exhibit 1 and Exhibits 3-7 of the ACR. 

Prospectively, SoCalGas is looking forward to Line 6916 going into service by March 2011. Based upon scheduled rates, operation of this facility could allow minimum flow requirements to be reduced by up to 80 MMcfd. SoCalGas plans on using call options and spot purchases over the next year to meet its minimum flow requirements. Base load purchase agreements will not be used this winter due to the relative expense of prior base load purchase agreements in comparison to available spot level purchases. 

Section 4 – Hourly Linepack Data

SoCalGas committed to provide hourly linepack data for 2009 and 2010 as provided in the SoCalGas response to Shell’s 4th Data Request, Question No. 1 in A. 08-02-001. Attachment 4 to this Report contains the requested data.

The units for linepack are in MMCF. The Gas Control department strives to operate the system such that there is no net change to the level of system linepack at the end of an operating day. However, since the level of system linepack is a function of system demand and available supply, an operating day may actually end in a net pack or net draft position. Furthermore, whether the level of linepack at the beginning of the operating day is sufficient to maintain system reliability is dependent upon the anticipated level of demand and available supply.

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