18. Ex Parte Communications

Article 8 of the Commission's Rules of Practice and Procedure applies to all communications with decisionmakers and advisors regarding the issues in this proceeding. This proceeding is categorized as ratesetting and Rule 8.2(c) restricts ex parte communications under certain circumstances and requires reporting. In addition, because this proceeding is closely related to expected adjudicatory proceedings, we authorize the assigned Commissioner pursuant to Rule 1.2 of the Commission's Rules of Practice and Procedure, to issue such further ex parte limitations, including complete prohibition, as may be necessary to ensure a just resolution of the issues presented.

IT IS ORDERED that:

1. The Commission hereby institutes this rulemaking on its own motion to initiate rule and policy changes for California natural gas transmission and distribution utilities.

2. Pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern California Gas Company, and Southwest Gas Corporation are named as respondents and are parties to this proceeding pursuant to Rule 1.4(d) the Commission Rules of Practice and Procedure (Rules). All natural gas distribution utilities including, West Coast Gas, Alpine Natural Gas, and Southern California Edison (Catalina Island), as well as natural gas storage companies, Wild Goose Storage, Lodi Gas Storage, Gill Ranch Storage, and Central Valley Gas Storage, and Sacramento Natural Gas Storage, LLC (if Application 07-04-013 is granted) are placed on notice that they may be subject to the decisions issued in this rulemaking, and this order shall be served upon them. Any error or omission in the service list shall not excuse any gas utility from complying with the decisions and rules issued in this proceeding.

3. No later than March 15, 2011, Pacific Gas and Electric Company and Southwest Gas Corporation shall file and serve on all parties to this proceeding their respective reports on its record review in compliance with the National Transportation and Safety Board's recommendations. San Diego Gas & Electric Company and Southern California Gas Company shall file and serve their respective reports in the record of this rulemaking no later than April 15, 2011.

4. Respondents shall be placed on the service list automatically as parties, but other interested parties and those interested in monitoring the proceeding must follow the directions set forth in Section 14 of this order instituting rulemaking to become a party or be placed on the official service list as a non-party.

5. This proceeding is classified as ratesetting, as that term is defined in Rule 1.3(e), and hearings may be necessary.

6. No later than 45 days after the mailing date of today's decision, parties may file comments that will serve as the basis for the establishment of a detailed scope for this proceeding and shall identify any other relevant procedural issues. Any person who objects to this order's determinations regarding categorization of the proceeding as ratesetting, the need for hearing, issues to be considered or scheduling shall state such objections in their comments. Comments on the proposed rule revisions set forth in Attachment A shall also be filed and served no later than 45 days after the mailing date of today's decision.

7. The Executive Director shall serve copies of this rulemaking on respondents, the other natural gas distribution and gas storage companies listed on the Commission's official records, the California Energy Commission, the Pipeline Safety Division of the State Fire Marshall, the most recent service list for General Order 112-E; Pacific Gas and Electric Company's General Rate Case, Application (A.) 09-12-020; Pacific Gas and Electric Company's Gas transmission and storage rate case A.09-09-013; San Diego Gas & Electric Company General Rate Case, A.10-12-005; and Southern California Gas Company's General Rate Case, A.10-12-006.

8. Parties serving documents in this proceeding shall comply with Section 14.4 of this order instituting rulemaking regarding electronic service. Any documents served on the assigned Commissioner and Administrative Law Judge shall be both by e-mail and by delivery or mailing a paper format copy of the document.

9. A party that expects to request intervenor compensation for its participation in this rulemaking shall file its notice of intent to claim intervenor compensation in accordance with Section 16 of this Order Instituting Rulemaking and Rule 17.1 of the Rules.

10. Ex parte communications in this rulemaking initially will be governed by Rule 8.2(c), and the assigned Commissioner is authorized to issue such further ex parte limitations, up to and including complete prohibition, as may be necessary to ensure a just resolution of the issues presented herein.

11. The assigned Commissioner or the Administrative Law Judge may make such revisions to the scheduling determinations made herein as may be necessary to facilitate the efficient management of this proceeding.

12. No later than 10 days after the effective date of this order, Pacific Gas and Electric Company shall submit to the Commission's Public Advisor for review and approval a draft customer notice of the San Bruno Public Participation Hearing with a mailing plan for timely notice to all customers.

This order is effective today.

Dated February 24, 2011, at San Francisco, California.

MICHAEL R. PEEVEY

President

TIMOTHY ALAN SIMON

MICHEL PETER FLORIO

Commissioners

Commissioner Catherine J.K. Sandoval, being necessarily absent, did not participate.

Attachment A - Proposed Rules for Immediate Implementation

A. New section for General Order 112 - E

145 STRENGTH TEST REQUIREMENTS FOR CERTAIN PIPELINES OPERATED BY PACIFIC GAS AND ELECTRIC COMPANY

145.1 Pacific Gas and Electric Company is prohibited from operating any natural gas transmission line that meets all of the characteristics listed in subsection 145.2 at more than 80% of actual maximum operating pressure reliably and verifiably recorded during the period February 15, 2006 through February 15, 2011. All overpressure protection devices on each such line must be set to control pressure to not exceed the limit established by this subsection.

145.2 The operating limitation set forth in Rule 145.1 applies to all natural gas transmission lines exhibiting all of the following characteristics:

145.2.1 Operated by Pacific Gas and Electric Company

145.2.2 Installed before January 1, 1970

145.2.3 Located in a High Consequence Area of Class 1 or Class 2, or in any area of a Class 3 or 4 pipeline location classification as defined in 49 CFR § 192.5.

145.2.4 Reliable, verifiable, and complete records of strength testing in accord with 49 CFR subpart J are not available for inspection by authorized Commission or federal pipeline authorities.

145.3 Pacific Gas and Electric Company may seek temporary exemptions from the above requirements as follows:

145.3.1 For exemptions to allow operating up to 90% of recorded maximum operating pressure and limited to no more than 30 days at the higher operating pressure, Pacific Gas and Electric Company may submit a letter request to the Commission's Executive Director, who, in consultation with the Commission's pipeline safety personnel, may grant, deny, or modify the request. Any such letter request must be submitted no less than 45 days before the proposed start date, with a copy sent to all municipalities in which the pipeline is located and parties in R.11-02 -___, or a successor proceeding. Pacific Gas and Electric Company will be responsible for serving the Executive Director's responsive letter on all municipalities and parties to R.11-02-___ or a successor proceeding.

145.3.2 Any other exemption requests will be by formal application to the Commission in accordance with the Commission's Rules of Practice and Procedure.

B. Proposed Revisions to Reporting Requirements in General Order 112-E, Section 122.2 (revisions underlined in bold)

122.2 Requirements for reporting to the CPUC.

(a) Each operator shall report incidents to the CPUC that meet the following criteria:

1. Incidents which require DOT notification.

i. An event that involves a release of gas from a pipeline or of liquefied natural gas (LNG) or gas from an LNG facility and

· A death, or personal injury necessitating in-patient hospitalization; or

· Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more.

ii. An event that results in an emergency shutdown of an LNG facility.

2. Incidents which have either attracted public attention or have been given significant news media coverage, that are suspected to involve natural gas and/or propane (LPG), which occur in the vicinity of the operator's facilities; regardless of whether or not the operator's facilities are involved.

3. Incidents where the failure of a pressure relieving and limiting stations, or any other event, results in pipeline system pressure exceeding its established Maximum Allowable Operating Pressure (MAOP) plus the allowable limitations set forth in 49 CFR § 192.201.

4. Incidents in which an under-pressure condition, caused by the failure of any pressure controlling device, or any other event other than excavation related damage, results in any part of the gas pipeline system being shut-down.

(b) (unchanged)

(c) Written Incident Reports .

1. The operator shall submit to the CPUC on DOT Form PHMSA F7100.1 ( http://ops.dot.gov/library/forms/forms.htm#7100.1)for distribution systems and on DOT Form PHMSA F7100.2 ( http://ops.dot.gov/library/forms/forms.htm#7100.2) for transmission and gathering systems a report describing any incident that required notice under Items 122.2(a)(1) or (2).

2. Together with the form required by (c)(1) above, the operator shall furnish a letter of explanation giving a more detailed account of the incident unless such letter is deemed not necessary by the CPUC staff. The operator may confirm the necessity of a letter of explanation by email. If, subsequent to the initial report or letter, the operator discovers additional material information related to the incident, the operator shall furnish a supplemental report to the CPUC as soon as practicable, with a clear reference by date and subject to the original report. These letters, forms, and reports shall be held confidential under the provisions of Paragraph 2, Exclusions, of General Order 66-C and Public Utilities Code Section 315.

3. The operator of a distribution system serving less than 100,000 customers need not submit the DOT forms required by paragraph (1) above; however, such operator must submit the letter of explanation required by (2) above, subsequent to any initial report to the CPUC, unless such letter is deemed unnecessary by the CPUC staff.

(d) Quarterly Summary Reports. Each operator shall submit to the CPUC quarterly, not later than the end of the month following the quarter, a summary of all CPUC reportable and non-reportable gas leak related incidents which occurred in the preceding quarter as follows:

1. Incidents that were reported through the Commission's Emergency Reporting website.

2. Incidents for which either a DOT Form PHMSA F7100.1 or F7100.2 was submitted.

3. Incidents which involved escaping gas from the operator's facilities and property damage including loss of gas in excess of $1,000.

4. Incidents which included property damage between $0 and $1,000, and involved fire, explosion, or underground dig-ins.

5. Incidents where the failure of a pressure relieving and limiting stations, or any other event, results in pipeline system pressure exceeding its established Maximum Allowable Operating Pressure (MAOP).

6. Incidents in which an under-pressure condition, caused by the failure of any pressure controlling device, or any other event other excavation related damage, result in a shut-down of any part of the gas pipeline system.

C. Proposed Revisions to Rule 125 - This entire rule is revised. The proposed new text is set out below.

125 PROPOSED INSTALLATION REPORT

125.1 This section applies to the construction of a new pipeline, or the reconstruction or reconditioning of an existing pipeline, to be operated at a hoop stress of 20 percent or more of the specified minimum yield strength.

125.2 The proposed installation reports required by this section shall be filed based on the following:

(a) For utilities with less than 50,000 services in the state of California according to the Annual DOT Report, Form PHMSA F 7100.1-1 that is required by 49 CFR §191.11, the Proposed Installation Report shall be submitted to the Commission for any installation that is estimated to cost $1,400,000 or more. The Annual DOT Report referenced above shall be the report filed by the utility for the year previous to that of the proposed installation; or

(b) For utilities with 50,000 services or more in the state of California according to the Annual DOT Report, Form PHMSA F 7100.1-1 required by 49 CFR §191.11, the Proposed Installation Report shall be submitted to the Commission for any installation that is estimated to cost $3,500,000 or more. The Annual DOT Report referenced above shall be the report filed by the utility for the year previous to that of the proposed installation.

125.3 Definitions:

(a) "Construction of a new pipeline" means the installation of pipeline that will serve as a loop or extension to an existing pipeline or as an independent or stand-alone pipeline, any of which will be placed in service for the first time by an operator who filed a Form PHMSA F-7100.1-1 for the calendar year preceding the year in which construction takes place. An operator commencing service for the first time shall file a Proposed Installation Report with the Commission after receiving CPCN approval from the Commission and prior to the start of construction of the approved project.

(b) "Reconstruction of an existing pipeline" means the installation of pipeline that will replace an existing pipeline or pipeline segment due to alignment interference, deteriorating or aging conditions, pressure/capacity enhancement, or other reason. 

(c) "Reconditioning of an existing pipeline" is defined as the work associated with repairing, structurally reinforcing, the replacement of fittings or short segments of pipe, or for the removal and reapplication of pipe coating. The term does not include altering or retrofitting a pipeline or its appurtenances to allow for the passage of internal inspection devices.

125.4 At least 30 days prior to the construction of a new pipeline, reconstruction, or reconditioning of an existing pipeline, a report shall be filed with the Commission setting forth the proposed route and general specifications for such pipeline. The specifications shall include but not be limited to the following items:

(a) Description and purpose of the proposed pipeline.

(b) Specifications covering the pipe selected for installation, route map segregating incorporated areas, class locations and design factors, terrain profile sketches indicating maximum and minimum elevations for each test section of pipeline, and, when applicable, reasons for use of casing or bridging where the minimum cover will be less than specified in §192.327.

(c) Maximum allowable operating pressure for which the line is being constructed.

(d) Test medium and pressure to be used during strength testing.

(e) Protection of pipeline from hazards as indicated in §192.317 and §192.319.

(f) Protection of pipeline from external corrosion.

(g) Estimated cost with supporting detail.

In cases of reconditioning projects that do not result in relocating pipeline from the general location it occupies prior to the project, then the information stated in Section 125.4 (b) does not need to be provided within the report filed per Section 125.4. Also, in cases of projects necessary on an emergency basis, the report required by Section 125.4 shall be filed with the Commission as far in advance of the project as practicable, but no later than 5 business days after the project has been initiated. Reports filed for emergency projects, in addition to other information required per Section 125.4, must also detail reasons that necessitated the project being performed on an emergency basis.

125.5 During strength testing of a pipeline to be operated at hoop stresses of 20 percent or more of the specified minimum yield strength of the pipe used, any failure shall be reported on appropriate forms established by the Secretary of Transportation to comply with the requirement of 49 CFR, §191.15. Copies of all reports submitted to the Secretary of Transportation pursuant to the foregoing requirements shall be submitted to the Commission concurrently.

(End of Attachment A)

Attachment B - Topics on which new rules will likely be proposed

Retrofitting of transmission lines to allow inline inspections

Rationale:  The technology for inline inspection of pipelines is continuously advancing and CFR 49, Part 192 recognizes this advancement in technology by requiring new transmission pipelines to be "piggable" (capable of being inspected by inline inspection tools).  However, our current aging pipeline infrastructure may contain conditions which may or may not allow such inline inspection tools to be used.  The new rule aims to promote the use of inline inspection technology in natural gas transmission pipelines throughout California.

Description:  The rule will require operators of natural gas transmission lines to establish a program that will continuously evaluate and prioritize transmission pipelines that are currently considered "non-piggable" to be retrofitted to allow inline inspection tools.  The rule will require operators to make continuous upgrades throughout their transmission systems such that, in a specified period of time, all transmission lines in California can accommodate inline inspection tools.

Require operators to perform evaluations for installing automatic or remote controlled valves on transmission pipelines 

Rationale: When a transmission line fails, it is important that an operator be able to respond in a timely fashion to a failure, especially if the failure is in a High Consequence (as defined in CFR 49, Part 192, Subpart O), Class 3 or Class 4 area.  Long distances and availability of personnel can impact this response.  A delayed response can result in loss of life and property damage. 

Description: This rule would require utilities to develop criteria for installing either automatic or remotely controlled valves located in High Consequence, Class 3 or Class 4 areas.  Considerations must include the location of the valve and the estimated response times.

Require operators to strengthen emergency response procedures

Rationale: Current rules in General Order 112-E and 49 CFR, Part 192 do not have specific incident response time requirements for operators. 49 CFR §192.615 (a)(3) requires "prompt and effective response to a notice of each type of emergency". "Prompt" and "effective" response by an operator should be improved upon in light of recent events. 

Description: The new rule would require that each operator to establish a program to monitor and analyze emergency response data in order to improve incident response time and response effectiveness. 

Requirement for the gas quality monitoring

Rationale: Liquid intrusion or sulfur buildup in an operator's pipeline can result in equipment failure which can cause the pipeline system pressure to exceed its Maximum Allowable Operating Pressure (as defined in CFR 49, Part 192).  With a program in place to monitor, analyze, and prevent liquid intrusion or sulfur buildup in a pipeline system, the likelihood of additional equipment failures due to liquid intrusion or sulfur buildup would be minimized.

Description: The new rule would require that each operator have a program in place to monitor, analyze, and prevent liquid intrusion and sulfur buildup in its pipeline system. 

Test requirements for pipelines operating below 100 psig and service lines

Rationale: Current rules do not specify durations for pressure tests for both distribution mains operating below 100 psig and service lines.  Additionally, there is no specific requirement for pressure test on service lines to be operated at less than 1 psig.  Instead, 49 CFR Part 192.511(a) contains a general statement requiring service lines to be tested for leaks at the operating pressure.  The proposed rule will define minimum pressure test durations and provide consistency for pressure test requirements for both distribution mains operating below 100 psig and service lines

Description: Consistent with the pressure test requirements for mains operating below 1 psig, the proposed rule will require new service lines to be operated below 1 psi gage to be pressure tested at a minimum pressure of 10 psi gage.  The proposed rule will also require short sections of pipeline used for repairs to be pressure tested at the operating pressure, at a minimum.  The minimum pressure test durations for new installations and repairs should be explored during the rulemaking process.

Clearance between gas pipelines and other subsurface structures

Rationale: The Commission's General Order 128 provides clearance requirements for underground electric and communication systems from other underground utilities, including gas pipelines.  The proposed rule will include these clearance requirements to provide uniformity for all underground utilities operators throughout California.

Description: The new rule will maintain the current requirement for transmission lines per 49 CFR 192.325, and contain similar clearance requirements as General Order 128, Rule 31.4.  It will also address instances wherein, if the required separations cannot be obtained, the party installing facilities will be required to contact the operator of the existing gas facilities near their installation to ensure that reduced separation will not compromise the integrity of the existing gas facilities.

Incorporating One-Call Law requirements for marking underground facilities

Rationale: Currently, CFR 49, Part 192, section 192.614(a) requires operators of buried pipelines to participate in "a written program to prevent damage to that pipeline from excavation activities."  The operator can substantially meet the requirements of 192.614 by participating in a qualified one-call system, and California has such a program that operators participate in (Government Code Sections 4216-4216.9).  The One Call Law has certain requirements for both pipeline operators and excavators.  One of these requirements addresses the need to accurately mark their facilities.  Inaccurate markings are one cause of dig-ins.  While section 192.614 provides an option for a utility to participate in the one call system, it does not mandate utilities to accurately mark their facilities. 

Description: This rule would incorporate the one call law by reference it into the general order and require jurisdictional utilities to accurately mark their facilities, as well as meet all other requirements contained therein. 

Report Cathodic Protection deficiencies and provide a timetable for remedial actions

Rationale: Cathodic Protection (CP) is an integral part of the system that prevents buried underground metallic pipe from rusting.  The longer an underground piping system stays without this protection, the more the pipe will rust and compromise its integrity.  For a variety of reasons, pipeline operators can and do take extended periods of time to restore areas to proper levels (defined in Part 192, Appendix D).  Some of the causes are within the operator's control, and some are outside of the operator's control. 

Description: This rule would require operators to report to the Utilities Reliability and Safety Branch (USRB) any CP systems that remain down for a period longer than six months.  It would also require operators to provide a timetable for restoring the CP, and the reasons for the delay.  This would provide the USRB a method to proactively monitor CP deficiencies.

Cover requirements for transmission lines

Rationale:  49 CFR, Part 192, section 192.327(c) currently allows installation of transmission lines or mains with less than the minimum cover required, provided that it has additional protection to withstand anticipated external loads.  However, this requirement does not address other external threats which the pipe may be susceptible to due to reduced cover such as excavation damage.

Description:  The rule will require operators to establish a program to monitor their transmission pipelines in order to identify segments, with reduced underground cover. The program must provide additional damage prevention measures for such segments.  Additionally, the new rule will require operators to continuously monitor these transmission pipelines for any damages caused, directly or indirectly, by the reduced cover and take corrective actions.

Reporting problems associated with mechanical/compression fittings

Rationale: Gas pipeline operators use mechanical fittings for joining and pressure sealing of two pipes together. Properly installed and supported fittings and couplings successfully connect steel, cast iron, copper, and plastic pipes. Past incidents indicate that failures occur when the couplings are incorrectly installed or supported or installed with components that differ from the original manufacturer specifications, modified prior to installation, or have entirely missing parts. Pipeline and Hazardous Materials Safety Administration (PHMSA) issued an advisory bulletin on March 4, 2008 to warn gas pipeline operators using mechanical couplings about the risks involved in installing mechanical/compression fittings. 49 CFR, Part 192 does not have specific requirements applicable to mechanical/compression fitting installations and failure analysis.

Description:  In the light of PHMSA's advisory bulletin, this rule would require operators to review procedures for using mechanical couplings, including coupling design and installation, and ensure that they meet manufacturer recommendations and take action to prevent future failures and minimize risks associated with mechanical/compression fittings.

Assessment of existing Meter Set Assemblies (MSA) and other pipeline components to protect them from excessive snow and ice loading

Rationale: Recent gas pipeline incidents indicated that excessive snow and ice accumulation on pipeline facilities can cause failures due to additional stress imposed on MSAs or other pipeline components. On March 10, 2008, PHMSA issued an advisory bulletin advising owners and operators of gas pipelines of the need to take steps to prevent damage to pipeline facilities from accumulated snow or ice. Current federal regulations do not require operators to monitor the potential impact of excessive snow and ice on these facilities or to inform the public about possible hazards from snow and ice accumulation on regulators and other pipeline facilities.

Description: This rule would require all California gas pipeline operators to initiate an assessment program to evaluate the condition of MSAs which are susceptible to snow and ice accumulation, replace or recondition all existing MSAs that are not adequately supported or protected from excessive snow and ice load and install protective barriers and support for all new MSA installations.

Require operators to identify threats along their pipelines and come up with a plan to mitigate the threats, including research and development (192.919)

Rationale: Current federal rules require operators to identify potential threats to each covered pipeline segment and the information supporting the threat identification, specify the methods selected to assess the integrity of the line pipe, and provide a schedule to complete integrity assessments. However, they do not specify the requirements to provide details about mitigation techniques they would use to comply with standards.

Description:This rule would require gas pipeline operators to provide details on their threat identification, assessment of pipeline conditions, mitigative actions to correct identified anomalies, defects, and imperfections and reassessment intervals for all threats, development of an improved management and analysis processes that integrate all available integrity-related data and information and assess the risks associated with pipeline segments in HCAs, any other damage prevention programs and any other preventive activities to implement additional risk control measures such as installing computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional inspection and maintenance programs.

(End of Attachment B)