2. Background
Pursuant to Pub. Util. Code § 451, each public utility in California must "furnish and maintain such adequate, efficient, just and reasonable service, instrumentalities, equipment, and facilities, . . . as are necessary to promote the safety, health, comfort, and convenience of its patrons, employees, and the public." Ensuring that the management of investor-owned gas utility systems fully performs its duty of safe operations is a core obligation of this Commission.
To meet this obligation with added urgency after the San Bruno events, the Commission has expanded its efforts in the following areas: (1) General Rate Cases, (2) this Rulemaking, and (3) enforcement proceedings. We have also obtained invaluable outside assistance from the National Transportation and Safety Board (NTSB) and the Independent Review Panel. Natural gas transmission system safety has, as its base, regulatory requirements promulgated at the federal level. After a summary of the federal Integrity Management programs, below, we turn to this Commission's efforts.
2.1. Integrity Management Plans
The Pipeline and Hazardous Materials Safety Administration (PHMSA) is part of the United States Department of Transportation and its Office of Pipeline Safety administers the Department's national regulatory program to assure the safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. The Office of Pipeline Safety develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities.3 PHMSA is responsible for the federal rules that are referenced in and adopted by the Commission's General Order (GO) 112-E.
PHMSA regulations, and in particular the Integrity Management Rule require each gas transmission system operator to develop and implement an Integrity Management Plan. The purpose of the Integrity Management Rule is to improve pipeline safety through:
· performing integrity assessment of pipeline segments in High Consequence Areas (HCA);
· improving integrity management systems within companies;
· improving the government's role in reviewing the adequacy of an operator's integrity programs and plans; and
· ensuring that the public is kept apprised of safety efforts.
The requirements for the Integrity Management Plan began with a framework:
By no later than December 17, 2004, each operator of a covered pipeline segment was required to develop and follow a written integrity management program that contains all the elements described in § 192.911 and that addresses the risks on each covered transmission pipeline segment. The initial integrity management program must consist, at a minimum, of a framework that describes the process for implementing each program element, how relevant decisions will be made and by whom, a time line for completing the work to implement the program element, and how information gained from experience will be continuously incorporated into the program. The framework will evolve into a more detailed and comprehensive program. An operator must make continual improvements to the program.4
Gas transmission pipeline operators are required to submit performance measures on their Integrity Management programs, along with the annual reports on their pipeline infrastructure. PHMSA uses these reports-due March 15 each year-to monitor industry progress in complying with requirements of the Integrity Management Rule, to prioritize regulatory inspections, and to respond to inquiries about PHMSA's oversight program.
These performance measure reports provide information pertaining to operators' Integrity Management Programs, including the amounts of miles inspected and assessed, the operator's repair activities addressing time-sensitive conditions, and the numbers and types of incidents, leaks, and failures occurring in HCA segments of their pipelines. After performing quality checks, PHMSA posts these reports for the public to view.
PHMSA also requires that operators of gas distribution pipelines develop and implement integrity management programs similar to those required for transmission pipelines. The purpose of these programs is to enhance safety by identifying and reducing pipeline integrity risks; however, unlike transmission, the distribution rule requirements apply to all distribution facilities and are not limited to the HCA.
Specifically, by August 2, 2011, each gas distribution pipeline operator must have developed and implemented an Integrity Management program that included a written Integrity Management Plan.5 The written Plan must contain procedures for developing and implementing the following elements:
(a) Knowledge. An operator must demonstrate an understanding of its gas distribution system developed from reasonably available information.
(b) Identify threats. The operator must consider the following categories of threats to each gas distribution pipeline: Corrosion, natural forces, excavation damage, other outside force damage, material, weld or joint failure (including compression coupling), equipment failure, incorrect operation, and other concerns that could threaten the integrity of its pipeline. An operator must consider reasonably available information to identify existing and potential threats. Sources of data may include, but are not limited to, incident and leak history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, and excavation damage experience.
(c) Evaluate and rank risk. An operator must evaluate the risks associated with its distribution pipeline. In this evaluation, the operator must determine the relative importance of each threat and estimate and rank the risks posed to its pipeline. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure. An operator may subdivide its pipeline into regions with similar characteristics (e.g., contiguous areas within a distribution pipeline consisting of mains, services and other appurtenances; areas with common materials or environmental factors), and for which similar actions likely would be effective in reducing risk.
(d) Identify and implement measures to address risks. Determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline. These measures must include an effective leak management program (unless all leaks are repaired when found).
(e) Measure performance, monitor results, and evaluate effectiveness. An operator must develop and monitor performance measures from an established baseline to evaluate the effectiveness of its program, and consider the results of its performance monitoring in periodically re-evaluating the threats and risks.
(f) Periodic Evaluation and Improvement. An operator must re-evaluate threats and risks on its entire pipeline and consider the relevance of threats in one location to other areas. Each operator must determine the appropriate period for conducting complete program evaluations based on the complexity of its system and changes in factors affecting the risk of failure. An operator must conduct a complete program re-evaluation at least every five years. The operator must consider the results of the performance monitoring in these evaluations.
(g) Report results. An operator must report, on an annual basis, the number of leaks and excavation damages to PHMSA and the state pipeline safety authority if a state exercises jurisdiction over the operator's pipeline.
The new regulations also require pipeline operators to report to the federal and state governments, on an annual basis, information related to the failure of compression couplings.
Operators of natural gas master-metered systems and small propane systems must also develop and implement an Integrity Management program that includes a written plan. However, the requirements for these operators are simpler in recognition of the lower complexity of these pipeline systems.
2.2. Commission Review - General Rate Cases
In a General Rate Case, this Commission considers a utility's overall operations and revenue requirement. Priorities are set for operating requirements and capital investment projects. Safety considerations are necessarily a primary component of the overall General Rate Case review. In addition, in PG&E gas transmission and storage rate case, A.09-09-013, we expanded the scope to include explicitly a "safety phase" to focus directly on PG&E's disaster and emergency plans, automated shut-off valve installation and monitoring, changes to capital project priorities, safety related protocols, and relationships with first responders.
The scope of General Rate Cases includes all utility operations and provides revenue requirement to support staffing levels, equipment, facilities, and needed capital investments. General Rate Cases are one of the logical places for the Commission to review comprehensively and order any improvements necessary to improve the safety of utility operations.
2.3. This Rulemaking
We initiated this Rulemaking to consolidate and coordinate our efforts, obtain public input, and propose rule and policy changes as necessary. We set forth the following primary objectives of this proceeding, as well as specific plans for achieving each objective:
A. Provide the public with a means to make their views known to this Commission;
B. Provide the public with the Independent Review Panel's expert recommendations regarding the technical explanation for the explosion, assessment of likelihood that similar events may occur, and recommendations for preventive measures and other improvements;
C. Develop and adopt safety-related changes to the Commission's regulation of natural gas transmission and distribution pipelines, including requirements for construction, especially automated shut-off valves, maintenance, inspections, operation, record retention, ratemaking, and the application of penalties;
D. Consider ways that this Commission can undertake a comprehensive risk assessment for all natural gas pipelines regulated by this Commission, and possibly for other industries that the Commission regulates;
E. Consider available options for the Commission to better align ratemaking policies, practices, and incentives to elevate safety considerations, and maintain utility management focus on the "nuts and bolts" details of prudent utility operations;
F. Consider the appropriate balance between the Commission's obligation to conduct its proceedings in a manner open to the public with the legitimate public safety concerns that arise from unlimited availability of certain utility information;
G. Consider if we need further rules or other protection for whistleblowers to inform the Commission of safety hazards; and
H. Expand our emergency and disaster planning coordination with local officials.
Since initiation, our primary efforts have been focused on ensuring that California's natural gas transmission system operators are properly determining the Maximum Allowable Operating Pressure (MAOP) for each segment of the natural gas transmission system. Our review caused us, on June 9, 2011, to order all California natural gas transmission pipeline operators to prepare Natural Gas Transmission Pipeline Comprehensive Pressure Testing Implementation Plans to either pressure test or replace all segments of natural gas pipelines that were not pressure tested or lacked sufficient details related to performance of any such test.6 We required that the Plans provide for testing or replacing all such pipeline as soon as practicable, and that at the completion of the implementation period, all California natural gas transmission pipeline segments would be (1) pressure tested, (2) have traceable, verifiable, and complete records readily available, and (3) where warranted, be capable of accommodating in-line inspection devices. The gas system operators have filed their Implementation Plans which propose multi-year programs with proposed costs of hundreds of millions of dollars. The evidentiary record is being prepared for Commission consideration of these Plans. In addition, the Commission required the operators to implement interim safety enhancement measures, including increased patrols and leak surveys, pressure reductions, prioritization of pressure testing for critical pipelines that must run at or near MAOP values which result in hoop stress levels at or above 30% SMYS, and other such measures that will enhance public safety during the implementation period.
Apart from the comprehensive Implementation Plan, PG&E also brought forward specific requests necessary to prepare for the winter heating season. PG&E requested Commission authorization to lift operating pressure restrictions that had been imposed on certain lines following the San Bruno rupture. To consider such requests, the Commission adopted a public process for PG&E to make its demonstration that line operation could be safely restored to pre-restriction levels. The Commission required that PG&E provide documentation showing that it had gone beyond a rote pressure test of the line in question, and include a responsible engineer's review of the pipeline construction and assessment of the results in a Safety Certification. Specifically, the PG&E officer responsible for gas system engineering was required to provide a verified statement showing the following information:
a) that PG&E has validated the pipeline engineering and construction;
b) that PG&E has reviewed pressure tests results and can confirm that a pressure test was performed on the pipeline in accordance with federal regulations; and,
c) that in the professional judgment of the engineering officer, the system would be safe to operate at the proposed restored pressure levels.7
2.4. Enforcement Proceedings
Where the Commission finds good cause to believe that a public utility has violated a Commission order or California law for which the Commission has enforcement authority, the Commission may open an investigation to consider imposing fines or other penalties for any such violations. The Commission has opened investigations into PG&E's operations regarding the San Bruno rupture, Investigation (I.) 12-01-007; PG&E's recordkeeping, I.11-02-106; and the HCA Investigation, I.11-11-009.
2.5. Reports from the NTSB and the Independent Review Panel
The NTSB and the Independent Review Panel convened by this Commission have made many recommendations related to the investigation of the San Bruno explosion.8
The NTSB report concluded that the Commission should do the following:
· With assistance from the Pipeline and Hazardous Materials Safety Administration, conduct a comprehensive audit of all aspects of Pacific Gas and Electric Company operations, including control room operations, emergency planning, record-keeping, performance-based risk and integrity management programs, and public awareness programs. (P-11-22)
· Require the Pacific Gas and Electric Company to correct all deficiencies identified as a result of the San Bruno, California, accident investigation, as well as any additional deficiencies identified through the comprehensive audit recommended in Safety Recommendation (P-11-22), and verify that all corrective actions are completed. (P-11-23)
Among the many recommendations for PG&E, the NTSB issued this comprehensive directive regarding PG&E's integrity management program and risk analysis:
· Assess every aspect of your integrity management program, paying particular attention to the areas identified in this investigation, and implement a revised program that includes, at a minimum, (1) a revised risk model to reflect the Pacific Gas and Electric Company's actual recent experience data on leaks, failures, and incidents; (2) consideration of all defect and leak data for the life of each pipeline, including its construction, in risk analysis for similar or related segments to ensure that all applicable threats are adequately addressed; (3) a revised risk analysis methodology to ensure that assessment methods are selected for each pipeline segment that address all applicable integrity threats, with particular emphasis on design/material and construction threats; and (4) an improved self-assessment that adequately measures whether the program is effectively assessing and evaluating the integrity of each covered pipeline segment. (P-11-29)
· Conduct threat assessments using the revised risk analysis methodology incorporated in your integrity management program, as recommended in Safety Recommendation
(P-11-29), and report the results of those assessments to the California Public Utilities Commission and the Pipeline and Hazardous Materials Safety Administration. (P-11-30)
The Independent Review Panel's full set of recommendations are reproduced in Appendix A to today's decision. These recommendations include instituting state-of-the-art risk analysis to evaluate the likelihood of various possible failures and to establish a culture of pipeline integrity. The Independent Review Panel's recommendation 5.4.4.5 captures the comprehensive and long-term perspective needed:
PG&E should develop and adopt a maturity framework that reflects the importance and advancement of thinking of pipeline integrity and safety as a journey, which is coherently applied across the enterprise, where progress is transparent and measurable, and is consistent with the best thinking on pipeline integrity and process safety management.
2.6. Public Utilitities Code Sections 961 and 963
Recent California legislation has also emphasized the need for increased and more effective safety procedures.9 As noted above, SB 705, codified as Pub. Util. Code §§ 961 and 963, requires each gas corporation to develop a plan for the "safe and reliable operation of its commission-regulated gas pipeline facility that implements the policy of paragraph (3) of subdivision (b) of Section 963, subject to approval, modification, and adequate funding by the commission." As provided in Pub. Util. Code § 961(e), the Commission and each gas corporation must "provide opportunities for meaningful, substantial, and ongoing participation by the gas corporation workforce in the development and implementation of the plan, with the objective of developing an industry-wide culture of safety that will minimize accidents, explosions, fires, and dangerous conditions for the protection of the public and the gas corporation workforce."
By December 31, 2012, the Commission is required to review and accept, modify, or reject the plan for each gas corporation as part of a proceeding that includes a hearing, and Pub. Util. Code § 961(c) and (d) provide specific details on what is required.
To organize the detailed Legislative directives, we grouped the list found in the two code sections into five overall topics: (1) safety systems, (2) emergency response, (3) state and federal regulations, (4) continuing operations, and (5) emerging issues. The items are grouped and listed below, along with references, where appropriate, to the ongoing Commission processes discussed above.
List of Issues from |
Overall Topic |
Commission Oversight Process |
Identify and minimize hazards and systemic risks. 961(d)(1) |
Safety Systems |
Utility Operations and Maintenance Plans in place, along with Integrity Management for both transmission and distribution systems to address threats and systemic risks. |
Identify the safety-related systems that will be deployed to minimize hazards. 961(d)(2) | ||
Equipment and personnel procedures to limit the damage from accidents. 961(d)(5) |
Emergency Response |
Emergency response procedures required by 49 CFR 192.615, utility customer service response set in General Rate Cases, with revenue requirement provided to meet the standards. Improving first-responder and utility coordination, and access to pipeline facility data already underway in Rulemaking. |
Timely response to reports of leaks, hazardous conditions, and emergency events. 961(d)(6) | ||
Prepare for and respond to earthquakes and other major events. 961(d)(8) | ||
Protocols for determining maximum allowable operating pressures. 961(d)(7) |
State and Federal Regulations |
Federal regulations currently specify maximum allowable operating criteria. Since September 13, 2010, where warranted, Commission has been ordering reductions of MAOP on a line-by-line basis, and has set standards for any authorized resumptions; Commission leads the U.S. by ordering all gas transmission lines to have MAOP established by pressure tests. GO 112-E requirements exceed federal regulations; however, staff has proposed revisions to GO 112 in this Rulemaking. |
Meet or exceed the minimum standards for safe design, construction, installation, operation, and maintenance of gas transmission and distribution facilities prescribed by regulations. 961(d)(9) | ||
Best practices in the gas industry and with federal pipeline safety statutes. | ||
Safety of the public and gas corporation employees as the top priority, take all reasonable and appropriate actions consistent with the principle of just and reasonable cost-based rates. 963(b)(3) |
Continuing Operations |
Federal regulations currently specify patrol and leak survey activities to inspect for leaks. Commission staff continually stays informed on new leak detection technologies to make activities more effective. General Rate Cases require overall review of operations which includes gas transportation capacity, newly created safety phase to focus on programs for safety. |
Provide adequate storage and transportation capacity to reliably and safely deliver gas to all customers. 961(d)(3) | ||
Provide for effective patrol and inspection to detect leaks. 961(d)(4) | ||
Ensure an adequately sized, qualified, and properly trained gas corporation workforce. 961(d)(10) | ||
Any additional matter that the commission determines should be included in the plan. 961(d)(11) |
Emerging Issues |
Commission has opened Rulemakings for longer-term issues, with Commission Executive Director empowered to take urgent actions as needed, and enforcement proceedings are the ultimate procedural mechanism. |
The legislation acknowledges both state and federal requirements, but this Commission must determine whether the utilities have properly assessed risks and are properly implementing the required mitigation measures. Similarly, the Independent Review Panel and the NTSB have provided recommendations and directives that focus on safety systems, to see safety as a long-term effort that must be consistently applied throughout gas system operations.
In addition to the directives codified in Pub. Util. Code §§ 961 and 963, other recent California legislation addresses many of these same topics. Emergency plans, pressure testing, safety reports to Consumer Protection and Safety Division (CPSD), and ratemaking requirements are found in new Pub. Util. Code §§ 956.5, 958, 958.5, 959 and 969. As with the directives in new §§ 961 and 963, discussed above, the Commission will be addressing these issues in on-going Commission processes.
The Legislature also added new section 957 to the Pub. Util. Code. This new section requires the Commission to order intrastate natural gas transmission line operators to install automatic or remote-controlled shut-off valves in certain locations as "consistent with protection of the public." As set forth above, the Commission included such valves within the initial scope of this proceeding, and each gas system operator has included proposals for increasing the number of shut-off values in their respective implementation plans. Thus, we conclude that these issues, like many of the issues found in §§ 961 and 963, are currently subject to active Commission oversight in this and other proceedings. Below, we discuss the issues that require expanded Commission review.
3 See generally, http://www.phmsa.dot.gov/portal/site/PHMSA.
4 49 CFR 192.907.
5 49 CFR §§ 192.1005, 1007.
6 The Commission's GO 112, which became effective on July 1, 1961, mandated pressure test requirements for new transmission pipelines (operating at 20% or more of Specified Minimum Yield Strength (SMYS)) installed in California after the effective date. Similar federal regulations followed in 1970, but exempted pipeline installed prior to that time from the pressure test requirement. Such pipeline is often referred to as "grandfathered" pipeline, because pursuant to 49 CFR 192. 619(c), pressure testing was not mandated.
7 D.11-09-006 at 18.
8 The entire Independent Review Panel report is found at http://www.cpuc.ca.gov/PUC/events/110609_sbpanel.htm. The NTSB report is at http://www.ntsb.gov/investigations/summary/PAR1101.html.
9 See SB 44, Assembly Bill 56, SB 216, SB 705, and SB 879. We discussed this legislation in Resolution ALJ-274.
