Gas systems

We work with regulatory agencies that oversee our transmission systems. The groups recommend how to keep our natural gas systems safe. The agencies include:

• The California Public Utilities Commission (CPUC)
• The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA)
• The National Transportation Safety Board (NTSB)

Our combined work aids us in reviewing our records, and in monitoring, surveying and testing pipelines throughout our entire natural gas pipeline system. Our top priority is the safety of our natural gas system.

We've taken significant actions to improve the safety and operations of our natural gas system. We strive to keep you and the communities we serve safe. Our actions included:

• Completing seven of the safety actions recommended by the NTSB
• Validating the maximum allowable operating pressure for all 6,750 miles of gas transmission pipelines
•  Converting more than 3.7 million paper records going back 50 years. We added the records to our new Geographic Information System (GIS) so field technicians have improved access to data
• Strength testing or validating prior strength testing of 456 miles of transmission pipeline
• Replacing 55 miles of pipeline
• Retrofitting 78 miles of pipeline to allow in-line inspections
• Automating 76 valves
• Performing in-line inspection of 39 miles of transmission pipe
•  Improving leak response time from fourth quartile to first quartile nationally
• Partnering with first responders and public safety officials to enhance emergency preparedness training programs
• Conducting more than 300 workshops with first responders
• Adding six new Mobile Command Center vehicles to our fleet. We packed the vehicles with the tools that crews need to address emergencies in the field

After the September 2010 San Bruno pipeline accident, we substantially reduced the pressure on pipelines that had segments with characteristics similar to the pipeline that ruptured. This was performed as a precautionary step until we can confirm the safety of the pipelines.

Remember the following important information:

• Know the signs of natural gas trouble by smell, sight or sound.
• Know what to do in case of an emergency, that is, always leave the area, call 9-1-1 and call PG&E at 1-800-743-5000.
• Know what's underneath you before you dig. Call 8-1-1 for free underground utility marking service.

We regularly leak survey and patrol all of our pipelines. We try to identify signs of damage, soil erosion and other concerns that can affect the safety of the line. We also use cathodic protection systems to prevent corrosion.

We follow even stricter safety standards on our larger-diameter transmission pipelines,. We inspect and test larger-diameter transmission pipelines using a variety of methods. The methods include pipeline devices equipped with sensors and cameras that travel the length of a pipeline. One such device, known as a "smart pig," performs in-line inspections. We also conduct hydrostatic pressure testing. This variant of testing involves charging the pipe with water at high pressures to safely reveal potential weaknesses. We can also dig up the pipelines to directly assess them.

Direct assessment is an effective technique for identifying potential coating damage. Coating is the first level of protection against lead-inducing external corrosion. This technology also assesses the current level of cathodic protection, which helps show the current and future health of the pipe. Direct assessment can be performed on nearly any pipeline, regardless of its diameter or configuration.

Leak surveys help us identify problems in a gas transmission pipeline. The problems can affect the integrity of the pipe or the operation of the transmission system. Leak surveys involve a variety of technologies, ranging from combustible gas indicators to newer infrared and laser devices.

Many internal line inspection, or in-line inspection (ILI) devices are available. The devices can be equipped with robotic cameras and sensors to check pipe thickness and welds while detecting flaws and corrosion. Although smart pigs are effective, their use is limited to certain types of pipes. Many of our pipelines were designed and constructed before smart pig technology was developed. Some of our pipelines require significant reconstruction to accommodate this form of inspection.

Hydrostatic testing involves water-pressure testing a pipeline. It's a proven method of verifying the actual capability of a natural gas pipeline. We want our system to operate at a safe level of pressure. Hydrostatic testing is also used to test such familiar items as scuba tanks, fire extinguishers and air compressor tanks.

A hydrostatic test involves pressurizing a section of pipe with water. The pressure is tested at a higher percentage of the pipe material's maximum design strength for natural gas. This verifies the capability of a pipeline to safely operate at the desired level or pressure. The test can also reveal weaknesses that can lead to defects and leaks in the pipe. To perform a hydrostatic test, the pipeline must be taken out of service for many days.

Transmission pipelines are generally larger and operate at a higher pressure than distribution pipelines. Transmission pipelines move natural gas from compressor stations and storage facilities to regulators. Regulators reduce the pressure before reaching the distribution system. The distribution system feeds the smaller lines that deliver gas to your business or home.

A properly maintained pipe can operate safely for 100 years or more. Pipeline age is a factor, but not the only factor that we consider when we inspect our pipelines.

Federal law requires that we establish MAOP for all pipeline systems. MAOP allows for a wide margin of safety. The MAOP is a fraction of the pipe's actual calculated strength. Pipes and pipelines typically operate well below the MAOP.

MAOP is determined in one of three ways:

• Calculating the Specified Minimum Yield Strength (SMYS) of the pipe. SMYS is the minimum pressure at which the pipe is expected to begin deforming. MAOP is then set at a fraction of the SMYS, allowing for a wide margin of safety.
• Basing it on pressure tests. MAOP is set safely below the pressures used in the pressure test.
• Basing it on the pressure at which the pipeline has operated safely for years (for pipe installed years ago).

Federal law requires that pipeline operators establish MAOP for each section of pipeline or each distinct segment of our gas pipeline system.

We have hundreds of automatic over-pressure protection control valves. The valves protect pipelines and are activated when the pressure gets too high. We also have some lines with rupture-control valves for specific needs. Our 24-hour Gas Control Center has the ability to shut down some pipeline systems via remote control.

The valves that we use differ in the following ways:

• Manual valves can be operated only by a trained, federally qualified individual at the valve location. The valves are hand-operated by wheel or gear assemblies. A technician can also use a wrench to open a valve. An indicator shows whether the valve is open or closed.
• Automatic shut-off valves are fully automated. Automatic valves don’t require remote control or on-site operation. Human intervention isn’t needed with automatic shut-off valves when certain pipeline conditions arise.
• Remote-controlled valves can be operated from an off-site location. We control the valves from our 24-hour staffed Gas Control Center.

Gas transmission pipelines are generally resistant to earthquake damage. We expect our pipelines to continue working after earthquakes occur. In locations where there is believed to be a greater risk of pipeline failure from an earthquake, we work to manage the risk of damage to the pipeline. We're also replacing some pipeline sections with a design that is more earthquake-resistant.

PG&E immediately walks the system after an earthquake occurs. Shortly thereafter, we evaluate the lines by helicopter. The inspections help us confidently determine whether our system has been damaged.

We work with external partners such as first responders and public safety officials. Our goal is to enhance training for emergency preparedness and response. Enhanced emergency prevention, preparedness and response programs consist of education programs. The programs are designed for first responders, contractors, infrastructure departments, community members, schoolchildren and other stakeholders.

We created educational programs with the following objectives:

• Increase educational and interactive sessions with first responders to meet demand
• Develop a contact list for all local first responders
• Launch a first responder website portal
• Conduct a joint California Independent System Operator (CAISO) and CPUC gas curtailment exercise, such as the one held on August 12, 2011
• Provide maps, GIS data and other information to first responders
• Conduct Incident Command System (ICS) training
• Launch first responder workshops, such as the one launched in the fourth quarter of 2011
• Provide a first responder online portal for training material downloads
• Schedule our representatives to deliver onsite training, such as the training delivered in the first quarter of 2012

PG&E wants to create an emergency response plan that incorporates learning from prior experience and industry benchmarks. A coordinated plan can help ensure that emergency response preparedness is embedded in our operations.

We expect the following benefits from our safety programs:

• Fewer preventable incidents
  
• More-informed and safer citizens
• Improved coordination during emergencies
• Faster restoration times following an incident
• Line-of-sight accountability for prevention, preparedness and response performance

We're conducting a full review of our gas operations to improve our performance. PG&E is striving to bring our system to industry-leading levels. We initiated this review following a CPUC request. The result is the implementation of a new procedure that calls for annual class reviews.

Pipelines are rated by the following four classes based on population:

• Class 1. Up to 10 residences or businesses per mile of pipeline
• Class 2. 11 or more residences or businesses per mile
• Class 3. 46 or more residences or businesses per mile
• Class 4. Urban areas with buildings of four or more stories

The review indicated that some segments of pipe have a MAOP higher than appropriate for the current class location. As a result, PG&E identified 7.5 miles of pipeline where we must reduce operating pressure. The length of the pipeline consists of multiple shorter segments in our service area.

We already completed pressure reduction on approximately 3.5 miles of pipelines. We're continuing to lower the pressure on the other 4 miles. The effort involves more than 30 different locations. We’re carefully planning how to lower the pressure to ensure safety.

We're still evaluating location data and operating pressures for approximately 100 miles of pipeline. We’re trying to complete the work as quickly as possible.

Safety is our top priority. We're verifying that operating pressure on all of our lines is appropriate for each location. Where necessary, we’re lowering the pressure.

We're continuing our engineering work and field upgrades of our newly classified segments. We’re bringing our system back up to the operating pressures needed, providing longer-term reliability.

The PG&E Pipeline Safety Enhancement Plan can allow us to:

• Replace more than 180 miles of pipeline.
• Strength test more than 780 miles.
• Retrofit about 200 miles to accommodate in-line inspections.
• Perform more than 200 miles of in-line inspection.

The PG&E Pipeline Safety Enhancement Plan was developed in response to the CPUC decision concerning new pipeline safety regulations. We plan to implement any new CPUC rules and regulations that it adopts.

The CPUC ordered California gas utilities to file implementation plans in June 2011. Before that date, PG&E already started taking action to fix our gas transmission pipelines. The steps were all taken prior to the CPUC order, and we're continuing the work today.

No, the plan represents only part of our overall plan to enhance gas transmission safety. We're improving our overall gas operations by strength testing or replacing all pre-1970's pipelines. The plan also includes:

• Installation of automatic shut-off valves
• Improvements in recordkeeping
• Interim safety measures
• Emergency response procedures

PG&E created a separate operating unit for our gas operations. The team is led by a gas operations expert who brings 30 years of experience in improving some of the nation's oldest gas systems. We're also implementing broad changes across the company to increase public safety.

The Pipeline Safety Enhancement Plan reflects new regulatory requirements. The requirements establish a known margin of safety across our gas transmission system. The plan incorporates the following considerations:

• Lessons from the San Bruno accident
• NTSB recommendations
• Independent review panel findings
• Industry benchmarking

Our plan also considers feedback from key regulators, industry experts, utilities and other interested parties.

The pressure testing and replacement work can be conducted in a manner that helps ensure the safety of the surrounding community. Our customer outreach plan is designed to provide the following information:

• When the work is scheduled
• What work we’re doing
• What to expect in terms of test length, impact to service and access restrictions

In certain limited cases, we may have to close streets or ask customers to vacate their homes while a test is conducted. Our customer outreach efforts are designed to minimize inconvenience. We want to provide clear information so that customers and the community know what to expect.

The PG&E plan proposes to automate 228 valves in Phase 1.

Approximately 60 percent of automation miles can be installed on pipelines located in the Bay Area. In 2011, we automated 29 valves on the San Francisco Peninsula.

Automatic valves have the following benefits:

• Shutting off gas pipelines quickly
• Isolating a segment of pipeline if it ruptures
• Facilitating an emergency response
• Reducing potential threats to the public and property
• Minimizing property damage
• Minimizing the quantity of gas released during a pipeline rupture
• Reducing the environmental impact of gas leaks

A typical residential customer might have an average monthly gas bill increase of $1.93, from $45.23 to $47.16. A typical small business customer might have an average monthly bill increase of $14.96, from $279.80 to $294.75.