Pipeline Performance Measures 2014 Data Report

Pipeline Performance Measures 2014 Data Report [PDF 505 KB]

November 2015

Copyright/Permission to Reproduce

ISSN 2368-5530

Table of Contents

Pipeline Performance Measures - Overview

This report marks the second year of the National Energy Board publishing pipeline performance measures gathered from Board-regulated companies. It includes data from 2013 and 2014 reporting years.

This reporting strengthens the Board’s proactive approach to protecting the public and the environment. Performance measures are a necessary component of effective safety management systems as they focus on both improving the performance of systems designed to prevent possible incidents (leading indicators), and measuring pipeline incidents after they have occurred (lagging indicators).

The NEB expects that industry leadership will use its management systems’ policies, goals, processes, and procedures to formally communicate their values and expectations. Through this formal communication, executive management establishes the initial framework of the corporate culture. Where a company is strongly in tune with establishing and maintaining a positive safety culture, it scrutinizes, as a normal business function, every decision to ensure that risk is considered and managed appropriately. It sets performance measures that provide a complete picture of the company’s current state in order to identify areas of weakness and to proactively manage safety to prevent incidents.

In 2014, the Board released a Safety Culture Framework intended to promote learning and a shared understanding of safety culture in the pipeline industry. Both the performance measures and safety culture initiatives build awareness of the role that management systems and culture plays in contributing to or building defenses against accidents. Incidents can be attributed to a breakdown in technology or management system elements, but they are often because of safety culture, as well.

The Board sees the information gathered for these primarily leading performance measures as an incentive for companies to set even more company internal performance measures for key programs required in a robust management system. A comprehensive set of measures informs employees on the performance being measured and the results are able to be tracked over time to contribute to continual improvement in operations and to contribute to a more positive safety culture.

The data generated from the measures in this report will also be used by the Board to better regulate pipeline operations. The NEB recognizes it takes a few reporting cycles to identify meaningful trend information. However, the Board is now using the performance measures data to inform its compliance verification planning. Data from these leading indicators are incorporated into the NEB’s risk-informed modelling and analysis. This additional information provides the Board with a more complete picture of regulated companies’ pipeline operations.

The Board also evaluates the performance data to determine if companies are providing information that is consistent with the Board’s knowledge of the pipeline and if they are planning the appropriate numbers of safety-related activities. If, in the Board’s view, there are inconsistencies, the Board will take action.

Performance Measures Data Format

The performance measures were developed through a public consultation to cover key activities in the programs required by the NEB:

  1. Safety Management
  2. Security
  3. Emergency Management
  4. Integrity Management
  5. Environmental Protection
  6. Damage Prevention

To facilitate the reporting and subsequent sharing of data, each performance measure is quantitative in terms of numbers, percentages and ratios. 

Most of the measures are to be reported on a pipeline-system basis. However, there are certain measures that must be reported either on a pipeline-specific basis, or for facilities. These exceptions have been indicated in the guidance. 

Data was received from 26 companies owning a total of 58 pipelines with a total length of 67,700 kilometres. The data was grouped in categories based on product (liquid or gas) and length of pipeline (greater than 50 kilometres and less than or greater than 5000 kilometres).

This report includes performance measure data for 2014 as well as the two-year 2013/2014 average. This shows the comparison between the 2013 and 2014 data and at the same time shows what the baseline would be. In future reports there is the potential to show trends by graphing the annual results. The data format in this report is illustrated in the following figure:

 49 → 2014 Data
 51 → 2013/2014 Average

Guidance

Guidance is provided with each measure to enhance the accuracy of company reporting, provide common understanding, and encourage consistent application for reporting purposes. In addition, definitions, descriptions of terms, and interpretation are included. 

Implementation

These performance measures are also posted on the Board’s website (www.neb-one.gc.ca) in the Safety and Environment section.

The submission of performance measure data is mandatory for companies selected by the Board given the number of kilometres of pipeline they own. The Board has directed these companies to electronically submit the data (for the previous calendar year) by 1 April of each year. The reporting form and the instructions for submission are available on the Board’s website.

Companies that are new to the Board’s jurisdiction should seek advice from the Board to determine if they should report on the measures. However, all companies are encouraged to use these measures in their integrated management system.

Observations Regarding Data Reported

Program-specific observations provide some indication of the company performance relative to planned activities and between different categories of pipelines.

Safety Management

The safety management performance measures all had high achievement percentages in each category of pipeline. In 2014 there were more corrective actions for liquid pipelines due to construction activities.

Security Management

In 2013 some companies had a significantly lower percentage of employees receiving security training. The NEB subsequently clarified requirements and the percentage of trained employees increased in 2014 from 88 to 93%.

Emergency Management

Planned emergency management liaison activities (with agencies involved in an emergency situation) exceeded planned activities and increased over 2013. In addition, the percentage participation on emergency management exercises increased in 2014.

Integrity Management Measures

There are several measures for this program.  Key observations are:

  1. Approximately two thirds of features, such as potential cracks or corrosion, identified by inspections are found to be defects and then repaired or mitigated. This indicates a high degree of accuracy in the interpretation of inspection tool data.
  2. In 2014 a greater amount of features were identified and a corresponding amount of defects were repaired than in 2013.

Environmental Protection

Employee Environmental Protection Program training showed 10,348 persons were trained - 800 more than in 2013. The number of environmental issues increased and their resolution decreased.  (Outstanding issues are to be addressed in subsequent calendar years.)

Damage Prevention

These measures relate to tracking pipeline crossing permissions and unauthorized crossing activities. This information allows for an assessment as to (1) whether awareness programs are effective, and (2) the trends for public awareness of pipelines.  The results for 2014 show a significant improvement over 2013 in that every type of activity, except those conducted by contractors, had less unauthorized activities and significantly more permissions. The greatest improvement was in landowner interactions with pipelines in general and in municipal interactions with large gas pipeline companies. Overall there was a decrease in unauthorized activities from 591 to 165.

I - Safety Management Performance Measures

1. Facility Safety Inspections

Guidance

The purpose of this measure is to track completion of safety inspections planned for facilities so as to prevent harm to employees, the public and the environment. This supports Paragraph 6.5(1)(u) of the National Energy Board Onshore Pipeline Regulations (OPR), which requires a process for inspecting and monitoring in order to evaluate the adequacy and effectiveness of a safety management program.

1. Facility Safety Inspections
2014 Company Performance
The total number of facility inspections conducted versus the total number of planned facility inspections.
Pipeline Type Average Number of Facilities Facility Inspections Percentage
Average Planned Average Inspections
Gas > 50 km and < 5000 km 49 88 87 99
2013/2014 Average 51 103.5 103 99.5
Gas > 5000 km 1,991 1,896 1,912 101
2013/2014 Average 1,900 1,724 1,717 100
Liquid > 50 km 39 163 163 100
2013/2014 Average 43 172 172 100
Pipeline Systems Total Facilities Total Planned Total Conducted Percentage
32 7,233 9,733 9,787 101
2013/2014 Average 6,988 9,395 9,377 100

What is a “facility”?

For the purposes of this measure, a facility is integral with a pipeline and may include pump stations, compressor stations, metering stations, mainline block valve yards, tank farms, terminals and launcher and receiver yards. This definition is consistent with the facilities identified in the Canadian Standards Association (CSA) Z662, Oil and Gas Pipeline Systems.Footnote 1

What is an “inspection”?

For the purposes of this measure, an inspection is a workplace inspection conducted at a field facility in accordance with the requirements of a company’s facility integrity and/or safety program management system. An inspection may include facility and equipment inspections conducted for both process safety and workplace safety purposes.

Inspections conducted to follow up on corrective actions are not recorded for this measure (see Safety Management Performance Measure #2). Although these inspections are an important component of a safety program, they are not included in this measure because the number of these inspections can vary depending on the situation.

2. Corrective and Preventative Actions

Guidance

The purpose of this measure is to support paragraphs 6.5(1)(r), (u) and (w) of the OPR with regard to the tracking of corrective and preventative actions and the completion of the actions in a timely manner. This measure will also help companies manage hazards and find ways to reduce the potential for safety incidents. This measure is not focused on the completion of actions in the same calendar year they were identified. Rather, as mentioned above, the focus is on the completion of actions in a timely manner.

Some companies’ management systems may track operations and maintenance activities separately. In this case the data is to be combined for reporting on the measure.

2. Corrective and Preventative Actions
2014 Company Performance

The total number of corrective and preventative actions completed versus the total number of corrective and preventative actions identified for the calendar year for:

  1. operations and maintenance; and
  2. construction.
Pipeline Type Safety Actions Percentage
Average Identified Average Corrected
a. Operations and Maintenance Corrective and Preventative Actions
Gas > 50 km and < 5000 km 1.7 1.6 94
2013/2014 Average 26 25 94
Gas > 5000 km 496 415 84
2013/2014 Average 915 763 83
Liquid > 50 km 479 472 99
2013/2014 Average 316 305 97
b. Construction Corrective and Preventative Actions
Gas > 50 km and < 5000 km 37 25 68
2013/2014 Average 22 16 72
Gas > 5000 km 69 53 77
2013/2014 Average 99 79 80
Liquid > 50 km 188 185 98
2013/2014 Average 152 150 99
Pipeline Systems Total Identified Total Corrected Percentage
32 15,389 14,793 96
2013/2014 Average 12,668 11,845 94

What is a “corrective and preventative action”?

A corrective and preventative action is an action that the company has determined is necessary based on findings from internal inspections, audits and investigations. The reported data would include both corrective and preventative actions.

An investigation is any assessment of an unsafe situation from a near miss to an incident. If any investigation generates corrective and/or preventative actions then these actions are considered a corrective and preventative action for the purposes of this measure and therefore should be reported.

How are corrective actions tracked if they are identified in one calendar year, but addressed in another calendar year?

It is recognized that some actions are not able to be addressed in the calendar year that they are discovered. For example, some may require more time than others, or some actions may be identified too late in the year.

Any corrective and preventative actions not completed in a calendar year are carried over to the next year. These actions are then identified in the management system at the start of the next calendar year. They will be supplemented with new actions identified over the course of that calendar year.

What is “construction”?

Construction activities are those conducted by employees, contractors or any other persons involved in the construction of a pipeline.

3. Near Misses

Guidance

The purpose of this measure is to track reporting and management of near misses for hazard management in accordance with Paragraph 6.5(1)(s) of the OPR, so as to reduce the potential for pipeline process safety incidents and occupational health and safety incidents.

3. Near Misses
2014 Company Performance

The total number of near misses reviewed by a competent person and addressed versus the total number of near misses reported by:

  1. the pipeline company; and
  2. contractors.
Pipeline Type Near Misses Percentage
Average Reported Average Addressed
a. Pipeline Company Near Misses
Gas > 50 km and < 5000 km 3.6 3.6 100
2013/2014 Average 3.8 3.8 100
Gas > 5000 km 114 113 99
2013/2014 Average 376 375 100
Liquid > 50 km 9 9 100
2013/2014 Average 16 15 97
b. Contractor Near Misses
Gas > 50 km and < 5000 km 3.7 3.7 100
2013/2014 Average 2.9 2.9 100
Gas > 5000 km 63 63 100
2013/2014 Average 66 66 100
Liquid > 50 km 87 87 100
2013/2014 Average 86 86 100
Pipeline Systems Total Reported Total Addressed Percentage
32 2,744 2,714 99
2013/2014 Average 3,580 3,436 96

What is a “near miss”?

A near miss is an undesired event that under slightly different circumstances could have resulted in harm to people, or damage to property, equipment or the environment. Near misses apply to operation, maintenance and construction activities conducted by a company. Near misses do not apply to other companies, public or third party incidents on pipelines as these events should be managed under a damage prevention program.

In order for a company to properly report on this measure, it may have to provide specific direction to each contractor so that all near misses are reported and reviewed. Such reporting should be included in a company safety management program in accordance with paragraph 6.5(1)(r) of the OPR.

What do “addressed” and “competent person” mean?

Addressed means that a determination of need for corrective and/or preventative action was made and where appropriate corrective and/or preventative action was taken. In some cases no action may be required. However, a determination must be made promptly to assess the risk and the need for corrective and/or preventative action.

Competent Person for a Pipeline Company:

The determination of a need for action at a company must be conducted by a person who is competent (i.e. a person who is qualified, trained and experienced to conduct safety incident investigations). A determination of need for action must also be reviewed by an appropriate authority (i.e. management) to confirm that the determination was appropriate, that related learning is incorporated, and that information has been shared with workers to increase awareness and prevent similar occurrences.

Competent Person for a Contractor:

The determination of a need for action at a company may also be conducted by a contractor if:

  1. the near miss resulted from an action taken by the contractor; and
  2. the contractor is competent (i.e. the contractor is qualified, trained and experienced to conduct safety incident investigations).

A determination of need for action must be reviewed by an appropriate authority. In the case of a contractor, the appropriate authority is either:

  1. the contractor’s management (and then the pipeline company must be advised of the determination); or
  2. the pipeline company’s management.

The review by the appropriate authority must be undertaken in order to confirm that the determination was appropriate, that related learning is incorporated, and that information has been shared with workers to increase awareness and prevent similar occurrences.

II - Security Performance Measures

1. Training and Competency

Guidance

Employees are a company’s greatest security asset; all employees must have knowledge of the company security management program, as well as their role and responsibilities within the program.

This measure will gather data on the company’s security training program.

This information collected as a result of this measure should not include data on a company’s security awareness process. The NEB recognizes that security awareness initiatives (such as posters, bulletins or notices on a company’s intranet, etc.) are valuable components of a company’s overall security management program. Nevertheless, security awareness initiatives do not replace the need for training for each employee.

Subsection 6.5(1) of the OPR states that a company shall, as part of its management system,

  • (j) establish and implement a process for developing competency requirements and training programs that provide employees and other persons working with or on behalf of the company with the training that will enable them to perform their duties in a manner that is safe, ensures the security of the pipeline and protects the environment;
  • (k) establish and implement a process for verifying that employees and other persons working with or on behalf of the company are trained and competent and for supervising them to ensure that they perform their duties in a manner that is safe, ensures the security of the pipeline and protects the environment.
1. Training and Competency
2014 Company Performance
The total number of company employees who have current security training versus the total number of company employees.
Pipeline Type Employees with Security Training Percentage
Average Employees Average Trained
Gas > 50 km and < 5000 km 104 100 96
2013/2014 Average 99 95 96
Gas > 5000 km 891 860 97
2013/2014 Average 837 793 95
Liquid > 50 km 519 476 92
2013/2014 Average 520 435 84
Pipeline Systems Total Employees Total Trained Percentage
32 11,184 10,424 93
2013/2014 Average 10,526 9,216 88

Who is a “company employee”?

This measure applies to all employees of a company. This includes employees that are involved in regular, abnormal or upset conditions on NEB-regulated pipelines. It also includes employees who are working in the same location as these employees but are not directly involved with NEB-regulated pipelines.

The company management system should identify any consultants and contractors that require security training. This measure also applies to these consultants and contractors.

Paragraph 6.5(1)(l) of the OPR requires that a company establish and implement a process to make persons working on behalf of a company aware of their responsibilities. Paragraph 6.5(1)(q) of the OPR requires that a company establish and implement a process for coordinating and controlling operational activities of employees or other people working with or on behalf of the company so that each person is aware of the activities of others.

What is “current security training”?

Current security training means that as of the end of the reporting period an employee has the required training as set out in the company’s security training program. The company’s security training program will define what level of training every employee requires and the length of time between initial and follow-up training.

While Clause 8.3.2 of CSA Z246.1, Security Management for Petroleum and Natural Gas Systems, recommends a 24-month recurring timeline for training, companies are expected to define the timeline for follow-up training within their management system, based on security training needs.

The type and extent of training may vary depending on an employee’s position and location in the company. For example, an employee working in a corporate environment may receive training regarding handling mail or on protection of information measures. Operations employees working at field locations may receive training on suspicious activity and photography, or on recognizing and handling suspicious packages. Finally, employees with a designated security role may receive enhanced training on documenting, reporting and managing security incidents.

Security training is a structured learning event with a means of assessing employee competence. Examples include:

  • computer-based module with a test/exam; or
  • instructor-led training with a test/exam.

This performance measure does not require a company to report the type of security training provided to employees. However, companies are expected to track this information internally along with its other performance measures for security for inclusion in the company’s annual report required under Subsection 6.6(1) of the OPR. The NEB will review this material during on-site compliance activities.

III - Emergency Management Performance Measures

1. Emergency Response Exercises

Guidance

The purpose of this measure is to collect information regarding a company’s preparedness to mitigate hazards and risks associated with emergency responses. Paragraphs 6.5(1)(f), (t) and (u) of the OPR provide guidance on the management system processes necessary for such mitigation. Each category of exercises in this measure is to be reported separately.

1. Emergency Response Exercises
2014 Company Performance

The total number of emergency response exercises conducted versus the total number of emergency response exercises planned for each of the following:Footnote 2

  • drills;
  • tabletop (i.e. mock) exercises;
  • functional (i.e. simulation) exercises; and
  • full scale (i.e. major) exercises.
Pipeline Type Emergency Response Exercises Percentage
Average Planned Average Conducted
a. Drills
Gas > 50 km and < 5000 km 0.6 0.8 133
2013/2014 Average 0.75 0.7 100
Gas > 5000 km 0 0 N/A
2013/2014 Average 0 0 N/A
Liquid > 50 km 4 4 100
2013/2014 Average 5 4.5 90
b. Tabletop Exercises
Gas > 50 km and < 5000 km 2.8 3.9 139
2013/2014 Average 2.7 3 113
Gas > 5000 km 20 22 110
2013/2014 Average 20 21 105
Liquid > 50 km 3 3 100
2013/2014 Average 4 4 100
c. Functional Exercises
Gas > 50 km and < 5000 km 1.2 1.2 100
2013/2014 Average 1.6 1.5 97
Gas > 5000 km 0 0 N/A
2013/2014 Average 0.5 0.5 100
Liquid > 50 km 1 1 100
2013/2014 Average 0.7 0.7 100
d. Full Scale Exercises
Gas > 50 km and < 5000 km 0.2 0.3 150
2013/2014 Average 0.15 0.3 200
Gas > 5000 km 2 3 150
2013/2014 Average 2 3 150
Liquid > 50 km 0 0 N/A
2013/2014 Average 0.15 0.15 100
Pipeline Systems Total Planned Total Conducted Percentage
32 281 278 99
2013/2014 Average 299 296 99

What is an “emergency response exercise”?

For the purposes of these performance measures, emergency response exercises are defined as follows:

  • Drills: a supervised activity that tests a single or specific operation or function. Drills are commonly used to provide training on new equipment, or test new procedures; to practice and maintain skills; or to prepare for more complex exercises. For the purposes of this measure, “man down” and fire drills are excluded and should not be reported.
  • Tabletop Exercise: a facilitated analysis of an emergency situation in an informal, stress-free environment. A tabletop exercise is designed to elicit constructive discussion as participants examine and resolve problems based on existing operational plans and identify where those plans need to be changed.
  • Functional Exercise: a single or multi-agency activity designed to evaluate capabilities and multiple functions using simulated response, without moving real people or equipment to a real site. A functional exercise is designed to evaluate management of emergency operations centers, command posts and headquarters.
  • Full-Scale Exercise: a multi-agency, multi-jurisdictional activity involving the mobilization and actual movement of emergency personnel, equipment, and resources, as if a real incident had occurred.

Companies may report a real incident as an exercise if it meets the same objectives as the planned exercise, if the incident occurs in the region that a planned exercise was to occur, and if appropriate methodology is used.

What is the difference between a drill and a functional exercise?

A drill involves a single function, whereas functional exercises involve multiple functions. Drills involve the actual deployment of resources and personnel, whereas functional exercises use simulation.

2. Communication

Guidance

Companies are required under section 33 of the OPR to establish and maintain liaison with the agencies that may be involved in an emergency situation. Under section 34, companies must take reasonable steps to make sure that all parties are aware of the procedures to be followed in an emergency situation. The information provided by the company must be consistent with what is specified in the company’s Emergency Procedures Manual (EPM), required by section 32 of the OPR.

At the time of an emergency situation, the assistance of various first responders (e.g. fire, police and medical) as well as other parties may be required. Prior knowledge of potential hazards and individual roles by the company personnel, first responders and other parities prior to an emergency is critical for the safety of all involved.

2. Communication
2014 Company Performance
The number of liaison activities conducted versus the number of liaison activities planned.
Pipeline Type Emergency Management Liaison Activities Percentage
Average Planned Average Conducted
Gas > 50 km and < 5000 km 66 82 124
2013/2014 Average 42 51 120
Gas > 5000 km 195 190 97
2013/2014 Average 211 204 96
Liquid > 50 km 42 43 102
2013/2014 Average 53 54 102
Pipeline Systems Total Planned Total Conducted Percentage
32 2,018 2,171 108
2013/2014 Average 2,034 2,099 103

What are “parties”?

Parties include: police, fire departments, emergency medical services, and all other appropriate organizations (e.g. mutual aid partners, contractors, spill cooperatives), government departments and agencies (e.g. NEB, Transport Safety Board), Aboriginal groups where applicable, and persons who may be associated with an emergency response activity on or adjacent to the pipeline.

What are liaison activities?

A liaison activity is an exchange of information to gain mutual understanding and cooperation with parties that may be involved in an emergency situation. Examples of information discussed in an exchange of information include:

  • the type and locations of a company’s facilities;
  • all potential hazardous products transported in the pipeline and/or stored at company facilities in significant volumes;
  • key roles of personnel and agencies involved in an emergency;
  • response capabilities (e.g. of people, equipment); and
  • emergency procedures and practices for dealing with an emergency consistent with those specified in the EPM.

Liaison activities reportable for this measure include: meetings, telephone conversations, information sessions, and presentations.

In the case of multiple parties participating in an integrated liaison event, each party that is participating can be considered a liaison activity for the purposes of this measure.

3. Training and Competency

Guidance

Section 46 of the OPR requires a company to develop and implement a training program for any employee directly involved in the operation of a pipeline. The section requires the training program to instruct the employee on the emergency procedures set out in the EPM and the procedures for the operation of all emergency equipment that the employee could reasonably be expected to use.

In addition, the EPM should list roles and responsibilities for employees and contractors of the company. The employees and contractor staff referred to in the measure are those identified as fulfilling a role in the EPM.

3. Training and Competency
2014 Company Performance
The total number of company employees and contractors identified as having a role and responsibility during an emergency versus the total number of company employees and contractors that have up-to-date training to carry out their expected emergency management roles and responsibilities.
Pipeline Type Persons With an Emergency Management Role Percentage
Average Persons Average Persons Trained
Gas > 50 km and < 5000 km 47 44 94
2013/2014 Average 50 47 95
Gas > 5000 km 267 247 93
2013/2014 Average 267 244 92
Liquid > 50 km 74 65 88
2013/2014 Average 81 73 90
Pipeline Systems Total Persons Total Persons Trained Percentage
32 2,240 2,035 91
2013/2014 Average 2,362 2,149 91

How does a Contractor fulfill a role in the EPM?

Often contractors fulfill a company role in responding to an emergency on its behalf or performing critical roles for incident command. For the purposes of this measure, these contractors are considered equivalent to company staff. Contractors that are fulfilling contract requirements for equipment or supplies on an “as needed” basis are not to be included in this measure.

What is “trained”?

Trained refers to employee training on the emergency procedures set out in the EPM and response plans, as well as training on the procedures for the operation of all emergency equipment that an employee could reasonably be expected to use.

Employees and contractors working with the company on December 31 of the year in which the measures are being reported on must be counted as trained for the purposes of this measure.  Employees and contractors who were trained earlier in that calendar year but who are no longer employed with the company are not to be counted as trained for this measure. Contractors that are on an “as needed basis” are also not to be counted as having been trained.

What is “up-to-date training”?

Up-to-date training means that at the end of the year being reported on, an employee or contractor has the required training. Training requirements for roles and responsibilities should either be in a training program, in a company management system or in the emergency management program. These processes should identify a frequency for training. An employee must meet the minimum requirements set out in these processes.

At the end of the reporting period the training records for all employees and contractor staff will be assessed to determine if the training is up-to-date with the company requirements. It is recognized that new employees may not have received all training by the end of the calendar year. However, the reported information must include all employees that have not met the training requirements, including new employees.

4. Coordinating Operational Activities

4. Coordinating Operational Activities
2014 Company Performance
The total number of company employees and contractors who have participated in emergency response exercises and drills versus the total number of company employees and contractors identified as having a role and responsibility in an emergency.
Pipeline Type Participation in Exercises and Drills Percentage
Average Persons Average Participation
Gas > 50 km and < 5000 km 47 40 85
2013/2014 Average 47 39 78
Gas > 5000 km 267 238 89
2013/2014 Average 267 235 88
Liquid > 50 km 64 62 97
2013/2014 Average 76 62 84
Pipeline Systems Total Persons Total Participation Percentage
32 2,224 2,039 92
2013/2014 Average 2,354 2,083 88

Guidance

What is an “emergency response exercise”?

Emergency response exercises and exercise frequency are discussed in Emergency Management Performance Measure #1.

What are “roles and responsibilities”?

The EPM should list roles and responsibilities for employees and contractors of the company. The employees and contractors referred to in the measure are those identified as fulfilling a role in the EPM.

If an employee, identified as having a role in the EPM, has participated in several drills or exercises, that person should only be counted once.

What is a “contractor”?

For the purposes of this measure, a contractor is a person that is not an employee of the company but that fulfills a company role in responding to an emergency or performing critical roles for incident command on the company’s behalf. These contractors must perform this role full time and be integrated into the company’s training plan (as if they were company employees). Contractors that are fulfilling contract requirements for equipment or supplies on an “as needed” basis are not to be included in this measure.

What if an employee participates in an exercise in the United States?

The geographic location of an exercise or drill does not preclude its inclusion in the reported information, provided that the conditions of the exercise are similar to those encountered along the company’s pipeline. However, when possible, exercises should be conducted in Canada to test integration with Canadian agencies.

IV - Integrity Management Performance Measures

1. Pipeline Condition

Guidance

This measure provides data which is a consideration in assessing the effectiveness of an Integrity Management Program (IMP) as per Paragraph 6.5(1)(u) of the OPR. A company IMP should track activities, methods of obtaining the data, the resulting data and the mitigation. The actual field verified defects confirmed through field investigations versus the number of features identified by ILI for field investigation will provide a leading measure of the effectiveness of the IMP. It is expected that all field verified defects will be repaired or mitigated.

As a result of processing times, permit approvals, weather restrictions and other such conditions, it is possible that field verification will not be executed within the same reporting year as the ILI. Only field verified data (e.g. Non-Destructive Examination (NDE) data) obtained in the year that is being reported on should be provided.

1. Pipeline Condition
2014 Company Performance

The total number of features identified by in-line inspection for field investigation (according to integrity management program dig criteria) versus the total number of field verified features found to be defects and repaired by permanent or temporary methods, or mitigated by pressure reduction for the following hazards:

  • metal loss;
  • dents; and
  • cracks with a depth greater than 40% of the nominal pipeline wall thickness.
Pipeline Type Average Features Identified for Investigation Average Defects Found and Repaired/Mitigated Percentage of Features that were Defects
a. Metal Loss
Gas > 50 km and < 5000 km 0.9 0.8 89
2013/2014 Average 1.3 0.5 36
Gas > 5000 km 38 47 124
2013/2014 Average 33 27 83
Liquid > 50 km 17 1.6 9
2013/2014 Average 13 3.6 28
b. Dents
Gas > 50 km and < 5000 km 0 0 N/A
2013/2014 Average 0 0 N/A
Gas > 5000 km 1.5 2.1 140
2013/2014 Average 2.8 2.1 75
Liquid > 50 km 2.2 4.8 51
2013/2014 Average 8 4.3 54
c. Cracks With a Depth Greater than 40% of the Nominal Pipeline Wall Thickness
Gas > 50 km and < 5000 km 0.1 1 1,000
2013/2014 Average 0.05 0.5 1,000
Gas > 5000 km 1.4 4 307
2013/2014 Average 1.7 3 185
Liquid > 50 km 2.2 5 218
2013/2014 Average 4.1 3.9 95
Pipeline Systems Total Features Total Defects Repaired/Mitigated Percentage
32 1,338 852 64
2013/2014 Average 1,165 669 57

What is an “ILI feature”?

An ILI feature is an unexamined deviation in pipe material or welds detected and/or reported by an ILI.

What is “metal loss”?

Pipeline metal loss is a reduction in wall thickness that is primarily due to corrosion, gouges and grooves. Metal loss defects are identified in accordance with Clause 10.10.2.7 of CSA Z662 (corrosion) and Clause 10.10.3 of CSA-Z662 (gouges and grooves).

What is a “dent”?

A dent is a dent defects as described in Clause 10.10.4.2 of CSA Z662.

What is a “crack”?

Cracks include both mechanically driven and environmentally assisted cracking (e.g. Stress Corrosion Cracking (SCC), Stress Corrosion Fatigue) on the pipe body, seam or girth weld, as defined by Annex H of CSA Z662.

With respect to the relation between cracks and ILI reports, the company must identify how it will address all cracks as a result of ILI reports. Cracks are reported using a variety of terminology. An ILI feature reported as “crack-like”, “crack-field”, “seam-weld anomaly”, or other linear anomaly which could be interpreted to be a crack, must be considered as a crack for this measure.

Why do cracks greater than 40% need to be addressed?

Cracks of any length or depth are considered defects according to CSA Z662. However, ILI technologies may not be able to accurately size cracks deeper than 40% of the nominal wall thickness. Therefore, companies must further investigate all cracks deeper than 40% of the nominal wall thickness for repair or mitigation.

What method should be used to measure cracks?

Depths and lengths of crack features can be measured by buffing or non-destructive examination, ILI, or a combination of these. Consideration must be given to each method’s uncertainty when selecting features to be field-investigated (as described in Annex D of CSA-Z662).

If a “colony” of cracks is encountered how is it dealt with?

For a cracking colony (e.g. SCC), companies must report each crack feature within the colony with a depth greater than 40% of the nominal wall thickness.

Will reporting on this measure replace significant SCC reporting?

At this time, this reporting is not intended to replace significant SCC reporting.

If an engineering assessment is conducted, do the defects identified through ILI or field investigation still have to be included as if they were defects as defined under CSA Z662 or exceeding the 40% crack criteria?

Yes. Even though the engineering assessment could provide the criticality analysis that the feature or defect can remain in the pipeline without the immediate impact on integrity, such defects must still be reported, because they exceed the acceptability criteria.

Therefore, companies must still report the number of features or defects remaining in the pipeline exceeding the criteria provided in the measure. Companies may provide clarification related to further action taken or to be taken when reporting on the measures.

What does a company report when it has not performed field investigation and repairs or mitigation?

If a company has not performed any field investigation (excavation) including repairs or mitigation of features, or where no defects were field verified, then this measure should be reported as no defects found for repair or mitigation. Companies should only report on actual field verification activities.

What are “permanent or temporary repair methods”?

Defects can be repaired using temporary or permanent methods. Temporary or permanent methods can be found in Clause 10.12 and Table 10.1 of CSA Z662, respectively.

What is a defect mitigated by pressure reduction?

A defect mitigated by pressure reduction is a field verified defect that is being mitigated by means of a pressure reduction (to restore factors of safety in accordance with CSA Z662). Where a pressure reduction is performed as both a repair and mitigation measure to address a single defect, the defect subjected to the pressure reduction is only reported under Integrity Management Performance Measure #1.

Where multiple repairs and/or mitigations are performed on a complex defect, the company must report the number of individual defects found and repaired/mitigated in the complex defect. For example, for a crack in a dent, if the company used pipe replacement to remove both defects as the repair method, it would report two defects repaired.

2. Equipment Inspection

Guidance

The purpose of this measure is to track completion of scheduled facility integrity inspections so as to prevent harm to employees, the public and the environment. This supports Paragraph 6.5(1)(u) of the OPR, which requires a process for inspections for an IMP.

2. Equipment Inspection
2014 Company Performance
  1. A = Tank(s)
  2. B = Mainline Valve(s)
    1. Total number of ___A/B___ inspections conducted versus total number of ___A/B___
    2. Routine staff ___A/B___ inspections conducted versus routine staff ___A/B___ inspections scheduled
    3. Certified maintenance _A/B_ inspections conducted versus certified maintenance _A/B_ inspections scheduled
Pipeline Type Data on Facility Inspections
A.i. Tank Inspections versus Number of Tanks
Pipeline Average Tanks Average Conducted Percentage
Gas > 50 km and < 5000 km 2 0.3 15
2013/2014 Average 2.5 3.7 146
Gas > 5000 km 0 0 N/A
2013/2014 Average 0 0 N/A
Liquid > 50 km 27 184 681
2013/2014 Average 28 222 805
Pipeline Systems Total Tanks Total Inspections Percentage
32 552 7,384 1,338
2013/2014 Average 550 8,660 1,574
B.i. Mainline Valve Inspections versus Number of Mainline Valves
Pipeline Average Mainline Valves Average Conducted Percentage
Gas > 50 km and < 5000 km 101 110 109
2013/2014 Average 87 104 119
Gas > 5000 km 4,780 2,539 53
2013/2014 Average 3,755 2,560 69
Liquid > 50 km 71 114 161
2013/2014 Average 66 276 421
Pipeline Systems Total Mainline Valves Total Inspections Percentage
32 16,670 21,779 131
2013/2014 Average 13,326 24,392 183
A.ii. Routine Staff Tank Inspections Conducted versus Scheduled
Pipeline Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 0.6 0.6 100
2013/2014 Average 6 8 134
Gas > 5000 km 0 0 N/A
2013/2014 Average 0 0 N/A
Liquid > 50 km 341 365 107
2013/2014 Average 409 440 107
A.iii. Certified Maintenance Tank Inspections Conducted versus Scheduled
Pipeline Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 0 0 N/A
2013/2014 Average 0 0 N/A
Gas > 5000 km 0 0 N/A
2013/2014 Average 0 0 N/A
Liquid > 50 km 4 4 100
2013/2014 Average 3.7 3.7 100
B.ii. Routine Staff Mainline Valve Inspections Conducted versus Scheduled
Pipeline Type Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 127 127 100
2013/2014 Average 129 129 100
Gas > 5000 km 328 327 100
2013/2014 Average 164 164 100
Liquid > 50 km 101 101 100
2013/2014 Average 442 442 100
B.iii. Certified Maintenance Mainline Valve Inspections Conducted versus Scheduled
Pipeline Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 93 93 100
2013/2014 Average 79 79 100
Gas > 5000 km 4,780 4,751 99
2013/2014 Average 3,723 3,702 99
Liquid > 50 km 127 126 99
2013/2014 Average 112 110 98
Pipeline Systems Total Inspections Scheduled Total Inspections Conducted Percentage
32 28,788 29,163 101
2013/2014 Average 32,552 33,051 102

What is a “facility”?

For the purposes of this measure, a facility may include pump stations, compressor stations, metering stations, mainline block valve yards, tank farms, and launcher and receiver yards. This definition is intended to be consistent with the facilities identified in CSA Z662.

What tanks and mainline valves are to be assessed - some or all?

All tanks and mainline valves that are suitable for service that have not been formally deactivated, decommissioned or abandoned are expected to be inspected.

What “tanks” are included?

A company shall include all tanks (see Clause 4.15 of CSA Z662) that are part of the pipeline system or facility and have not been formally deactivated, decommissioned or abandoned. This includes sump tanks for laboratories.

What is considered a “mainline valve”?

Mainline valves are sectionalizing valves as defined in CSA Z662. Clause 4.4.3 of CSA Z662 identifies where these valves may be installed. Generally these valves are installed between large sections of pipeline and are able to stop the flow in a pipeline section.

What does “scheduled inspection” mean?

For the purposes of this measure, a scheduled inspection includes inspections, both initially planned (for the year being reported), as well as inspections that were subsequently added (during the year being reported). However, a scheduled inspection does not include corrective action (follow-up) inspections unless they are scheduled at the start of the year in which the measure is being reported.

As a result, the number of completed inspections should not exceed the number scheduled.1

What is an inspection?

An inspection that is typically counted in this measure is one that has been scheduled in the following categories:

  • Routine staff inspections (e.g. daily and monthly); and
  • Certified inspections (e.g. according to a maintenance schedule which may or may not be linked to a required standard).

As a minimum, the company is required to report the number of inspections scheduled and conducted as required by CSA Z662 (Clauses 10.9.2.1, 10.9.3.1 and 10.9.6.2). Certified inspections would be carried out in accordance with any standards referenced within CSA Z662 such as American Petroleum Institute (API) 653, which covers above-ground tanks. Inspections of a valve must include partial operation of the valve.

Inspections of underground tanks must include leak detection systems and should be conducted in accordance with National Fire Protection Association (NFPA) 326, Standard for the Safeguarding of Tanks and Containers for Entry, Cleaning, or Repair and National Leak Prevention Association (NLPA) Standard 631, Entry, Cleaning, Interior Inspection, Repair, and Lining of Underground Storage Tanks.

3. Facility Piping Inspection

Guidance

The purpose of this measure is to track completion of planned facility integrity inspections so as to prevent harm to employees, the public and the environment. This supports Paragraph 6.5(1)(u) of the OPR, which requires a process for inspections for integrity management.

3. Facility Piping Inspection
2014 Company Performance

A. Liquid Pump Stations

Facility Piping Inspection

  1. routine staff inspection; and
  2. certified maintenance inspection

The total number of stations must also be reported so that the data may be normalized for additional comparisons.

B. Gas Compressor Stations

The total number of compressor stations where piping was inspected versus the total number of compressor stations where the piping was scheduled to be inspected for:

  1. routine staff inspection; and
  2. certified maintenance inspection

The total number of stations must also be reported so that the data may be normalized for additional comparisons.

Pipeline Type Facility Piping Inspections Percentage
Average Scheduled Average Conducted
A.i. Liquid Pump Station Piping Routine Staff Inspections
Liquid > 50 km 7.6 8 105
2013/2014 Average 7.8 8 103
ii. Liquid Pump Station Piping Certified Maintenance Inspections
Liquid > 50 km 5 5 100
2013/2014 Average 4.8 4.8 100
B.i. Gas Compressor Station Piping Routine Staff Inspections
Gas > 50 km and < 5000 km 2 2 100
2013/2014 Average 4 4 100
Gas > 5000 km 39 39 100
2013/2014 Average 39 39 100
ii. Gas Compressor Station Piping Certified Maintenance Inspections
Gas > 50 km and < 5000 km 1 1 100
2013/2014 Average 1.2 1.2 100
Gas > 5000 km 12 11 92
2013/2014 Average 14 13 93
Pipeline Systems Total Scheduled Total Inspected Percentage
32 421 420 100
2013/2014 Average 430 429 100

What does “scheduled inspection” mean?

For the purposes of this measure, a scheduled inspection includes inspections, both initially planned (for the year being reported), as well as inspections that were added (during the year being reported). However, this does not include corrective action (follow-up) inspections unless they are scheduled at the start of the planning year.

What is a “piping inspection”?

An adequate and effective IMP should identify that piping inspections are to be conducted commensurate to the hazards (see API 570, referenced within CSA Z662). This may include: visual inspections, non‐destructive testing inspections, cathodic protection surveys, pressure testing and other methods. Certified maintenance inspections are those that are conducted in accordance with a detailed maintenance schedule that should be guided by a standard such as API. Any above-ground and below-ground piping at a facility that carries product is to be included when reporting on this measure.

4. Facility Inspection Effectiveness

Guidance

The purpose of this measure is to track the number of incidents at liquid and gas facilities and to compare this number so as to develop any required mitigation strategies.

4. Facility Inspection Effectiveness
2014 Company Performance
  1. A. Liquid Facilities
    The total number of reportable incidents at liquid facilities versus the total number of liquid facilities.
  2. B. Gas Facilities
    The total number of reportable incidents at gas facilities versus the total number of gas facilities.
Pipeline Type Reportable Incidents at Facilities Percentage
Average Facilities Average Incidents
A. Reportable Incidents at Liquid Facilities
Liquid > 50 km 39 1.5 4
2013/2014 Average 43 1.5 3
B. Reportable Incidents at Gas Facilities
Gas > 50 km and < 5000 km 49 3 6
2013/2014 Average 51 3 6
Gas > 5000 km 1,991 19 0.95
2013/2014 Average 1,901 14 0.7
Pipeline Systems Total Scheduled Total Incidents Percentage
32 7,233 112 1.5
2013/2014 Average 6,988 95 1.4

What are “reportable incidents”?

A reportable incident refers to the definition of incident contained in the OPR. Reporting requirements for incidents, as defined in the OPR, are identified in section 52 of the OPR.

What are “liquid facilities”?

Liquid facilities are above-ground or in vaults and include: pump stations, metering stations, mainline block valves, tank farms, terminals and launcher and receiver yards.

What are “gas facilities”?

Gas facilities are above-ground or in vaults and include: compressor stations, metering stations, mainline block valve, and launcher and receiver yards.

5. Assessment of Pipeline Hazards

Guidance

The purpose of this measure is to track completion of planned pipeline integrity inspections so as to prevent harm to the public and the environment. This supports Paragraph 6.5(1)(u) of the OPR that requires a process for monitoring facilities.

5. Assessment of Pipeline Hazards
2014 Company Performance

The kilometres of pipeline that have been assessed for an integrity hazard versus the kilometres of pipeline that are susceptible to the integrity hazard prior to any form of mitigation. For each pipeline the integrity hazard assessment method is to be reported for the following categories:

  1. metal loss;
  2. cracking;
  3. external interference;
  4. material, manufacturing or construction; and
  5. geotechnical and weather-related.
Pipeline Type Pipeline Kilometres Assessed for Susceptible Hazards Percentage
Average Susceptible Average Assessed
a. Metal Loss Hazard Assessment
Gas > 50 km and < 5000 km 207 160 77
2013/2014 Average 182 141 77
Gas > 5000 km 1,194 1,109 93
2013/2014 Average 1,186 1,136 96
Liquid > 50 km 309 184 60
2013/2014 Average 296 204 69
b. Cracking Hazard Assessment
Gas > 50 km and < 5000 km 145 110 76
2013/2014 Average 124 104 84
Gas > 5000 km 569 290 51
2013/2014 Average 502 306 61
Liquid > 50 km 186 142 76
2013/2014 Average 174 261 150
c. External Interference Hazard Assessment
Gas > 50 km and < 5000 km 135 126 93
2013/2014 Average 133 120 90
Gas > 5000 km 662 662 100
2013/2014 Average 657 723 110
Liquid > 50 km 347 206 59
2013/2014 Average 335 202 60
d. Material, Manufacturing or Construction Hazard Assessment
Gas > 50 km and < 5000 km 195 148 76
2013/2014 Average 163 131 80
Gas > 5000 km 285 243 85
2013/2014 Average 205 167 81
Liquid > 50 km 180 157 87
2013/2014 Average 159 189 119
e. Geotechnical or Weather Related Hazard Assessment
Gas > 50 km and < 5000 km 119 107 90
2013/2014 Average 116 110 95
Gas > 5000 km 663 663 100
2013/2014 Average 658 658 100
Liquid > 50 km 122 67 55
2013/2014 Average 104 88 85
Number of Pipelines Total Susceptible Total Assessed Percentage
58 77,499 58,825 76
2013/2014 Average 73,252 64,824 88

How does a company report this measure?

Companies are to report this measure based upon integrity hazard assessment reports received in the year that is being reported on. Each hazard assessment method is to be identified for each hazard and if ILI is used for assessment then the ILI resolution must be recorded and reported.

What does “integrity hazard” mean?

An integrity hazard is any of the five pipeline integrity hazards identified in the measure that are encountered through digs or through integrity assessments. A section of pipeline may have more than one identified hazard. Each hazard will be assessed under more than one measure regardless of quantity and severity. Clause 2.6.1 of Annex H of CSA Z662 describes the hazards in terms of primary causes of pipeline failures.

What is “susceptible hazard”?

A pipeline is considered susceptible to a hazard unless it has been demonstrated (e.g. through ILI, investigative digs) that the likelihood of this hazard condition is negligible.

What is included in a pipeline integrity hazard assessment?

A pipeline integrity hazard assessment is:

  • conducted for every pipeline integrity hazard. This means that there may be multiple measures based on the number of hazards for a pipeline; and
  • validated with data from ILI, hydro-testing and direct assessment.

A pipeline integrity hazard assessment must consider manufacturing, construction, testing and operational and maintenance records (e.g. operating pressures, repairs, growth rates, incidents), and condition monitoring.

What is to be reported for external interference?

The potential for external interference from unauthorized activities on the right-of-way exists on all portions of a pipeline. In this case the hazard is limited to pipeline depth of cover less than originally designed, as determined through surveys.

6. Shutdowns for Hazard Control

Guidance

This measure is not a leading measure; it is a lagging measure. However, it provides an indication of a company’s safety culture by following the number of shutdowns to protect the public and the environment.

6. Shutdowns for Hazard Control
2014 Company Performance

The total number of shutdowns of a pipeline segment or facility to protect the public, property and the environment as a result of:

  • emergency;
  • precautionary (i.e. a false alarm);
  • unplanned repair; and
  • planned integrity testing, maintenance or repair.
Pipeline Type Shutdowns for Hazard Control
a. Emergency b. Precaution c. Unplanned Repair d. Planned Repair Total
Gas > 50 km and < 5000 km 0 0 0.18 0.06 4
2013/2014 Average 0.25 0 0.14 0.08 8
Gas > 5000 km 1 3 4 5 104
2013/2014 Average 1.2 1.7 3.3 5.7 94
Liquid > 50 km 1 10 0 5 505
2013/2014 Average 1.2 11.3 0.2 4.4 559
Total 65 426 36 182 709
2013/2014 Average 48 385 40 189 661

What is a facility?

In addition to pipeline segments being shutdown, for the purposes of this measure, a facility shutdown may include pump stations, compressor stations, and tank farms. A facility does not include processing plants.

What is a shutdown for an “emergency”?

An emergency shutdown is for a condition that could include: overpressure, off-spec gas, geotechnical conditions, weather conditions, or release of product. For the shutdown to be considered an emergency it must occur within five days of the condition being identified.

What is a “precautionary” shutdown (i.e. a false alarm)?

A precautionary shutdown (i.e. a false alarm) could occur where the control room operators proactively shutdown the system (based on approved procedures) when they are unable to identify the cause for various alarms on the system. A precautionary shutdown could also occur as a result of calls on the emergency line (before they are followed up with and determined to be a false alarm by company employees).

What is an “unplanned repair”?

An unplanned repair is a repair that was identified as being necessary between six days and 12 weeks from an operations or maintenance activity such as an investigative dig. The unplanned repair must have been identified as being necessary as a result of the operations or maintenance activity. The decision as to whether to undertake an unplanned repair would be based on information obtained at the time of the activity.

What is “planned integrity testing, maintenance or repair”?

Planned integrity testing, maintenance or repair refers to a scheduled activity that should be in the IMP for the year that is being reported on. It may also be a shutdown that was planned more than 12 weeks prior to the shutdown.

V - Environmental Protection Performance Measures

1. Program Training

Guidance

The intent of this measure is to gather data on the employees required to have training in the EP Program, and to determine whether these employees have received an appropriate level of training.

The information collected as a result of this measure should not include data on a company’s environmental awareness process. Notwithstanding the fact that this measure does not apply to this type of data, awareness of the EP Program and of environmental protection in general should be promoted throughout a company, both in the office and in the field. In addition to the employees requiring training on the EP Program, the EP Program should also identify a process and procedures for implementation of an awareness process at corporate, regional and field offices.

1. Program Training
2014 Company Performance

The number of company employees who have received training on the company-wide Environmental Protection Program (EP Program) versus the number of employees required by the EP Program to receive training on it.

Pipeline Type Employees Receiving Training on the Environmental Protection Program Percentage
Average Employees Requiring Training Average Trained
Gas > 50 km and < 5000 km 60 54 90
2013/2014 Average 58 51 88
Gas > 5000 km 550 526 96
2013/2014 Average 694 653 94
Liquid > 50 km 486 414 85
2013/2014 Average 518 440 85
Pipeline Systems Total Employees Requiring Training Total Trained Percentage
32 11,910 10,348 87
2013/2014 Average 11,007 9,558 87

What is an EP Program?

Section 48 of the OPR requires companies to develop an EP Program that anticipates, prevents, manages and mitigates conditions which could adversely affect the environment. EP Programs must be management-system based. Refer to Sections 6.1 to 6.6 of the OPR for details regarding the requirements for a management system, and to section 55 for internal audit requirements.

Who does this measure apply to?

This measure applies to all employees of a company that are required by the EP Program to have training on the program. The company’s management system will include a process for training and establishing competency requirements for employees for their assigned tasks related to environmental protection. In addition, the EP Program must identify all employees who have tasks that could involve supervising staff or observing situations where the environment may be impacted. Paragraphs 6.5(1)(j) and (k) identify requirements relating to the processes for training programs, competency requirements and supervision.

What is a “company employee”?

A company employee includes employees that are involved in regular, abnormal or upset conditions on NEB-regulated pipelines.

The company management system should identify any consultants and contractors that require EP Program training as substitute resources or provisional contractors. This measure also applies to these consultants and contractors.

Paragraph 6.5(1)(l) of the OPR requires that a company establish and implement a process to make persons working on behalf of a company aware of their responsibilities. Paragraph 6.5(1)(q) of the OPR requires that a company establish and implement a process for coordinating and controlling operational activities of employees or other people working with or on behalf of the company so that each person is aware of the activities of others.

What is “training on the company-wide EP Program”?

Training on the company-wide EP Program is considered to be a structured learning event with a means of assessing competence. The level of training for each employee along with competency requirements will be appropriate to the level of accountability, and will be identified in the company’s management system-based EP Program. For example:

  • administrative staff working in the field might be required to take an overview with a quiz;
  • managers, professionals and technical (e.g. construction, operation and maintenance) staff might take an on-line module with a test; and
  • staff with direct accountability for environmental compliance, such as an environmental specialist/inspector, may be required to have formal classroom training with an exam.

When should employees be re-trained?

Training must be up-to-date. Up-to-date training means that at the end of the year in which the measures are being reported on, an employee or contractor has the required training. This should also be identified in the EP Program or management system. However, re-training is recommended within five years due to advances in industry best practices and potential changes to legislation.

How is this measure reported?

For the purposes of this measure, only employees that are employed with the company as of December 31 in the year in which the measures are being reported on will be counted as completing the training identified in the EP Program.

2. Site Specific Training

Guidance

The purpose of this measure is to gather data regarding the level of training on a company’s EP Plans so that environmental impacts can be avoided and that appropriate action is taken if they occur.

For both large construction projects and small maintenance digs, any employees and contractors on site are expected to be trained and competent for company environmental protection measures relevant to their assigned tasks.

For additional guidance, refer to Environmental Protection Performance Measure #1.

2. Site Specific Training
2014 Company Performance

The number of construction staff, both contractors and employees, with training on the site-specific Environmental Protection Plan (EP Plan) versus the number of persons working on construction sites.

Pipeline Type Construction Staff with Training on the Site-Specific Environmental Protection Plan Percentage
Average Construction Staff Average Trained
Gas > 50 km and < 5000 km 61 60 98
2013/2014 Average 5 44 98
Gas > 5000 km 1,640 1,624 99
2013/2014 Average 1,578 1,547 98
Liquid > 50 km 355 355 100
2013/2014 Average 396 393 99
Pipeline Systems Total Construction Staff Total Trained Percentage
32 12,561 12,505 100
2013/2014 Average 12,803 12,650 99

What is an EP Plan?

An EP Plan is a site-specific or project-specific plan designed for a construction project of any size where environmental impacts could occur. The EP Plan resides within the EP Program. The NEB Filing Manual contains additional information about EP Plans.

When is an EP Plan required?

An EP Plan is required for any activity that requires construction, repair or maintenance of a pipeline that has the potential to cause environmental impacts. The level of complexity of an EP Plan may vary. For example, for small maintenance digs, the EP Plan could be the company standard operating procedures (SOPs) that are identified in the EP Program.

3. Restoration of Agricultural Land

Guidance

The intent of this measure is for companies to track the status of reclamation on right-of-way that is in agricultural production. It is the Board’s expectation that within a five year period, the right-of-way will be fully reclaimed to a condition similar to the surrounding environment and consistent with the current use of the land.

3. Restoration of Agricultural Land
2014 Company Performance
  1. Kilometres of NEB-regulated right-of-way on agricultural lands that are restored to a condition similar to the surrounding environment and consistent with the current land use within five years of the in-service date versus the total kilometres of NEB-regulated right-of-way that is disturbed agricultural land
  2. Number of operational excavations on agricultural lands that are restored to a condition similar to the surrounding environment and consistent with the current land use within five years of the excavation versus the total number of operational excavations on agricultural land
Pipeline Type Pipelines with Disturbed Land Kilometres of Disturbed Agricultural Land Restored  
Average Disturbed Land Average Restored Percentage
A. NEB-Regulated Right-Of-Way on Agricultural Lands that are Restored
Gas > 50 km and < 5000 km 1 0.1 0.1 100
2013/2014 Average 0.5 0.05 0.05 100
Gas > 5000 km 3 49 41 84
2013/2014 Average 3 62 55 89
Liquid > 50 km 7 94 93 99
2013/2014 Average 78 106 94 89
Pipeline Systems Total Total Disturbed Total Restored Percentage
32 11 2,027 1,986 98
2013/2014 Average 11 2,291 2,049 89
B. Operational Excavations on Agricultural Lands that are Restored
Gas > 50 km and < 5000 km 3 5 3 60
2013/2014 Average 3 4.3 2.7 62
Gas > 5000 km 3 403 221 55
2013/2014 Average 3 478 244 51
Liquid > 50 km 14 169 136 80
2013/2014 Average 13 167 144 86
Pipeline Systems Total Total Excavated Total Restored Percentage
32 20 4,627 3,406 74
2013/2014 Average 19 4,797 3,618 75

To what precision must the length of pipeline right-of-way that is restored be reported?

The length of pipeline right-of-way that is restored is to be reported to a precision of 0.1 of a kilometre (100 metres).

What is “agricultural land”?

Agricultural land is the land currently used for agricultural production for both crop and pasture. Woody vegetation crops (e.g orchards, berry shrubs, etc.) and native prairie are excluded. In addition, agricultural land use reserve that does not have a demonstrated production is excluded.

What does “restored” mean?

Section 21 of the OPR, as well as CSA Z662 uses the term “restored”.

For the purposes of this measure, restored means that the right-of-way is reclaimed or returned to a state comparable to the surrounding environment and that the desired agricultural land use of those lands affected is accommodated when it is reasonable to do so.

Though some forested land is designated as agricultural land, it is not expected that trees would be planted in the right-of-way in these circumstances unless there is a specific requirement for wildlife habitat restoration.

Restoration of roads, railways and wetlands crossed by the pipeline within agricultural land are excluded from this measure.

What is “disturbed agricultural land”?

A right-of-way is considered disturbed agricultural land if there is an activity that breaks ground. This would include disturbances caused by pipe maintenance and new pipeline construction.

What is an “operational excavation”?

An operational excavation is an operations or maintenance activity that breaks ground to conduct a repair or investigation. It may occur at several locations along a pipeline. Each occurrence should be recorded and the reclamation for each occurrence should be tracked within the company management system for the EP Program.

How does a company report this measure?

All right-of-way that has been disturbed five years prior to the reporting year is to be assessed against the commitments made by the company in the original application for the pipeline, in the EP Plan and in compliance with the conditions of approval and the OPR. Therefore, any pipelines built during or after 2009 would be reported on in 2014. This measure includes newly purchased pipelines that are under construction, or new pipelines where post-construction monitoring is being conducted.

This measure is not intended to be retroactive. Rather, it is intended to assess the current reclamation status of the right-of-way for five-year-old pipelines. Therefore, companies are not expected to report on pipelines built prior to 2009.

4. Resolution of Environmental Issues

Guidance

The purpose of this measure is to identify environmental issues following the post-construction reclamation period and to make sure that they are recorded and addressed appropriately.

4. Resolution of Environmental Issues
2014 Company Performance

The total number of operational environmental issues identified in the EP Program or EP Plan that have been addressed versus the total number of operational environmental issues identified in the EP Program or EP Plan over a five-year period.

Pipeline Type Operational Environmental Issues  
Average Identified Average Addressed Percentage
Gas > 50 km and < 5000 km 13 9 69
2013/2014 Average 25 19 76
Gas > 5000 km 127 111 87
2013/2014 Average 99 81 82
Liquid > 50 km 101 51 50
2013/2014 Average 92 65 70
Pipeline Systems Total Identified Total Addressed Percentage
32 2,509 1,436 57
2013/2014 Average 2,336 1,693 72

What is an “operational environmental issue”?

An operational environmental issue is a liquid release, or an environmental issue that is identified as a result of monitoring and surveillance activities under the company EP Program or EP Plan. Operational issues are identified after the conclusion of the post-construction monitoring (either as voluntarily committed to or as a NEB condition of construction) and do not include right-of-way reclamation as a result of construction activities.

Operational environmental issues can include but are not limited to the topics in the following:

Operational environmental issues can include but are not limited to the topics in the following:

Residual Contamination RemediationFootnote 3

  • Contamination removal
  • Contamination containment
  • Pump and treat

Erosion

  • Slopes
  • Berms
  • Drainages and watercourses
  • Ditch line subsidence and excessive elevation

Water Course Crossings

  • Bank erosion
  • Bank slumping
  • Reclamation of fish habitat
  • Topography consistent with surroundings
  • Reclamation of riparian vegetation
  • Removal of temporary structures, such as bridges or sediment fencing
  • Potential barriers to fish passage
  • Changes to watercourse geomorphology

Soils

  • Poor drainage
  • Admixing
  • Compaction

Vegetation

  • Inappropriate reclamation strategy
  • Incorrect seed mix
  • Invasive plant and weed infestation

Access Control

  • Damage or removal

What is “addressed”?

For the purposes of this measure, addressed means that corrective action has been taken and, over a specified time, resolution will be achieved as committed to in either the company EP Program or EP Plan. For example, if a decision has been made to contain an oil spill to company property and monitor it until a point in time when remediation will occur (e.g. abandonment), then it has been addressed for the purposes of this measure. The issue should be under control and should no longer be causing additional adverse effects on the environment.

How does a company report this measure over five years?

To begin reporting, a company must have completed its post construction monitoring period (i.e. reclamation) as defined in the NEB conditions for the project or as defined in the company EP Program. Then a company must determine the number of operational environmental issues it currently has outstanding at the beginning of a calendar year. This will be determined from the EP Program or from its management system inventory of hazards.

  • During the first year all new issues and all addressed issues will be recorded and tracked along with the initial list.
  • In the second year the same process will occur and the first year’s results are reported on.
  • In the third year the same process will occur and the previous two years are reported on.
  • This process will continue until it becomes a moving five-year tracking process when, for example, in the seventh year, the report will be for year two to year six.

This performance measure will allow for ongoing tracking and trending of both the number of issues identified and the number addressed. The resulting ratio from the reported numbers could be considered as a rolling average. A company is encouraged to use the ratio in its own monitoring and analysis of this measure.

5. Environmental Inspections

Guidance

The purpose of this measure is to have adequate resources to provide maximum environmental protection during construction through appropriate oversight by qualified inspectors.

5. Environmental Inspections
2014 Company Performance

The total number of inspection days by a qualified environmental inspector for newly constructed pipeline versus the total number of construction days for all the company’s newly constructed pipeline.

Pipeline Type Pipelines With Construction Environmental Inspections Percentage
Average Construction Days Average Inspection Days
Gas > 50 km and < 5000 km 1 3 2 67
2013/2014 Average 0.5 1.5 1 67
Gas > 5000 km 2 256 408 159
2013/2014 Average 2 323 484 150
Liquid > 50 km 3 41 75 183
2013/2014 Average 3 29 57 198
Pipeline Systems Total Pipelines Total Construction Days Total Inspection Days Percentage
32 6 1,620 2,733 169
2013/2014 Average 6 1,352 2,291 170

What is an “inspection day”?

Each day that a qualified environmental inspector inspects a pipeline site is considered an inspection day. If two inspectors are on site on the same day for different aspects of construction then two inspection days should be reported. It is possible to have more inspection days than construction days on large sites where the length of the project calls for multiple inspectors.

What is a “qualified environmental inspector”?

For the purposes of this measure, a qualified environmental inspector is a person who has relevant post-secondary education or a suitable equivalent (e.g. a combination of training and experience), has proven competency in the field of environmental protection, and has appropriate training on the company’s EP Program and EP Plan. The company management system must provide further detail on qualifications for environmental inspectors.

What is “newly constructed pipeline”?

Newly constructed pipeline would include pipeline replacements or new pipelines that require NEB approval under sections 52 and 58 of the National Energy Board Act. Pipeline construction includes the clearing of land and does not include operational activities such as digs or repairs. This measure does not apply to pump stations, compressor stations, metering stations, mainline block valve yards, tank farms, launcher and receiver yards.

What is the construction period for this measure?

The construction period is from beginning of construction (which includes clearing) to the in-service date.

VI - Damage Prevention Performance Measures

1. Public Awareness of Pipelines

INTERPRETATION

In this measure, higher permissions and lower unauthorized activities result in a higher ratio. The ratio gives an indication of the effectiveness of damage prevention programs.

GUIDANCE

The NEB expects that a company’s Damage Prevention Program will follow a management system approach. A management system approach includes the development of:

  1. performance measures for assessing the company’s success in achieving its goals, objectives and targets;
  2. processes for identifying hazards and making sure that the hazards are mitigated and controlled; and
  3. a process for external communication of information.

This performance measure can be used to guide the implementation of a company’s damage prevention program and the communication plan for external party awareness.

The intent of this measure is for companies to report on unauthorized activity statistics by groups that are most likely to require permissions to conduct an activity in or near a pipeline right-of-way. These statistics should be used by a company to identify groups where Public Awareness Programs are particularly effective. They should also provide an indication of which groups require additional focus (for example, which groups may need awareness).

1. Public Awareness of Pipelines
2014 Company Performance
  1. The total number of unauthorized activities by contractors versus the total number of permissions granted to contractors.
  2. The total number of unauthorized activities by municipalities versus the total number of permissions granted to municipalities.
  3. The total number of unauthorized activities by landowners versus the total number of permissions granted to landowners.
  4. The total number of unauthorized activities by others versus the total number of permissions granted to others.
Pipeline Type Unauthorized Activities versus Permissions Ratio
Average Unauthorized Activities Average Permissions
A. Contractors
Gas > 50 km and < 5000 km 1.2 83 69
2013/2014 Average 1.4 94 67
Gas > 5000 km 12 190 16
2013/2014 Average 9 512 60
Liquid > 50 km 3 89 30
2013/2014 Average 2.7 87 33
B. Municipalities
Gas > 50 km and < 5000 km 0.1 3 30
2013/2014 Average 0.05 4 70
Gas > 5000 km 0.7 21 30
2013/2014 Average 0.9 20 24
Liquid > 50 km 0.3 28 93
2013/2014 Average 0.3 26 87
C. Landowners
Gas > 50 km and < 5000 km 0.4 1.7 4.3
2013/2014 Average 1.25 1.15 0.9
Gas > 5000 km 5 24 4.8
2013/2014 Average 27 14 0.5
Liquid > 50 km 1.3 17 13
2013/2014 Average 9.15 9.1 1
D. Others
Gas > 50 km and < 5000 km 0.2 15 75
2013/2014 Average 0.15 12 80
Gas > 5000 km 1.7 617 363
2013/2014 Average 2 390 195
Liquid > 50 km 0.2 51 255
2013/2014 Average 0.2 45 225
Pipeline Systems Total Unauthorized Activities Total Permissions Ratio
32 165 7,199 44
2013/2014 Average 378 7,043 19

What is an “unauthorized activity”?

An unauthorized activity that should be reported as part of this measure is:

  • Unauthorized construction or installation across, on, along, or under a right-of-way;
  • Excavation using power-operated equipment;
  • Explosives within the 30 metre (100 foot) safety zone; and
  • Any contravention of the Pipeline Crossing Regulations (PCR), Part I and PCR Part II, including any activity of the facility owner, as defined in section 2 of the PCR, Parts I and II, or an excavator that the pipeline company considers to be potentially hazardous to a pipe.

What is the definition of “permission”?

Permission means the consent given by a pipeline company to a facility owner (as defined in section 2 of the PCR, Parts I and II) or to an excavator to construct or install a facility or to excavate. For example, permission from the pipeline company is required for:

  • construction or installation of a facility across, on, along, or under an existing right-of-way;
  • excavation using explosives or power-operated equipment over the right-of-way;
  • in certain circumstances, operation of a vehicle or mobile equipment across a right-of-way, outside the travelled portion of a highway or public road; and
  • excavation using explosives or power-operated equipment within the 30 metre (100 foot) safety zone.

How is this Measure Reported?

This measure should be reported based on the person that conducts the physical activity on the right-of-way. In most cases, that person will be a contractor hired by the Project Owner (usually, the Project owner is one of the categories identified in this performance measure, for example, a municipality).

For example if the Project Owner is a municipality that receives permission for an activity on a right-of-way, but hires a contractor that performs an unauthorized activity, it is the contractor that is the subject of the measure.

What is a “contractor”?

For the purposes of this performance measure, a contractor is an excavator (i.e. a company or individual) hired to perform an activity which results in a ground disturbance. By extension the contractor is any agent, affiliate or subcontractor of the contractor that has direct control over the person performing the excavation.

What is the “other” category?

This includes but is not limited to any entity or person that may conduct activities in a pipeline right-of-way that does not fit into the Municipal, Contractor or Landowner categories. Typically this would be a provincial, federal, railway or utility entity.

 

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