Pipeline Performance Measures 2013 Data Report

Pipeline Performance Measures 2013 Data Report [PDF 610 KB]

October 2014

Amended July 2015

Copyright/Permission to Reproduce

ISSN 2368-5530

Table of Contents

Message from the Chair

The National Energy Board takes its mandate to protect the public and the environment seriously. I, along with our Board Members and the over 400 employees of the NEB, come to work every day to help ensure that pipelines we regulate are safe and can be made even safer. As a result we are working diligently to strengthen all aspects of our pipeline oversight.

The development of leading pipeline performance measures is unprecedented. It raises the bar on the Board’s expectations for the oil and gas industry and also lays the groundwork for companies the NEB regulates to produce measures of their own. These measures challenge companies to take a hard look at how they manage the risks associated with their operations. The measures also promote continual improvement, and set the stage for further initiatives to assess safety culture in pipeline companies.

This leading edge initiative is in addition to the NEB’s already comprehensive compliance programs. In the past year alone, the NEB conducted almost 300 activities designed to hold companies accountable for their commitments to Canadians. These activities included inspections, emergency response exercises, comprehensive audits and technical meetings. On top of this, the NEB assessed and followed up on all incidents relating to pipeline and worker safety, security, emergency management and environmental protection.

The expertise required to deliver this complex mandate is impressive. The National Energy Board is made up of highly skilled specialists - all fiercely proud of the work they do protecting the interests of Canadians. The new measures of pipeline company performance provide our specialists with even more data to assess the risk a company poses and track industry trends in order to assist both ourselves and industry to be even more proactive going forward.

Companies are expected to use this data to improve performance collectively and on a company basis. The 45 measures required by the NEB focus on key aspects of compliance programs, increasing the amount of information that companies are required to report on by over 700 per cent. The data collected from the first year of reporting shows 12,795 construction personnel were trained on environmental protection; almost 6,000 kilometres of agricultural land was reclaimed since 2009; 70,822 kilometres of multiple in-line inspections were conducted allowing companies to address defects; and 313 emergency exercises conducted.

I am confident that the efforts of the proud men and women of the National Energy Board are making a difference in keeping energy infrastructure safe and reliable for Canadians. I am pleased to provide the public and the pipeline industry with this new information on Canadian pipeline performance.

C. Peter Watson, P. Eng., FCAE
Chair and CEO

Pipeline Performance Measures - Executive Summary

The National Energy Board (NEB or the Board) is taking a regulatory leadership role in requiring companies to report on leading pipeline performance measures. 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).

This report summarizes the first year of annual pipeline company reporting on performance measures required by the Board.

The data generated from these measures will be used by the Board to better regulate pipeline operations. The NEB expects that it will take at least three annual reporting cycles to identify meaningful trend information. However, the Board will immediately begin using the performance measures data to inform its compliance verification planning. Data from these leading indicators will be incorporated into the NEB’s risk-informed modelling and analysis. This additional information will provide the Board with a more complete picture of pipeline operations for its regulated companies.

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

The performance measures were developed through a public consultation to cover key activities in the programs required by the NEB as part of an effective safety management system:

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

The submission of this performance data was mandatory for 25 companies having pipelines greater than 50 kilometres in length. These 25 companies represent 96% of the length of pipelines regulated by the NEB.

Performance measures, and the information gathered from them, are a key component in enabling pipeline companies to achieve the Board’s stated goal of zero incidents on its regulated pipelines. Companies will use the resulting data to trend and compare performance, as well as to facilitate continual improvement and management of risks associated with pipelines. The integration of these measures in a company’s safety management system will shift pipeline operation from reactive to proactive management.

I - Introduction

General

The National Energy Board (Board) requires the pipeline industry to use safety management systems for anticipating, preventing, managing and mitigating issues that can affect safety, security and environmental protection. A necessary component of a safety management system is the use of performance measures to gather consistent and comparable information for continual improvement. Following public consultation on appropriate performance measures in 2011 and 2012, the Board required companies with pipelines greater than 50 kilometres in length to annually file performance measures data. This report contains the 2013 data that was submitted to the Board in 2014.

Report Purpose

The performance measures contained in this document are predictive and forward looking leading measures. In addition to these measures, the Board also currently requires all companies to report on incidents, such as releases of substances and serious injuries. These lagging measures provide a historic view of company performance. A mix of leading, lagging and qualitative measures can provide an overview of the effectiveness of a company in meeting safety management system program objectives.

The primary purpose of reporting on the performance measure data is to provide a summary of the data collected for each measure. Results for each individual measure are provided along with that measure and the measure’s guidance, so that each company can better assess their performance. Over time, companies will be able to assess their progress against any trends they identify in future reports.

Data Management

Data was received from 25 companies owning a total of 58 pipelines with a total length of 67,000 kilometres. The raw data for each pipeline that makes up each measure 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). The data was then averaged for the appropriate category. This report is located on the Board’s website (www.neb-one.gc.ca) in the Safety and Environment section.

Data Interpretation

To facilitate the tracking, reporting and subsequent sharing of data, each performance measure is quantitative in terms of numbers, percentages and ratios. In some instances the achievement percentage exceeds 100. This can be a result of a greater number of activities conducted than planned, which is encouraged.

Compliance Verification

The Board will be evaluating the data submitted to determine if companies are providing information that is consistent with the Board’s knowledge of the pipeline, and are establishing appropriate numbers of activities to be measured.

The Board will also be adding the performance measures data to other data it uses in assessing risk for compliance verification planning. Compliance verification planning is used to determine the location and frequency of audits, meetings and inspections each year.

II - Safety Management Performance Measures

1. Facility Safety Inspections

1. Facility Safety Inspections
The total number of facility inspections conducted versus the total number of planned facility inspections.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Average Number of Facilities Facility Inspections Percentage
Average Planned Average Inspections
Gas > 50 km and < 5000 km 53 109 109 100
Gas > 5000 km 1,810 1,551 1,522 98
Liquid > 50 km 47 180 180 100
Pipeline Systems Total Facilities Total Planned Total Conducted Percentage
31 6,742 9,056 8,967 99

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.

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.[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

2. Corrective and Preventative Actions

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

  • operations and maintenance; and
  • construction.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Safety Actions Percentage
Average Identified Average Completed
a. Operations and Maintenance Corrective and Preventative Actions
Gas > 50 km and < 5000 km 51 48 94
Gas > 5000 km 1,333 1,110 83
Liquid > 50 km 152 138 92
b. Construction Corrective and Preventative Actions
Gas > 50 km and < 5000 km 7 7 100
Gas > 5000 km 128 104 81
Liquid > 50 km 116 115 99
Pipeline Systems Total Identified Total Completed Percentage
31 9,946 8,897 89

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.

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.

Operations and Maintenance

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.

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

3. Near Misses

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

  • the pipeline company; and
  • contractors.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Near Misses Percentage
Average Reported Average Addressed
a. Pipeline Company Near Misses
Gas > 50 km and < 5000 km 4 4 100
Gas > 5000 km 637 637 100
Liquid > 50 km 22 21 95
b. Contractor Near Misses
Gas > 50 km and < 5000 km 2 2 100
Gas > 5000 km 69 69 100
Liquid > 50 km 77 77 100
Pipeline Systems Total Reported Total Addressed Percentage
31 4,416 4,157 99

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.

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:

  • the near miss resulted from an action taken by the contractor; and
  • 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:

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

III – Security Performance Measures

1. Training and Competency

1. Training and Competency
The total number of company employees who have current security training versus the total number of company employees.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Employees with Security Training Percentage
Average Employees Average Trained
Gas > 50 km and < 5000 km 93 89 96
Gas > 5000 km 783 783 93
Liquid > 50 km 521 394 76
Pipeline Systems Total Employees Total Trained Percentage
31 9,869 8,007 81

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.

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.

IV - Emergency Management Performance Measures

1. Emergency Response Exercises

1. Emergency Response Exercises

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

  • drills;
  • tabletop (i.e. mock) exercises;
  • functional (i.e. simulation) exercises; and
  • full scale (i.e. major) exercises.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Emergency Response Exercises Percentage
Average Planned Average Conducted
a. Drills
Gas > 50 km and < 5000 km 0.9 0.6 67
Gas > 5000 km 0 0 NA
Liquid > 50 km 6 5 83
b. Tabletop (i.e. Mock) Exercises
Gas > 50 km and < 5000 km 2.5 2.1 84
Gas > 5000 km 19 19 100
Liquid > 50 km 5 5 100
c. Functional (i.e. Simulation) Exercises
Gas > 50 km and < 5000 km 1.9 1.8 95
Gas > 5000 km 1 1 100
Liquid > 50 km 0.3 0.3 100
d. Full Scale (i.e. Major) Exercises
Gas > 50 km and < 5000 km 0.1 0.3 300
Gas > 5000 km 2 3 150
Liquid > 50 km 0.3 0.3 100
Pipeline Systems Total Planned Total Conducted Percentage
31 317 313 99

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.

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

2. Communication
The number of liaison activities conducted versus the number of liaison activities planned.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Emergency Management Liaison Activities Percentage
Average Planned Average Conducted
Gas > 50 km and < 5000 km 18 19 106
Gas > 5000 km 227 217 96
Liquid > 50 km 64 65 102
Pipeline Systems Total Planned Total Conducted Percentage
31 2,049 2,026 99

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.

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

3. Training and Competency
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.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Persons With an Emergency Management Role Percentage
Average Persons Average Persons Trained
Gas > 50 km and < 5000 km 52 50 96
Gas > 5000 km 266 241 91
Liquid > 50 km 88 80 91
Pipeline Systems Total Persons Total Persons Trained Percentage
31 2,484 2,264 91

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.

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
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.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Participation in Exercises and Drills Percentage
Average Persons Average Participation
Gas > 50 km and < 5000 km 52 37 71
Gas > 5000 km 266 232 87
Liquid > 50 km 88 62 70
Pipeline Systems Total Persons Total Participation Percentage
31 2,484 2,126 86

What is an “emergency response exercise”?

This is 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.

V - Integrity Management Performance Measures

1. Pipeline Condition

1. Pipeline Condition

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.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
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 1.6 0.1 6
Gas > 5000 km 27 7 26
Liquid > 50 km 9 5.6 62
b. Dents
Gas > 50 km and < 5000 km 0 0 NA
Gas > 5000 km 3 2 50
Liquid > 50 km 5 3 60
c. Cracks With a Depth Greater than 40% of the Nominal Pipeline Wall Thickness
Gas > 50 km and < 5000 km 0 0 NA
Gas > 5000 km 2 2 100
Liquid > 50 km 6 3 50
Pipeline Systems Total Features Total Defects Percentage
58 991 482 49

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.

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

2. Equipment Inspection
  • The total number of tank inspections versus:
    • the total number of tanks; and
    • the total number of scheduled tank inspections by:
      • routine staff inspection; and
      • certified maintenance inspection.
  • The total number of mainline valve inspections versus:
    • the total number of mainline valves; and
    • the total number of scheduled mainline valve inspections by:
      • routine staff inspection; and
      • certified maintenance inspection.
2013 Company Performance
A.a. Tank Inspections versus Number of Tanks
Pipeline Type Average Tanks Average Conducted Percentage
Gas > 50 km and < 5000 km 3 7 233
Gas > 5000 km 0 0 NA
Liquid > 50 km 28 259 925
Pipeline Systems Total Tanks Total Inspections Percentage
31 548 9,935 181
B.a. Mainline Valve Inspections versus Number of Mainline Valves
Pipeline Type Average Mainline Valves Average Conducted Percentage
Gas > 50 km and < 5000 km 73 97 133
Gas > 5000 km 2,730 2,652 97
Liquid > 50 km 60 438 781
Pipeline Systems Total Mainline Valves Total Inspections Percentage
31 9,982 27,004 270
A.b.i. Routine Staff Tank Inspections versus Scheduled Routine Staff Inspections
Pipeline Type Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 11 15 136
Gas > 5000 km 0 0 NA
Liquid > 50 km 477 514 108
A.b.ii. Certified Maintenance Tank Inspections versus Scheduled Certified Maintenance Inspections
Pipeline Type Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 0 0 NA
Gas > 5000 km 0 0 NA
Liquid > 50 km 3.3 3.3 100
B.b.i. Routine Staff Mainline Valve Inspections versus Scheduled Routine Staff Inspections
Pipeline Type Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 130 130 100
Gas > 5000 km 0 0 NA
Liquid > 50 km 782 782 100
B.b.ii. Certified Maintenance Mainline Valve Inspections versus Scheduled Certified Maintenance Inspections
Pipeline Type Average Scheduled Average Conducted Percentage
Gas > 50 km and < 5000 km 64 64 100
Gas > 5000 km 2,666 2,652 99
Liquid > 50 km 96 93 97
Pipeline Systems Total Inspections Scheduled Total Inspections Conducted Percentage
31 36,316 36,939 102

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.

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.

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

3. Facility Piping Inspection

A. Liquid Pump Stations

Facility Piping Inspection

  • routine staff inspection; and
  • 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:

  • routine staff inspection; and
  • certified maintenance inspection

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

2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Facility Piping Inspections Percentage
Average Scheduled Average Conducted
A.i. Liquid Pump Station Piping Routine Inspections
Liquid > 50 km 8 8 100
ii. Liquid Pump Station Piping Certified Maintenance Inspections
Liquid > 50 km 4.6 4.6 100
B.i. Gas Compressor Station Piping Routine Inspections
Gas > 50 km and < 5000 km 2 2 100
Gas > 5000 km 38 38 100
ii. Gas Compressor Station Piping Certified Maintenance Inspections
Gas > 50 km and < 5000 km 1.4 1.4 100
Gas > 5000 km 15 14 93
Pipeline Systems Total Scheduled Total Inspected Percentage
31 438 437 100

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.

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

4. Facility Inspection Effectiveness

A. Liquid Facilities

The total number of reportable incidents at liquid facilities versus the total number of liquid facilities.

B. Gas Facilities

The total number of reportable incidents at gas facilities versus the total number of gas facilities.

2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Reportable Incidents at Facilities Percentage
Average Facilities Average Incidents
A. Reportable Incidents at Liquid Facilities
Liquid > 50 km 47 1.4 3
B. Reportable Incidents at Gas Facilities
Gas > 50 km and < 5000 km 53 3 1600
Gas > 5000 km 1,810 9 0.5
Pipeline Systems Total Scheduled Total Incidents Percentage
31 6,742 77 1

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.

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

5. Assessment of Pipeline Hazards

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:

  • metal loss;
  • cracking;
  • external interference;
  • material, manufacturing or construction; and
  • geotechnical and weather-related.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Pipeline Kilometres Assessed for Susceptible Hazards Percentage
Average Susceptible Average Assessed
a. Metal Loss Hazard Assessment
Gas > 50 km and < 5000 km 156 121 78
Gas > 5000 km 1177 1162 99
Liquid > 50 km 283 223 79
b. Cracking Hazard Assessment
Gas > 50 km and < 5000 km 103 98 95
Gas > 5000 km 434 321 74
Liquid > 50 km 162 380 235
c. External Interference Hazard Assessment
Gas > 50 km and < 5000 km 131 113 86
Gas > 5000 km 651 783 120
Liquid > 50 km 323 198 61
d. Material, Manufacturing or Construction Hazard Assessment
Gas > 50 km and < 5000 km 130 113 87
Gas > 5000 km 124 90 73
Liquid > 50 km 137 221 161
e. Geotechnical or Weather Related Hazard Assessment
Gas > 50 km and < 5000 km 113 113 100
Gas > 5000 km 652 652 100
Liquid > 50 km 86 109 127
Number of Pipelines Total Susceptible Total Assessed Percentage
58 69,005 70,822 103

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.

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

6. Shutdowns for Hazard Control

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.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length)
Shutdowns for Hazard Control
a. Emergency b. Precaution c. Unplanned Repair d. Planned Repair Total
Gas > 50 km and < 5000 km 0,5 0 0,1 0,1 12
Gas > 5000 km 1,4 0,3 2,5 6,4 84
Liquid > 50 km 1.4 12.5 0,4 3.8 613
Total 65 426 36 182 709

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.

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.

VI - Environmental Protection Performance Measures

1. Program Training

1. Program Training

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.

2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Employees Receiving Training on the Environmental Protection Program Percentage
Average Employees Requiring Training Average Trained
Gas > 50 km and < 5000 km 56 48 86
Gas > 5000 km 45 780 93
Liquid > 50 km 549 465 85
Pipeline Systems Total Employees Requiring Training Total Trained Percentage
31 10,104 8,768 87

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.

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

2. Site Specific Training

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.

2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Construction Staff with Training on the Site-Specific Environmental Protection Plan Percentage
Average Construction Staff Average Trained
Gas > 50 km and < 5000 km 28 27 96
Gas > 5000 km 1,515 1,470 97
Liquid > 50 km 436 430 99
Pipeline Systems Total Construction Staff Total Trained Percentage
31 13,045 12,795 98

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.

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

3. Restoration of Agricultural Land
  • 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
  • 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
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
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 0 0 0 NA
Gas > 5000 km 3 74 68 92
Liquid > 50 km 9 117 95 81
Pipeline Systems Total Total Disturbed Total Restored Percentage
31 12 2,555 2,111 83
B. Operational Excavations on Agricultural Lands that are Restored
Gas > 50 km and < 5000 km 3 3.5 2.3 66
Gas > 5000 km 3 553 266 50
Liquid > 50 km 12 164 151 92
Pipeline Systems Total Total Excavated Total Restored Percentage
31 18 4,967 3,830 77

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.

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

4. Resolution of Environmental Issues

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.

2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Operational Environmental Issues  
Average Identified Average Addressed Percentage
Gas > 50 km and < 5000 km 36 28 78
Gas > 5000 km 71 51 72
Liquid > 50 km 82 78 95
Pipeline Systems Total Identified Total Addressed Percentage
31 2,163 1,949 90

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.

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 Remediation[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

5. Environmental Inspections

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.

2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Pipelines With Construction Environmental Inspections Percentage
Average Construction Days Average Inspection Days
Gas > 50 km and < 5000 km 0 0 0 NA
Gas > 5000 km 2 389 559 144
Liquid > 50 km 3 16 38 238
Pipeline Systems Total Total Total Percentage
31 5 1,083 1,849 171

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

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.

VII - Damage Prevention Performance Measures

1. Public Awareness of Pipelines

1. Public Awareness of Pipelines
  • The total number of unauthorized activities by contractors versus the total number of permissions granted to contractors.
  • The total number of unauthorized activities by municipalities versus the total number of permissions granted to municipalities.
  • The total number of unauthorized activities by landowners versus the total number of permissions granted to landowners.
  • The total number of unauthorized activities by others versus the total number of permissions granted to others.
2013 Company Performance
Pipeline Type
(Based on Pipeline Length in Kilometres)
Unauthorized Activities versus Permissions Ratio
Average Unauthorized Activities Average Permissions
A. Contractors
Gas > 50 km and < 5000 km 1.6 104 65
Gas > 5000 km 5 834 167
Liquid > 50 km 2.3 84 37
B. Municipalities
Gas > 50 km and < 5000 km 0 4 NA
Gas > 5000 km 1 19 19
Liquid > 50 km 0.3 25 83
C. Landowners
Gas > 50 km and < 5000 km 2.1 0.6 0.3
Gas > 5000 km 48 4 0.1
Liquid > 50 km 17 1.2 0.1
D. Others
Gas > 50 km and < 5000 km 0.1 9 90
Gas > 5000 km 2.3 163 71
Liquid > 50 km 0.2 39 195
Pipeline Systems Total Unauthorized Activities Total Permissions Ratio
31 591 6,886 11.7

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).

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.

Endnotes

[1] The OPR defines CSA Z662 as the CSA standard entitled Oil and Gas Pipeline Systems, as amended from time to time. Accordingly, companies should use the most up to date version of CSA Z662 when reporting data for all measures.

[2] Federal Emergency Management Agency (FEMA) naming conventions and definitions are used for exercises.

[3] For further information, see the NEB Remediation Process Guide.

 

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