Industry Performance

Updated June 2025

Metrics

The most common metric for reporting pipeline performance is the number of incidents per 1000 kilometres of pipeline per year. This metric is useful when comparing companies but does not tell the whole story. A lot goes into determining how a pipeline company performs, and the results might differ depending on the metric used.

For a meaningful comparison of pipeline performance between companies, we must compare companies with similar operations, including the number, size, and type (pipeline materials and substances transported) of pipelines they operate.

We use the following performance metrics:

• the number of incidents per 1000 kilometres per year of pipeline
• the total number of incidents
• the number of incidents by consequence rating (low, medium, high)
• the volume and type of product released

Some companies are examined more closely than others because of their compliance history or the location of their pipelines and the products those pipelines carry. For example, a pipeline near a water body that transports a hazardous substance (e.g., sour gas, produced water, or oil well effluent) may pose a greater risk to the public, the environment, wildlife, and livestock.

The following table summarizes the high consequence incidents for 2024.

* Incident numbers can be used to look up additional information on the Compliance Dashboard.

Figure 5 shows data by company for each performance metric.

Products Released

In 2024, the total volume of hydrocarbon liquid and produced water released from pipelines was 43% lower than in 2023. 

The following table lists the top five incidents with the largest release volumes. The top five incidents account for 41% of the total volume of hydrocarbon liquid and produced water released.

* Incident numbers can be used to look up additional information on the Compliance Dashboard.

As a result of any given incident, the AER requires the licensee to identify the causes and gaps in their integrity management programs and to implement improvements to the program.

Pipeline Failure

Leaks and ruptures are categorized as pipeline failures. Of the 307 pipeline incidents in 2024, 237 were pipeline failures.

If a failure occurs, companies must investigate the cause, implement a plan to prevent it from happening again, and provide us with the details of the investigation and remedial actions.

Leading Causes of Failure

Incidents are categorized by their leading cause of failure. However, it is sometimes difficult to identify the root cause as it could include poor design or poor operations and maintenance. For companies to select a suitable pipeline material, an assessment is required on a project-by-project basis that is based on a thorough understanding of the intended service conditions, potential upset conditions, future development or changes in services, temperature and pressure variations, production rates, and other factors. In addition, companies must continually monitor and assess their pipelines for these conditions throughout the life of the pipeline.

In 2024, the following were the most common types of pipeline failure:

• internal corrosion (43%)
• external corrosion (13%)
• valve fitting failure (12%)
• pipe body failure (9%)
• operator error (8%)

85% of the pipelines we license are steel pipelines and highly susceptible to corrosion. Effective programs must be in place to monitor and prevent these pipelines from corroding to an unacceptable level – and confirming that companies have such programs is the focus of our pipeline inspections and assessments.

Figure 7 shows the percentage of failure types and a ranking of causes.

Internal Corrosion

In 2024, internal corrosion remained the leading type of pipeline failure, representing 43% of all pipeline leaks and ruptures. This is up 1% from 2023. Seventy-one per cent of internal corrosion failures were on uncoated steel pipelines, with the remainder occurring on the metallic risers and piping of otherwise nonmetallic pipelines.

In 2024, 32% of pipeline failures from internal corrosion were caused by multiple corrosion mechanisms (called multimechanism corrosion). Other causes of internal corrosion include the following:

• microbiologically influenced corrosion (14%)
• corrosion under internal coating (13%)
• under-deposit corrosion (12%)
• corrosion on steel components of nonmetallic mainline (8%)

Forty per cent of internal corrosion failures were on pipelines transporting oil-well effluent, which is attributable to the corrosive nature of these fluids and operating conditions.

For pipelines transporting corrosive fluids, companies must develop programs to monitor for corrosion and, where corrosion occurs, minimize its progression, or replace the pipe if needed.

Typically, internal corrosion can be mitigated by the following:

• doing effective cleaning (called "pigging") of pipeline segments to remove solids, water, bacteria, and debris
• using biocide chemical treatments to kill microbial organisms in the pipeline
• periodically applying or batching large quantities of a corrosion inhibitor as a protective barrier on the inside of the pipe
• continuously injecting an inhibitor chemical to reduce the corrosiveness of the transported fluid or to function as a protective barrier on the inside of the pipe
• removing water from the pipeline or preventing it from entering
• installing pipe with a permanent protective inner coating or a corrosion-resistant liner inside an uncoated steel pipe
• installing polymeric, fibreglass, or spoolable composite pipe

The risk of internal corrosion increases the longer a pipeline is inactive and not purged. Water and solids left inside a pipeline accelerate the rate of corrosion. Companies must properly clean inactive pipelines and apply corrosion inhibitors to prevent corrosion from happening whenever a pipeline is inactive for extended periods to preserve it for future use. When companies bring an inactive pipeline back into operation, an appropriate engineering assessment and any necessary inspections, testing, and requalification must be done before resumption to ensure that the pipeline still has suitable integrity.

External Corrosion

The exterior surface of a steel pipe is susceptible to corrosion if the pipeline does not have an effective protective coating. In 2024, external corrosion accounted for 13% of pipeline failure types.

Buried pipelines must have an external coating that must be inspected before the pipeline is buried. Cathodic protection is required for all underground steel pipelines to counteract corrosion in areas where the external coating may be compromised. Cathodic protection must be periodically measured and maintained to ensure an appropriate current along the entire pipeline.

In 2024, 37% of the external corrosion pipeline failures were caused by missing or damaged coating, and 30% was caused by the field-applied coating disbonding from the pipe surface. Coatings can disbond due to improper installation, aging, or excessive operating temperature. Field applied coatings at welds and repairs and on risers and bends are frequent failure locations for coatings. Disbonded coatings prevent effective cathodic protection at the area where the disbonding occurs, although overall cathodic protection levels on the pipeline may be acceptable.

Older pipelines were often constructed with tape-wrapped coatings, which have a tendency to degrade and disbond over time, as compared to the factory-applied extruded or fusion-bonded coatings that are typically used now.

Valve or fitting failure

In 2024, the third leading type of pipeline failure was valve or fitting related (12%). The leading cause of these incidents were related to pigging facility components (24%) and gasket, seal, or packing issues (24 per cent). Releases from pigging facility components often signal wear and tear, as well as insufficient maintenance and operational procedures. Regular inspection, proper upkeep, and timely replacement of damaged components are essential to ensuring reliability and preventing operational disruptions and releases. Gasket, seal, or packing failures are indicative of poor maintenance of pipeline components. Although these failures typically involve small release volumes and are rated as low-consequence incidents, improper maintenance can lead to higher-consequence incidents if not addressed. Routine inspection and maintenance of valves and fittings at scheduled intervals are essential for ensuring optimal functionality. Proper upkeep enhances the valves' ability to effectively isolate pipelines during emergencies, minimizing risks and ensuring operational reliability.

Pipe Body Failure

In 2024, pipe body failure (see the glossary) accounted for 9% of pipeline failure types.

In steel pipe, body failure can occur by cracking of the pipe due to its operating environment. For nonmetallic pipelines, body failure can result from a gradual degradation of the pipe material or an overpressure condition.

As composite pipelines age, service conditions can cause or propagate degradation within the pipe material. Newer composite technologies and installation techniques have greatly reduced the risk for many of these degradation mechanisms, but older composite inventory can still be susceptible to failure. Operators should be aware of this and manage it as part of their safety and loss management system and integrity management programs.

The statistics show a sizable increase in pipe body failure. This is likely because of two factors: more accurate reporting of failure type in composite pipe and a significant number of stress corrosion cracking (SCC) failures in aboveground high-temperature thermal recovery project pipelines. The AER issued Bulletin 2021-36 in 2021 identifying this issue to industry.

Operator error

In 2024, the fifth leading type of pipeline failure was operator error, making up 8% of the failures. The leading cause of these incidents were relating to valves being left open (9%) and improper operation (9%). Improper operation of pipelines often stems from insufficient training, inadequate procedures, or complacency. Many licensees lack comprehensive training programs and clearly defined operational procedures, increasing the risk of human error.

Additionally, incidents resulting from operator error are frequently not investigated by the licensee in sufficient depth. As a result, essential improvements—such as updates to operations and maintenance procedures, contractor selection criteria, and operational expectations—are overlooked, leaving licensees vulnerable to repeated failures.

To prevent operator-related incidents, licensees must prioritize rigorous training, enforce well-documented procedures, and foster a proactive safety culture. Licensees should conduct thorough investigations whenever errors occur, ensuring that lessons learned lead to meaningful improvements in operations, risk management, and overall pipeline integrity.

Additional Information

Additional data about pipeline performance in Alberta is available in the full workbook.

The following resources provide information on pipeline safety practices:

• “Safe Excavation Near Pipelines” brochure
• Working Around Oil and Gas Pipelines
• Improving Pipeline Safety