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The Canada Energy Regulator (CER) regulates various economic aspects of pipelines under its jurisdiction, including tolls and tariffs; requirements for companies to have access to financial resources to cover costs of potential unintended or uncontrolled releases; and setting aside funds for future abandonment costs. Effective economic regulation helps the CER to fulfil its mission to regulate energy infrastructure in a way that prevents harm and ensures the safe, reliable, competitive and environmentally sustainable delivery of energy to Canada and the world. The “About the CER” section in the introduction of this report provides a more detailed overview of the CER’s mandate.Footnote 1
Since it can be more cost-effective to build one larger pipeline rather than multiple smaller competing pipelines, facilities under CER jurisdiction often operate as a monopoly in the markets they serve and therefore have market power. Through effective economic regulation, the CER ensures that where market power exists, it is not abused and that tolls for pipeline services are just and reasonable, and not unjustly discriminatory.
The CER regulates the tolls and tariffs of pipeline companies under its jurisdiction. Tolls are the rates that shippers pay to move their product on a pipeline. Tariffs are the terms and conditions of service and access on the pipeline and include tolls and the pipeline’s rules and regulations. The CER regulates tolls and tariffs to ensure that tolls are just and reasonable, and that there is no unjust discrimination in tolls or services on the pipeline.
A pipeline company cannot charge a toll unless it is included in a tariff filed with the CER or approved by an order of the Commission. Pipeline companies must also file their tariffs with the CER. Tariffs can include, but are not limited to:
The CER actively monitors compliance with toll and tariff regulatory requirements. Some of the activities undertaken by the CER include requiring regular compliance filings by companies, conducting financial regulatory audits,Footnote 2 and soliciting shipper feedback via an annual survey.Footnote 3
Parties may also file formal complaints with the CER if they are unable to resolve concerns on specific toll and tariff matters. If a complaint is filed, the Commission may establish a process to examine the matters related to the complaint.
Pipeline companies regulated by the CER are divided into two groups for the regulation of tolls and tariffs:
As of September 2026, the CER currently regulates 13 Group 1 companies and 90 Group 2 companies.
When setting tolls for the Group 1 companies, the CER typically follows one of two processes. The first is to assess a detailed tolls application filed by the company. The second is much more common, which is to consider a negotiated toll settlement reached between a pipeline company and its shippers, with input from other parties with a commercial interest in the tolls, under the Revised Guidelines for Negotiated Settlements of Traffic, Tolls, and Tariffs (Settlement Guidelines). These processes are discussed in more detail below.
For Group 2 companies, the CER uses a complaint-based approach to regulate the tolls and tariffs. As noted above, shippers or other parties who cannot resolve a concern with any pipeline company may file a complaint with the CER. In the case of Group 2 companies, the complaint-based approach means that if no complaint is filed, the Commission will operate under the presumption that the tolls are just and reasonable and will generally not undertake a detailed examination of the Group 2 company’s tolls. Under the complaint-based approach, the Group 2 pipeline company is responsible for providing shippers and other interested persons with enough information regarding tolls and tariffs to enable them to determine whether a complaint is warranted.
Historically, Group 1 pipeline companies would submit regular (e.g. annual) detailed toll applications, which defended each element of their applications. This process would often result in lengthy hearings for many applications.
Since the mid-1980s, the CER and its predecessor the NEB, have supported the use of negotiated settlements to improve the effectiveness and efficiency of the regulatory process, as an alternative to the detailed toll applications and the resulting hearings. Negotiated settlements, which are discussed below, have become the norm for CER-regulated pipelines.
A negotiated settlement is an agreement between a pipeline company and its shippers, with input from other parties with a commercial interest in the tolls, as applicable, regarding issues related to the company’s tolls and tariffs. They can cover all or certain elements of a pipeline’s tolls or tariffs. Often, negotiated settlements address a pipeline’s toll design, toll levels, and services. They can take many forms, and the Commission and NEB have approved tolls based on different approaches, providing flexibility for parties to arrive at market-driven solutions. For example, some negotiated settlements include tolls that vary annually and are explicitly derived from a negotiated revenue requirement where each major cost element is itemized,Footnote 4 and other negotiated settlements feature negotiated tolls that are fixed for multiple years without any direct association with a revenue requirement.
The Settlement Guidelines establish acceptable criteria for a settlement process. Generally, the Commission wants to ensure all interested parties have a fair opportunity to participate in the settlement process and that there is a general acceptance of the outcome. If no party opposes a negotiated settlement that is submitted to the CER, the Commission may conclude that the resulting tolls are just and reasonable, with minimal process – effectively deferring to the judgement and ability of the sophisticated negotiating parties to adequately represent their own interests. However, per the Settlement Guidelines, the Commission may examine broader public interest considerations beyond the interests of the negotiating parties and consider the need for further process. Historically, the Commission has recognized that negotiated settlements involve give-and-take, and has accordingly accepted or rejected a negotiated settlement package in its entirety, rather than modifying any part of the settlement.
A pipeline company may also file an application for approval when it has not obtained support from all of its shippers and other parties with a commercial interest in the tolls but, in its judgement, believes it has an agreement that justifies seeking the Commission’s approval. This is called a contested settlement. Regarding a contested settlement, the Commission may decide whether to:
The Group 1 negotiated settlements below illustrate both negotiated settlements approved pursuant to the Settlement Guidelines, as well as applications with substantial negotiated components approved under the detailed tolls application assessment process.
To clarify, while detailed tolls applications can often involve substantial negotiated components, if an application does not meet the criteria for an acceptable settlement process in the Settlement Guidelines or the applicant does not apply under the Settlement Guidelines, the application is considered a detailed tolls application.
Oil and liquids pipeline negotiated settlements
Oil and liquids pipeline companies have implemented several new settlements in recent years. Figure 1 shows current and historic settlements on oil and liquids pipelines, approved by the CER or NEB.
The Enbridge Canadian Mainline Competitive Toll Settlement expired on 1 July 2021 and was replaced by the Mainline Tolling Settlement,Footnote 5 which will be in effect until 31 December 2028.
The tolling methodology for the Trans Mountain ULC (Trans Mountain) Expanded System was originally approved in Reasons for Decision RH-001-2012Footnote 6 and came into effect on 1 May 2024, which was the in-service date of the Trans Mountain Expansion Project. The tolling methodology calculated tolls primarily based on the capital costs required to build the Trans Mountain Expansion Project, while also including certain variable costs that can be recovered from shippers.Footnote 7 In July 2026, Trans Mountain filed an application for approval of a new negotiated settlement for tolls, tariffs and other matters related to transportation service on the Trans Mountain System. Among other things, that settlement would establish the tolling framework applicable on the Trans Mountain System on 1 January 2027. The application was approved on 28 September 2026 by the Commission.
On the Trans-Northern Pipelines Inc. (TNPI) system, tolls had been calculated for many years in accordance with TNPI’s Incentive Toll Principles of Settlement, which had been in place since 1996. To address falling utilization on the system and changing market conditions, TNPI more recently reached a series of new settlements with its shippers. A new Incentive Toll Settlement Agreement was approved by the Commission and took effect on 1 January 2023, with an expiry date of 31 December 2027. It was modified by the Backstop Toll Settlement Agreement, which took effect 1 January 2025. In December 2025, TNPI filed an application for approval of the Revised Incentive Toll Settlement and Ottawa Firm Toll Settlement Agreements. TNPI’s application was approved by the Commission on 30 June 2026. Of note, the Revised Incentive Toll Settlement and Ottawa Firm Toll Settlement Agreements replaced the Incentive Toll Settlement and Backstop Toll Settlement agreement.
Figure 1: Toll settlement timelines for Group 1 oil and liquids pipelines
Source: CER – REGDOCS
Text Alternative: The figure represents the historical settlement timelines for several CER-regulated Group 1 oil and liquids companies.
Gas pipeline negotiated settlements
Some gas pipelines operate according to multiple concurrent settlements, which address different aspects of the pipeline’s tolls or tariffs. Settlements have continued to play a large role in resolving toll and tariff issues on gas pipelines in recent years. Figure 2 shows current and historic settlements on gas pipelines, approved by the CER or NEB.
Certain notable gas settlements were reached since 2020, including NGTL GP Ltd.’s, (NGTL’s) 2020-2024 Revenue Requirement Settlement and subsequently the 2025-2029 Revenue Requirement Settlement, both concerning NGTL’s revenue requirement. The NGTL Rates and Services Settlement, which addresses rate design methodology and was approved in 2020, remains in effect and continues to govern rates and services on the NGTL System.
TransCanada PipeLines Limited (TCPL)’s Mainline 2021-2026 Settlement for the TC Canadian Mainline, addressing tolls and services, was approved in April 2020. TCPL applied for the Mainline 2027-2030 Settlement in March 2026, and the Commission approved the settlement in July 2026.
Westcoast Energy Inc.’s (Westcoast’s) 2022 to 2026 Transmission Toll Settlement has been in place since January 2022 and is effective until the end of 2026.
Alliance Pipeline Ltd. (Alliance) reached an agreement with its shippers and stakeholders on the 2025-2035 Toll Settlement Agreement, which was approved in September 2025 and establishes how tolls will be determined to October 2035. That settlement was reached after the Commission initiated a proceeding in May 2024 to review whether Alliance’s tolls (established pursuant to the methodology approved in RH-002-2014) remained just and reasonable, including in light of Alliance’s high historical rates of return on equity and some comments from shippers on the Pipeline Services Survey regarding Alliance’s return on equity.
Figure 2: Toll settlement timelines for Group 1 gas pipelines
Source: CER – REGDOCS
Text Alternative: The figure represents the historical settlement timelines for several CER-regulated Group 1 gas companies.
A toll is the price charged by a pipeline company for transportation and other services. Tolls provide funds for companies to recover capital (the money used to build the pipeline); pay debts and expenses; and provide a return to investors. Stable and reasonable tolls are a key concern for shippers and are, therefore, one of the indicators of the efficiency of a transportation system.
Pipeline tolls vary for several reasons, such as changes in throughput, operating costs, and capital costs. Often, lower throughput leads to higher tolls because a pipeline’s costs may be shared across all volumes moving on the system. Large expenditures, such as expansions, can change tolls depending on the impacts on costs, throughput, and revenue.
Oil pipelines toll index
This section reviews toll trends since 2015 on CER-regulated oil pipelines. Benchmark tollsFootnote 8 for select major oil pipelines, as well as the gross domestic product (GDP) deflatorFootnote 9 normalized to 2015, are shown in Figure 3. The TNPI benchmark toll increased significantly compared to the GDP deflator between 2015 and 2025 due to factors such as declining throughputs and increased spending on pipeline integrity. The Enbridge Canadian Mainline’s benchmark toll decreased in 2023, narrowing the spread from the GDP deflator, due to the implementation of a new negotiated settlement. The Trans Mountain System’s benchmark toll increased significantly in 2024, compared to the GDP deflator, reflecting the costs of the Trans Mountain Expansion Project, which came into service during the year. The Keystone Pipeline’s benchmark toll has generally aligned with the GDP deflator, dropping slightly below from 2021 to 2025.
Figure 3: Oil pipeline benchmark tolls compared to GDP deflator
Source: CER – REGDOCS, GDP data from Statistics Canada Table 36-10-0130-01
Text Alternative: This chart presents CER-regulated oil pipeline benchmark tolls for selected pipelines, compared with the GDP deflator, indexed to 2015.
Gas pipelines toll index
This section reviews toll trends since 2015 on CER-regulated gas pipelines. The benchmark tolls for select Group 1 natural gas pipelines,Footnote 10 as well as the normalized GDP deflator, are shown in Figure 4.
The benchmark tolls for Alliance Pipeline’s services remained consistent in nominal terms from December 2015 through October 2025 and have not trended with the increase in the GDP deflator. The benchmark tolls decreased in November 2025 due to a new settlement agreement.
The Westcoast Pipeline’s tolls have increased more than the GDP deflator and the other gas pipeline benchmark tolls, largely from capital expenditures over the 2015-2025 period, including pipeline integrity and maintenance projects; the Spruce Ridge Program; and the T-South Reliability and Expansion Program.
New fixed-toll services were introduced on the TC Canadian Mainline to increase use of the pipeline, which has helped decrease cost-of-service tolls for its shippers. This trend continued with the Mainline 2021-2026 Settlement, and tolls continued to decrease relative to the GDP deflator.
Benchmark tolls on the NGTL System have generally increased since 2021. By 2025, they have risen above the GDP deflator after tracking below it in earlier years. Throughout the period, NGTL completed several sizeable expansion projects, including the Edson Mainline Expansion Project; the 2021 NGTL System Expansion Project; the North Corridor Expansion; and the West Path Delivery Program.
The benchmark tolls for Trans Québec and Maritimes Pipeline Inc. (TQM) were consistently below or approximated the GDP deflator until 2022. From 2022 through 2025, the benchmark tolls exceeded the GDP deflator as TQM’s rate base rose, including due to the TQM Reinforcement Project and Asset Purchase.Footnote 11
The tolls on Maritimes & Northeast Pipeline Management Ltd.’s (M&NP’s) pipeline increased significantly between 2015 and 2020, outpacing the GDP deflator. This increase occurred during the pipeline’s transition from a supply-driven system to one focused on serving domestic markets. As offshore natural gas production in Nova Scotia declined and eventually shut down, and the original 20-year backstop agreements approached expiry at the end of 2019, M&NP accelerated the recovery of certain asset costs (e.g., through depreciation expense). After 2020, tolls generally decreased due to reductions in costs and increases in billing determinants, and also became more volatile.
Figure 4: Gas pipeline benchmark tolls compared to GDP deflator
Source: CER – REGDOCS, GDP data from Statistics Canada Table 36-10-0130-01
Text Alternative: This chart presents CER-regulated gas pipeline benchmark tolls for selected pipelines, compared with the GDP deflator, indexed to 2015.
The CER Act requires companies operating oil, gas and commodity pipelines to maintain financial resources to cover the costs of any unintended or uncontrolled release from a pipeline, such as a spill. This requirement applies only to authorized pipelines. Authorized means pipelines that are currently in operation. It does not apply to pipelines that are still under construction, or those that have been deactivated, decommissioned, or abandoned under a Commission order.
An unintended or uncontrolled release of oil, gas, or any other commodity from a pipeline is subject to absolute liability. Absolute liability means that a company is liable for any unintended or uncontrolled release up to its defined limits of liability (a set dollar limit, discussed below), regardless of whether there is proof of the company’s fault or negligence. A company whose fault or negligence caused an unintended or uncontrolled release must pay all costs related to the release, even if those costs exceed the company's absolute liability limit.Footnote 12
Companies are required to maintain financial resources that, at a minimum, match the absolute liability limit applicable to the company under the CER Act and the Pipeline Financial Requirements Regulations (Regulations). The Commission also has the authority to direct companies to maintain financial resources greater than their absolute liability limits when necessary.Footnote 13
Major oil pipelines, defined as pipeline-operating companies that individually or in the aggregate have the capacity to transport at least 250,000 barrels of oil per day, are subject to an absolute liability limit of $1 billion, as set out in the CER Act.Footnote 14 All other oil, gas, and commodity pipeline companies are placed into certain classes and subject to specific absolute liability limits ranging from $5 million to $300 million, as set out in the Regulations as follows:
The Regulations also provide that if a company operates two or more authorized pipelines that are unconnected and transport different commodities, the limit of liability is determined as if the company were operating or transporting only the pipeline or commodity that results in the highest limit of liability. Figure 5 shows the aggregate absolute liability limits, by class, for all CER-regulated oil and gas companies.
To view the absolute liability limit and class type of each applicable CER-regulated company, see the Annual Report of the Commission of the CER.Footnote 15
Figure 5: Aggregate absolute liability limits for oil and gas companies
Source: CER Regulatory Filings – REGDOCS
Text Alternative: This chart illustrates the aggregate amount of financial resource requirements that must be maintained (at minimum) by company class, for oil and gas pipelines. Oil Class 2, followed by Oil Class 1, then Gas Class 1 make up the top three company classes by aggregate amount of resources that must be maintained. Oil companies in aggregate must maintain more financial resources than gas companies regulated by the CER.
In order to demonstrate how a company’s financial resources meet the requirements of the CER Act and the Regulations, the company must file a Financial Resources Plan (FR Plan) with the CER, for approval. The FR Plan details the types and amounts of financial resources available to the company, as well as the readily accessible portion (discussed below) and the timing of access for each resource. The Pipeline Financial Requirements Guidelines (Guidelines) provide details on how a pipeline company should demonstrate that it meets the financial resources requirements established in the CER Act and Regulations, including the attributes for each type of financial instrument; additional information that should be submitted by the company; and the format that should be used to show the relied upon financial resources.
In proposing an FR Plan, a company may choose from the types of financial resources set out in the Regulations, as listed below. The Commission also has the authority to direct a company to use any of these financial resources, in specified amounts, if the Commission is not satisfied with the company’s plan to meet the financial resources requirements:
As illustrated in Figure 6, CER-regulated oil and gas companies use a variety of financial resources to satisfy their requirements.
Figure 6: Financial instruments used in Financial Resource Plans by oil and gas companiesFootnote 16
Source: CER Regulatory Filings – REGDOCS
Text Alternative: The chart on the left shows the total values of the financial resources maintained for all oil and gas pipelines, for each type of financial instrument. The line of credit has the highest aggregate value of all financial instruments used. The chart on the right shows the number of oil and gas companies that hold each type of financial instrument as part of their FR Plans. Insurance, line of credit, and cash are the most frequently used financial instruments.
The Regulations also stipulate that companies must maintain a certain amount of financial resources in readily accessible forms. The Guidelines clarify that readily accessible means a company can gain access within five business days. The Guidelines also summarize the readily accessible resource levels required.Footnote 17 Gas pipeline companies with a risk value of at least $100,000, and all oil pipeline companies, must maintain at least 5%Footnote 18 of their absolute liability limit as financial resources in readily accessible forms. Companies are permitted to use letters of credit, lines of credit, participation in pooled funds, and cash and/or cash equivalents to meet this requirement.
As set out in Section 8.1 of the Guidelines, each company with an authorized pipeline must file annual updates to its FR Plan by April 30 of each year.Footnote 19 Moreover, Section 8.2 of the Guidelines describes each company’s ongoing obligation to notify the Commission, in writing, of any material revisions to its financial resources or its FR Plan that occur during the year.Footnote 20
When a company wants to, or must, permanently stop operating all or partFootnote 21 of its pipeline, the company must apply to the CER to abandon the pipeline. Abandonment can be done by removing the pipeline from the ground or by abandoning it in place, both of which require the right-of-wayFootnote 22 to be reclaimed and returned to a state comparable to its surroundings.
CER-regulated pipeline companies are liable for the costs of pipeline abandonment and, since 2014, have been required to have a process and mechanism in place that will provide adequate funds to pay for future abandonment. As part of this process, the CER calculates an Abandonment Cost Estimate for each CER-regulated company, which is the estimated cost to abandon a company’s pipeline(s) based on the pipeline(s) characteristics and the land crossed.Footnote 23
Companies can choose from various financial instruments to help ensure that adequate funds will be available at the time when abandonment activities take place. These instruments include qualifying trusts, letters of credit, and surety bonds:
All companies are required to report abandonment funding information to the CER on an annual basis.Footnote 27 Companies using trusts report information on their pipeline and detailed financial information of their trust, such as the amount contributed and earnings on investments in the trust, and audited financial statements. Companies that do not use trusts report on the status of their pipeline and financial instruments.
Figure 7: Abandonment Cost Estimates and trust balances for CER-regulated pipelines using trusts, as of 31 December 2025
Source: CER Regulatory Filings – REGDOCS
Text Alternative: The top chart illustrates aggregated Abandonment Cost Estimates and trust balances for CER-regulated companies as of 31 December 2025 and a breakdown by Group 1 and Group 2 companies. Approximately $4.7 billion has already been set aside and approximately $11.6 billion remains to be collected.
The bottom chart illustrates, for each Group 1 company using a trust, the relevant Abandonment Cost Estimate and the amount of funds set aside as of 31 December 2025. The chart also shows the remaining amount of each estimate to be set aside by the company. NGTL GP Ltd., as general partner, on behalf of NGTL Limited Partnership has the highest Abandonment Cost Estimate, at approximately $5.20 billion, followed by TransCanada PipeLines Limited at $4.13 billion and Enbridge Pipelines Inc. at $2.45 billion.
