Key Briefings - Briefing Binder for CER Appearance at the House of Commons Standing Committee on Natural Resources

TMEP – Overview of Review Process

• The Trans Mountain Expansion Project came before the National Energy Board in December 2013 and was initially approved by the Governor in Council in late 2016.

Federal Court of Appeal Decision

• On August 30, 2018, the Federal Court of Appeal released a decision that quashed the Order in Council approving the Project, and nullified the Certificate issued by the NEB for the Project.^{Footnote 1} Shortly thereafter, the NEB cancelled all ongoing detailed route hearings and advised Trans Mountain to safely cease all construction activity in a manner that minimizes environmental impact.

Reconsideration Report

• In February 2019 the NEB delivered its Reconsideration Report to the Government, with an overall recommendation that the Project was in the Canadian public interest and should be approved with conditions.
• The NEB imposed 156 conditions and made 16 new recommendations to the Government of Canada. The recommendations related to matters that fell outside of the NEB’s regulatory mandate, but within the authority of the Government of Canada.
• In June 2019, after consideration of the Reconsideration Report and the Crown Consultation and Accommodation Report, Governor in Council approved TMEP, subject to 156 conditions.
• The TMEP is subject to 156 project conditions related to environmental protection, pipeline and facility integrity, safety, Indigenous relations, socio-economic matters, emergency management, worker accommodations, and financial assurances, among other things.
• On July 19, 2019, the NEB decided how regulatory processes for the Project would continue, including detailed route and condition compliance processes.
• Construction, which was paused in September 2018, resumed in July 2019.

TMEP – Key Facts

• Line 1 was constructed in 1953. Line 2 Expansion application submitted in December 2013 to expand capacity from 300,000 bbl/d to 890,000 bbl/d.
• Project includes 983 kilometres of pipeline (7 spreads), 4 terminal expansions, Burnaby tunnel, and 12 pump stations
• 156 conditions.
  • To-date, approximately 133 conditions have been either partially or fully assessed.
  • All prior to commencing operations conditions have been satisfied.
  • Approximately 27 conditions, or sections thereof, remain to be filed or continue to be under assessment.
• Approximately 130 variances and relief requests related to condition compliance
• 180 compliance verification activities (inspections) to date, 142 with Indigenous Monitors
• 20 emergency response exercises, all with Indigenous Monitors
• 36,900+ people worked on the Project, 100+ million hours worked
• 1,643 watercourse crossings, 199 highway crossings, 50 railroad crossings
• 584,495 m3 of Grade Rock Blasting
• 101 km through urban areas
• 1.56 million amphibians salvaged and relocated
• 255,000+ artifacts recovered

TMEP – Current Status of Project

• The CER issued the final authorization for the TMEP pipeline to operate on April 30, 2024, and authorized it to carry crude oil from Trans Mountain’s Edmonton Terminal, located in Strathcona County, AB, to its Westridge Marine Terminal, located in Burnaby, BC, in Western Canada.

Line Fill and Commencing Operations

• All prior to commencing operations conditions have been satisfied.
• Line Fill for the new pipeline took place over 23 days, from April 16 to May 9, 2024.
• The volume filled at Burnaby Terminal was 4,002,000 bbl (636,00 m3).
• Line 2 entered commercial service on May 1, 2024. The tankers began taking Project oil from Westridge in late May (first docking window was May 20-22, second was May 22-24).

Leave to Open (LTO)

• Before a pipeline can go into service, a company must apply for and be granted leave to open.
• In a leave to open application, a company must demonstrate that the section of the pipeline is safe to operate.
• Leave to open applications are extensive and require the company to submit detailed engineering information on hydrotesting results and pipeline integrity.
• Trans Mountain submitted 42 LTO applications. The status of these are on the CER website.
• The final LTO application for the pipeline was approved on April 30, 2024. Tanks 96 and 98 at Burnaby Terminal remain as the only facilities left needing LTO.

Toll and Tariff

• The Commission approved preliminary interim tolls for the expanded Trans Mountain pipeline system in November 2023. This decision allowed the company to charge new tolls for pipeline services once expanded operations began in May of this year. Interim tolls are subject to adjustment.
• The next step in the interim tolling process is the final interim tolls hearing that will continue throughout 2024 and into 2025, which will include a detailed cost review of the project. Following a determination on final interim tolls, a final tolls decision will follow.
• The tolls hearing is currently at the stage where the Commission and intervenors are asking Trans Mountain for more information in follow up to the evidence that Trans Mountain has filed.
• Going forward, key steps in the hearing are currently scheduled as follows:
  • Intervenor evidence and Letters of Comment: December 2024
  • Trans Mountain’s Reply Evidence: April 2025
  • Oral cross examination starts: May 2025^Footnote 2

Compensation Hearing Applications

• To date, the CER has received 17 compensation hearing applications involving the Project. The majority have been withdrawn, or are on hold due to negotiations between the parties.
• The claims primarily involve compensation for the acquisition or lease of lands, and for damages due to construction.

CER Oversight in 2024/2025

• Final clean up and reclamation work will be ongoing along portions of B.C. pipeline. Compliance verification activities to oversee this work will continue through 2024/2025.
• Trans Mountain is required to undertake five emergency response exercises within five years after commencing operations.
• Post construction monitoring reports will arrive starting in January and will continue over several years.

TMEP - Purchase / Sale to Canada

• The CER was not involved, in any way, in the Government’s decisions to purchase the Trans Mountain Pipeline System; nor was its predecessor the NEB.
• The NEB review of the TMX Project assessed the economic feasibility of the Project and found that TMX was in the public interest. No further economic analysis was conducted by the NEB related to the Government’s decision to purchase the Trans Mountain.

Government of Canada’s purchase

• On May 29, 2018, the Government of Canada and Kinder Morgan announced they had reached an agreement for the Government of Canada to acquire the Trans Mountain Pipeline system and the expansion project for Canadian $4.5 billion.
  • Under the Share and Unit Purchase Agreement (Agreement), the Government of Canada would purchase the shares and units of all the entities that own and operate the existing Trans Mountain Pipeline system, and the company that was authorized to construct and operate the Trans Mountain Expansion Project.
• On August 30, 2018, Kinder Morgan Canada shareholders voted to approve the transaction.
• The CER Act requires companies to apply for approval to sell or purchase pipeline assets.
  • This ensures that if the pipeline operator changes, the new operator must demonstrate to the CER that it can operate the pipeline safely, and that it has management systems in place to ensure it can meet the CER’s regulatory requirements.
• When the Government of Canada acquired Trans Mountain, it was a share transaction, meaning the pipeline operator didn’t change – Trans Mountain Pipeline ULC continued to own and operate the pipeline, but the owner of Trans Mountain Pipeline ULC changed. Accordingly, the CER did not need to review a new set of management systems, and approval from the CER was not required in order for the transaction to occur.
• However, the CER did need to re-evaluate Trans Mountain’s financial resources, given the change to the parent company.
  • As a major oil pipeline company, Trans Mountain Pipeline ULC is required by the CER Act to maintain $1 billion (CAD) in financial resources. This did not change after the acquisition (though the requirement grew to $1.1 billion once TMEP commenced operations, pursuant to Condition 121 from the TMEP Certificate).
  • On August 8, 2019, Trans Mountain applied to replace its Financial Resources Requirement Plan as a result of the Agreement. Trans Mountain proposed it would meet the $1 billion requirement via a combination of $500 million in insurance, and a $500 million Line of Credit backstop from Canada TMP Finance Ltd. (a federal Crown corporation wholly-owned by Canada Development Investment Corporation).
  • After seeking public comments, the NEB approved the new Financial Resources Requirement Plan on March, 20 2019.

TMEP - Potential Sale and Role of the CER

• Depending on the nature of any eventual Trans Mountain sale, CER approval may or may not be required.
• The Commission’s leave is required under section 181 of the CER Act if a company intends to sell, purchase, transfer or lease pipeline facilities or assets that are regulated by the CER.
• The new operator must demonstrate to the CER that it can operate the pipeline safely, that it has management systems in place to ensure it can meet the CER’s regulatory requirements.
• Also, the new operator must demonstrate that it has plans in place to fund both pipeline abandonment and financial resources.
• In instances where only the shares are transferred, but the operator remains the same, CER approval may only be required for any changes to the company’s financial resource plan, as was the case with the transfer from Kinder Morgan to the Government of Canada.
• Valuation/sale price:
  • In normal course of business, companies and assets tend to sell at multiples to their earnings.
  • Accordingly, we recognize that Trans Mountain’s future revenues, and hence earnings, will be impacted by the Commission’s tolls decision. The Commission has an obligation to ensure tolls are just and reasonable and not unjustly discriminatory. That is what the Commission is in the process of doing.

CER’s Regulatory Oversight Responsibilities

• As an independent regulator, the CER treats all projects and project proponents the same, whether they are a Crown Corporation or a publicly held company.
• The owner must comply with all CER regulatory requirements and TMX certificate conditions (unless it applies to vary those conditions).

TMEP - Unique Elements

• Given the complex nature of the project and the natural environment in which it is installed, the company’s inherent planning needed to be equally complex.

Construction

• The CER is aware that a number of unique elements that contributed to construction delays. The following information is intended be overview in nature. There currently is a Trans Mountain toll hearing before the Commission of the CER where one of the issues to be determined is whether a wide range of construction costs were reasonably and necessarily incurred. No conclusions have yet been reached.
• In enacting its own oversight of its project, the company’s management had to appropriately plan and execute various applications or requests throughout its construction (e.g., variances in design and routing). These were necessary to uphold rights to Indigenous peoples, affected landowners, and for continued protection of the environment and safety of people.
• Trans Mountain’s filings in the ongoing tolls hearing before the Commission state in part that construction was intermittently impacted by external factors including:
  • Two wildfire seasons which impacted the ability to progress construction in affected areas.
  • Major flooding in B.C., due to an atmospheric river event which occurred in November 2021, flooding impacted the right of way that was under construction, as well as limited access and ease of worker movement to/from work areas and likely required the reestablishment of access roads.
  • The COVID-19 pandemic, which caused most industry activities in Canada to come to a stop or slow. Specific impacts included:
    • limitations on construction execution (number of workers having access concurrently to work areas; worker transportation would have needed expansion, etc.);
    • changes to procedures and reporting (worker time lost due to illness; provincial/federal health reporting);
    • procurement challenges (supply chain impacts; purchase of new/unforeseen PPE such as masks, additional sanitization).
  • Certain legal and regulatory requirements were beyond what Trans Mountain had assumed when developing its early estimates (time for detailed route hearings, right of entry applications and leave to application applications was not included in Trans Mountain’s 2013 application).
  • The costs to accommodate and protect Indigenous rights and the archaeological heritage of Indigenous nations were significantly higher than anticipated.
• We are providing this overview information from Trans Mountain to be responsive to the Committee questions. The specific extent to which these and other factors may have contributed to cost overruns has not yet been determined. There currently is an ongoing hearing before the Commission of the CER where the issue of whether costs were reasonably and necessarily incurred will be determined. At this stage no conclusions have been reached.

TMEP - Regulatory Requirements and Timing

Regulatory Requirements

• While Canadians mostly hear about the CER’s involvement at the beginning of a project, we regulate federal energy infrastructure throughout its entire lifecycle.
• We do not simply make a decision on a project and walk away.
• When approved projects are being built and operated, we inspect and audit them.
• When a pipeline has reached the end of its usefulness, the CER ensures that it is abandoned in a safe and environmentally responsible manner.
• In other words, the CER regulates from “start to finish”, which can span the course of many decades. And we hold pipeline companies responsible for the full lifecycle of the pipelines they operate.

Condition Compliance

• The degree of regulatory oversight is proportional to a project's complexity and scale. This ensures that larger and more multifaceted projects have the necessary monitoring and guidance to meet the conditions set for a project.
• We use the necessary enforcement tools to ensure companies are following our regulations and workers are kept safe.
• Safety is always our top priority, including all workers and contractors on job sites.
• We confidently enforce some of the strictest safety and environmental standards in the world.
• During the project's lifecycle, compliance with conditions set by the CER is crucial. If the CER identifies an issue during compliance activities, it can affect the project, including its construction timeline.

Time Limits

• The CER Act mandates that all applications and proceedings before the Commission must be dealt with as expeditiously as the circumstances and procedural fairness and natural justice permit, and within the time limit provided for in the CER Act.
• The time limit must not exceed the legislated number of days from the day which the company/applicant has provided a complete application, as decided by the Commission. The Commission must complete its assessment and make its recommendation or decision within this time limit.
• The Lead Commissioner of the CER Commission will set time limits for certain types of applications and ensure these time limits are met.
• The CER has always strived for efficiency in our hearing and application processes. The time limits maintain this efficiency and enhance certainty and predictability for all parties involved.
• Our commitment to conducting fair and efficient processes, including meeting the time limits, has not changed since becoming the CER and will not change.
• Project applications are categorized as small, medium, or large, with processing times under the CER Act varying based on complexity, potential information requests, and expected third-party interest.
  • Small projects (less than 40km of new right of way) are assessed within 10 months.
  • Medium projects (more than 40km but less than 75km of new right of way) are assessed within 15 months.
  • Large projects (75km or more of new right of way) will have assessments that range from 10 to 20 months.
  • Large projects will go through an integrated review led by the new Impact Assessment Agency with support from the CER.
• The Commission’s expert advice on safe design, construction and operation of pipelines, as well as its comprehensive analysis of any project, will support the recommendation it makes as to whether or not a project is in the public interest.
• The CER’s report on a project will include conditions to be attached to any certificate issued. Cabinet may refer back to the Commission its approval or denial or add or revise conditions, but the CER makes the final decision as to what its recommendation will be.
• This recommendation is published and provided to the Governor in Council for a final decision.

TMEP Specific Information – Regulatory Requirements and Timing

• TMEP application was assessed under the NEB Act in which the legislation called for fixed beginning-to-end time limits of 18 months for most NEB applications. This was broken down into 15 months from the date the Board determined an application was complete until the Board completed its assessment with the issuance of a Decision or Recommendation to Governor in Council.
• There was a pause in the NEB process after Trans Mountain changed project routing to go through Burnaby Mountain. Trans Mountain was required to file studies for the new routing on the public record.
• TMEP came before the NEB in 2013 and was initially approved in 2016. The project encountered a legal challenge in 2018, leading to a Reconsideration process.
• In 2019, the NEB published its Reconsideration Report, which recommended that the TMEP was in the public interest and should be approved with conditions.
• Since the Governor in Council approved TMEP in 2016 and then again in 2019, the CER has been actively monitoring the project's construction and ensuring compliance with regulatory requirements.
• The TMEP is subject to 156 project conditions related to environmental protection, pipeline and facility integrity, safety, Indigenous relations, socio-economic matters, emergency management, worker accommodations, and financial assurances, among other things.

Adjudicative Processes

• At the time of the TMEP application, there were several outstanding aspects yet to have been completed and/or which would have been unknowns, such as detailed design, detailed route, and engineering assessment of the portions of the existing facilities that were to be reactivated.
• Trans Mountain faced numerous challenges post-approval that resulted in additional regulatory processes required by legislation, including with respect to reaching land agreements and obstacles encountered during construction that required project design and route revisions.
  • 96 Statements of Opposition were received post-certificate, resulting in 39 detailed route hearings (20 new hearings, and 19 previous hearings resumed), a process which spanned 20 months. In the end, 26 Statements of Opposition were withdrawn, and decisions were issued in relation to 14. Construction was not able to occur on these sections of land until detailed route decisions were issued.
  • 121 Right of Entry applications were required to access lands for which Trans Mountain could not come to an agreement with landowners.
  • 63 Route Deviation decisions were made.
• There were significant number of Information Requests during the hearing:
  • First hearing – 6 official rounds, plus 5 additional significant packages on specific filings
  • Reconsideration – 2 official rounds
  • The NEB also asked many IRs of intervenors and government departments.

Conditions and construction oversight

• Should the Commission identify a risk during the review of an application, they may ask a company to meet a number of conditions specific to the project. Conditions are imposed to reduce risks, prevent harm, promote safety, and protect the environment.
• During the adjudicative phase, proposed conditions were floated, offering fair opportunity for Trans Mountain to comment, and to raise concerns regarding the content and/or timing of these proposed requirements.
• Many of the conditions ultimately imposed pertained to commitments made by the company through the proceeding, or to demonstrate compliance with current standards (i.e., they would have had to do them regardless of whether there had been a condition or not).
• To-date, approximately 133 of the 156 conditions have been either partially or fully assessed. Approximately 27 conditions, or sections thereof, remain to be filed or continue to be under assessment.
• Between August 2017 and August 2018 there were 22 Condition Compliance letter reports issued by the NEB. When the Project was recommended in July 2018, these decisions were adopted (reassessment of these conditions was not required post-reconsideration which led to some efficiencies).
• Between August 2019 and May 2024, the Commission issued a total of 275 Letter Reports and Decisions on matters related to condition compliance. 177 Information Requests were also issued on condition compliance matters.
• In 2022-2023 alone, the TEMP filed 828 Post-Approval Compliance documents.

Inspection Officer Orders

• A total of 12 Inspection Officer Orders (IOOs) were issued to Trans Mountain following project approval in 2019, five of which included stop work orders on specific spreads for 215^Footnote 3, 10, 6, 13, and 43 days. All the stop-work orders impacted localized areas vs. the entire project.
• Trans Mountain reported at least 7 incidents, as required by the OPR, to the CER (e.g., serious injuries) that involved voluntary work stoppages. The length of these stoppages is unknown.

Variances

• Routing Variances (West Alternative Route Variance Application, Chilliwack BC Hydro Route Realignment)
  • After first hearing: 7
  • After reconsideration: 3
• Non-routing Variances (Mountain 3 change in pipe size, change to the no. of tanks at Edmonton terminal, change in the location of the Hargraves Trap Site)
  • After first hearing: 3
  • After reconsideration: unknown

TMEP - Cost Increase

• The estimated cost of the TMEP when the project application was first submitted to the NEB was $5.4 billion. The latest estimate that Trans Mountain has provided in the tolls hearing is $34.2 billion (an over 6x increase).
• In the tolls hearing that is currently unfolding, the Commission has required Trans Mountain to provide detailed information about what contributed to the increase in project costs.
• Given that the matter is before the Commission, the CER will provide only overview information about events that occurred after Trans Mountain’s application was first submitted. With the issue of whether costs were reasonably and necessarily incurred before the Commission, we will not be commenting on the specific causes of the cost increases.
• While Trans Mountain has submitted much evidence in this regard, other parties in the hearing – such as shippers – have not yet submitted their evidence in response. Further, after the oral phase of the hearing, the Commission will consider all the evidence and issue its tolls decision. This is why we will not get into detailed discussion of all the various factors that contributed to the rise in costs. We have to respect the independence of the Commission’s ongoing adjudicative hearing.
• One of the issues in the hearing is whether costs were reasonably and necessarily incurred. This is why we will not get into detailed discussion of all the various factors that contributed to the rise in costs.
• At a high level, Trans Mountain has pointed to a variety of factors as having contributed to the rise in costs. For example, Trans Mountain points to the following:
  • The physical conditions encountered on the ground sometimes differed significantly from what Trans Mountain assumed when developing its early estimates, which were based on assumptions developed before ground truthing could be conducted.
  • Certain legal and regulatory requirements were beyond what Trans Mountain had assumed when developing its early estimates.
  • The costs to accommodate and protect Indigenous rights and the archaeological heritage of Indigenous nations were significantly higher than anticipated.
  • Other factors contributed to the rise in costs, such as extreme weather events like the atmospheric river flooding and the COVID pandemic.
  • Also, the prolonged project schedule meant the company incurred more carrying charges until the project was completed.
• These are factors pointed to by Trans Mountain in its public filings and no determination has been made as to the specific impact if any of these factors on the increase in costs. As we have said, there is significant evidence yet to come to the Commission’s toll hearing and no determinations have been made.

TMEP - Economic Feasibility of TMEP as considered by the NEB and Commission

• In the initial hearing for TMEP (OH-001-2014), the NEB considered the economic feasibility of the pipeline. The cost estimate at that time was $5.5 billion.
• The Board placed significant weight on the existence of long-term firm service agreements with shippers in determining whether the facilities were needed and likely to be well utilized over their economic life.
  • TMEP had 13 shippers with firm commitments for 15 or 20 years for 80% of the expanded system’s capacity.
• Given the importance of the contracts to the NEB’s assessment of TMEP, the Board imposed Condition 57, requiring Trans Mountain to file with the NEB 90 days prior to construction, signed confirmation that secured agreements or contracts remain in force with shippers for a minimum 60 per cent of its total capacity. Trans Mountain did so, confirming it continued to have firm commitments with 13 shippers for 80% of the expanded system’s capacity.
• The economic feasibility and the cost estimate have not been reviewed by the Board or the Commission since the initial hearing for TMEP. The report from the initial hearing was released in May 2016.
• Neither the economic feasibility of the pipeline nor the cost estimate were within the scope of the Reconsideration Report (MH-052-2018). The scope of the Reconsideration Report focused on marine shipping and Crown consultation related to TMEP.
• Following the issuance of a certificate, the Commission does not review the ongoing economic feasibility of a pipeline as it is being constructed.

TMEP - Cost Increase and Tolls, Utilization of Pipeline

• I’ll be mindful that the CER has a hearing underway on Trans Mountain’s tolls, but I can provide some background information.
• Of course, tolls are a key factor in Trans Mountain’s revenue generation, and hence tolls are an important consideration in how much Trans Mountain might sell for.
• By way of background, before Trans Mountain applied for approval of the expansion project, it received NEB approval for a toll methodology that would apply to the expansion (or more accurately, a toll methodology that would apply to the whole system post-expansion – because post-TMEP, the same tolls are charged without differentiating between service on the original and new pipe).
• The methodology had been negotiated by Trans Mountain and shippers, and was spelled out in the contracts that shippers signed for service on the expanded Trans Mountain system.
• The toll methodology divided the costs to build TMX into two buckets. One was called “Capped Costs” and the other was “Uncapped Costs”.
• The methodology stipulated that once Trans Mountain received regulatory approval for TMEP, Trans Mountain would update its project cost estimate and re-base tolls for that new estimate. From that point forward, tolls would not change to account for any escalation in Capped Costs, but they would increase by 7 cents for every $100 million that Uncapped Costs escalated.
• Trans Mountain’s 2017 cost estimate was $7.4 billion, and under the methodology, it was fully reflected in re-based tolls at that time.
• Fast forward to 2023, and as the project was getting closer to completion, Trans Mountain applied for the interim tolls that would apply once TMEP commenced service, based on the preapproved toll methodology and updated project cost information.
• According to Trans Mountain’s evidence in the tolls hearing that is underway, since the 2017 estimate of $7.4 billion:
  • Uncapped Costs have risen by $8.0 Billion, and
  • Capped Costs have risen $18.7 billion.
• In the tolls hearing, the Commission will be examining what toll numbers actually result from the toll methodology that was approved in 2013.
  • This will involve looking at whether costs have been properly split between the Capped and Uncapped buckets.
  • It will also involve examining whether all the project costs allocated to Uncapped Costs were “reasonably and necessarily incurred” – which is something stipulated in the approved methodology.
• Additionally, however, the Commission will also be considering whether the tolls that come out of the methodology approved in 2013, are still appropriate – that is, are they just and reasonable and not unjustly discriminatory.
  • This will involve considering Trans Mountain’s financial position, and considering market impacts.

[If Desire to Keep Going:]

• In terms of just how much Trans Mountain recovers of its costs, that is something that is being examined in the tolls hearing.
• If one is just looking at the pre-approved methodology, it may not be as straightforward as looking just at the $18.7 billion rise in Capped Costs as a share of the $34.2 billion total.
  • One might also need to consider factors such as how lucrative – or not – the 7 cents per $100 million is, and how lucrative – or not – the re-based toll is that is associated with the $7.4 billion.

Additional contextual background information:

• As an example, Trans Mountain’s project management costs were in the Capped bucket, while its consultation and accommodation costs were Uncapped. As another example, pipeline construction costs for most of the project was in the Capped Cost bucket, but a few specific segments were included in the Uncapped Cost category.

Timeline for Final Tolls (When will final tolls be set?)

• We don’t yet know the exact timing.
• The Commission expects that final tolls will be set in accordance with the decision it will release in the hearing that’s currently underway. As an example of this, the Commission said that final tolls might require a true up to account for the final as-built costs that Trans Mountain will record over the coming months.

Utilization of Pipeline (Will Trans Mountain be used? Will tolls be so high nobody ships on Trans Mountain?)

• There are different elements to this.
• One is that 80% of the system’s expanded capacity is under contract for the next 15 to 20 years. Under these contracts, shippers have to pay most of the toll even if they do not ship any volumes. That will make it attractive for them to ship on Trans Mountain.
• For the remaining 20% of capacity that will be available on a monthly basis, the degree of utilization may be more susceptible to changing market forces.
• I will note that one of the issues being considered by the Commission in the tolls hearing that is underway, is the market impacts of Trans Mountain’s tolls.

TMEP Market Impacts (What has happened with oil and refined product flows and markets since TMEP came into service?)

• Since the TMEP has come into service, the Trans Mountain system shipped 704,000 barrels per day in June 2024, up from the 2023 average of 346,000 barrels per day. Almost all of these June barrels were contracted volumes.
• Marine shipments from the Westridge Terminal reached 360,000 barrels per day in June, from about 50,000 prior to the start-up of the expansion. In June and July, about half of the crude oil exported by marine is destined for US destinations (California, Washington) with the remainder going to Asian countries including China, India, and South Korea.
• In June, the system shipped 43,000 barrels per day of refined petroleum products in BC markets and has capacity available to move refined products to supply BC markets as needed. (Due to the changes in how Trans Mountain reports gasoline and diesel products, public data is not yet available to indicate how shipments of gasoline and diesel have changed with TMEP in-service.)
• Crude by rail volumes have stayed between 80,000 and 100,000 barrels per day since January 2024, having been on a downward trend since reaching record highs in early 2020. It is expected that crude by rail will remain stable at roughly these levels since these crudes are being exported to destinations that are not easily accessible by pipeline or have specific formulations that make them difficult to ship via pipeline. Historically, if there is sufficient pipeline capacity, as is the case today, crude by rail has not been used for any more than necessary.
• Crude oil in storage in Alberta has decreased by 15 million barrels (20%) to 60 million barrels since the start of TMEP based on data from the Alberta Energy Regulator.
• All export pipelines from western Canada were running at close to capacity before TMEP came into service. Since May 2024, media has reported that Canada’s largest oil pipeline, Enbridge Mainline has had some spare capacity and has cut tolls in response to increased competition from an expanded Trans Mountain. Keystone Pipeline remains at or near capacity.

Gasoline Prices

• Trans Mountain has long been able to transport refined petroleum products (RPPs), like gasoline, as well as crude oil for use in refineries.
• Prior to TMEP, the pipeline had insufficient capacity to satisfy shippers’ demand for transporting RPPs and crude oil. TMEP has lifted these capacity constraints. As a result, southern B.C. markets can now acquire additional RPP supply using the TMEP’s extra capacity rather than alternatives, such as rail and truck.
• However, how exactly gasoline prices in the Lower Mainland will be impacted, could depend on a number of factors.
• Due to the ongoing Trans Mountain tolls hearing, we will refrain from providing further comments on this topic.
• The hearing will consider, in part, how Trans Mountain’s tolls could impact markets, generally, and there have already been submissions regarding British Columbia gasoline prices.

Contextual background Information - recent media coverage:

• On 13 August 2024, the C.D. Howe Institute published an e-brief, “The Big Squeeze: Lessons from the Trans Mountain Pipeline about the Costs of Invisible Bottlenecks”, which discusses the costs of insufficient transportation infrastructure. It was referenced by several news agencies.
  • The report discusses Trans Mountain’s past capacity constraints as well as the NEB’s 2015 decision regarding Trans Mountain’s procedures for verifying shippers’ nominations. The report concludes that the 2015 rule change, which limited the ability of shippers to over-nominate volumes, reduced RPP shipments on Trans Mountain. This resulted in more RPPs moving from Edmonton to B.C. via higher-cost rail. According to the report, the capacity constraint added more than 10 cents per litre to B.C. Lower Mainland wholesale fuel prices since 2019, and between 20 and 30 cents per litre in 2023.
  • The report states that B.C. residents should see lower gasoline prices with the TMEP. According to the report, the increase in tolls from the TMEP is more than offset by reduced shipping costs as RPPs move back onto the Trans Mountain pipeline and away from higher-cost rail.
  • The CER staff has not verified the data and conclusions in the report. The impacts of Trans Mountain’s post-expansion tolls on refined product markets, including prices, may be assessed as part of an ongoing hearing process.
• Recommended response to questions:
  • As described in the report, the TMEP will increase the amount of pipeline capacity available to transport RPPs, enabling southern B.C. to acquire a greater proportion of its RPP supply from the pipeline rather than alternatives, if it chooses.
  • However, the exact impacts on gasoline and diesel prices in B.C. could depend on a number of other factors.
  • The impacts of Trans Mountain’s post-expansion tolls on refined product markets may be assessed as part of an ongoing hearing process, so we are unable to comment further.

TMEP - Export Capacity and Emission Reduction Targets

• Increased pipeline capacity may impact production and greenhouse gas (GHG) emissions, but global crude oil prices play a greater role;
• Estimated export pipeline capacity out of Western Canada was about 4.6 million barrels per day (MMb/d) prior to the start of operation of the Trans Mountain Expansion project.
  • This is estimated to increase to 5.2 MMb/d when TMEP is fully operating.
• The CER has previously undertaken analysis of the impact of pipeline capacity on crude oil production in its Canada’s Energy Future series. Though the analysis is not specific to TMEP, in the CER’s Energy Futures 2016 report, a “Reference” case with unconstrained pipeline capacity (compared to a “Constrained” case limited to 4 MMb/d of export pipeline capacity), resulted in higher prices to Canadian oil producers, increased oil project investments, higher production levels (9% higher by 2040 compared to the constrained case), and increased energy use between 2015 and 2040.
  • The report assumes that when the marginal barrel is exported from Canada via pipeline, as in the Reference case, the price of crude oil in Western Canada is higher compared to a scenario where rail provides the marginal source of transportation. Given the higher cost of transporting crude by rail, Western Canadian crude oil prices are lower. This difference in prices is the driver of different production trends in the two scenarios.
  • Although GHG emissions were not quantified, increased production and energy use would have likely led to higher upstream GHG emissions. However, moving crude via pipeline vs rail (as in the “Constrained” case) would result in lower oil transportation emissions.
  • This analysis (although dated) highlights the potential impact of pipeline capacity limits and the complexities of pipeline bottlenecks on Canada’s energy system and economy.
• Environment and Climate Change Canada (ECCC) estimated that the upstream GHG emissions resulting from the production, processing, and refining of products associated with the TMEP’s capacity (of 590 Mb/d) would be 13.5-17 million tonnes (Mt) of CO2e per year.
• ECCC notes that whether those emissions are truly incremental depends on the considerations such as the expected price of oil, the availability, and costs of other transportation modes (e.g., crude by rail), and whether other pipeline projects are built.
  • Note that the emission intensity of Canadian oil production has fallen steadily over the past several years, falling over 20% from 2005 to 2022 according to ECCC.
• World oil prices have a greater impact on production than the transportation method. At sustained high oil prices, new production would likely be transported by rail if pipelines are unavailable. However, there is a price range (around $60-80/bbl) where additional production would come online because Trans Mountain provides a cheaper option than rail.

Emissions Reduction Targets in Canada and the Oil and Gas (O&G) Sector

• Canada has committed to reduce the country’s GHG emissions to 40-45% below 2005’s levels by 2030 (to a level of around 440 million tonnes (Mt)), and to reach net-zero GHG emissions by 2050.
• GHG emissions from upstream oil & gas (O&G) production were 186 Mt of CO2e in 2022. That is 26% of Canada’s total emissions that year (of 708 Mt), and a 16% increase relative to 2005’s levels.
• ECCC is currently developing a regulatory framework to cap GHG emissions from the O&G sector. This will be achieved through a cap-and-trade system that would require emissions reductions by 2030 at two levels – one at 35-38% below 2019’s levels (the emissions cap), and one higher at 20-23% below 2019’s levels (the legal upper bound). The gap between the two is meant to create a buffer of compliance flexibility.
  • Relative to 2022’s emissions levels, this would require the O&G sector to reduce emissions by 16-35% by 2030. Since the regulatory framework is not expected to come in force until 2026, assuming emissions levels in 2025 equivalent to those in 2022, would require industry to reduce emissions by 3-7% per year between 2026 and 2030.
  • For context, the global financial crisis of 2008-09, the Fort McMurray wildfires of 2016, and the COVID-19 pandemic, were the only times in recent history when upstream O&G GHG emissions declined in that order of magnitude.
• A limit on GHG emissions from the sector doesn’t equate to a limit on production – because producers can use various technology and compliance options to reduce their GHG emissions while maintaining or continuing to grow production levels. Regulations are expected to be finalized by 2025 and to come into force in 2026.

TMEP - Crown Consultation

• The Government of Canada consulted potentially impacted Indigenous communities on the TMX pipeline, first in 2016 and then again in 2018-2019, in response to the August 30, 2018 Federal Court of Appeal decision.
• In making the decision to approve the project, the government took into consideration a wide variety of information, including the NEB’s (now CER) Reconsideration Report, the Crown Consultation and Accommodation Report (CCAR), the Honourable Frank Iacobucci’s independent advice, evidence-based science and Indigenous knowledge.
• There are 156 conditions that the proponent must comply with and that would be transferred to a new owner.

TMEP - Shipper Termination Rights

The contracts shippers signed to use the Trans Mountain Expansion initially had termination rights, where they could cancel their contracts if certain triggers were met (for example with respect to costs). Those termination rights are now lapsed. For further detail see below points:

• The Facility Support Agreement (FSA) (Section 5.4, A3E7D3) lays out termination rights for shippers.
• The termination right following a toll adjustment could have been exercised once shippers received Trans Mountain’s toll adjustment following the receipt of the Certificate of Public Convenience and Necessity (CPCN).
• Within 60 days, Trans Mountain provided its shippers with a new cost estimate which would set out a revised toll for shippers. The fixed toll would increase by $0.07 per barrel for every one hundred million dollar increase in the cost estimate. If the new cost estimate increased tolls beyond the Open Season Toll limit (which it did), then shippers would have the right to terminate their contracts.
• Trans Mountain received its (initial) CPCN in December 2016 (A80871-1). Trans Mountain has indicated that with the quashing and later re-issuance of the CPCN, it was not required to reissue the cost estimate and Trans Mountain did not do so (C01495-1).
• Shippers had other termination rights in the FSA, but these were related to failure to satisfy conditions precedent (e.g., failure to obtain NEB approval of the toll methodology or other regulatory approvals), rather than the tolls.
• All termination rights have now passed.

TMEP – Financial Conditions

Prior to construction, Trans Mountain was required to file confirmation that at least 60% of the pipeline’s total capacity was underpinned with long-term contracts. The NEB approved the condition on August 3, 2017. For further detail see below points:

Condition 57: Commercial Support for the Project

• The Board imposed Condition 57 (link) on Trans Mountain, which required Trans Mountain to file with the Board 90 days prior to construction, signed confirmation that secured agreements or contracts remain in force with shippers for a minimum 60 per cent of its total capacity and that any rights to terminate held by shippers had lapsed and or expired because their conditions precedent have been satisfied or waived.
• On May 10 2017, Trans Mountain filed confirmation that the Project had secured 15-year and 20-year firm service commitments from 13 shippers, totaling 707,500 barrels per day representing 80 per cent of its total capacity. This exceeded the 60 per cent threshold set forth in this Condition.
• Further, as required by Condition 57 b) Trans Mountain confirmed that all shippers’ rights to terminate had expired because their conditions precedent had been satisfied or waived. (A83349-1).
• On August 3, 2017, the NEB issued a letter finding that Trans Mountain had met the requirements of Condition 57 (A85310-1).
• In subsequent filings, Trans Mountain indicated that after the re-issuance of the CPCN (following the reconsideration hearing), Trans Mountain did not re-issue a new CPCN cost estimate to shippers. Accordingly, shipper termination rights were not reopened. (C01495-1)

Prior to applying for leave to open the expansion, Trans Mountain was required to file a Financial Assurances plan detailing how it could access $1.1 billion to respond to spills or incidents on the pipeline. The plan included insurance of $550 million, and a letter of credit from TMEP Finance Canada Ltd for $550 million. The Commission approved the plan on September 29, 2023. For further detail see below points:

Condition 121: Financial Assurances Plan – operations phase

• The Board imposed Condition 121 (link) on Trans Mountain, which required Trans Mountain to maintain $1.1 billion of financial assurances to respond to spills or incidents. Trans Mountain was required to file a Financial Assurances Plan, for approval, at least 6 months prior to applying to leave to open Line 2 that would provide details on types of financial resources, including ready cash available.
• As part of Condition 121, Trans Mountain must file a letter annually signed by an officer of the company verifying that all components of the Financial Assurances Plan remain as approved. Any changes to the Financial Assurances Plan must be approved by the Commission in advance.
• On August 19, 2022, the Commission confirmed that the total requirement for Trans Mountain is $1.1 billion. That is, the $1 billion financial resources requirement in the CER Act for major oil pipelines and the $1.1 billion requirement in Condition 121 of the TMEP Certificate are not additive.
• On December 21, 2022, Trans Mountain filed its Financial Assurances Plan for approval (C22670-1) and filed a report from an independent third-party, MNP LLP, that assessed Trans Mountain’s Financial Assurances Plan and its key components (C22671-1).
• Trans Mountain’s Financial Assurances Plan consists of a $550 million line of credit from Canada TMP Finance Ltd. and $550 million of third-party liability insurance coverage.
• On September 29, 2023, the Commission conditionally approved Trans Mountain’s Financial Assurances Plan to become the expanded system’s new Financial Resources Plan and accepted the filing of independent third-party report (C26371-1). The Commission provided final approval of the new Financial Resources Plan for the expanded system on 23 February 2024 (C28479-1).

CNRL Vapor Pressure Tariff Complaint

Key Points

• In April of 2024, CNRL and some of Trans Mountain’s shippers complained that the Trans Mountain tariff allows for the blending of various crude oil types in a way that could harm the crude sales price for some producers.
• The Commission has regulatory oversight of pipeline tolls and tariffs, including the product specifications that are set out in pipeline tariffs.
• At the request of parties, the Commission stayed the process, and Trans Mountain and its shippers negotiated, arriving at a solution at the end of August.
  • Crude specifications have now been agreed upon, with Trans Mountain filing updated tariffs on 14 June – which revised the heavy crude specifications, and 30 August – which revised the light crude specifications; with support of the shippers, including CNRL.
  • Trans Mountain’s tariff crude specifications now largely parallel those used for the Enbridge Mainline.
  • At this time, no further process is required on the complaint.
• The CER can only provide an overview of the submissions that have been received and the process that took place. We cannot speak to the veracity of the complaint.
• To be clear, no party suggested that Trans Mountain’s crude specifications would result in any safety issues for the pipeline.

Further Details - CNRL Complaint about Trans Mountain’s Expanded System Tariff

• Canadian Natural Resources Limited, with support from Suncor and Imperial Oil, filed a complaint on 12 April 2024 for the expanded system tariff.
• The complaint alleged that with expanded service taking effect on the system:
  1. Crude specifications have now been agreed upon, with Trans Mountain filing updated tariffs on 14 June – which revised the heavy crude specifications, and 30 August – which revised the light crude specifications; with support of the shippers, including CNRL.
  2. Trans Mountain’s tariff crude specifications now largely parallel those used for the Enbridge Mainline.
  3. At this time, no further process is required on the complaint.

Process

• On 12 April 2024 CNRL submitted a complaint to the Commission related to Trans Mountain’s tariff.
• Trans Mountain filed a letter of comment on 17 May 2024 (C29697) and advised that a review process is underway and Trans Mountain is committed to working with CNRL and all other shippers to review the technical specifications in the tariff that are subject to the Complaint.
• On 24 May 2024 (C29752) in consideration of Trans Mountain being prepared to discuss this matter further, CNRL requested that the Commission hold the Complaint in abeyance for a period of 45 days to allow parties to negotiate. The Commission granted the abeyance request on 5 June 2024 and requested CNRL to provide an update on the ongoing review process by 8 July 2024.
• In the meantime, Trans Mountain filed a revised tariff on 14 June 2024 (C30039) and stated that CNRL’s concerns regarding the heavy crude pools have been addressed. Following this submission, CNRL filed a request for an additional 45-day abeyance on 8 July 2024 (C30606) so that its concerns with the light crude pools could be resolved.
• On 16 July 2024 (C30703), the Commission issued a letter approving this extension until 3 September 2024.
• Trans Mountain filed on 30 August 2024 (C31220) another revised tariff in which it submitted that shippers concerns pertaining to the light crude pools specifications have been addressed and it is not aware of any shipper that intends to oppose the revisions.
• CNRL provided an update on the outcome of discussions with Trans Mountain on 3 September 2024 (C31236) and stated that its concerns have been resolved but it will continue to monitor the quality of the crudes being shipped on the TMX. With the support of Imperial and Suncor, CNRL stated that it is willing to withdraw the complaint but reserves the right to file a subsequent one should the quality of the crude pool changes.
• As of now, the PWG has been disbanded and no further process is required on this file.

CER’s Role in Regulation of GHG Emissions

• The CER does not directly regulate GHG emissions. Rather, it regulates the infrastructure itself.
  • Releases of methane and other GHG emissions from CER-regulated facilities are subject to ECCC and provincial regulations.
• The Commission considers the potential GHG emissions of new energy infrastructure when assessing projects under the CER Act, particularly the extent to which the project would hinder or contribute to Canada's commitments in respect of climate change.
• These assessments are guided by the CER Filing Manual, which reflects the principles and objectives of ECCC’s Strategic Assessment of Climate Change; notably the new requirement for proponents to provide a credible plan to achieve net-zero emissions by 2050.
• An assessment of the upstream GHG emissions (and their incrementality) will also be considered for projects above a designated threshold, currently set by the SACC at 500kt CO2e/year.
• Throughout Operations, the CER verifies compliance to Onshore Pipeline Regulations and CSA Z662 requirements for companies to develop, implement and maintain an Integrity Management Program. An effective Integrity Management Program will lead to decreased nonplanned emissions.

Fugitive Emissions

• The CER does not regulate fugitive emissions; however, the CER is responsible for verifying that companies have implemented a pipeline control system that includes a leak detection system.
• According to the most recent National Inventory Report, Canada’s oil and gas sector accounted for 28 percent of national emissions in 2021, making it the largest contributor to Canada’s emissions.
  • Unintentional fugitive releases from oil, natural gas, and CO2 transmission pipelines accounted for less than 1 per cent of those emissions from Canada’s oil and gas sector.
  • Around 6 percent of emissions produced by Canada’s oil and gas sector were emitted from pipeline compressor stations & fugitive gas emissions. Use of electricity in powering compressor stations can reduce these emissions.
• Oil pipelines tend to use electric motors to power the pumps that pressurizes the crude oil, and therefore emit fewer GHG emissions than natural gas pipelines.
• Natural gas pipelines could reduce/eliminate GHG emissions from compressor stations that keep gas flowing over long distances & changing elevations by using to electric compressors – albeit at a cost.
• Pipeline companies are working to reduce their carbon footprint by electrifying compressor stations, improving leak detection & implementing waste heat recovery.

TMX Unannounced Fire Response Exercise Evaluation

CER EM Exercise Evaluation / Évaluation de l'exercice de gestion des urgences de la Régie de l’énergie du Canada

Activity # / Activité n^o: 2021-236
Date: 4 March 2021

Trans Mountain Pipeline ULC (TMPU)
Unannounced Fire Response Exercise Evaluation

Company: Trans Mountain Pipeline ULC (TMPU)
Location: Burnaby, British Columbia
Facility: Burnaby Terminal

Remarks

Background/Scope of Activity:

On 4 March 2021 at 16:10 PST, the Canada Energy Regulator (CER) initiated an unannounced exercise to simulate a response to a full surface crude oil tank fire at the TMPU Burnaby Terminal. The unannounced exercise was conducted in order for TMPU to fulfill the requirement detailed in the Trans Mountain Pipeline ULC (TMPU) Addendum Final Audit Report – Emergency Management (EM) Program, Fire Preparedness Planning of 31 May 2019. The requirement was for TMPU to respond to a CER fire response unannounced exercise at a time and location of the CER’s choosing within 12 months of TMPU establishing and integrating a four (4) hour response target, as described in the addendum letter:

For its Burnaby and Edmonton Terminals, TMPU must establish and integrate into all fire plans and associated planning and preparedness activities, a four (4) hour response target time to initiate extinguishment of a full surface tank fire for the largest tank at each facility.

Trans Mountain had to demonstrate that it could get the needed personnel and equipment on site and ready to extinguish a fire within four hours. This timeframe is intended to mitigate potential boil over from the tank itself. The exercise was timed to coincide with the start of rush hour traffic in the Lower Mainland as well as early evening light conditions in order to add an additional level of complexity. An unintentional complexity adding to the scenario was the rainy weather experienced during the exercise.

CER Evaluation:

Two CER staff members and one Indigenous monitor attended the exercise to observe and evaluate.

Response Management

1. CER staff observed:
   • The establishment of TMPU’s on-site command post;
   • First responder briefings, tactical planning and mustering;
   • Onsite incident and oversight activities;
   • Physical emergency response team assembly and simulated response to the full-surface tank fire, including fire response equipment deployment up to, but not including, application of water/foam to the tank surface;
   • Incident Stand-down; and
   • Post-exercise review.
2. The following key observations were made by CER staff:
   • A pre-exercise safety orientation was provided to CER staff and the Indigenous monitor. This included:
     • how to access first aid;
     • COVID-19 safety measures;
     • site emergency procedures [mustering, operational and emergency horns etc.];
     • site specific hazards;
     • heavy equipment and construction activities;
     • traffic flow/speed limit and traffic lights/signs;
     • slips trips and falls; and
     • hot work permit for taking photographs.
   • The Incident Command Post (ICP) was set up in the Maintenance Building;
   • The ICP was well organized and provided an appropriate venue for management of the incident;
   • Wall charts [201 – Fire Organization Chart, Trans Mountain Tank Fire Response Chart], wall maps [Burnaby Terminal Aerial Photo map and Burnaby Terminal Plot Plan] and information posters [tank #, tank level, burn rate, water level, heat layer, hours to boil over and time of advised evacuation] were effectively used to help inform the response;
   • Response activities observed as per Trans Mountain’s fire pre-plan and checklists;
   • A firefighting team of four firefighters was assembled by 17:32 in the Maintenance Building, with two more firefighters joining the response at 17:39 and 17:45pm and two additional firefighters arriving at 18:00 pm and 18:15pm;
   • Initial briefing to the first five firefighters was conducted at 17:39 with response directions being discussed. The briefing included:
     • summary of the scenario (timing, tank level, hours to boil over);
     • designated leader in the field;
     • safety orientation and emergency response procedures for firefighters to follow;
     • identification of a hot zone;
     • radio frequency being used for communication;
     • reconnaissance of the route to take to the impacted tank;
     • assess access en route and easiest position to set up equipment based on gas monitor readings [O2, LELs, H2S, CO and VOCs] and infrared tank level readings; and
     • firefighters were to assume worst case scenario for product in tank [i.e., product has H2S and LELs].
   • Fire equipment and firefighting team leave Maintenance Building and head to the impacted tank at 17:55;
   • Firefighters in gear with truck and equipment arrive at impacted tank at 18:14;
   • Firefighters begin connecting hoses to manifold and to fire foam cannon;
   • Equipment (pumps, hoses, etc.) deployed and ready to flow foam or water 18:39;
   • While firefighters were able to effectively and efficiently set up fire response equipment, the lighting on the upper road where equipment was being set up could have been better. However, firefighters did have personal flashlights which they did not need to use; and
   • No safety or other issues noted by CER staff either in the incident command post or during field activities.

3. CER staff and Indigenous monitor observed and participated in exercise debrief held after activities (no significant deficiencies or plan deviations noted/observed). Some of the items discussed that worked well included communication and updates from the firefighters to the ICP and vice versa was adequate and staging of equipment went well. Firefighters indicated that they worked well together in spite of the rain and night conditions. Firefighters indicated that while the existing lighting did not hamper response efforts, lighting on the upper road could be improved.
   The total response time from the initiation of the exercise to firefighters ready to apply foam/water to the tank surface was determined to be 2 hours and 28 minutes. This response time was well within the 4-hour response window established by the CER.

4. Indigenous Advisory Monitoring Committee (IAMC) Indigenous Monitor (IM) observations: Additional observations recorded by the IAMC IM participating in the CER compliance verification activity, are provided below verbatim. Any compliance related observations that require specific regulatory follow-up have been recorded above.

Indigenous Monitor (IM) completed site specific safety orientation and introductions to site staff.

Observed Trans Mountain’s (TM) command post that was set up in their Maintenance building – this included maps and charts of designated staff and responders and other relevant information.

Fire Responders arrived, were briefed on the exercise scenario/pertinent information and initiated their deployment on site.

Observed the fire responders connect hoses to manifold and fire cannon. The outdoor lighting for this activity was dark due to the early evening nightfall – fire responders had personal flashlights on their person but didn’t feel the need to use them.

The fire responders successfully completed the exercise in approximately 2 hours and 28 minutes.

TM held a debrief discussion collectively with all individuals involved – no significant deficiencies identified. A common theme of discussion was the effective communications and efficient staging of equipment.

IM has reviewed this report in its entirety and agrees with its content.

END OF REPORT.

CER’s Role in Financial Regulation

• The CER’s financial regulatory oversight mandate applies to several facets of pipelines under its jurisdiction, including:
  • evaluating economic feasibility of proposed pipelines when weighing whether a pipeline is in the public interest,
  • ensuring tolls and tariffs are just and reasonable,
  • requiring companies to have access to financial resources to cover potential costs of spills or unintended releases, and
  • requiring companies to save and set aside money for pipeline decommissioning and reclamation
• In considering whether to recommend that a new pipeline is in the public interest, a major consideration in the public interest test is the evaluation of a pipeline’s economic feasibility. The Commission evaluates whether the pipeline has commercial support and considers whether the pipeline is likely to be used and useful over its economic life. This includes consideration of commodity supply and market demand. The Commission also considers the economic benefits a pipeline could have for the Canadian economy both during construction and once in operation.
• With respect to toll regulation: since it can be more cost effective to build one pipeline system rather than many competing pipelines, facilities under CER jurisdiction often have market power and in some instances, operate as monopolies in the markets they serve. The CER’s role is to ensure that where market power exists, it is not abused and that tolls for pipeline services are just and reasonable, and non-discriminatory.
• The CER monitors how pipeline companies comply with regulatory requirements and whether they are providing services to shippers at reasonable prices (tolls). The CER monitors compliance in a variety of ways, including by: requiring regular compliance filings by companies, undertaking financial audits of companies, and soliciting shipper feedback via surveys. Parties may also file formal complaints with the CER if they are unable to resolve concerns on specific toll and tariff matters.
• Determining whether or not pipeline construction costs are reasonable (or have been prudently incurred), and the amount of costs to be included in pipeline tolls, are both subjects the Commission may consider in toll hearings.
• Although the CER conducts financial regulatory audits of companies, in accordance with the Financial Regulatory Audit Policy the audits focus more on compliance with the CER Act, verification of company financial information, examining whether cross-subsidies have occurred, and reviewing company operations. Financial regulatory audits generally don’t make findings with respect to whether tolls are just and reasonable. The CER generally conducts between 1-3 financial regulatory audits per year, and the last financial regulatory audit of Trans Mountain was conducted in 2008.

Tolls, Cost and Capacity Summary

1. Tolls and cost summary

   Tolls and cost summary

   -	Capped Costs ($Bn)	Uncapped Costs ($Bn)	Total Costs ($Bn)	Total Costs ($Bn)
   2017 CPCN Estimate	5.7	1.8	7.4	5.76
   Interim Commencement Date Estimate in Application	21.8	9.1	30.9	10.88
   Updated Estimate from December 2023	24.4	9.8	34.2	11.37

   Notes:

   • The fixed toll varies according to factors such as the destination, and the length and size of the shipper’s contract. The above toll is for the benchmark toll, which is for Edmonton to Burnaby service, for a shipper with a 15-year contract and a volume commitment under 75,000 barrels per day.
   • On top of the Fixed Toll, shippers also pay a variable toll. Currently, the variable component of the benchmark toll is $0.58/bbl, so the current total benchmark toll is $11.46/bbl ($10.88 + $0.58).
2. Tolling timeline
   • May 2013: NEB approval of toll methodology for TMX (application was June 2012)
   • December 2013: Trans Mountain filed its application for TMX
   • Q1 2017: Trans Mountain delivered the “2017 CPCN Cost Estimate” of $7.4 Bn and revised tolls to its shippers.
   • June 2023: Trans Mountain applied for approval of interim Commencement Date tolls.
   • November 2023: Commission issued Preliminary Decision approving interim Commencement Date tolls.
   • May 2025: Oral cross examination will commence in the Final Interim Tolls hearing.
   • Date TBD: Trans Mountain will apply for final tolls based on the outcome of this hearing, as well as final costs and other potential steps such as a shipper audit.
3. Capacity Information
   • Pre-expansion, capacity was about 300,000 b/d, while Expanded System will have a capacity of 890,000 b/d.
   • Pre-expansion was mostly uncommitted capacity, with the exception of some capacity to the Westridge Dock. On the Expanded System, 80% of the total capacity is now committed under long-term contracts.
   • Pre-expansion, the pipeline had a high utilization of approximately 100% of available capacity and was regularly apportioned.

Indigenous Advisory and Monitoring Committees and UNDA

Background – IAMCs:

• The Government of Canada announced its commitment to the creation of IAMCs for the Line 3 and Trans Mountain Expansion projects at the time these projects were approved, and further committed to support the IAMCs over the lifecycle of the projects (50+ years) as a sustainable mechanism for engagement with impacted Indigenous Nations, governments and communities.

IAMC Renewal:

• On April 16, 2024, the Government of Canada committed through Budget 2024 $44 million over three years for the renewal of the IAMCs for the Enbridge Line 3 Replacement (Line 3) and Trans Mountain Expansion (TMX) projects (current funding expired in March 2024).
• The renewal included resources for the CER and other federal departments for a two-year period (2024/25 – 2025/26).
• A Treasury Board Submission has been co-developed by NRCAN, the Indigenous Caucuses of both IAMCs and other federal partners, including the CER (aiming for Fall 2024 submission).

What the IAMCs do:

• Allow for Indigenous participation in project oversight, which is necessary to help ensure projects are built and operated in a manner that:
  • Respects and incorporates Indigenous peoples’ knowledge, perspectives, and the relationship Indigenous Peoples have with the land.  
  • Reflects Canada’s commitments to Indigenous Peoples; 
  • Advances best practices and improves safety and environmental outcomes; 
  • Is part of a coherent, predictable and transparent operating environment, contributing to Canada’s global competitiveness. 
• Provide for better decision-making related to the oversight of major projects, in a manner that aligns with the United Nations Declaration on the Rights of Indigenous Peoples Act (UNDA) to achieve the Government of Canada’s commitment to Reconciliation with Indigenous Peoples.
• Build Trust and Confidence in the regulatory oversight of the TMX and Line 3 projects, and by extension, in the natural resource sector and its management in Canada.
• Lead to a partnership-based approach to oversight among federal and Indigenous Committee members.
• Support Indigenous engagement and the provision of advice and recommendations, grounded in technical expertise, to federal regulatory bodies and decision-makers.
• Contribute resources to Indigenous Nations and communities to develop the capacity for the regulatory oversight of the TMX and L3 energy projects.
• Help foster a more predictable and transparent operating environment, which contributes to Canada’s global Competitiveness.

UNDA and Reconciliation

• The CER Act creates opportunities for CER to carry out its mandate in a manner that advances Reconciliation with First Nations, Métis and Inuit communities.
  • The preamble of the CER Act references the Government of Canada’s commitments to Reconciliation and the implementation of the UN Declaration on the Rights of Indigenous Peoples (UN Declaration).
  • The CER’s mandate includes an obligation for it to perform its duties and functions in a manner that respects the government’s commitments with respect to the rights of Indigenous Peoples.
  • One of the priorities in the CER’s Strategic Plan is centered around Reconciliation and Implementing the UNDA.  
  • The Government’s Action Plan provides a roadmap of measures that need to be taken to implement the UNDA. Action Plan Measure #34 involves the CER, and also NRCan.

Action Plan Measure (APM) 34

Background:

• APM 34 was co-developed by the Indigenous Caucus of the TMX-IAMC, NRCan and the CER. 
• APM 34 calls for the Government of Canada to work with in consultation and cooperation with First Nations, Métis and Inuit communities, governments, and to:
  • enhance the participation of Indigenous Peoples in; and 
  • set the measures that could enable them to exercise federal regulatory authority in respect of, projects and matters that are currently regulated by the CER.

The APM contains four components:

1. Develop regulations to allow the Minister of NRCan to enter into arrangements with Indigenous governing bodies to exercise specific powers, duties and functions related to the Canadian Energy Regulator Act.
2. Amend the CER Onshore Pipeline Regulations (OPR) and Filing Manuals in a manner that incorporates Indigenous laws, policies and knowledge and strengthens measures to prevent and address impacts to rights and interests.  
3. Develop a systemic model to enhance Indigenous Peoples’ involvement in the oversight of CER regulated infrastructure.
4. Consult and cooperate to identify and take measures needed to support Indigenous governing bodies and/or potential establishment of new decision-making institutions to exercise regulatory authority on certain projects/matters regulated by the CER.

Note: APM 34 is a shared responsibility with NRCan and collaborative work with the IAMCs on APM 34 is in its early stages.

Overall Progress to Date

• In February 2024, the TMX-IAMC Indigenous Caucus, along with the Indigenous Caucus for the Line 3 IAMC facilitated a pipe ceremony in Tsuut'ina territory to guide the implementation work required under APM 34.
• The ceremony was guided by elders and involved representatives of the Indigenous Caucuses, the CER and NRCAN.
• In addition to the pipe ceremony, participants discussed how to coordinate work required under measure 34 and engaged in preliminary strategic planning regarding the development of a leadership structure to ensure accountability in implementation.
• A leadership group composed of the Indigenous Co-Chairs of the IAMCs for Line 3 and TMX, the Executive Vice President (EVP) for Transparency and Strategic Engagement of the CER, and Assistant Deputy Minister (ADM) Nòkwewashk of NRCan has been established to oversee and lead the implementation of Action Plan Measure (APM) 34 by ensuring that the carrying out of the various identified aspects of APM 34 advances the objectives described in APM 34 of the United Nations Declaration on the Rights of Indigenous Peoples (UN Declaration) Act (UNDA) Action Plan (the Action Plan). Work is underway to co-develop a Terms of Reference to guide the work of this group.

Below is a summary of the work underway under each of the APM’s elements.

Indigenous Ministerial Arrangement Regulations (IMARs)

• NRCan is leading the work specific to developing the Indigenous Ministerial Arrangement Regulations (IMARs) that would provide the authority for the Minister to enter the arrangements called for under APM 34.

OPR & Filing Manual

• In January 2022, the CER launched a multi-year process to improve our regulatory framework for onshore pipelines and the Filing Manual.
• In June 2023, after the launch, on behalf of the Government of Canada, the Department of Justice published the UNDA and Canada's Action Plan (the Action Plan). Measure 34 of the Action Plan includes a commitment regarding consulting and cooperating with First Nation, Métis and Inuit communities, governments, and organizations to amend the OPR and FM.
• The CER launched its second phase of engagement in June 2024, focused on technical options for improvement. This engagement will help inform the development of a regulatory proposal, which will be released for feedback in Phase 3.

Systemic Model to Enhance Indigenous Peoples’ Involvement in Oversight:

• The commitment to co-develop a collaborative oversight mechanism for NGTL was made alongside the CER’s pledge to co-develop a broader, systemic model for Indigenous peoples’ involvement in compliance and oversight of new major CER-regulated projects and existing infrastructure.
• At the time, it was acknowledged that a systemic model for Indigenous involvement in CER’s regulatory oversight should incorporate learnings from the NGTL collaborative mechanism (still in co-development), from the Indigenous Advisory and Monitoring Committees for the Trans Mountain Existing Pipeline and Expansion and the Line 3 Replacement Program and seek opportunities with other federal departments and agencies.
• Later, in 2023, the CER continued to demonstrate a steadfast commitment to its goal of codeveloping a systemic model by including language in Action Plan Measure 34:
  [The CER will] Develop a systemic model to enhance Indigenous peoples’ involvement in compliance and oversight over the lifecycle (design, construction, operation and abandonment) of CER-regulated infrastructure. The model should integrate learnings from existing structures and relationships].
• Learnings from IOF engagement will be incorporated into analysis and recommendations for APM 34, including but not limited to Element 3 (systemic model of compliance and oversight). These learnings will be drawn from a comprehensive analysis of engagement session meeting notes and the summary report, as well as direct input from CER staff involved in IOF work.
• At this stage it is too early to tell what the systemic model will be.
• We acknowledge the incredible amount of work and the long journey that is still before us. For example, we have yet to imagine how the NGTL, IAMC-TMX, and Line 3 IAMC will collectively shape the CER’s systemic model for Indigenous oversight.
• One thing we know for certain is that these mechanisms are keystones for success. Together, the Indigenous oversight bodies for NGTL, Line 3 and TMX represent and will provide Indigenous oversight for approximately 37% of the pipelines we regulate in Canada. It’s a start.

Decision Making Authorities:

• Work has yet to commence.

Free, Prior and Informed Consent

• The UN Declaration includes an article which imposes an obligation on the state to consult and cooperate in order to obtain FPIC from Indigenous Peoples prior to approving a project affecting their lands, territories, or resources.
• The Government of Canada has stated that meaningful engagement with Indigenous Peoples aims to secure their FPIC when Canada proposes to take actions that impact them and their rights, including their lands, territories, and resources.
• The Commission of the CER has stated that it understands the concept of FPIC is focused on parties working together in partnership and respect, and striving to achieve consensus in good faith regarding decisions that may impact the rights and interests of Indigenous Peoples.
• The Commission has also stated that it does not consider that the concept of FPIC, as articulated through the UN Declaration, to be a direct legal requirement in Canada. However, the core elements of FPIC are best practices.

Crown Consultation – General Messages

• The CER is an agent of the Crown established under section 10 (2) the CER Act
• The CER’s intent is to fulfill the Crown’s duty to consult through the Commission’s regulatory process as much as possible.
• All relevant issues and concerns brought forward by Indigenous Peoples will be considered by the Commission with the intent that issues and concerns will be mitigated, or where necessary accommodated, to the extent possible.
• For certain applications, including those that require a GIC decision (e.g., a section 183 application), the CER will act as the federal Crown Consultation Coordinator (CCC) and conduct supplemental consultations with Indigenous communities before, during, and after the Commission’s hearing process.
• During the Commission’s hearing process, the Crown Consultation Coordinator will typically file submissions, which may include recommendations, for the Commission’s consideration.
• The Crown Consultation Coordinator encourages Indigenous communities to participate directly in the hearing process.
• The Crown Consultation Coordinator seeks to work collaboratively with proponents throughout the regulatory process, including inviting proponents to consultation meetings, sharing questions/concerns for consideration and response and sharing relevant portions of its submissions to the proponent to review/validate the accuracy of the information (e.g., meetings with communities).

Crown Consultation: Where We Are Now

• Since the CER Act came into force in 2019, the Crown Consultation Coordinator has conducted supplemental consultation on two section 183 projects.
• The consultations were completed without extension to timelines on the most recent of these, Northriver NEBC Connector, for the first time since 2015. In addition, there has not been any litigation. This all supports competitiveness and predictability.
• The Crown Consultation Coordinator is currently conducting supplemental consultation on two section 183 projects, Pouce Coupé’s Taylor to Gordondale and Westcoast Energy’s Sunrise Expansion Program.

Role of the Commission

The Commission is responsible for adjudicative decisions and operates as a quasi-judicial body that is at arm’s length from other branches of the CER’s governance structure as well as from and the Government of Canada.

• The Commission is part of the CER and, although its adjudicative role is independent, it contributes to the overall effective delivery of the CER’s mandate, the CER’s Strategic Priorities, and corporate outcomes, where applicable.
• The Commission renders decisions pursuant to its mandate as set out in the CER Act and other legislation.
  • In its adjudicative role, it adheres to the purpose and provisions of the CER Act, while recognizing and respecting the rights of Indigenous Peoples protected by section 35 of the Constitution Act, 1982.
  • The Commission adheres to the requirements found in Part III of the Official Languages Act, as well as the rules of natural justice and relevant jurisprudence.
• Predictability of the timeliness of application decisions is a key component of the competitiveness of the regulatory framework. In the 2022-2023 year, the Commission met all time limits for completion of its assessments and its recommendations or decisions.

CER Stats

Mandate

• The CER’s mandate is set out in the CER Act, which came into force in 2019.
• The CER oversees ~71,000 km of federally regulated pipelines from project design to end of life to ensure the safe and efficient delivery of energy to Canada and the world. We also regulate ~1,500 km of power lines crossing the Canada – US border.
• We have an important economic regulatory role with respect to pipeline tolls and tariffs, as well as energy exports.
• Alongside our regulatory functions, the CER has an energy information mandate to provide data and analysis to Canadians that informs decision-making and the energy dialogue in Canada. This includes fully modeling net-zero GHG emissions by 2050 in our Canada’s Energy Future series.
• Our mandate is set out for us in the Canadian Energy Regulator Act, which came into force in 2019 and replaced the National Energy Board with the Canada Energy Regulator.

Strategic Plan

• The CER’s Strategic Plan has three parts:
  • Our Mission is what we do every day under the CER Act
  • Our Vision sets a clear path for where we are headed
  • Our four interconnected Strategic Priorities reflect areas of cross-organizational focus and improvement to help us better deliver on our Mission and reach out Vision.
• Mission - We 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. We recognize and respect the inherent and constitutionally protected rights of First Nations, Inuit and Métis. We provide energy information and analysis that informs and supports Canada’s transition towards a net zero future.
• Vision - The Canada Energy Regulator (CER) is a recognized leader in the regulation of energy infrastructure. We enable safe, reliable, competitive and environmentally sustainable energy transmission. We have the confidence of Canadians and we uphold the inherent and constitutionally protected rights of First Nations, Inuit and Métis. Our commitment to regulatory excellence enhances Canada’s global competitiveness.
• Strategic Priorities:
  • Trust and Confidence: We foster the trust and confidence of Canadians by effectively delivering on our mission with safety at the forefront. We engage and empower our diverse workforce. We strengthen relationships that uphold the rights and interests of First Nations, Inuit and Métis, and we communicate transparently and engage meaningfully with all our stakeholders.
  • Reconciliation and Implementing the UN Declaration: We are implementing the United Nations (UN) Declaration on the Rights of Indigenous Peoples (UN Declaration) and delivering on the commitments made in the UN Declaration Act Action Plan. We do so based on the recognition of rights, respect, co- operation and partnership, by working together with First Nations, Inuit and Métis governments, communities, and organizations. We continue to build the cultural intelligence of the CER.
  • Competitiveness and Regulatory Excellence: We enhance Canada’s global competitiveness through leadership in regulatory innovation and best practices, focusing on cost effectiveness, transparency, predictability, timeliness and efficiency of regulatory processes.
  • Preparing for the Energy Future: We inform the energy transition by offering expertise and insight as the energy system transitions to a net zero economy across Canada. We focus on energy innovation, security, competitiveness, and safe and reliable energy transmission infrastructure that is resilient to the effects of climate change.

CER Energy Information Program

• With the increasing pace of change in Canadian and global energy markets and climate policy, the need for up-to-date analysis of energy trends is needed more than ever.
• We produce timely, fact-based, and relevant energy analysis to inform the energy conversation in Canada.
• Our goal is to produce informative products for a diverse audience and reflect the diversity of relevant energy issues in Canada in an engaging and transparent way.
• Our Energy Information program, which includes the flagship publication Canada’s Energy Future, is one of our four core responsibilities at the CER.
• Canada’s Energy Future series has also been expanded to include modelling consistent with Canada’s commitment to achieve net-zero by 2050, as requested by the Honourable Wilkinson, Minister of Natural Resources, in December 2021.

Annual Budget

• In Budget 2023, the government committed to reducing spending by $14.1 billion over the next five years, starting in 2023–24, and by $4.1 billion annually after that.
• As part of meeting this commitment, the CER is planning the following spending reductions.
  • 2024–25: $2,859,000
  • 2025–26: $3,763,000
  • 2026–27 and after: $5,000,000
• The following is the 2024–25 spending by core responsibility and internal services:
  • Energy Adjudication: $28,730,875 (25.79%)
  • Safety and Environment Oversight: $22,962,958 (20.61%)
  • Energy Information: $6,780,584 (6.09%)
  • Engagement: $9,187,376 (8.25%)
  • Internal Services: $43,731,861 (39.26%)

Cost Recovery

• The Canada Energy Regulator (CER) is funded through Parliamentary appropriations.
• The Government of Canada currently recovers approximately 99 per cent of the appropriation from the industry the CER regulates.
• As per the CER Act, recovered costs must be attributable to the carrying out of the CER’s mandate.
• The National Energy Board Cost Recovery Regulations (Regulations) set out which costs the CER recovers and the manner in which money is recovered.
• The CER consults with regulated companies with respect to cost recovery through a Cost Recovery Liaison Committee which is comprised of industry and government representatives.

Staff

• More than 500 CER staff across Canada work every day on behalf of Canadians to ensure that the energy infrastructure we regulate is designed and operated with the highest standards. Our team is made up of specialists who love the work they do. They include:
  • engineers
  • scientists
  • auditors
  • inspectors
  • socio-economic specialists
  • lawyers
  • economists

Date modified:

2025-01-08