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Canadian Energy Oil and Gas: Top Regulatory Decisions and Developments in 2019

This year witnessed some dramatic events in the energy regulatory world. Since our review of the major 2018 regulatory developments, significant progress has been made on the Trans Mountain Expansion Project (the Project). Not only has the National Energy Board (NEB) and federal cabinet re-approved the project, but the Supreme Court of Canada has dismissed British Columbia’s attempt to regulate interprovincial heavy oil transportation. These developments have paved the way for construction and clarified important principles underpinning federal-provincial regulatory jurisdiction.

There were also major developments in Alberta’s electricity market, with the new government’s commitment to return to an energy only electricity market and the Alberta Court of Appeal denial of several appeals from the Alberta Utilities Commission (UAC) relating to electricity line loss. The AUC also confirmed the post Stores Block and utility asset disposition (UAD) principles related to stranded assets, but also prompted a discussion about the framework’s “possible deleterious effects” while calling for “debate on the evolution of public utility regulation in Alberta.”

In response to the growing public focus on reclamation and clean up of oil and gas sites, the British Columbia government recently enacted the Dormancy and Shutdown Regulation, which creates mandatory timelines for decommissioning dormant well sites.

On the international stage, Canada and the United States inched closer to ratifying the Canada-United States-Mexico Agreement, which will usher in important changes to NAFTA’s Chapter 11 dispute resolution mechanism. These changes will have important implications for how certain North American energy disputes are resolved.

In this article, we review these and other regulatory developments important to the Canadian energy industry from the previous year.

1. NEB reapproves TMX project and SCC dismisses BC’s bid to regulate interprovincial heavy oil transportation

The Project witnessed several significant and promising advances in 2019. In 2018 the Project was fraught with seemingly insurmountable political, legal, and financial risk, including the Federal Court of Appeal’s decision in Tsleil-Waututh Nation v. Canada (Attorney General),1 British Columbia’s attempt to regulate interprovincial heavy oil transportation, and the federal government’s eventual purchase of the Project.2

The Project now has a far brighter outlook and has reached a number of key milestones. On February 22, 2019, the NEB released its reconsideration report, recommending that the Project proceed with 16 new recommendations aimed at mitigating the environmental impacts of marine shipping. Shortly thereafter, cabinet accepted the NEB’s recommendation and approved the Project.3

Additionally, in May 2019, the British Columbia Court of Appeal issued its reference opinion concerning BC’s proposed amendments to its Environmental Management Act.4 A unanimous five-member panel of the Court of Appeal held that the proposed amendments were outside of provincial jurisdiction as they primarily focused on a federal interprovincial undertaking.5 On January 16, 2020, the Supreme Court of Canada unanimously dismissed BC’s appeal of the reference, reaffirming the BCCA’s decision. This unanimous decision provided much-needed legal clarity on federal-provincial energy jurisdiction and removed a major potential hurdle for the completion of the Project.

Since construction of the Project officially began on December 3, 2019,6 the Project’s approval is still subject to several Federal Court appeals based on whether the Crown failed to discharge its duty to consult in the re-approval of the Project.7 A decision on these appeals has not yet been rendered.

While litigation and financial risk are still present, the Project is now in a much more stable and promising position.

2. NEB releases jurisdiction decision on coastal GasLink pipeline project

On July 26, 2019, the NEB released its decision concerning the Coastal GasLink Pipeline Project (CGL Pipeline). It ruled that the CGL Pipeline, including the LNG Export Terminal under development in Kitimat, is properly under provincial jurisdiction.

The proceeding before the NEB did not address whether the CGL Pipeline should be approved, whether it is in the public interest, or what the environmental, economic, and indigenous impacts are. Instead, the board was solely focused on assessing whether the CGL Pipeline is a local undertaking, which the province of BC should have jurisdiction over, or whether it is part of, or integral to, larger interprovincial work under exclusive federal jurisdiction.

The decision comes on the heels of several high profile, energy related division of power disputes between the provinces and the federal government and reaffirms traditional division of powers principles between the federal and provincial governments. Although a project may have interprovincial implications, such as CGL's ability to export LNG to international markets, those implications alone will not create federal jurisdiction over the entire project.8

3. Canadian energy regulator halts Enbridge mainline open season

In an unprecedented decision released on September 27, 2019, the Commission of the Canada Energy Regulator (Commission) concluded that the commercial open season bidding process (Open Season) initiated by Enbridge Pipelines Inc. (Enbridge) for contracted transportation capacity on its Mainline pipeline system could not move forward without prior approval from the Commission of the tolls, terms, and conditions of service being offered by Enbridge.

Enbridge’s Open Season had formally commenced on August 2, 2019, with bidding to remain open until October 2, 2019. Enbridge proposed to offer up to 90 per cent of the existing oil and liquids capacity on the Mainline, which has historically operated as a common carrier pipeline without any capacity reserved for contracted service.

The proposed shift from common carriage to firm contracted service raised concerns among numerous shippers on the Mainline. Suncor Energy Inc., Shell Canada Limited, Canadian Natural Resources Limited, and the Exploration and Producers Association of Canada, on behalf of its members, filed formal complaints and letters between August 23 and 26, 2019.

The submissions focused on the dependence of western Canadian oil producers upon access to transportation capacity on the Mainline, in light of the Mainline’s unique position as the primary mode of transportation (representing about 70 per cent of total capacity) to refining and export markets from western Canada. Certain shippers argued that there was an imbalance of market power between Enbridge and its shippers. They would have no choice but to accept the terms of contract service offered by Enbridge in order for the shippers to ensure that they would have enough transportation capacity to continue moving their product to market and the ability to fulfill their existing downstream obligations. Otherwise, the submissions argued that shippers who did not accept Enbridge’s offer and elected not to participate in the Open Season risked losing access to the Mainline entirely, as they would need to rely on the 10 per cent of capacity reserved for common carriage, in circumstances of existing over-demand and significant apportionment of capacity allocation between shippers. To prevent this exercise of market power, it was argued that there must be regulatory oversight and approval of the tolls, terms, and conditions of any contract service on the Mainline before it is offered to shippers.

The Commission ultimately agreed with the submissions that the Open Season represented an exercise of market power. The Commission acknowledged that the former NEB had never before intervened in a commercial open season process, and ordinarily only evaluated the tolls, terms, and conditions of service after an open season had concluded  after the pipeline had made its formal application for approval of the new service. However, the Commission found that a constellation of factors unique to the Mainline warranted intervention in this case.

4. Alberta returns to energy only electricity market

On July 26, 2019, Alberta's newly formed government announced its intention to return to an energy-only electricity market. The announcement marks the end of the previous government's multi-year transition of the electricity-generation sector to a capacity market model. The reversal comes as part of a broader public policy shift away from the previous government's focus on its Climate Action Plan, which included a phase-out of coal and subsidies for renewable electricity generation.

The previous government’s Climate Action Plan attempted to introduce an electricity market that relied heavily on renewable generators. However, concerns were raised relating to the intermittent nature of renewable electricity generators and their potential inability to respond in periods of high demand. To meet high demand, the market would still require conventional electricity sources to fill in where renewables were insufficient. If renewables were to take a significant amount of the market space, however, conventional sources would be dis-incentivized to maintain capacity for high demand. In 2016, Alberta Electric System Operator (AESO) responded to such concerns by recommending a quick transition to a capacity market.

However, following the recent change in government, and a review of the capacity market, the Alberta Ministry of Energy announced that Alberta would be returning to its energy-only market and legislative and regulatory reversals would follow shortly. These moves aligned with other related policy shifts including the cancellation of the carbon tax and the Renewable Energy Program.

Uncertainty remains with respect to this policy reversal and it is unclear what changes will be codified in the previous government’s Bill 13. All eyes will be on both the provincial government's approach to legislative repeal, and the federal government's legislated phase-out of coal-powered generation.9

5. Alberta Court of Appeal denies leave to appeal the AUC's decisions in the electricity line loss saga

Justice Brian O’Ferrall of the Alberta Court of Appeal recently issued three decisions denying permission to appeal (PTA) applications in respect of decisions of the AUC in Proceeding 790 relating to the Milner Power line loss dispute.10 These decisions are significant as they highlight the high level of deference shown by the courts towards the Commission in the context of PTA applications.

Section 29 of the Alberta Utilities Commission Act provides that an appeal lie from a decision of the Commission to the Court of Appeal “on a question of jurisdiction or on a question of law”. Additionally, the Court has also required applicants for PTA to demonstrate that their question raises a “serious, arguable point”.11 This requirement is not found in the legislation, but is imposed by the Court itself as a “gatekeeping” test that allows a motions judge to decide whether a given question of law or jurisdiction merits the Court’s attention in a full appeal.12

In the CPC, Milner and ENMAX decisions, Justice O’Ferrall adopts a novel approach to the “gatekeeping” test. While he recognizes the significance of the legal or jurisdictional question is an important consideration in whether to grant the PTA, he also states that some questions of law or jurisdiction are best answered by regulators, and not by the Court. For instance, he writes “[T]here are some questions of regulatory law and jurisdiction which this Court is not uniquely suited to answer. That is, it is sometimes preferable to have the regulators resolve their own controversial questions of regulatory law and/or jurisdiction themselves.” Indeed, Justice O’Ferrall restates the “test” for PTA as “whether there is a question of law or jurisdiction which, for some good reason, perhaps because of its importance, requires an answer from the Court of Appeal, keeping in mind that there are some questions of law or jurisdiction which are better left to the Commission to decide or resolve over time.”

The suggestion that the Court could leave certain questions of law or jurisdiction to the Commission is an expression of judicial deference. Participants in regulated industries are familiar with the concept of deference, according to which an appellate court will not automatically substitute its own view for that of an expert tribunal, where the tribunal is interpreting its enabling statutes or in respect of matters that engage the tribunal’s particular expertise. Under the established approach, this concept is expressed through the court’s selection of the standard of review applicable to a given issue: rather than reviewing the tribunal’s decision for its legal “correctness”, in situations where deference is appropriate the court may instead apply the lower standard of “reasonableness”. Justice O’Ferrall’s view that “there are some questions of law or jurisdiction which are better left to the Commission to decide or resolve over time” appears to extend of the concept of deference significantly beyond the appropriate standard of review. Rather than effectively according the Commission the benefit of the doubt after a full hearing and analysis of the issues, as contemplated by the traditional approach to deference, Justice O’Ferrall would have the Court refuse entirely to consider certain questions, on the basis of a single judge’s assessment at the PTA stage, of whether or not a given question is “better left to the Commission”. This, conceptually, is a pre-emptive deference standard.

Justice O’Ferrall’s approach to deference in the Milner cases is arguably inconsistent with the SCC’s subsequent decision in Canada (Minister of Citizenship and Immigration) v. Vavilov.13 The Vavilov framework presumes that the applicable standard of review is reasonableness, except where the legislative intent indicates otherwise. After Vavilov, legislation that provides a statutory right of appeal is to be interpreted as requiring the reviewing court to apply appellate standards of review. Thus, if the question being appealed is a question of law, including questions of statutory interpretation and those concerning the scope of a decision maker’s authority, the appeal is to be reviewed on a correctness standard.

Section 29 of the AUC Act provides a statutory right of appeal on questions of law or jurisdiction. Unlike the deferential approach to appeals under this section promulgated by Justice O’Ferrall in the Milner PTA decisions, Vavilov appears to require the Court to apply a correctness standard. Litigants in the energy regulatory sphere will look forward with interest to the Court of Appeal’s post-Vavilov interpretation of section 29.

6. The Provost and Fincastle proceedings — developing issues on AESO and DFO roles in SASR-driven NID applications

The AUC recent decisions in Provost14 and Fincastle15 underscore interesting and developing issues with respect to system access service request (SASR) driven Needs Identification Document (NID) applications and the role of AESO in assessing the system need when it is requested by the distribution facility owner (DFO).

In both cases, the AUC assessed the NID application submitted by an existing DFO in the context of a SASR. While various topics of interest were discussed in both decisions, a notable tension arose between AUC Vice Chair Anne Michaud and the other Commission members (the Majority). In both cases, Vice Chair Michaud took issue with whether a proper assessment of the public interest was conducted given that the DFO themselves submitted the NID. Vice Chair Michaud was of the view that what is in the best interest of the DFO as outlined in their SASR request may not perfectly align with a dispassionate assessment of the public interest.

As such, and as it is AESO’s responsibility to assess the reasonableness of the changes in system access, Vice Chair Michaud took the position that if the AESO did not make an assessment of the reasonableness of the request, no public interest assessment had taken place. Accordingly, as stated at paragraph 313 of the Provost Decision, she would have sent the NID requests back to the AESO, requesting that: 

“the NID application incorporates an analysis of the need for the project that includes a weighing of the expected increase in reliability against the potential impacts of the project, having regard for the fact that the AESO is not required in all circumstances to respond to a SASR with a proposed transmission solution.”

On the contrary, the Majority concluded that the:

“[g]iven the legislated obligations of a DFO, the AESO is entitled to rely on a DFO to provide information about its distribution system in the course of developing a NID. The majority finds that this is an acceptable and necessary practice, in keeping with the parties’ duties under the legislative scheme. The majority agrees with the AESO’s statements that it does not have the mandate, expertise or information necessary to plan the distribution system, and the majority finds that a certain level of reliance upon DFOs is therefore required.”

While the applications were approved, the difference in opinion between Vice Chair Michaud and the Majority highlights the implicit tension between the general public interest in increasing system reliability, and the specific private interest of DFOs to expand operations. The Commission touched on this, addressing the need for all industry players to weigh in through a possible generic proceeding to discuss:

“distribution planning criteria for reliability with all stakeholders to examine DFO reliability planning criteria including, for example, the merits of probabilistic versus deterministic criteria for N-1 contingencies and the social, economic and environmental impacts to customers.”

It remains to be seen whether the AUC will commence a generic proceeding to address these issues. However, if one is commenced, the Majority has suggested that depending on its outcome, it may lead to significant changes to the regulatory landscape including potential changes to the NID applications from the AESO under the current Rule 007: Applications for Power Plants, Substations, Transmission Lines, Industrial System Designations and Hydro Developments. BLG will follow this development as it unfolds.

7. AUC and EPCOR Water Services Inc. — uncertainty in the application of market rules for self-generators

On February 20, 2019, the AUC approved an application by EPCOR Water Services Inc. (EPCOR) under the Hydro and Electric Energy Act (HEEA) to construct and operate a 45,000 panel, 12 MW solar power plant at its EL Smith water treatment plant in Edmonton’s North Saskatchewan Valley (the Solar Plant). The Solar Plant will provide electricity for EPCOR’s water treatment plant, which will use approximately 70per cent of the Solar Plant’s generation, with the remaining 30 per cent to be exported from the site and sold into Alberta’s wholesale electricity market. Various environmental, zoning, and community considerations arose, with the Commission finding that they were properly mitigated, or in any event, in the public interest. Ultimately, it was EPCOR’s request to interconnect the power plant (Connection Application) to the Alberta Interconnected Electric System (AIES) that had the surprising potential to influence both past and future owners of on-site generation in Alberta.

EPCOR’s connection application

By way of background, sections 18(2) and 101(1) of the Electric Utilities Act require all electricity entering or leaving the AIES to be exchanged through the Power Pool of Alberta (Must Offer Rule), and for persons to only obtain electricity through the electric distribution utility holding the service area in which the person’s site is located. Exemptions for self-generated electricity exist for those intending to use it privately. EPCOR applied for authorization to be exempted under Section 2(1)(b) of the EUA which states that the EUA does not apply to “electric energy produced on property of which a person is the owner or a tenant, and consumed solely by that person and solely on that property.”

EPCOR took the position that Section 2(1)(b) effectively creates an exemption for the portion of electricity that was to be consumed on site (70 per cent of generation in this case).Also, that there were no restrictions in the legislation that would preclude the export and sale into the wholesale market of the excess generation (30 per cent in this case). The Commission disagreed, and held that Section 2(1)(b), read in the context of the full scheme of the legislation, does not allow both consumption and export of on-site generation (Hybrid Arrangements). The Commission held that for the 2(1)(b) exemption to apply, all electricity generated from the plant had to be consumed on site.

In reaching its conclusion, the Commission considered Section 2(1)(b) in the context of Sections 18(2) and 101(1) of the EUA, Section 13 of the HEEA, Section 6 of the Isolated Generating Units and Customer Choice Regulation, and Section 2(f) of the Fair, Efficient and Open Competition Regulation.The Commission also considered the specific mechanisms in place in the legislative scheme that would allow for Hybrid Arrangements, such as an industrial system designation (ISD) under Section 4 of the HEEA and Section 117 of the EUA and microgeneration under Section 99 of the EUA and the Micro-generation Regulation. Overall, the Commission held that the legislation creates a statutory framework that “reflect[s] the ‘closed loop’ nature of a self- supply arrangement”. As such, self supply from on-site generation is permitted, but the export of excess generation onto the grid will not be permitted under Section 2(1)(b). ;

Hybrid arrangements achieved through alternative means

Referencing the availability of other mechanisms that would allow for Hybrid Arrangements (e.g., ISDs and microgeneration), the Commission ultimately held that while EPCOR could not rely on the exemption in Section 2(1)(b), there were likely means available to EPCOR to comply with the EUA. As such, the Commission granted the connection order on the condition that EPCOR file a compliance statement outlining how it would comply with the legislative framework. EPCOR ultimately relied on mechanisms provided in the Municipal Own Use Generation Regulation to satisfy this condition.

Uncertainty for previous applicants

However, the Commission noted that because Section 2(1)(b) does not allow for Hybrid Arrangements, and given that previous Hybrid Arrangement applications had been previously approved by the Commission for other proponents of on-site generation under Section 2(1)(b), issues may arise for existing generators who are both self-consuming and exporting from their sites. More specifically, owners of on-site generation who are employing Hybrid Arrangements could be offside the legislative framework given the Commission’s findings in this decision. The Commission stated that it “cannot address those ramification within the scope of this proceeding”.

Given this finding, on September 13, 2019 the AUC released a bulletin requesting input from stakeholders on whether legislative amendments are required to address the issue, and if so, whether amendments should allow for limited or unlimited self-supply and export. On January 9, 2020, the AUC followed up with a second bulletin, outlining the feedback received and asking for clarification. One notable argument raised against increasing self-supply and export is the likelihood of market signal distortion due to various small-scale exporters not adjusting generation according to supply or demand. Notably, while the majority of submissions supported unlimited self-supply and export, submissions were divided on the issue of cost apportionment. The primary concern of those pushing for carefully considered new or altered tariff treatment for self-supply exporters are couched in the concern that those connected to the grid must shoulder a fair amount of the cost of maintaining it. The AUC has requested submissions responding to both the arguments against unlimited self-supply and export, and the grid tariff issue. Submissions are due on February 14, 2020.

8. AUC confirms UAD approach in Fort McMurray wildfire decisions, but calls for debate

Three decisions relating to utility assets destroyed in the 2016 Fort McMurray wildfire confirmed the Commission’s interpretation of its UAD framework, but also prompted comments from the Commission on the framework’s “possible deleterious effects” and calls for “debate on the evolution of public utility regulation in Alberta”. Commissioner Lyttle propounded an alternative approach to the UAD framework that focused on the continued need for lost assets rather than the fact and circumstances of the loss.

In Decisions 21608-D01-2018 and 22742-D02-2019, the Commission approved ATCO Gas’ and ATCO Electric Transmission’s applications to recover $1.2 million and $0.7 million, respectively, representing the undepreciated net book value of assets destroyed in the Fort McMurray wildfire. However, in Decision 21609-D01-2019, the Commission denied ATCO Electric Distribution’s application to recover $3.2 million of net book value associated with assets destroyed in the same wildfire. In all three cases the Commission (in Decision 22742-D02-2019, the majority) applied its established approach to the UAD framework, and approved or disallowed recovery of each utility’s undepreciated capital costs based on whether similar losses had previously been experienced by the utility and reflected in the utility’s depreciation study.

The $3.2 million ATCO Electric Distribution disallowance was among the largest UAD disallowances to date, second only to the Commission’s 2018 denial of $9 million in undepreciated capital costs relating to EPCOR Distribution & Transmission Inc. obsolete energy meters.16 In both of the ATCO Electric decisions, the Commission acknowledged concerns with the UAD framework, commenting that while it was not in the interests of utilities to risk having prudently-incurred costs disallowed, nor was it in the interests of customers to bear the consequences of that risk (such as higher rates or compromised service quality).17 The Commission related these concerns to the “deleterious effects” of the UAD policy on the regulation of utilities in Alberta alluded to by the Court of Appeal in its judgment denying utilities’ appeal of the UAD decision.18

In the ATCO Electric Transmission decision, Commissioner Lyttle, though concurring with the majority that the utility should recover its undepreciated costs related to the destroyed assets, questioned the public policy justification of the traditional analysis. Determining a utility’s entitlement based on the similarity of the retirement event to previous events considered in the utility’s depreciation studies, in his view, resulted in inconsistent regulatory treatment of utilities and could eventually lead to customers bearing disproportionate risk. Instead, Commissioner Lyttle looked to the continued need for the facilities. In his view, “to assign the loss to the account of shareholders, as detailed in the UAD decision, the event would have had to also eliminate or alter the need to provide the service, not just destroy the individual components of the electricity delivery mechanism”. As long as the need for the destroyed assets remained, then the capital costs of those assets should continue to be recovered from customers.19

Although the Commission’s comments on the potential “deleterious effects” of the UAD policy and Commissioner Lyttle’s proposed alternative approach to UAD issues contribute to existing uncertainty in the area, the Commission’s expressed expectation that its comments “will encourage debate on the evolution of public utility regulation in Alberta”20 suggests that its approach to this difficult question may be evolving.

9. British Columbia introduces oil and gas site remediation timelines

British Columbia has responded to the growing public focus on reclamation and clean up of oil and gas sites through its recent enactment of the Dormancy and Shutdown Regulation, BC Reg 112/2019 (the Regulation). Enacted under the Oil and Gas Activities Act, SBC 2008, c 36 on May 31, 2019, the Regulation creates immediately applicable, mandatory timelines, for decommissioning dormant well sites.

In conjunction with the Regulation, the British Columbia Oil and Gas Commission (the Commission), also introduced the Comprehensive Liability Management Plan (CLMP) which provides colour to the regulation. The policy objectives of BC’s new regulatory regime can be generally summarized as being focussed on ensuring industry is held accountable for clean up costs, that BC is a leader in reclamation, that collaboration with indigenous communities takes place and that reclamation costs are addressed ex ante.

The new framework aims to require closure of all currently inactive sites by 2036 and to ensure that 100 per cent of the costs for site cleanup and closure are covered by the oil and gas industry. This will be achieved by requiring all dormant well sites to be decommissioned, assessed and restored within various timeframes following dormancy. To avoid a finding of dormancy, producers must demonstrate that production or injection occurred for more than 720 hours in a calendar year, a zone was completed, a drilling event occurred, or an observation well was active for at least one day.

The Regulation applies a gradual phase in of the framework, which focuses on ensuring that any wells found to be dormant after 2024 will be restored within 10 years. The framework operates as follows:


Dormancy Finding

Decommission Deadline

Assessment Deadline

Restoration Deadline


Up to Dec 31, 2018

30 per cent by Dec 31, 2021
70 per cent by Dec 31, 2026
100 per cent by Dec 31, 2031

- Decommissioned before Jan 1, 2020: by Dec 31, 2030.
- Otherwise, 2 years from decommissioning

40 per cent by end of 2024
70 per cent by end of 2030
100 per cent by end of 2036


2019 – 2023

8 years

2 years from decommissioning

13 years from dormancy


2024 and on

5 years

2 years from decommissioning

10 years from dormancy

Certain provisions also exist that allow the Commission to expedite certain sites for public interest reasons.

British Columbia has taken an aggressive approach to shifting its regulatory policy towards a more stringent decommissioning regime, making itself the first province in Western Canada to do so. BLG will follow the implementation and application of the framework as it unfolds.

10. Notable changes for oil and gas investors under the Canada-United States-Mexico agreement

On November 30, 2018, Canada, the United States and Mexico signed the new Canada-United States-Mexico Agreement (CUSMA or Agreement). The Agreement is moving through domestic ratification channels with the United States Senate recently approving the Agreement in January 2020. Canada is also currently in the process of approving the CUSMA. Mexico approved the Agreement in 2019.

Canada is pitching CUSMA as a substantial improvement to the Agreement’s predecessor, including revisions to state-to-state dispute settlement, labour protection, environmental protection, intellectual property, and automotive rules of origin. Our colleagues have highlighted some of these key provisions in a previous article.

Changes to NAFTA’s Chapter 11 are of particular interest to the energy industry as it allows investors in Mexico, United States, and Canada to initiate binding arbitration proceedings against a party government where certain obligations to treat investors under Chapter 11 are breached. The mechanism, known as the investor-state dispute settlement (ISDS), is designed to encourage foreign investment by providing an avenue to settle investor-state trade and investment disputes.

The new Agreement removes Canada from the ISDS scheme. What remains are bilateral mechanisms including the NAFTA-like ISDS mechanism in the Comprehensive and Progressive Agreement for Trans-Pacific Partnership between Canada and Mexico, a heavily altered ISDS agreement between Mexico and the United States, and no investor-state mechanisms outside of domestic law between the United States and Canada. It should be noted that the ISDS is preserved for a three-year phase out period under the new Agreement.

Interestingly, reportedly underpinning this shift between Canada and United States were two unintentionally aligned positions. First, the United States took the position that the mechanism supported outsourcing of jobs and investments, which is best understood in the context of a developing general aversion to binding international dispute settlement mechanisms and the rise of protectionist trade policies. Second, Canada, perhaps bruised by its own unsuccessful track record with the mechanism, reportedly doubted the effectiveness of its application.

The most pressing impact is the now de facto requirement for investors with potential ISDS challenges to commence their claims prior to the earlier noted three-year expiry period. Certainly, there have been notable cases that have led to some success, and given the imminent loss of the ISDS mechanism, fewer options to push back against discriminatory state action will exist. From a strategic perspective, it may be difficult to assess the value of commencing a claim with the ISDS’s imminent extinction.

On the one hand, despite the United States’ perfect track record of dismissals, the mechanisms have still been used by the oil and gas industry. Consider, for example, the $15-billion NAFTA investor claim initiated by TransCanada Corporation in 2016 after former President Barack Obama rejected its application for a presidential permit to approve the construction of Keystone XL in the United States. TransCanada argued that the rejection was politically motivated and in breach of the United States' NAFTA commitment to protect Canadian investments with respect to national treatment, most-favoured-nation treatment, minimum standard of treatment, and expropriation. TransCanada's claim was withdrawn after President Trump reversed the decision and issued a presidential permit authorizing the construction of the project.

North of the border, the proceedings have largely been successful. For instance, in 2015, ExxonMobil and Murphy Oil successfully claimed for damages against the government of Canada. The claim was argued on the basis that requirements imposed by Canada and Newfoundland and Labrador for corporate payment of research and training fees based on offshore revenues constituted performance requirements contrary to NAFTA. More recently, Lone Pine Resources brought a $250-million NAFTA claim against the government of Canada after Quebec introduced a moratorium on fracking under the St. Lawrence River.

Further, investors from other natural resource sectors have also brought claims under Chapter 11. For example, in 2011, American forestry company AbitibiBowater Inc. (now Resolute Forest Products) obtained a $130-million settlement against Canada for Newfoundland and Labrador's expropriation of its water and timber rights, and hydroelectric generation facilities.

The elimination of the ISDS between Canada and the United States leaves investors only domestic law when searching for remedies. It should be noted that due to USMCA’s exclusively state-to-state remedies between Canada and the USA, the only remaining recourse for enforcing private investor rights through the USMCA is to have a host state take on the private investor’s cause.

Domestically, an article recently written by our colleagues outlining Canada's recognition of the common law cause of action for de facto or disguised expropriation may be notable to investors in Canada. Relying on this common law cause may be one of the potential domestic claims that investors seek against the government of Canada.  Disguised expropriation will remain available as a form of recourse through local courts and has been used previously to compensate interest holders for the effective expropriation of those interests by government actions.  For instance, the doctrine is being used by LGX Oil & Gas Inc. (LGX) to push back against the government of Canada's emergency order to protect the greater sage-grouse habitat in southern Alberta and Saskatchewan, which LGX claims has inhibited its operations to such an extent that its oil and gas interests were effectively expropriated. 

Further, as a Canadian plan to the protect woodland caribou under the Species at Risk Act, 1 SC 2002, c 29 develops, similar claims may arise in the future. BLG staff will continue to monitor the implementation of the USMCA and its effect on the oil and gas industry as it moves toward implementation.

1 2018 FCA 153, online: available here.

2 BLG acted for the government of Canada in this transaction.

3 For further analysis of the NEB approval, available here.

4 BLG lawyers Michael Marion, Alan Ross and Brett Carlson acted as counsel to an intervening party, the Canadian Energy Pipeline Association.

5 For a full review of the BCCA and SCC, available here.

6 For Trans Mountain News Release, available here.

7 For further analysis of the Appeal, available here.

8 For further analysis of this decision, available here.

9 For additional analysis, available here.

10 The decisions were (1) Capital Power Corporation v Alberta Utilities Commission, 2018 ABCA 437 (CPC), denying the applicants PTA the Commission’s determination in Decision 790-D02-2015 that it had jurisdiction to order retroactive adjustments to line loss charges unlawfully paid pursuant to the ISO tariff; (2) Milner Power Inc v. Alberta Utilities Commission, 2019 ABCA 127 (Milner), denying permission to Milner and ATCO to appeal the Commission’s determinations in Decision 790-D04-2016 regarding interest and costs and (3) ENMAX Energy Corporation v. Alberta Utilities Commission, 2019 ABCA 222 (ENMAX), denying PTA applications by ENMAX, CPC, TCE and Powerex in respect of the ultimate remedy ordered by the Commission for the unlawful line loss charges in Decision 790-D06-2017.

11 Chevron Standard Ltd. v. Alberta (Energy Resources Conservation Board) (1983), 26 Alta. L.R. (2d) 10 at 13; ATCO Electric Limited v. Alberta (Energy and Utilities Board), 2003 ABCA 44 at para. 17.

12 Milner at para 10.

13 2019 SCC 65 (Vavilov).

14 AUC Decision 23339-D01-2019, Alberta Electric System Operator Needs Identification Document Application, AltaLink Management Ltd. Facility Application, Provost Reliability Upgrade Project, January 22, 2019 (the Provost Decision).

15 AUC Decision 23393-D01-2019, Alberta Electric System Operator Needs Identification Document Application, AltaLink Management Ltd. Facility Application, Fincastle 336S Substation Upgrade, February 14, 2019 (the Fincastle Decision).

16 Decision 22394-D01-2018, Rebasing for the 2018-2022 PBR Plans for Alberta Electric and Gas Distribution Utilities, First Compliance Proceeding, February 5, 2018, at paras. 371-395.

17 Decision 21609-D01-2019, ATCO Electric Ltd., Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire (October 2, 2019) at paras. 132-134; Decision 22742-D02-2019, ATCO Electric Ltd., 2018-2019 Transmission General Tariff Application (October 2, 2019) at paras. 89-91.

18 FortisAlberta Inc v Alberta (Utilities Commission), 2015 ABCA 295 at para. 161.

19 Decision 22742-D02-2019, ATCO Electric Ltd., 2018-2019 Transmission General Tariff Application (October 2, 2019) at paras. 67-85.

20 Decision 21609-D01-2019, ATCO Electric Ltd., Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire (October 2, 2019) at para. 134.

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