At the beginning of 2018, our review of the 2017 Canadian regulatory events described them as dramatic, but the 2018 saga turned out to be nothing short of a blockbuster. Pressure built up to a bubble point at the federal and provincial levels of governments, and at the National Energy Board (“NEB”), regarding interjurisdictional pipelines that provide market access for western Canadian oil and gas production. By the end of the year, the situation was a mixture of partial success, major setback and promise of hope. While the Government of Canada purchased the Trans Mountain Expansion Project to alleviate the political risks associated with its construction, the Project encountered yet another hurdle when its federal approval was sent back to the NEB for reconsideration. Further, questions about federal/provincial jurisdiction over a pipeline wholly within a province were raised and have significant implications for similar facilities.
So acute were the pipeline capacity issues that the Government of Alberta had to cut oil production to decongest the bottleneck and improve the discounted price of Alberta’s crude oil that could not access external markets. Prior to the oil cut, however, the Alberta Energy Regulator (“AER”) approved a new oil sands in situ project with a signal that a cap on cumulative impacts of oil sands development must be determined at the policy level. The Alberta Utility Commission (“AUC”), on the other hand, approved electricity generation and transmission facilities consistent with Alberta’s plan of 30 percent renewable electricity by 2030.
In British Columbia, hydraulic fracturing was given a thumbs-up by the British Columbia Oil and Gas Appeal Tribunal. Finally, in Ontario, the Ontario Energy Board (“OEB”) approved an amalgamation of the two largest gas distribution companies, largely on the basis that the deal would not cause harm to Ontario ratepayers.
1. Trans Mountain Expansion purchased by Canada, the Project Approval quashed and NEB reconsidering aspects of the Project’s 2016 Recommendation Report
The Trans Mountain Expansion Project (the “Project”) witnessed a significant promise and a major setback in 2018. In the spring, the Project was confronted with uncertainty amidst seemingly insurmountable political and legal hurdles. By the fall, while the political risk seemed to have decreased, the Project went back to the NEB for reconsideration of related marine shipping.
Project Milestones in 2018
In early 2018, the Project was making progress on its detailed route hearings, including the NEB’s approval of detailed route Segments 1 & 2 (Edmonton to Jasper National Park)1 and portions of Segment 7 (BC lower mainland, including the Burnaby Mountain tunnel).2
As the detailed route hearings continued into the spring, Kinder Morgan sought greater certainty from the Government of Canada about the viability of the Project in the face of mounting political, legal3and financial risks. Kinder Morgan imposed a deadline of May 31, 2018 for the Government of Canada to provide a solution. Shortly thereafter, on May 29, 2018, the Government of Canada announced its decision to purchase the Project for $4.5 billion, after other proposed solutions were rejected.4 The purchase transaction closed on August 31, 2018.
Meanwhile, on August 30, 2018, the Federal Court of Appeal released its decision in Tsleil-Waututh Nation v. Canada (Attorney General).5 The decision quashed the Order in Council that approved the Project and nullified the NEB’s Certificate of Public Convenience and Necessity (“CPCN”) on the basis that the Government of Canada had engaged in a flawed consultation process with affected Indigenous communities, and that the NEB unreasonably failed to consider Project-related marine shipping impacts from its environmental assessment of the Project. Consequently, construction activities relating to the Project were halted.
On September 21, 2018, the Government of Canada issued a new Order in Council6 referring the Project back to the NEB for reconsideration of the impact of the Project-related marine shipping, while reinitiating its own consultation process with affected Indigenous communities.
The NEB reconsideration process remains ongoing. On January 10, 2019, the NEB released its draft conditions and recommendations relating to the reconsideration hearing. The NEB is expected to deliver its final report on the reconsideration no later than February 22, 2019.
2. The National Energy Board approves the North Montney Mainline Pipeline Project in Northeastern BC to proceed without the Pacific NorthWest Liquefied Natural Gas Facility
On May 23, 2018, the NEB released its decision granting Nova Gas Transmission Ltd.’s (“NGTL”) application to vary the North Montney Mainline Project (the “Project”) as previously approved in 2015. The NEB allowed the Project to proceed notwithstanding the cancellation of a proposed liquefied natural gas facility which underpinned the initial approval.
The 2015 approval was conditional upon a firm investment decision being made on the Pacific NorthWest Liquefied Natural Gas (“PNW LNG”) facility by Petronas. The Project was intended to include a westbound segment to connect to the PNW LNG facility, and the majority of the gas shipped on the Project was expected to flow to that facility. The firm investment decision did not occur and the “sunset clause” deadline for NGTL to start construction of the Project approached. NGTL sought to vary the conditions of the Project in order to allow it to connect solely to the existing NGTL pipeline network in Alberta, with no service running west.
Given the high stakes in pipeline activities in Northeastern British Columbia (previously discussed here), the NEB conducted a public hearing of the variance application. A number of interested parties7participated in the hearing including gas producers operating in the North Montney, competitor pipelines, and affected Indigenous groups. While some competitors, such as Westcoast Energy Inc., opposed the Project and argued among other reasons that the Project was no longer needed without the PNW LNG facility, a number of North Montney producers supported the Project without the PNW LNG facility.
The NEB ultimately granted NGTL’s application to vary the conditions of the Project (and approved associated facilities) giving North Montney producers a new route eastward. However, the NEB rejected the existing Toll Order from the 2015 approval on the basis that it did not accurately reflect cost causation on the new facilities. NGTL was granted leave to re-apply for a revised toll methodology.
3. The National Energy Board directs Enbridge to consult stakeholders towards the resolution of the Mainline’s Apportionment and Air Barrels Nomination issues
On June 6, 2018, British Petroleum (“BP”) filed a Notice of Complaint with the NEB alleging that Enbridge Pipelines Inc. (“Enbridge”) unreasonably decided to implement, and then later resiled from, the Supply Verification Procedure (the “Procedure”). The Procedure was for verifying that shippers on the Enbridge Mainline Pipeline (the “Mainline”) had adequate supply to fulfill the volumes that they were nominating for transportation on the Mainline each month.
Enbridge’s decision to implement the Procedure arose out of the chronic apportionment issues relating to the constrained Mainline capacity. Some shippers appeared to be over-nominating volumes relative to their available supply on a monthly basis to maximize the capacity they would be allocated after apportionment was applied. The Procedure, announced on May 24, 2018 and effective July 2018, would have limited the volumes shippers were permitted to nominate based on their 12-month rolling average of actual volumes injected into the Mainline, plus an additional percentage allowance depending on the type of oil. However, Enbridge announced on June 4, 2018 that the Procedure would not be implemented in July but without any direction as to its future implementation.
The basis of BP’s complaint included three grounds: (a) revoking the Procedure within the ordinary trading period created unreasonable and unnecessary uncertainty in the market; (b) Enbridge failed to sufficiently consult with its shippers before making both the decision to implement the Procedure and the decision to revoke it; and (c) the lack of certainty regarding any future implementation of the Procedure imposed undue market risks on shippers.
Pursuant to comments received from interested parties,8 the NEB decided not to conduct a hearing and directed Enbridge to consult with its stakeholders to develop a solution to the apportionment issues. Enbridge committed to not: (a) implement any supply verification procedures without the NEB’s approval; (b) change existing procedures during a trading period other than in exceptional circumstances; and (c) provide shippers with at least one month’s notice prior to implementing any future solutions in respect of the over-nomination issue.9
Commercial discussions relating to over-nominations and apportionment on the Mainline are ongoing. Recently, the NEB released its own report on the state of Western Canadian crude oil supply, markets, and pipeline capacity, including an assessment of apportionment rates on federally-regulated oil pipelines.
Meanwhile, in December 2018, the Alberta Government cut oil production and introduced new production curtailment rules in order to decongest the pipeline capacity bottleneck and close the pricing gap between Western Canadian oil and the US benchmarks. These and other issues surrounding Western Canada’s landlocked oil and gas resources are expected to fully unfold in 2019.
4. The National Energy Board determines a prima facie case for federal jurisdiction over Coastal GasLink Pipeline
In 2014, TransCanada Pipelines Limited (“TCPL”) obtained approval for the development of the Coastal GasLink Project (the “Project”) from the British Columbia Oil and Gas Commission. The Project is located entirely within the provincial borders of British Columbia and does not connect to any existing federally-regulated facilities. The Project would receive gas from within British Columbia and transport it to a proposed liquefied natural gas (“LNG”) export facility operated by LNG Canada Development Inc. near Kitimat.
On July 30, 2018, an application was filed at the NEB by an individual seeking a declaration that the Project properly falls within the NEB’s federal jurisdiction rather than provincial jurisdiction. The basis for the application is that while the Project is located within provincial boundaries, in the future it is likely to connect to the existing federally-regulated NGTL system thereby becoming functionally integrated and forming part of a single federal work or undertaking. The applicant argued that the fundamental purpose of the Project is to move gas from the Western Canadian Sedimentary Basin (including, potentially at some point, gas from the existing NGTL system) to the coast for international export. Further, the applicant argued that both Coastal GasLink and NGTL are under TCPL’s common management and control.
Coastal GasLink, among other things, argued that the application was untimely, having been brought four years after the approval was issues, and an abuse of process designed to frustrate natural gas development in British Columbia. Coastal GasLink further argued that in the absence of an existing or applied-for connection to the NGTL system, the Project cannot be said to form part of a federal work or undertaking.
Following comments from interested parties,10 the NEB determined that the applicant established a prima facie case that the Project may form part of a federal undertaking. As a result, a formal hearing process is now underway with evidence and argument set for the first quarter of 2019.11
This is not the only ongoing proceeding relating to the federal/provincial jurisdictions over pipelines in Canada. In 2018, a reference case was commenced at the British Columbia Court of Appeal respecting the ability of British Columbia to implement new environmental legislation to regulate the transportation of heavy oil through the province. Oral argument has been set for March 2019. Depending on their respective outcomes, both of these cases may have a significant impact on the regulatory landscape over the coming years.
5. The AER approves Prosper Petroleum Ltd.’s 2013 Applications for its Oil Sands SAGD Rigel Project
On June 12, 2018, the Alberta Energy Regulator (“AER”) finally issued its decision approving a series of applications for construction of a new oil sands steam-assisted gravity drainage project (the “Project”) by Prosper Petroleum Ltd. near Fort McKay, Alberta. The Project is expected to produce up to 1,600m3/d (10,000 bbl/d) of bitumen once in service. The applications for the Project were filed in 2013 but the hearing did not commence until January 2018.
Interested parties included the Fort Chipewyan Métis Local 125, Athabasca Chipewyan First Nation, Fort McKay First Nation, Fort McKay Métis Community Association (Fort McKay Métis), Fort McMurray Métis Local 1935, Mikisew Cree First Nation, and Brion Energy Corporation (now PetroChina Canada).
Among the issues were the specific impacts of Prosper’s Rigel project on Aboriginal rights and traditional land use. However, the AER determined that the Moose Lake Access Management Plan (“MLAMP”) does not exist as a subregional plan and consideration of it was not within its mandate. In June 2017, the Fort McKay First Nation filed a Notice of Question of Constitutional Law (“NQCL”) respecting the AER’s decision to not hear issues related to the MLAMP, and requested the AER to suspend the proceeding and refer their questions to the Alberta Court of Queen’s Bench. In July 2017, the AER sought submissions from the parties on the relevance and impacts of Supreme Court of Canada decisions Clyde River (Hamlet) v. Petroleum Geo-Services Inc. and Chippewas of the Thames First Nation v. Enbridge Pipelines Inc.
The hearing was concluded in March 2018. The AER found that the Project met the requirements for water use under the Water Act, was consistent with the Environmental Protection and Enhancement Act, and was in the public interest overall.
The AER’s decision is notable for its consideration of the Project’s impact on habitat loss in the area. The AER noted that the Project is situated in an area with significant existing oil sands development, both in situ and surface mining. The AER explained that while the cumulative effect of the Project alongside the existing developments provides important context for understanding the severity of the potential impacts of the Project, its decision must ultimately be based on Project-specific impacts. The AER concluded that any decision “to halt resource and industrial development generally in an area … is a policy-level decision” outside the scope of its review.
6. The AER approves TransCanada Pipelines Limited’s White Spruce Pipeline Project
On February 22, 2018, the AER approved TCPL’s White Spruce Pipeline Project (the “Project”) in the Fort McKay Area. Our previous post about this Project can be found here. While this is not an interprovincial pipeline, it involves two crude oil pipelines providing an important link that would deliver synthetic crude from Canadian Natural Resources Limited’s (“CNRL”) Horizon processing plant to the Grand Rapids Pipeline GP Ltd.’s MacKay Terminal (the “MacKay Terminal”) for onward delivery to markets. The Project will accommodate an expected increase in production once the next expansion phase of the Horizon Plant is implemented.
In its decision, the AER also dealt squarely with the issue of the cumulative effects of oil sands development concentrated in a particular region. The Fort McKay First Nation (“FMFN”) intervened in the hearing, and raised particular concerns about watercourse crossings, wildlife and habitat, herbicide use, and the cumulative effects of development on their ability to exercise their treaty and Aboriginal rights in the area.
The AER was asked to consider the Lower Athabasca Regional Plan (“LARP“),12 approved by Alberta Environment and Parks in 2012, which established frameworks for managing air and water quality and land conservation in the region in order to address the cumulative effects of industrial development on the environment. The AER noted that while it is required to act in accordance with the LARP frameworks, the LARP frameworks relating to the exercise of treaty and Aboriginal rights are not yet completed or in effect. The AER stated that “[w]hen complete, such frameworks should provide clearer direction and guidance to the AER in determining issues like those raised by [FMFN] in this hearing.”
This decision is consistent with the Prosper Petroleum Rigel Project decision above, and sends a clear signal that limits on cumulative (as opposed to project-specific) effects must be determined at the policy level.
Further, considering the pending jurisdictional question in the British Columbia Coastal GasLink Pipeline Project, one wonders whether TCPL’s Alberta White Spruce Pipeline Project may sometime be opened up for similar jurisdictional consideration.
7. The Alberta Utilities Commission approves connecting the historically isolated Jasper area to the Alberta electricity grid
The Alberta Utilities Commission (“AUC”), in May 2018, released its decision approving the needs identification document (“NID”) application and associated transmission facilities applications to connect the Jasper area of Alberta to the Alberta grid (the Alberta Interconnected Electric System, “AIES”).
The Jasper area has been an isolated community served entirely by local power generation. Due to the aging local generation facilities, the Alberta Electric System Operator (“AESO”) assessed a long-term need for the Jasper area to be connected to the AIES. ATCO Electric Transmission (“ATCO”) and AltaLink Management Ltd. (“AltaLink”) each filed transmission facility applications to jointly meet the need identified by the AESO. The AUC had to decide whether it is in the public interest to supply Jasper with electricity through a transmission solution or to continue using an isolated generation system.
Among the interveners was the Jasper Environmental Association (“JEA”) seeking to have the aging local generating units replaced with new, dual-fuel (natural gas and diesel) generating units rather than connecting to the AIES. The JEA’s primary concern was that any new transmission facilities would necessarily run through Jasper National Park.
Rejecting the JEA’s isolated generation alternative, the AUC made the following key findings:
(a) JEA’s generation option would not meet minimum reliability requirements, while the new transmission option would reduce the frequency and duration of outages;
(b) The environmental and land use impacts of the new transmission option could be effectively mitigated, and overall, isolated generation would have a greater negative long-term impact because it would prolong the Jasper area’s dependence on fossil fuels; and
(c) The project cost of the new transmission option would be equal to or lower than replacing the existing aging isolated generation facilities.
The AUC gave considerable weight to the overall fuel efficiency of the AIES and the reduced environmental impact of an integrated system over the long term. The expected in-service date for the new facilities is December 30, 2019.
8. The Alberta Utilities Commission approves the Sharp Hills Wind Project with the tallest turbines that had not been used in Alberta
Consistent with a growing trend toward renewable energy in Alberta, the AUC on September 21, 2018, released its decision approving applications by EDP Renewables SH Project GP Ltd. (“EDP”) to construct and operate a 298.8 MW wind power project and collector station approximately 18km southeast of Consort, Alberta (the “Project”). The Project will be one of the largest wind-generation facilities in North America, consisting of 83 turbines with a hub height of 132 meters and a rotor diameter of 136 meters, making them the tallest turbines currently applied-for or constructed in Alberta.
The Project was strongly opposed by the Clearview Group, consisting of approximately 62 families who reside in the area. The Clearview Group argued that EDP failed to meaningfully consult with local residents about the Project, raised aesthetic and health concerns, and stated that the environmental studies backing the Project were unreliable because turbines of this size had never faced an objective, third-party study in North America.
The AUC found that EDP’s consultation satisfied its regulatory requirements. While the visual impact was a factor in the AUC’s public interest determination, it was not prohibitive and the AUC was satisfied that there was a very low health and safety risk. Finally, notwithstanding the potential for certain environmental impacts, the AUC determined that those impacts could be effectively mitigated by imposing conditions including wildlife monitoring, complying with Alberta Environment and Parks reporting requirements, and complying with construction and operational mitigation plans.
9. The British Columbia Oil and Gas Appeal Tribunal Dismisses Appeal Challenging Safety of Hydraulic Fracturing
In Penalty Ranch v. Oil and Gas Commission, the British Columbia Oil and Gas Appeal Tribunal (the “Tribunal”) dismissed an appeal that challenged permits granted to Crew Energy Inc. (“Crew”) in respect of its proposed hydraulic fracturing operations on lands located in Northeastern British Columbia.13 The Appellants were leaseholders of Crown land on which the wells were located. They asserted that their interests had not been sufficiently addressed when the permits were granted, given concerns they had raised about the potential impact on their drinking water (which was sourced from nearby natural springs) and induced seismicity.
The Tribunal heard evidence from expert witnesses on the potential impact of hydraulic fracturing on water, and in particular whether there is a risk of contaminating potable water as a result of the drilling and completion of the wells at issue, as well as the potential impact of induced seismicity (i.e. earthquakes that may be caused as a result of hydraulic fracturing) on water. The Tribunal concluded that the existing regulations in place in British Columbia, combined with the company’s commitment to maintaining safe practices, were sufficient to address the Appellants’ concerns, including their concerns regarding induced seismicity and potential impact to groundwater.
The Tribunal dismissed the appeal and upheld the permits. This case is the first reported decision in British Columbia that directly addresses issues around the potential impact of hydraulic fracturing on groundwater and induced seismicity, and the sufficiency of regulations relating to such issues.
10. The Ontario Energy Board issues approval for the amalgamation of the two largest gas distribution companies, Enbridge and Union
On August 30, 2018, the OEB issued its decision approving the amalgamation of Enbridge Gas Distribution Inc. (“Enbridge”) and Union Gas Limited (“Union”), in a deal that resulted in a new single entity serving the vast majority of Ontario ratepayers.
Enbridge and Union filed for approval of the amalgamation on November 2, 2017, as well as for a new rate setting mechanism on November 23, 2017. The two applications were consolidated and the oral hearing took place between May 3 and May 28, 2018.
The OEB determined that the relevant test to apply in considering the amalgamation was the “no harm” test. The OEB accepted the argument of Enbridge and Union that an amalgamated entity would be capable of maintaining the reliability and quality of gas service in Ontario, that the entity would be financially viable, and that there would not be a negative impact on the cost of service to each utility’s current customers. In fact, the OEB determined that cost efficiencies could be gained through the amalgamation.
The OEB also granted the utilities’ request to defer a rebasing of their rates for five years in order to allow them to implement the mechanics of the amalgamation. Enbridge and Union were granted permission in the meantime to make an annual rate change based on a price cap index tethered to inflation.
At the time of the applications, Enbridge and Union served distinct geographical areas in Ontario. While Enbridge served the Toronto/York, Niagara and Ottawa regions, Union served most of the remaining regions in southern and northern Ontario. The impact of the amalgamation on competition in the Ontario gas market, potential new market entrants, and on western Canadian gas producers who sell into Ontario, are all issues that are expected to unfold in 2019.
BLG will continue to monitor these and other regulatory developments on the front burner and provide updates.