a hand holding a guitar



2017 Year In Review: Top 10 Regulatory Decisions of Importance to the Canadian Energy Industry

2017 witnessed some dramatic events in the energy regulatory world. The Trans Mountain Expansion Project has proceeded to the construction phase despite all legal challenges, particularly by the City of Burnaby. On the other hand, the Energy East Pipeline project was withdrawn from the National Energy Board ("NEB") regulatory process after the NEB voided all decisions made by the previous hearing panel and began a new hearing process. At the Provincial level, the British Columbia Utilities Commission ("BCUC") and Alberta Utilities Commission ("AUC") were kept busy with the BCUC inquiry into certain aspects of BC Hydro's Site C project that resulted in British Columbia's decision to complete the project, while the AUC inched closer to the end of the Transmission Line Loss proceedings that has lasted over a decade by approving the methodology for calculation of final loss factor and who should receive revised invoices.  The Alberta Energy Regulator ("AER"), continued to deal with the fallout of the energy downturn and insolvent licensees with escalated enforcement actions and enhanced risk management strategies, including revising the eligibility requirements for acquiring and holding its licenses to eliminate unreasonable risks. And with that, we highlight below some of the top 10 regulatory decisions of impact from 2017.

1. Trans Mountain Expansion Project Continues, But Legal Challenges Loom

The Trans Mountain Expansion Project (the "Project") continued full-speed ahead in 2017. However, the success of the Project remains uncertain while legal challenges to the Project wind their way through the Federal Courts.

Project Milestones in 2017

In the winter of 2017, the B.C. Provincial Government issued an environmental assessment certificate for the B.C. portion of the Project, subject to 37 conditions relating to key areas of provincial jurisdiction and interest, including parks and protected areas, greenhouse gas emissions and terrestrial and marine spills.1 Shortly thereafter, Kinder Morgan filed seven applications with the National Energy Board (the NEB) requesting variances to the general pipeline route approved in the Certificate of Public Convenience and Necessity OC-064 issued for the Project (the Certificate) and the NEB approved the plan, profile and book of reference (the PPBoR) for the pipeline portion of the Project (the Pipeline).2

In the spring of 2017, Kinder Morgan provided public notice of the proposed detailed route of the Pipeline and secured the Project's required financing through successful completion of an Initial Public Offering for Kinder Morgan Canada Limited.3

In the summer of 2017, landowners and other persons who anticipated that their lands might be adversely affected filed a total of 452 statements of opposition to the proposed detailed route of the Pipeline with the NEB.

In the fall of 2017, Kinder Morgan selected six contractors to construct the Project4 and cleared all applicable NEB pre-construction conditions for priority temporary infrastructure sites.5 For its part, the NEB took the following steps to advance the Project:

  1. Kinder Morgan's Variance Applications – The NEB approved six of Kinder Morgan's seven applications requesting variances to the general pipeline route approved in the Certificate, subject to approval by the Governor-in-Council. A hearing with respect to the seventh application is currently underway.6
  2. Approval of the PPBoR/Detailed Route Hearings – The NEB approved those portions of the PPBoR in Segments 1, 2, 3 and 4 of the Pipeline in respect of which statements of opposition were not received.7 The NEB also conducted detailed route hearings for statements of opposition filed in respect of Segments 1 and 2 of the Pipeline and announced detailed route hearings for statements of opposition filed in respect of Segments 3, 4 and 7 of the Pipeline. No detailed route hearings have yet been announced for statements of opposition filed in respect of Segments 5 and 6 of the Pipeline.8
  3. Approval of the EPP – The NEB approved Kinder Morgan's Environmental Protection Plan, with directions.9
  4. Decision on City of Burnaby Bylaws – The NEB issued an order declaring that Kinder Morgan is not required to comply with two sections of the City of Burnaby's bylaws which required Kinder Morgan to obtain preliminary plan approvals and tree cutting permits for project-related work at the Burnaby Terminal, Westridge Marine Terminal, and at a nearby temporary infrastructure site. This decision allows Kinder Morgan to begin work at its temporary infrastructure site near the Westridge Marine Terminal, and some work at the Burnaby Terminal, subject to any other permits or authorizations that may be required.10

Pending Legal Challenges

Despite the numerous steps taken by Kinder Morgan and the NEB to advance the Project in 2017, it remains to be determined whether the Project will survive the 15 consolidated legal challenges to the federal approvals granted for the Project. The Federal Court of Appeal heard oral arguments in respect of those legal challenges in October 2017,11 and its decision in respect of those challenges is pending.

2. The Alberta Energy Regulator appoints Receiver for the Regulated Assets of Insolvent Licensee and issues Declaration against Directors in the case of Lexin Resources Ltd.

As a lesson from its ordeal with Redwater Energy Corporation's and Spyglass Resources Corp.'s insolvencies, the AER escalated enforcement actions against Lexin Resources Ltd. ("Lexin"). As background to the 2017 events, Lexin had laid off all but six people to manage its entire operations which included over 1660 AER-licenses. The AER issued closure and abandonment orders to Lexin in respect of expired surface rights for 3 wells and mineral rights for 24 wells but Lexin did not comply with the AER orders. The AER issued a suspension order in respect of operations at Lexin's Mazeppa Facility and related infrastructure, and Lexin partially complied. The AER then required Lexin to address a hydrocarbon spill at its sour gas facility and Lexin did not comply. In addition to noncompliance with multiple orders, Lexin owed over $1 million in orphan fund levies and annual administrative fees and over $70 million in security deposits for its end of life obligations required under the Licensee Liability Rating ("LLR") program. While the AER recovered $112,659.48 from third parties from garnishment activities, repeated attempts by the AER to bring Lexin into compliance failed. In January 2017, Lexin advised the AER that it was unable to provide proper health and safety overview and measures for its sour wells beyond February 15, 2017.

Despite the AER correspondence directing Lexin not to remove equipment from any of its sites, the AER found that equipment was being removed, and it obtained from the Alberta Court of Queen's Bench for an interim order prohibiting removal of equipment from Lexin's AER-licensed sites on February 14, 2017. The Court Order preventing removal of equipment from Lexin sites was confirmed and extended on March 7, 2017.

On February 15, 2017, the AER issued a closure order suspending the licences of all Lexin 1,380 wells, 81 facilities, and 201 pipelines requiring Lexin to cease all production, pursuant to s. 27 and s. 106(3) of the OGCA; s. 12 of the Pipeline Act, RSA 2000, c. P-15; and the Responsible Energy Development Act, SA 2012, c. R-17.3 ("REDA"). The AER granted site access to Lexin's WIPs to secure, shut in, and provide emergency and incident response at the sites where they have interests. The Lexin sites without WIPs were designated as orphans in the care and custody of the Orphan Well Association ("OWA"). The AER also issued environmental protection orders, pursuant to ss. 113 and 241 of the Environmental Protection and Enhancement Act RSA 2000, c E-12 ("EPEA"), against Lexin as the facility license holder, LR Processing Ltd. an affiliated entity as the environmental approval holder, and the Lexin directors as persons in direct or indirect control at the time of the failures, requiring them to address the substance release and environmental concerns at the Mazeppa sour gas facility.

The AER notified Lexin's directors, Michael J. Smith, Jasmina Cezek, and Rob Jennings, of its intention to name them in a declaration pursuant to section 106 of the OGCA. Time was provided to permit the directors to show cause as to why a declaration should not be made against them. However other than challenge the validity of the levies issued to Lexin, (by that time outside of the applicable appeal periods) the directors did not provide evidence as to why a declaration should not be made. As a result, the AER denied their request for a hearing and issued a section 106 declaration naming the Lexin directors on January 19, 2017, found here.12 Upon receiving written confirmation that Mr. Jennings would not directly or indirectly control any Alberta Energy Regulator licensed entity without the written prior consent of the Alberta Energy Regulator, the AER varied the Declaration to remove reference to Mr. Jennings.13

On March 21, 2017, the AER obtained a receivership order appointing Grant Thornton LLP as Receiver over all assets of Lexin regulated by the AER.14 The Receiver was to facilitate a sales process to market and sell Lexin's assets but not take possession of the assets. Care and custody of Lexin's assets remained with the Orphan Well Association and identified working interest participants until the sales process is complete. On June 13, 2017, Lexin agreed to include its related entities into the receivership order and to cooperate in addressing safety issues at Lexin sites. Michael J. Smith, the director of Lexin, also accepted responsibility for Lexin's non-compliances and agreed to pay $175 000 and not control any licensee or approval holder in Alberta. While the AER's investigation into Lexin's non-compliances has been concluded, Lexin or any purchaser of a Lexin licence, are still required to address outstanding orders.15

3. The Alberta Energy Regulator confirms that the Receiver of an Insolvent Licensee is not eligible to request a Regulatory Appeal under the Responsible Energy Development Act

Ernst & Young Inc.'s ("E&Y"), the Court-appointed receiver of Spyglass Resources Corp. ("Spyglass"), requested a regulatory appeal of the AER's decision to issue Order No. ACO 2016 – 01 (the "Order"), which is an abandonment cost order requiring Spyglass to pay abandonment costs of $755,006.50 plus a penalty of $188,751.63. Those amounts are related to abandoned facilities operated by Bonavista Energy Corporation ("Bonavista") and in which Spyglass has a working interest. E&Y requested that the penalty be removed from the Order.

E&Y submitted that the Receiver has authority over the affairs of Spyglass, and an obligation to enhance and facilitate the preservation and realization of Spyglass' assets for the benefit of all stakeholders. The Order, as a claim in the receivership, may reduce the realization proceeds available to other unsecured creditors. Accordingly, E&Y claimed the Receiver is a person who is directly and adversely affected by a decision of the Regulator that was made under an energy resources enactment, and thus fulfills the criteria set out in section 36(b)(ii) of the Responsible Energy Development Act("REDA").

By a letter decision dated June 15, 2017,16 the AER dismissed E&Y's regulatory appeal request on the grounds that that E&Y is not an eligible person. The AER held that E&Y's characterization of the Order as a claim in the receivership which reduces proceeds for unsecured creditors does not demonstrate that the Order directly and adversely affects E&Y. Rather, it demonstrates that the Order is a matter the Receiver must have regard to when complying with the receivership order. While the Order might directly and adversely affect certain creditors, as it may change the amounts available to them and might affect Spyglass, that does not translate into direct and adverse effect upon E&Y. E&Y will still have certain obligations under the receivership order and the Order will not prevent E&Y from fulfilling its obligations.

4. The Alberta Energy Regulator confirms that short-term economic advantage of an extra pipeline did not justify additional disturbance to lands

In ABAER 001 - Bonavista Energy Corporation A Regulatory Appeal of Two Well Licences and an Application for a Pipeline Gilby Field January 23, 2017, the AER confirmed two horizontal gas well licenses it issued to Bonavista Energy Corporation ("Bonavista") while denying Bonavista's application for an additional pipeline for the proposed gas production. While the wells were needed and the surface drilling location was optimal, the AER found that the short-term economic advantage of the extra pipeline capacity to Bonavista did not justify the impacts to landowners created by the additional disturbance to their lands.

Bonavista submitted non-routine applications for two horizontal gas wells to be drilled from an existing well site, which already had two wells Bonavista drilled in 2013. Bonavista also applied for approval to construct and operate an additional pipeline to transport natural gas from the well site to an existing compressor station. The public notice of the well license applications and as the applications met the AER requirements and no statements of concern were received, the AER issued the horizontal well licences. Subsequently, the landowners requested a regulatory appeal of the AER's decision to issue the well licences to Bonavista and registered a statement of concern against Bonavista's pipeline application.

The panel found that while the wells were needed and the well site was the optimal surface location to drill them, the economics of the pipeline were not justified. The panel found that the need for extra pipeline capacity would be relatively short-lived, since production rates from the proposed two new wells will decline enough within six to seven months to eliminate the need for an additional pipeline to handle production from the four wells at the well site. While having the additional pipeline would minimally expedite production of the resources, the absence of it would not strand resources or prevent their future production. Production would not be lost, but merely deferred and there was no evidence that reserve recovery would be hindered by the short-term deferral. The modest increase in revenue in the short term from the extra pipeline was not a compelling reason in the face of the Applicants' opposition. Denying Bonavista's application for the pipeline, the panel held that Bonavista's need for the proposed pipeline for possible future projects was speculative and that Bonavista could apply for a future pipeline project. 

5. The Alberta Utilities Commission rules on the methodology for calculation of final loss factor and who should receive revised invoices in the Transmission Line Loss proceedings      

We have previously covered aspects of the line loss proceedings relating to Decision 790-D02-2015 on Phase 2 Module A. The AUC ruled on Phase 2 Module Cin Milner Power Inc. & ATCO Power Ltd. Complaints Regarding the ISO Transmission Loss Factor Rule and Loss Factor Methodology, Phase 2 Module C, AUC Decision 790-D06-2017, December 18, 2017. As background to the 2017 decision in Phase 2 Module C, the AUC had determined that the Independent System Operator ("ISO")'s Line Loss Rule was unjust, unreasonable, unduly preferential, and arbitrarily and unjustly discriminatory on the basis that the rule disadvantaged generators that are loss savers and does not properly charge loss creators for their losses.  The AUC determined that the Line Loss Rule was ultimately inconsistent with the Electric Utilities Act ("EUA") and the Transmission Regulation made thereunder. The AUC determined that it has jurisdiction to grant tariff-based relief as a remedy for its previous findings with respect to the Line Loss Rule.  Further, such relief may involve retrospective adjustments to the ISO tariff going back to when the Line Loss Rule first came into force, being January 1, 2006. The AUC considered proposals for a new line loss methodology (the Module B methodology) which was approved and adopted by AUC Decision 790-D03-2015.

In the 2017 Phase 2 Module C decision, two issues that were determined were: (a) the methodology to be applied to the historical period between January 1, 2006 and December 31, 2016; and (b) who should receive the revised invoices for line loss charges or credits for the historical period. The AUC approved the Modified Module B methodology for calculating loss factors for the historical period, and directed the Alberta Electric System Operator ("AESO") to re-issue invoices for loss charges or credits to those original parties that held Supply Transmission Service ("STS") contracts when the charges or credits were first incurred.

The AUC considered the Milner methodology, the Old AESO methodology and the Modified Module B methodology. The relevant criteria applied were: compliance with the statutory scheme; consistency; expediency (i.e., timeliness); and verifiability (i.e., replicability), with consistency being the most important. Consistency means the degree to which each methodology is able to reasonably represent or emulate what would happen when a generating unit unexpectedly comes off line. The AUC concluded that the Modified Module B methodology would result in rates that are consistent with the statutory scheme, just and reasonable, and not unduly preferential, arbitrary or unjustly discriminatory.

In terms of the method for and timing of collection and reimbursement, the AUC directed the AESO to recalculate the bills for the historical period and issue new statements of account, and to implement the single settlement approach with simultaneous collection and reimbursement pursuant to the ISO tariff. The AUC also directed the AESO to release the yearly line loss results and the updated line loss charges for each year as they become available and to award (charge) interest, equal to the Bank of Canada rate plus one and one half per cent. The AESO was required to set out the interest attributed to the monthly amounts for each market participant when it issued updated statements of account for the historical line loss charges.

6. The National Energy Board voids all previous panel decisions, commences new hearing process, and TransCanada withdraws its Application for the Energy East Pipeline Project 

We previously covered the recusal of the National Energy Board ("NEB") Energy East hearing panel and suspension of the hearing proceedings. We noted that while a new panel was appointed on January 9, 2017, a new notice of motion was filed seeking to void the entire proceeding on the basis of apprehension of bias arising from the recusals by the panel.

In 2017, the NEB issued a number of Rulings.17 In its Ruling No. 1 of January 27, 2017, the NEB voided all decisions made by the previous panel and began a new hearing process. The voided processes include the completeness determination, the List of Participants issued as well as the ruling on Aboriginal intervenors, all subsequent rulings on participation, the Hearing Order, the Lists of Issues and Factors and Scope of the Factors for Environmental Assessments ("EA Factors Documents"), and all procedural directions, process guidance documents.

On 23 August and September 1, 2017 respectively, the NEB released a new final Lists of Issues and EA Factors Documents for the project, which included the quantification of indirect greenhouse gas emissions, and the hearing record. In its Ruling No. 10 of September 8, 2017, the NEB granted the request of Energy East Pipeline Ltd. and TransCanada PipeLines Limited (the "Applicants") for a 30-day suspension of the review process to enable them assess the new final Lists of Issues and EA Factors Documents and the resulting implications for the project. One of the main concerns was the assessment of upstream and downstream greenhouse gas emissions ("GHGs") for the project.

On October 5, 2017, the Applicants formally withdrew their Applications for the Energy East project from the NEB review process, found here.18 The reasons given were the substantial uncertainty surrounding the scope, timing and cost associated with future delays resulting from the regulatory review process, and the question of jurisdiction that arises from the NEB's Decision.19

7.B.C. Completes Site C Inquiry and Gives Green Light to the Project

On August 2, 2017, the B.C. Provincial Government issued an Order in Council (OIC) requesting the B.C. Utilities Commission (the Commission) undertake an inquiry into certain aspects of BC Hydro's Site C project in the Peace River Regional District. Specifically, the OIC asked the Commission to report on the implications of: (1) completing the Site C project by 2024, (2) suspending the Site C project, while maintaining the option to resume construction until 2024, and (3) terminating the Site C project and remediating the site. The OIC also asked the Commission to compare the costs to ratepayers for the completion and the termination scenarios.

After receipt of the OIC, the Commission solicited submissions from First Nations impacted by the Site C project, members of the general public, BC Hydro and Deloitte (an independent consultant retained by the Commission to gather information and provide analysis to assist the Commission in answering the questions posed in the OIC).

On November 1, 2017, the Commission released a report with the final findings from its inquiry, found here.20 In its report, the Commission came to the following conclusions in respect of the completion, suspension and termination scenarios described in the OIC:

  1. The completion scenario - The Site C project is not within the proposed budget of $8.335 billion. The total cost at completion may be in excess of $10.0 billion as there are significant risks remaining which could lead to further budget overruns. In addition, there are significant risks that could prevent the project from remaining on schedule.
  2. The suspension scenario - The suspension scenario results in the highest cost to ratepayers as well as various other implications. The cost of putting the Site C project in a state of suspension, awaiting future remobilization in about five years, would be just as costly as terminating the project. In addition, there are the remobilization costs and the costs to complete the project beginning in 2024. There is no certainty that the remaining project budget would be adequate to complete the construction following remobilization in 2024. Contracts would have to be retendered and First Nations' benefit agreements may have to be renegotiated. Environmental permitting would have to begin anew upon resumption of construction.
  3. The termination scenario - In the event the Site C project is terminated, the construction site must be remediated. This would cost approximately $1.8 billion. In addition to this remediation cost, depending upon the load, a portfolio of commercially feasible generating projects and demand side management initiatives may be required.

In its report, the Commission stated that the cost to ratepayers of the completion and termination scenarios were virtually equivalent. However, the Commission stated that, regardless of the comparative costs, there are also other issues to consider when comparing the completion and termination cases. Both scenarios involve risk that is not easy to quantify. In the short term, the Commission found that the major risk of Site C is whether there will be further construction cost overruns. The project has already exceeded its budget and it is one year behind the schedule to which it was actually being managed. In the long term, a disruptive technology such as affordable utility or home-scale storage technology could reduce the anticipated benefits of Site C, by allowing the production of non-dispatchable energy from renewables at declining prices. Combined with a continued glut in North American energy markets, the Commission held it could make it increasingly difficult to sell Site C surplus energy and disruptive storage technology could incent customers to generate their own electricity.

On December 11, 2017, after reviewing the Commission's report, the B.C. Provincial Government announced that it will complete construction of the Site C project, here.21 The Provincial Government stated that it will launch a "Site C turnaround plan" to contain project costs and will pursue an alternative energy strategy to "put B.C. more firmly on the path to green, renewable power that helps the province exceed its climate goals."22

8. Application by the Market Surveillance Administrator regarding the Publication of the Historical Trading Report

The Market Surveillance Administrator (the "MSA") in Proceeding 21115, applied to the Alberta Utilities Commission (the "Commission") pursuant to Section 51(1)(b) of the Alberta Utilities Commission Act, SA 2007, c A-37.2 ("AUCA") regarding the discontinuation of an hourly spreadsheet published by the AESO known as the "Historical Trading Report" or "HTR". The HTR was an hourly spreadsheet published by the AESO five to ten minutes after the end of each hour which published the price and quantity of each offer made to the power pool in that hour but not the market participant that made the offer or the associated generating unit. In the MSA's view, the HTR undermined the fair, efficient and openly competitive nature of the wholesale electricity market and adversely affected the structure and performance of the market by relieving competitive constraints on the exercise of market power.  For those reasons, the MSA sought an order from the Commission that the AESO cease publishing the HTR immediately. The application was opposed by the Alberta Electric System Operator (the "AESO") as well as all of Alberta's major power producers.  Proceeding 21115 was ultimately the subject of a four day oral hearing presided by over three Commission members, which was followed by extensive written arguments filed by all participants.

On May 17, 2017, the Commission released Decision 21115-D01-2017 (the "Decision"). The Commission found that the publication of the HTR was not consistent with the fair, efficient and openly competitive operation of the market because it enabled market participants to exercise market power with greater precision than would be possible without the HTR. The Commission directed the AESO to cease publication of the HTR, and the AESO did so on May 23, 2017.

Two of the participants in Proceeding 21115 filed applications for review and variance of the Decision (Proceeding 22797). Written submissions were filed by each of the applicants, the MSA, and two entities who were involved in Proceeding 21115. The Commission ultimately dismissed the applications for review and variance on December 11, 2017 in Decision 22797-D01-2017. The Commission found that the applicants had failed to demonstrate the existence of an error of law, fact or jurisdiction that could lead the Commission to materially vary or rescind the Decision.

Three participants in Proceeding 21115 have also filed applications for permission to appeal the Decision at the Alberta Court of Appeal. The appeals are currently scheduled to be heard in June of 2018.23 

9.B.C. Oil and Gas Appeal Tribunal Confirms B.C. Oil and Gas Commission Has Broad Authority to Issue Orders to Mitigate a Risk to Public Safety and to Protect the Environment

On August 21, 2017, the B.C. Oil and Gas Appeal Tribunal (the Tribunal) released its decision24 in respect of an appeal by Canada Energy Partners Inc. (CEP) of general order 2017-008 (the Order) issued on March 16, 2017 by the Vice President, Compliance Operations, Oil and Gas Commission (the OGC). The Order, which was issued pursuant to s.49(1)(b) of the Oil and Gas Activities Act to mitigate a risk to public safety and to protect the environment, required CEP to suspend all disposal activities at well WA#22031 (the Well) pending a review of additional technical information. The Order was issued a day after BC Hydro informed the OGC that disposal operations at the Well increased the risk of an induced seismic event sufficient to cause damage to the Peace Canyon Dam 3.3 km away from the Well.

CEP appealed the Order on the grounds that, among other things:

  1. The Order was not was not fair or timely, in that the OGC issued the Order one day after receiving the complaint from BC Hydro and without giving CEP prior notice or an opportunity for input.
  2. There was insufficient evidence to support the issuance of the Order.
  3. The Order was issued only three months after the OGC issued a public statement that it had reviewed all disposal wells in the province to ensure their ongoing integrity, and that the Order was issued in violation of an OGC policy of "grandfathering" existing operations within five km of BC Hydro's facilities.

The Tribunal dismissed CEP's appeal in its entirety.

With respect to CEP's first ground of appeal, the Tribunal noted that although the OGC issued the Order without input from, or prior notice to CEP, and only a short time after BC Hydro advised the OGC of its concerns regarding the potential impacts of the Well's disposal operations on the Peace Canyon Dam, CEP had since been accorded a full and fair hearing before the Tribunal. The Tribunal found that, given the Tribunal's powers and procedures, and the process by which the appeal was heard and considered, the appeal process cured any procedural defects that may have occurred in the OGC's process that led to the Order being issued.

With respect to CEP's second ground of appeal, the Tribunal found that the OGC had sufficient evidence to support the issuance of the Order. The information before the OGC when the Order was issued indicated that there was a real, but poorly understood, risk to public safety and to the environmental arising from potential disposal activities at the Well to cause an induced seismic event that could de-stabilize the Peace Canyon Dam. Given the significant consequences in terms of the risk to public safety and the potential for harm to the environment if disposal activities at the Well triggered a seismic event that adversely affected the Dam, the Tribunal found that it was prudent to suspend disposal operations at the Well to mitigate those risks, until the OGC could gather more information and better assess the nature and level of the risk posed by disposal activities at the Well.

With respect to CEP's third ground of appeal, the Tribunal found that any public statements or policies that the OGC may have made did not limit or prevent it from exercising its statutory authority under section 49 of the Oil and Gas Activities Act.

On December 4, 2017, the OGC issued a decision which permits CEP to resume disposal operations at the Well, subject to conditions which require CEP to: (1) limit daily disposal volumes to 200 m³/day, (2) install seismic detection and accelerometer equipment and regularly report gathered data; and (3) cease disposal operations if BC Hydro's safety factor at the Peace Canyon Dam falls below an acceptable level.25

10. The AER revises the Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals in Directive 67

On December 6, 2017, the Alberta Energy Regulator (AER) released a revised edition of Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licenses and Approvals, together with Bulletin 2017-21 New Edition of Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licenses and Approvals. The AER emphasized that acquiring and holding a License or approval in Alberta is a privilege, not a right. The revised Directive 067 increases the scrutiny the AER applies to ensure that such a privilege is only granted to, and retained by, responsible parties. Changes include requiring additional information at the time of application, increased discretion regarding the rejection of applications where an applicant poses a risk, and requirements for keeping corporate information up to date.

A Business Associate Code ("BA Code") does not automatically qualify the holder for AER Licenses or approvals. For new applicants, the new requirements include, among others, a declaration of the applicant attesting to the truth and completeness of the application, consenting to the release and collection of compliance information regarding the applicant from other jurisdictions and regulators as applicable, and attorning to the jurisdiction of Alberta. It also includes an assessment by the AER as to whether the applicant poses an unreasonable risk. The AER may audit the information provided for accuracy and completeness at any time before or after granting eligibility.

The AER may grant license eligibility with or without restrictions, terms and conditions, or it may refuse to grant License eligibility. Such restrictions, terms, and conditions may include: (a) the types and number of Licenses or approvals that may be held; (b) additional scrutiny required at time of application for or transfer of a License or approval; (c) requirement to provide full or partial security at time of application for or transfer of a License or approval; (d) requirements regarding the minimum or maximum working interest percentage permitted, or (e) requirement to address outstanding non-compliances of current or former AER licensees that are directly or indirectly associated with the applicant or its directors, officers, or shareholders.

In assessing whether the applicant poses an unreasonable risk, the AER considers a number of factors. All existing license or approval holders must meet license eligibility requirements on an ongoing basis and ensure that the information the AER has on file is kept accurate. An updated Schedule 1 of Directive 067 must be provided within 30 days of any material change. Material changes include: (a) changes to legal status and corporate structure; (b) addition or removal of a related corporate entity; (c) amalgamation, merger, or acquisition; (c) changes to directors, officers, or control persons; (d) appointment of a monitor, receiver, or trustee over the licensee's property; (e) plan of arrangement or any other transaction that results in a material change to the operations of the licensee; (f) the sale of all or substantially all of the licensee's assets; or (g) cancellation of insurance coverage.

All parties with current Directive 067 eligibility are required to ensure that the AER has accurate information on file, and have until January 31, 2018, to provide an updated schedule 1. Failure to provide the updated schedule may result in the AER either revoking or restricting licence eligibility. 

1 Online: click here
2 The plan and profile is a detailed drawing of the Pipeline as seen from above (aerial view) and from the side (profile view) showing the proposed detailed route of each of the seven segments of the Pipeline. The book of reference identifies the lands and the landowners, and shows the dimensions (length, width and total area) of the right-of-way required for the Pipeline.
3 Online: click here. 
Online: click here.  
Online: click here. 
Online: click here. 
Online: click here. 
10 Online: click here. 
11 Online: click here. 
12 AER 20170124A - Lexin Resources Ltd. Decision to Issue a Declaration Naming Michael J. Smith, Jasmina Cezek, and Rob Jennings, January 19, 2017, online: click here.
13 1893772 and 1879855  Lexin Resources Inc. – Robert Jennings  Reconsideration request granted July 13, 2017, online: click here.  
14 BLG is counsel to the Receiver.
15 AER News Release "Lexin agrees to cooperate with receivership, director pays $175 000", online: click here.
16 Spyglass/E&Y Request for Regulatory Appeal by Ernst & Young Inc. Court-Appointed Receiver of Spyglass Resources Corp. Abandonment Costs Order No.: ACO 2016-01 Regulatory
Appeal No. 1862824, June 15, 2017, online: click here.
17 NEB, Ruling No. 1 - No. 10, online: click here.
18 2014-10-30 - Applications for Energy East, Asset Transfer and Eastern Mainline (OH-002-2016), online: click here.
19 BLG acted for an intervenor in this matter.
20 Online: click here
21 Online: click here. 
23 BLG acted for the MSA in this matter.
24 Online: click here
25 Online: click here