Project Law Blog

Replacement of Insolvent Operators: Bank of Montreal v. Bumper Development Corporation

Posted in Mining, Oil & Gas Law, Project Development, Public Utility, Regulatory, Regulatory Compliance
Comment

When will the replacement of operator provisions in the 2007 CAPL Operating Procedure (“Paragraph 2.02”) be enforced against a party in receivership in the context of a court approved sale of the underlying oil and gas properties? This question was recently considered by Justice Macleod in Bank of Montreal v. Bumper Development Corporation Ltd., 2016 ABQB 363 (CanLII).

In this case, what was specifically at issue was whether Eagle Energy Inc. (“Eagle”) could rely on Paragraph 2.02 to take over operatorship from Bumper Development Corporation Ltd. (“Bumper”) (the party in receivership). Bumper had been placed in receivership by Bank of Montreal, which applied for and was granted a receivership order pursuant to s. 243 of the Bankruptcy and Insolvency Act, RSC 1985, c B-3. As is common in most receivership orders, upon the appointment of the Receiver (Alvarez & Marsal Canada Inc.), Justice Macleod also ordered that there be a stay of proceedings.

At the time the receivership order was granted, Eagle and Bumper were parties to a Joint Operating Agreement (“JOA”) that pertained to several wells and was governed by the 2007 CAPL Operating Procedure which reads in part at Paragraph 2.02:

2.02 Replacement of Operator

  1. Immediate Replacement – The Parties acknowledge that the Operator’s ability to fulfill its duties and obligations for the Parties’ benefit is largely dependent on its ongoing financial viability and that the operator may not seek relief at law, in equity or under the Regulations to prevent its replacement in accordance with this Subclause. The Operator will be replaced immediately after service of notice from Non-Operator to the other Parties to such effect if:

(a) the Operator becomes bankrupt or insolvent, commits or suffers any act of bankruptcy or insolvency, is placed in receivership or seeks debtor relief protection under applicable legislation (including the Bankruptcy and Insolvency Act (Canada) and the Companies’ Creditors Arrangement Act (Canada)), and it will be deemed to be insolvent for this purpose if it is unable to pay its debts as they fall due in the usual course of business or if it does not have sufficient assets to satisfy its cumulative liabilities in full…

Upon learning of the receivership, Eagle notified the Receiver of its intention to take over operatorship. The Receiver responded that, because of the stay of proceedings, Eagle could not terminate Bumper’s operatorship and, as a result, Bumper remained as operator. In the interim, the Receiver undertook a sales process of Bumper’s assets (including its interests in the wells). Later, an agreement was reached that in the event Eagle was not the successful bidder for the properties, the Receiver would not entertain any offer to convey operatorship of Bumper’s assets. Bids were received from both Eagle and Forent Energy Ltd., with Forent being the successful bidder. A vesting order was granted subject to Eagle’s claim; the claim which formed the basis for this decision.

Ultimately, Justice Macleod decided that the JOA provided Eagle with a clear, contractual right to take over operatorship, despite the receivership and accompanying stay of proceedings. Stating that finding the contrary would “be tantamount to appropriating Eagle’s right for the benefit of Bumper’s creditors”, Justice McLeod lifted the stay and declared that Eagle was entitled to enforce the terms of the JOA.

As this was a liquidating receivership, the purpose of the stay was to permit the “orderly realization and distribution” of Bumper’s assets, rather than the ongoing survival of Bumper. This distinguishes this case from other insolvency proceedings where the goal is either to sell a company as a going concern or where the company is seeking to restructure its affairs. As stated by Justice Macleod at paragraph 20 of the decision, this liquidating scenario was different from that dealt with in the case of Norcen Energy Resources Ltd v Oakwood Petroleums Ltd (1988), 1988 CanLII 3560 (AB QB), 92 AR 81 (ABQB), 63 Alta LR (2d) 361:

In that case s. 11 of the Companies Creditor’s Arrangement Act, RSC 1970, c C-25 (CCAA) was at issue. Section 11 gives very broad powers to the Court in situations where arrangements involving compromise can be utilized to rescue insolvent companies. The CCAA has proved to be an extraordinarily flexible Act. The Act has been used effectively to give debtors respite from creditors in order to allow the stakeholders to negotiate a proposal for continuing the business, rather than allowing the business to fall into bankruptcy. Here, the issue is not Bumper’s survival but the realization on its assets.

In the Norcen case, the court upheld the stay and permitted the company under CCAA protection to retain operatorship in order to help facilitate it remaining a going concern.  In this case, Bumper’s assets were in the process of being sold and there was no “going concern” to be preserved.

So, what does this decision mean for joint-operator’s rights in the event of an insolvent operator? First, it clearly depends on the goal of the insolvency proceedings: sell off the assets of the debtor company or rearrange the debtor’s affairs and preserve its business as a going concern? Given this decision, a joint-operator is likely going to have more success enforcing its rights under a JOA when dealing with a liquidation scenario and, as a corollary, less success when the insolvent operator is using the process to restructure and carry on in operation. Second, this case illustrates the importance of being aware of an operator’s financial situation. In the event that an operator becomes insolvent or commits an act of bankruptcy, a notice to replace the operator should be served as soon as possible pursuant to the applicable replacement of operator provisions. Alternatively, if a trustee/receiver has already been appointed, contacting the trustee/receiver at the outset to advise of the intention to enforce the JOA and seeking the lifting of the stay early in the proceedings may be more likely to result in a decision in the joint-operator’s favour.

 

 

AER issues Bulletin 2016-21 to Clarify AER Bulletin 2016-16 – In Wake of Redwater (Take 2)

Posted in Mining, Oil & Gas Law, Project Development, Project Permitting, Public Utility, Regulatory, Regulatory Compliance
Comment

The AER has issued Bulletin 2016-21  to respond to the industry’s outcry to Bulletin 2016-16 which imposed a 2.0 LMR minimum threshold for eligibility to take transfers of AER-licensed assets.  Bulletin 2016-16 was in response to the Alberta Court of Queen’s Bench decision in Redwater Energy Corporation (Re), 2016 ABQB 278, which we previously commented on.

This Bulletin confirms the changes that it implemented in Bulletin 2016-16 which include that, in the interim, an LMR of 2.0 post-transfer is still the minimum threshold in order to be approved to take transfers.  However, the AER has now provided itself some discretion to approve transfers where the transferee may not have an LMR of 2.0.  In particular, the Bulletin provides in part that:

3)  As a condition of transferring existing AER licences, approvals, and permits, the AER will require transferees to demonstrate that they have a LMR of 2.0 or higher immediately following the transfer or provide other evidence that the transferee will be able to meet their obligations throughout the life cycle of energy development with an LMR of less than 2.0.

The AER has not specified by what means they will be satisfied that the transferee will be able to meet its “obligations throughout the life cycle of energy development.”

We further note that in the last paragraph of page 2 of the Bulletin it states: “For this reason, the AER will permit licensees to acquire additional AER-licensed assets if (i) the licensee already has an LMR of 2.0 or higher …”.  We have sought clarification from the AER as to whether this means that a transferee’s LMR may be below 2.0 post-transfer if pre-transfer they were above 2.0.

What does this mean to potential transferees?  There appears to be some reason for optimism.  However, given that this Bulletin encourages licensees with transactions in progress to “contact the AER to arrange a review of their specific circumstances” it would appear that guidance will only be provided on a case by case basis and only after the specifics of a transaction are already in place. Although this does open the door to allow transfers where a transferee will have an LMR of less than 2.0 post-transfer, it does not provide certainty prior to negotiating transactions.  In particular, it does not provide any guidance as to what particular factors will be considered and whether there is a minimum post-transfer LMR required in order for a company to avail itself of this discretion.

Doing Indirectly What You Cannot Do Directly: ROFR’s and the Duty of Good Faith

Posted in Mining, Oil & Gas Law, Project Development, Project Permitting, Public Utility, Regulatory, Regulatory Compliance
Comment

Can you ever do indirectly that which you cannot do directly? The answer appears to be yes, in certain circumstances according to the Saskatchewan Court of Queen’s Bench decision in Northrock Resources v ExxonMobil Canada Energy, 2016 SKQB 188.  This case considers this issue in the context of rights of first refusal (“ROFR”) when dealing with oil and gas transactions.

Among other issues, this case looks at whether a ROFR obligation exists when interests are transferred to an affiliate and then that affiliate is sold to a third party. Specifically, if a ROFR is owed to Northrock in the event that ExxonMobil disposes of its interests, and then ExxonMobil enters into transactions whereby it transfers its interest to its wholly owned subsidiaries (“Affiliates”) and then sells the shares of Affiliates to Crescent Point without providing a ROFR notice to Northrock, is this a breach of contract or a breach of a duty of good faith?

In this case the ROFR provisions provided for an exception where a transfer is to an affiliate. The issue arose as to whether the subsequent sale of that affiliate to a third party is circumventing the ROFR obligation. The case looked at the issue in the context of both breach of contract and breach of the duty of good faith, but our review focuses mainly on the duty of good faith.

Breach of Contract

Justice Currie concluded that the agreements containing the ROFR provisions provided for an exemption for transfers to affiliates and did not speak to any subsequent sale of the shares of such affiliate. At paragraphs 42 and 54 he states:

[42] I conclude that I am to construe the ROFR provisions on a plain, straightforward interpretation consistent with the ordinary meaning of the words and consistent with the other provisions of the agreements. If the ROFR provisions are unambiguous, I am to construe them accordingly and not inject terms that the parties had not inserted into the agreements.

[54] In addition, an examination of the ROFR provisions reveals that the parties to the agreements did not intend that every circumstance of a party divesting itself of an interest would trigger a ROFR. In negotiating the ROFR provisions they chose which divestitures would be singled out for a restriction on the right of a party to deal with its own property.

It would appear then that unless expressly prohibited, a sale to an affiliate and a subsequent sale of the affiliate’s shares to a third party will not be construed as a breach of contract with regards to ROFR obligations in CAPL Operating Procedures and other ROFR clauses that provide an exception for a disposition to an affiliate but do not include a provision that a ROFR is triggered by a change of control. The fact that there was ultimately a change of control of the assets does not in itself constitute a breach of the ROFR provisions.

Duty of Good Faith

Justice Currie reviewed the case law regarding the duty of honest contractual performance and the duty of good faith. Reference was made to the concept of duty of honest contractual performance introduced by the Supreme Court of Canada in Bhasin v Hrynew, 2014 SCC 71, [2014] 3 SCR 494 which states in part at paragraph 93:

… a duty of honest performance, which requires the parties to be honest with each other in relation to the performance of their contractual obligations.

but further clarifies at paragraph 65 that:

While “appropriate regard” for the other party’s interests will vary depending on the context of the contractual relationship, it does not require acting to serve those interests in all cases. It merely requires that a party not seek to undermine those interests in bad faith.

Justice Currie then concluded at paragraph 66 of this case:

I conclude that a breach of a duty of good faith may be established where a party is shown to have lied or misled, thereby breaching the duty of honest performance.

In looking at the duty of good faith in the context of a ROFR Justice Currie reviewed a trio of cases: GATX Corp. v Hawker Siddeley Canada Inc. (1996), 27 BLR (2d) 251 (Ont Ct J); Glimmer Resources Inc. v Exall Resources Ltd. (1997), 35 BLR (2d) 297 (Ont Ct J); and Chase Manhattan Bank of Canada v Sunoma Energy Corp., 2002 ABCA 286, 317 AR 308. Together these cases provide that a breach of the duty of good faith will not be found if the structure of the transaction was chosen for reasons other than to avoid a ROFR. For example, in paragraph 71 of GATX it states:

It is well established that the grantor of a right of first refusal must act reasonably and in good faith in relation to that right, and must not act in a fashion designed to eviscerate the very right which has been given. This is an illustration of the application of the good faith doctrine of contractual performance …

Based on his review of the ROFR cases Justice Currie determined that:

[66] … a breach [of a duty of good faith] may be established where a party is shown to have structured a transaction for the purpose of avoiding a ROFR.

[67] If, on the other hand, a structure was chosen for reasons other than to avoid a ROFR, then the choice of that structure did not constitute a breach of a duty of good faith.

In this case Justice Currie concluded that:

[104] The defendants did not lie. The defendants did not mislead. The defendants did not use the busted butterfly structure for the purpose of avoiding the ROFRs. Rather, they used it for other legitimate purposes – albeit recognizing that it would have (in their view) the side effect of not triggering ROFR notices. Knowledge does not always translate into intention, and in this case it did not.

Justice Currie acknowledges that another possibility exists i.e. that the avoidance of ROFRs was not the sole reason but was a reason contributing to the choice of structure. As he did not find that situation to exist on these facts he did not address this issue.

This case provides some direct precedent (at least at a Saskatchewan QB level) as to whether a ROFR obligation is triggered, where there is an affiliate exception, in the event that interests are transferred to an affiliate and then the affiliate is sold to a third party. It reaffirms that a breach of the duty of good faith will not be found if the structure of the transaction that is chosen has the effect of avoiding a ROFR if that was not the purpose for which the structure was chosen. However, it remains to be seen whether the courts will find it to be a breach of the duty of good faith where the avoidance of a ROFR is a contributing factor in choosing the structure of the transaction.

 

 

Federal Government Announces Review of Key Environmental and Regulatory Legislation and Processes

Posted in Aboriginal, Consultation, Environmental, Mining, Oil & Gas Law, Project Development, Project Permitting, Public Utility, Regulatory, Regulatory Compliance
Comment

On June 20, 2016 the Government of Canada announced its review of several environmental and regulatory processes. The review will focus on three areas:

  1. the federal Environmental Assessment process, which was revised in 2012 by the Conservative government,
  2. modernization of the National Energy Board, and
  3. the federal Fisheries Act and Navigation Protection Act, both of which were amended in recent years under the Conservative government.

This review follows up on the Liberal government’s earlier commitment to review and restore public confidence in federal environmental and regulatory processes. The reviews of the federal Environmental Assessment processes and of the National Energy Board will each be conducted by an Expert Panel established for that purpose. The review of the recent Fisheries Act and Navigation Protection Act amendments will be conducted by the Parliamentary Standing Committees on Fisheries and Oceans and on Transport, Infrastructure and Communities. All of these reviews will seek input from the Canadian public.

The draft Terms of Reference for the Expert Panels are open for public comment until July 20, 2016. The Expert Panels are expected to submit their reports to the applicable Ministers by January 31, 2017. Similarly, it is anticipated that the Parliamentary Standing Committees will submit their reports to Parliament in early 2017.

Notably, the draft Terms of Reference for the Expert Panels require those Panels to consider the relationship between the processes under review and the Aboriginal and treaty rights of Indigenous peoples, and to reflect the principles outlined in the United Nations Declaration on the Rights of Indigenous Peoples (UNDRIP). This follows Canada’s announcement at the United Nations in May 2016 that Canada is now a full supporter of UNDRIP, without reservation. How Canada will implement UNDRIP is an open question, but it appears that these reviews are expected to align with that plan.

The following sections describe each of these three reviews in more detail.

  1. Review of Environmental Assessment processes
  • The Minister of Environment and Climate Change will establish an Expert Panel to review federal environmental assessment processes associated with the Canadian Environmental Assessment Act, 2012 (CEAA 2012).
  • This includes a review of how environmental assessment is conducted by the three responsible authorities under CEAA 2012: the National Energy Board, the Canadian Environmental Assessment Agency, and the Canadian Nuclear Safety Commission.
  • The Expert Panel will engage and consult with the public, Indigenous groups and key stakeholders in order to develop recommendations for improving federal environmental assessment processes.
  • Input is invited from the public and Indigenous groups on the draft Terms of Reference for the Expert Panel until July 20, 2016. Comments may be submitted via the designated email address (CEAA.EAReview-ExamenEE.ACEE@ceaa-acee.gc.ca), and will be posted publically.
  • The Expert Panel is expected to consider the following matters:
    • How to restore robust oversight and thorough environmental assessments of areas under federal jurisdiction, while working with the provinces and territories to avoid duplication;
    • How to ensure decisions are based on science, facts and evidence and serve the public’s interest;
    • How to provide ways for Canadians to express their views and opportunities for experts to meaningfully participate;
    • How to require project advocates to choose the best technologies available to reduce environmental impacts; and
    • How to ensure that environmental assessment legislation is amended to enhance the consultation, engagement and participatory capacity of Indigenous groups in reviewing and monitoring major resource development projects.
  • In assessing practices and procedures, the Panel is to consider the relationship between environmental assessment processes and the Aboriginal and treaty rights of Indigenous peoples, and reflect the principles outlined in the United Nations Declaration on the Rights of Indigenous Peoples.
  • The Panel is also to consider how to enhance regulatory certainty in the development of major projects in Canada.
  • The Minister will establish a Multi-Interest Advisory Committee with representatives of Indigenous organizations, industry associations and environmental groups to provide advice to the Expert Panel.
  • The Expert Panel must provide its resulting report to the Minister by January 31, 2017, including the Panel’s conclusions, recommendations and rationale, as well as a summary of the input that the Panel receives.
  • Northern Environmental Assessment regimes that are applicable in Nunavut, the Northwest Territories and Yukon are not being reviewed by this Panel. Rather, the Minister of Indigenous and Northern Affairs is responsible for reviewing the northern Environmental Assessment regimes.
  1. National Energy Board Modernization
  • The Minister of Natural Resources has been given the mandate to modernize the National Energy Board and to ensure that its composition reflects regional views and has sufficient expertise in the fields of environmental science, community development, and Indigenous traditional knowledge.
  • The Government will establish an Expert Panel this summer that will consult with Indigenous peoples, key stakeholders and Canadians across the country and provide advice on potential reforms to the National Energy Board and the National Energy Board Act.
  • This review will focus on issues that fall outside the separate review of federal Environmental Assessment processes being conducted (described above) by the panel reporting to the Minister of Environment and Climate Change. The NEB modernization review will focus on the following matters:
    1. Governance and structure, including, among other things, composition and expertise the Board, as well as the governance and division of the NEB’s operational and adjudicative functions;
    2. Mandate and future opportunities, potentially including recommendations on defining and measuring public interest, and the possibility of expanding the mandate of the NEB to support the transition to a low carbon economy;
    3. Decision-making on major projects, including the assignment of decision-making as between the NEB, the Minister, and the federal Cabinet;
    4. Compliance, enforcement, and ongoing monitoring, particularly the legislative tools available to the NEB;
    5. Engagement with Indigenous peoples, including how the interests of Indigenous peoples are balanced against the many societal interests involved; and
    6. Public participation, including the potential for legislative changes to support increased stakeholder and public participation in NEB activities.
  • In assessing NEB activities the Panel is to consider the relationship between processes and the aboriginal and treaty rights of Indigenous peoples, and reflect the principles outlined in the United Nations Declaration on the Rights of Indigenous Peoples.
  • The draft Terms of Reference for the Expert Panel are available for public review and comment until July 20, 2016. Comments may be submitted by email to the following address NRCan.NEBModernization-ModernisationONE.RNCan@Canada.ca.
  • The Expert Panel is expected to provide a report with recommendations to the Minister of Natural Resources by January 31, 2017, which will be made public. The report is to include the Panel’s findings and recommendations to modernize the NEB, including potential legislative amendments, and a summary of the input received.
  1. Review of recent changes to the Fisheries Act and the Navigation Protection Act
  • The Minister of Fisheries, Oceans and the Canadian Coast Guard and the Minister of Transport are asking Parliament’s Standing Committee on Fisheries and Oceans and the Standing Committee on Transport, Infrastructure and Communities to examine changes made to the Fisheries Act in 2013 and to the Navigable Waters Protection Act (now called the Navigation Protection Act) in 2014.
  • Engagement with the provinces and territories will occur during the Summer of 2016.
  • Public engagement with the Standing Committees is to occur in the Fall of 2016. Canadians are welcome to submit briefs or to request to appear as witnesses before the Standing Committees. The public may also attend committee hearings or watch them on the parliamentary web channel.
  • Canadians are also encouraged to share their views online.
  • The Parliamentary Standing Committees are expected to submit their reports and recommendations to Parliament in early 2017.

The government’s June 20th announcement can be found at www.canada.ca/environmentalreviews.

We recognize that many of our clients and others may wish to submit recommendations to these reviews. If you would like assistance in that regard, please contact any of the following lawyers: Brad Armstrong, QC, Christine Kowbel, or Jennifer Nyland.

 

Death by a Thousand Cuts – AER Issues Bulletin 2016-16 – In Wake of Redwater

Posted in Mining, Oil & Gas Law, Project Development, Project Permitting, Public Utility, Regulatory, Regulatory Compliance
Comment

In response to the Alberta Court of Queen’s Bench decision in Redwater Energy Corporation (Re), 2016 ABQB 278, the Alberta Energy Regulator (“AER”) has issued Bulletin 2016-16 (the “Bulletin”) to minimize the risk to Albertans.

In Redwater the Court held that a trustee in bankruptcy has the right to disclaim unproductive oil and gas assets, including those subject to abandonment orders. This creates a risk that if the Orphan Well Association is unable to fund the increase in abandonment and reclamation liabilities from disclaimed assets, the obligation to do so will borne by Alberta taxpayers.

The Redwater case is under appeal. The Bulletin has been issued pending the earlier of the appeal decision in Redwater or the implementation of appropriate regulatory measures.  The Bulletin provides that effective immediately:

  1. The AER will consider and process all applications for licence eligibility under Directive 067: Applying for Approval to Hold EUB Licences as nonroutine and may exercise its discretion to refuse an application or impose terms and conditions on a licence eligibility approval if appropriate in the circumstances.
  2. For holders of existing but previously unused licence eligibility approvals, prior to approval of any application (including licence transfer applications), the AER may require evidence that there have been no material changes since approving the licence eligibility. This may include evidence that the holder continues to maintain adequate insurance and that the directors, officers, and/or shareholders are substantially the same as when licence eligibility was originally granted.
  3. As a condition of transferring existing AER licences, approvals, and permits, the AER will require all transferees to demonstrate that they have a liability management ratio (LMR) of 2.0 or higher immediately following the transfer.

Previously, a post transfer LMR of 1.0 was required under the Licensee Liability Rating Program. The AER acknowledges that the requirement of an LMR of 2.0 or higher is a significant change and that “these measures may inconvenience some stakeholders.” This is an understatement.

What are the ramifications of this policy?

  • It is likely that a reduction in eligible purchasers will result in fewer acquisition and divestiture (“A&D”) transactions being able to proceed, given that only 28% of licensees currently have an LMR of 2.0 or greater (219 of 788 licensees) (according to the AER Liability Management Programs Results Report dated June 4, 2016). In contrast, 54% of licensees currently have an LMR of 1.0 or greater (426 of 788 licensees);
  • We may see more negotiations providing for the purchaser to post security to offset any LMR shortfall reducing the purchase price for the assets and creating a further barrier to A&D activity;
  • The injection of new capital into the industry could be deterred by this dramatic and immediate increase in the LMR threshold;
  • There is a retrospective effect to this change given that many deals will have been in planning stages for months. Those transactions in particular that were slated for a second quarter closing may now be derailed with very little to no notice. Further, the Bulletin does not address whether closed deals with pending transfers are affected by this new policy; and
  • Perhaps corporate acquisitions rather than asset deals will be an alternative that is considered when dealing with asset transactions that would otherwise result in an LMR rating below 2.0.

The Bulletin does not explain why the AER has chosen an LMR of 2.0 as the new standard for transfers. At a time when the oil and gas industry is already suffering from a prolonged period of low commodity prices, a supply glut, increased taxes and a new carbon emissions regime, this additional hurdle to completing transactions may be unduly restrictive.

The Bulletin indicates that this change will only affect those wishing to acquire AER licensed assets so current licensees with an LMR rating under 2.0 not contemplating any transactions should not be directly affected by this change. In addition, the Bulletin indicates that these are temporary measures and that it will work with industry, other stakeholders and the Government to develop broader and more permanent regulatory measures to ensure that environmental obligations are met by industry. However, this does beg the question of whether increased LMR requirements for all licensees are forthcoming.

Hopefully a full and meaningful consultation with industry does occur and a balance is achieved that will allow the industry to recover and grow while ensuring that abandonment and reclamation obligations are met by industry and not passed on to the Alberta taxpayers.

“Supreme Court of Canada to hear appeal on Yukon Peel watershed decision”

Posted in Aboriginal, Constitutional Law, Consultation, Mining, Oil & Gas Law, Project Development, Project Permitting, Regulatory
Comment

Update: On June 9, 2016, the Supreme Court of Canada agreed to hear an appeal from Yukon Court of Appeal’s Peel watershed decision.  Click here to read our earlier blog post on the Court of Appeal’s decision handed down November 4, 2015.

Alberta Energy Regulator Issues Announcement Regarding Licensee Obligations in the Event of Insolvencies

Posted in Mining, Oil & Gas Law, Project Development, Project Permitting, Public Utility, Regulatory, Regulatory Compliance
Comment

On April 8, 2016, the Alberta Energy Regulator (“AER”) sent a sombre reminder to licensees and their directors and officers, of their corporate responsibilities when ceasing operations because of insolvency or for any other reason. Bulletin 2016-10 reinforced the need for compliance with all AER requirements when ceasing operations. Among several other obligations, such as ensuring continued care of AER licensed properties and maintenance of records, the bulletin stressed that either approval for transfer of licences, approvals and permits to an eligible party (i.e. with an LMR of at least 1.0 post-transfer) under Directive 006 be obtained; or abandonment and reclamation of all sites be in compliance with AER requirements; or that security be posted in accordance with Directive 006.  If a licensee fails to meet these obligations, the AER may pursue various enforcement measures not only against the licensee but may also name individual directors and officers of the licensee under Section 106 of the Oil and Gas Conservation Act (“OGCA”).

Section 106 of the OGCA provides, among other things, that where a licensee, approval holder or working interest participant contravenes or fails to comply with an order of the AER, or has an outstanding debt to the AER, or to the AER to the account of the orphan fund, in respect of suspension, abandonment or reclamation costs, and where the AER considers it in the public interest to do so, the AER may make a declaration setting out the nature of the contravention, failure to comply or debt and naming one or more directors, officers, agents or other persons who, in the AER’s opinion, were directly or indirectly in control of the licensee, approval holder or working interest participant at the time of the contravention, failure to comply or failure to pay.

In past AER decisions, including Decision 2015 ABAER 005, citing Decision 2011 ABERCB 037, the AER has confirmed that the purpose of a Section 106 declaration is to prevent a licensee or a person in control of a licensee from continuing to breach AER requirements and orders and from incurring abandonment costs or incurring new breaches or additional debts, thereby safeguarding the public interest.

The test for a section 106 declaration, as set out by the AER in Decision 2015 ABAER 005 (at para 16), is as follows:

  • Were there contraventions of or failures to comply with AER orders?
  • If there was a contravention or failure, was the director, officer, or other person in direct or indirect control of the relevant company at the relevant time?
  • If there was a contravention or failure, and such person was in control, is the requested declaration and order in the public interest?

Further, the AER has indicated in Decision 2015 ABAER 005 (at para 41) that the public interest purposes of a section 106 declaration include:

  • To protect the public and the environment,
  • To ensure confidence in the regulatory scheme,
  • To deter like-minded individuals from engaging in similar conduct, and
  • To serve as a warning to others who may engage in business with the named individuals.

Bulletin 2016-10 does not break new ground in terms of adding new obligations. But it does remind officers or agents of companies that should a company fail in its AER obligations it could be subject to enforcement proceedings by the AER. In addition to other sanctions, notably Section 106(3) of the OGCA provides that named officers, directors or agents may be responsible for payment of abandonment and reclamation deposits in an amount determined by the Regulator.

What are the implications of this? This is merely a reminder of already existing sanctions available to the AER. However, at a time in the industry where we are likely to be seeing more insolvencies, officers, directors or other persons in control of companies should heed this warning and be aware of whether such companies are AER non-compliant.

The Daniels Decision: All Aboriginal Peoples, including Métis and non-status Indians, are “Indians” under section 91(24) of the Constitution Act, 1867

Posted in Aboriginal, Constitutional Law, Consultation
Comment

The Supreme Court of Canada has handed down its decision in the Daniels case. The Supreme Court’s decision resolves a question of constitutional responsibility for Aboriginal peoples other than First Nations and Inuit — Canada’s Métis and non-status Indians.

Under section 91(24) of the Constitution Act, 1867, the federal Parliament has exclusive legislative authority for “Indians, and Lands reserved for the Indians.” In 1939, a decision of the Supreme Court confirmed that Inuit are also “Indians” within the meaning of section 91(24). However, there has been uncertainty about which level of government — federal or provincial — has constitutional authority in relation to Métis and non-status Indians. Neither level of government has been keen to assert constitutional jurisdiction — in part due to the obligations to provide programs and services that may flow from that constitutional jurisdiction.

As a result, in 1999 four individual claimants, along with the Congress of Aboriginal Peoples, commenced this action against the Government of Canada in the Federal Court seeking a declaration that Métis and non-status Indians fall within federal jurisdiction. They also sought declarations that the Crown owes a fiduciary duty to Métis and non-status Indians, and that the Métis and non-status Indians have a right to be consulted and negotiated with by the federal government respecting their rights, interests and needs as Aboriginal peoples.

Federal Court Decision

At trial, the claimants succeeded in obtaining the first declaration. The Federal Court held that Métis and non-status Indians, as defined in the decision, were Indians, within the meaning of the expression “Indians, and Lands reserved for the Indians” in section 91(24) (Reference Re Eskimos, [1939] S.C.R. 104). However, the Federal Court refused to grant the other two declarations sought, regarding the Crown’s fiduciary duty and the right to be consulted by and negotiate with the federal government, on the grounds that the declarations sought were vague and redundant.

Federal Court of Appeal Decision

Canada appealed the part of the Federal Court decision declaring Métis and non-status Indians to be Indians within the meaning of section 91(24). The claimants appealed the part of the Federal Court decision refusing to grant the other two declarations sought.  In April 2014, the Federal Court of Appeal released its decision.

The Federal Court of Appeal upheld the trial court’s finding that Métis are to be considered Indians as that term is used in section 91(24). However, the Federal Court of Appeal held that non-status Indians were clearly “Indians,” and therefore there was no practical utility in declaring that non-status Indians are also Indians within the meaning of section 91(24). The Federal Court of Appeal therefore excluded non-status Indians from its declaration and upheld the trial court’s decision not to grant the other two declarations.

Supreme Court of Canada Decision

With its decision, the Supreme Court has resolved this long-standing area of constitutional uncertainty. The Supreme Court held that all Aboriginal peoples of Canada are “Indians” as that term is used in section 91(24). The Court noted that, historically, the federal government wanted authority over all Aboriginal peoples, including Métis, to ensure that it had the jurisdiction needed to complete nation-building initiatives such as construction of a national railway. In addition, Canada had at times legislated in respect of Métis, and often assumed for policy purposes that its jurisdiction under section 91(24) extended to Métis people. The Court also noted that reading section 91(24) of the Constitution Act, 1867, as applicable to all Aboriginal peoples made sense in light of section 35 of the Constitution Act, 1982, which defines Canada’s Aboriginal peoples to include Indians, Inuit and Métis: the Court held that it would be constitutionally anomalous for Métis to be the only Aboriginal people to be expressly recognized and included in section 35, but excluded from the constitutional scope of section 91(24). As a result, the Supreme Court upheld the trial court’s decision to declare that both Métis and non-status Indians are “Indians” for the purposes of section 91(24) of the Constitution Act, 1867.

The Supreme Court noted that exclusive federal jurisdiction over Métis and non-status Indians did not necessarily render invalid provincial legislation pertaining to Métis or non-status Indians. The Court emphasized that courts should favour the ordinary operation of statutes at both levels of government, and that federal authority is not a bar to provincial schemes that do not impair the core of the federal power over “Indians” under section 91(24).

The Supreme Court also upheld the trial court’s decision not to grant the second and third declarations sought, on the grounds that they lacked practical utility. The Court noted that it is already settled law that the Crown is in a fiduciary relationship with Aboriginal peoples, and that the Court has already recognized a context-specific duty on the Crown to negotiate when Aboriginal rights are engaged.

Implications of the Decision

Daniels’ clarification of constitutional authority to make laws about Métis and non-status Indians removes a significant area of jurisdictional uncertainty. What will flow from that clarification is less clear. The federal government argued before the Supreme Court that, even if it were found to have legislative authority over Métis and non-status Indians, that would not mean that Parliament would be obligated to exercise that authority. On one level, this is correct — while Inuit are within federal legislative competence under section 91(24), Parliament has not enacted a legislative regime for Inuit peoples comparable to the Indian Act regime applicable to most First Nations.

However, on another level, questions may arise as to the extent to which the federal government can lawfully, or legitimately, discriminate between programs and services provided to the different Aboriginal peoples that are now recognized as being within federal jurisdiction. The recent decision of the Canadian Human Rights Tribunal in relation to Canada’s obligation to provide child welfare services to children on reserves at levels comparable to services provided to children off reserve is an example of the type of discrimination-based claims that the Daniels decision may facilitate for Métis and non-status Indians. The decision may also provide policy-based justification for making federal programs and services more available to Métis and non-status Indians. In this sense, the Daniels decision could have significant implications for the federal government.

The decision is unlikely to have any direct consequences for consultation obligations with Métis and non-status Indians in the context of resource development projects. The Supreme Court refused to grant the declarations sought by the claimants in relation to the Crown’s fiduciary relationship with Métis and non-status Indians, and in relation to the Crown’s obligation to consult and negotiate with Métis and non-status Indians, on the grounds that those were matters of settled law. The Crown’s fiduciary relationship with Métis peoples was confirmed in the Manitoba Métis Federation decision. The Crown’s consultation and negotiation obligations in relation to Aboriginal rights have been addressed in decisions like Haida Nation and Tsilhqot’in Nation. While the Daniels decision may not change the law in these areas, it will be seen as a victory for Métis and non-status Indians and may, in turn, encourage use of regulatory and other legal proceedings to assert Aboriginal rights and a right to be consulted about government decisions affecting those rights.

It is also unclear where the Daniels decision leaves provincial legislation like the Alberta Metis Settlements Act. This provincial law establishes eight Métis settlements, sets out eligibility for membership in the settlements, establishes their governance structures, and provides a land base for those settlements. There is a long line of cases that holds that a provincial law which goes to the core of federal jurisdiction under section 91(24) is either beyond the powers of the provincial legislature to enact, or constitutionally inapplicable to First Nations, their lands and their members. However, the Supreme Court stated in Daniels that federal jurisdiction over Métis and non-status Indians does not necessarily mean that provincial legislation pertaining to Métis and non-status Indians is inherently beyond the power of provincial legislatures, and emphasized that courts should try to find ways to uphold the validity of laws of both levels of government. In addition, a recent decision of the Supreme Court considered a dispute arising under the Metis Settlements Act (RSA 2000, c M-14) without questioning the constitutional validity of the Act — although its validity was not before the Court in that case.  Nevertheless, the Daniels decision creates uncertainty about the validity the Metis Settlements Act. This will be a continuing concern not only for the Métis settlements and their members, but also for third parties who have been granted rights and tenures pursuant to the Act.

New Consultation Policy and Guidelines for Métis Settlements in Alberta

Posted in Aboriginal, Constitutional Law, Consultation, Project Development, Project Permitting, Regulatory, Regulatory Compliance
Comment

On April 4, 2016, the Government of Alberta (“GoA”) implemented its first formal consultation process between the government, project proponents, and Métis Settlements with the release of The Government of Alberta’s Guidelines on Consultation with Métis Settlements on Land and Natural Resource Management, 2016 (“Guidelines”) and The Government of Alberta’s Policy on Consultation with Métis Settlements on Land and Natural Resource Management, 2015 (“Policy”)The Guidelines and Policy apply to the eight Métis Settlements created under the Alberta-Métis Settlements Accord, but do not apply to consultations with other Métis groups in Alberta.

The Métis consultation process is closely modeled after the current First Nations consultation policy and guidelines which came into effect in 2013. The GoA has said that development of the Policy aligns with its commitment to implement the objectives and principles of the United Nations Declaration on the Rights of Indigenous People (“UNDRIP”). For more information on UNDRIP, see our previous blog post.

The Guidelines provide for consultation on strategic and project-specific decisions that have the potential to adversely impact Métis Settlement members’ harvesting or traditional use activities. Decisions that trigger consultation could include regulatory changes, infrastructure and facility development, policy development and planning initiatives. The Guidelines are intended to clarify the expectations of parties engaged in the consultation process and provide an overview of the procedures to follow. The process, however, is meant to be flexible enough to allow the GoA to assess consultation requirements on a case-by-case basis.

Under the Guidelines, the GoA is responsible for overseeing and managing the substantive aspects of consultation. This includes: a) whether consultation is triggered; b) the depth of the consultation; c) providing notice to the Métis Settlement; d) considering information to the specific project; and, e) assessing accommodation. Similar to consultation requirements with First Nations, the GoA may delegate procedural aspects but retains the sole responsibility for overseeing the overall consultation process and ensuring that the proponent’s consultation activities comply with the Policy and Guidelines.

The Guidelines also include two appendices. The appendices provide further information for sector-specific consultation. Generally, if consultation was deemed adequate within the past two years or if amendments and renewals are within the scope of the original approval, consultation may not be required.

Involvement of the Alberta Energy Regulator

For activities requiring Alberta Energy Regulator (“AER”) approval, the Aboriginal Consultation Office (“ACO”) will manage the consultation process for the GoA. Interaction between the ACO and AER will be described in a new Ministerial Order and the ACO and AER will either create or update the existing joint operating procedures to set out the operations of the ACO and the AER on matters relating to Métis Settlements consultation. Once consultation has been completed, the ACO will decide whether consultation was adequate and provide that decision to the AER. The Guidelines provide that the ACO will work closely with the AER so that consultation requirements for applications made to the AER will occur prior to the AER’s regulatory decision.

Timelines

Generally, the GoA assessment of consultation adequacy will occur within statutory and regulatory timelines, depending on the specifics of the proposed project or initiative, consultation timelines may vary. Through the delegation process, project proponents may be required to notify and engage with Métis Settlements to discuss project-specific issues and possible mitigation. Proponents are encouraged to notify and consult with Métis Settlements as early as possible in the pre-application stage and must document their consultation activities. The consultation record is shared with Métis Settlements and GoA staff.

The Guidelines provide timelines for three levels of consultation, depending on whether the project has a low, moderate or high impact. The Métis Settlement has between 15-20 days to respond to notification and the consultation process may last anywhere from 15 to 60 days.

Comparison to Consultation with First Nations

The Guidelines are comparable to The Government of Alberta’s Guidelines on Consultation with First Nations on Land and Natural Resource Management, July 28, 2014. The purposes of both guidelines are similar and the primary goal of accommodation remains to avoid, minimize, or mitigate adverse impacts of a Crown decision. There are not substantive differences between the two policies and guidelines.

In terms of the stages of consultation, proponents can continue to follow the same process with Métis Settlements as they have been following with First Nations. The consultation process is identical in both guidelines.

As noted at the outset, the Policy and the Guidelines only apply to consultations with Alberta’s eight Métis Settlements. Although reports have suggested that the GoA is discussing consultation processes with other Alberta Métis groups, this announcement does not apply to those groups, or shed any light on whether or how the GoA will approach consultations with them.

Government of Canada Proposes Methodology for Estimating Upstream GHG Emissions in Major Project Review

Posted in Aboriginal, Consultation, Environmental, Mining, Oil & Gas Law, Project Development, Project Permitting, Regulatory, Regulatory Compliance
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Late last week, the Government of Canada released a proposed methodology for estimating upstream GHG emissions from proposed oil and gas projects undergoing federal environmental assessment. This comes on the heels of the Government’s announcement in late January of its new guiding principles for project review, one of which included assessment of “direct and upstream greenhouse gas emissions linked to the projects under review” (see our previous blog post here). Interested parties have until April 18 to provide comment to the Oil, Gas and Alternate Energy Division of Environment and Climate Change Canada, following which a final methodology will be developed.

What does “upstream” mean? The proposed methodology defines upstream to include all industrial activities from the point of extraction to the project under review. While the specifics will vary by resource and project type, in general this would include extraction, processing, handling and transportation. The example provided in the proposed methodology is that an upstream GHG assessment of a crude oil pipeline project would include the following activities:

  • Extraction — crude oil and gas wells and oil sands mining and in situ facilities;
  • Processing — field processing and upgrading, if occurring;
  • Handling — product transfer at terminals; and
  • Transportation — any pipeline operation in advance of the project.

Having defined the scope of what will be assessed, the proposed methodology then sets out a two part assessment:

  1. a quantitative estimation of the GHG emissions released as a result of upstream production associated with the project, and
  1. a discussion of the project’s potential impact on Canadian and global GHG emissions.

The first component, quantitative estimation, will take into account emissions from the upstream activities “exclusively linked to the project,” such as emissions from combustion or from fugitive, venting and flaring gas emissions. An example of a quantitative estimate that Environment and Climate Change Canada developed for the proposed Pacific Northwest LNG project can be found here.

The second component is intended to assess the conditions under which the Canadian upstream emissions estimated in the first component could be expected to occur even if the project were not built. The baseline for any such assessment under the proposal would require an examination of current production levels and the expected growth of resource production in Canada, as well as the potential global markets for future resource production growth with and without the proposed project.

Project proponents, opponents, and regulators that have been through the EA process in the past will be familiar with the second component of the methodology in particular, as uncertainty with respect to whether upstream impacts will actually occur with or without any particular project has frequently been relied on by regulators in the past as a basis to deny consideration of upstream effects.  It remains to be seen whether this newly proposed methodology, focussing not only on Canadian but also on global market conditions for resource growth within which to benchmark a project’s emissions, will allow regulators to make the assessments they have previously said they are unwilling or unable to make.