2014 was a landmark year for legislative and regulatory changes relevant to the oil and gas sector. The federal government not only introduced pipeline safety legislation in furtherance of its Responsible Resource Development policy framework, but also required additional financial reporting from the natural resource industry. Ottawa was conspicuous by its absence in 2014 respecting greenhouse gas policy, perhaps the biggest regulatory story of the year. However, several of the provinces jumped into the breach through their own carbon mandates, a trend which may continue in 2015.

Provincial energy regulation was especially active in 2014, if not exactly coherent with each other. British Columbia introduced LNG-driven reforms in tax and facilities regulation to provide clarity to potential investors. Alberta enhanced its aboriginal consultation framework and significantly expanded the energy regulator’s jurisdiction. Saskatchewan, Manitoba and Ontario were relatively quiet on the legislative front. Québec and New Brunswick took measures to block oil and gas development generally, and fracking in particular.

On the international front, the federal government sanctioned Russia’s oil and gas industry, monitored US political developments on Keystone XL and weathered impacts of rapidly declining oil prices, including a deferral of the federal budget until later this year. These political issues will continue to intersect with economic and regulatory ones in 2015. For Canadian energy companies, we expect that navigating the shoals of legislation and regulations across the country will never be as important – or difficult – as in the upcoming year.

1. Safety in Numbers? “Polluter Pay” To Be Enshrined Under New Federal Pipeline Legislation

On December 8, 2014, Canada’s Minister of Natural Resources introduced Bill C-46, entitled the Pipeline Safety Act. It amends the National Energy Board Act and the Canada Oil and Gas Operations Act to increase the National Energy Board’s (“NEB”) oversight powers as well as pipeline operators’ liability. Together with new rail safety and tanker safety regulations, these regulatory changes enhance the federal regime for transporting oil, petroleum, and natural gas products.

New NEB powers include:

  • ordering any company that operates a pipeline from which an unintended or uncontrolled release of oil, gas or any other commodity occurs, to reimburse government institutions for costs incurred in taking any action respecting the release;
  • ordering pipeline companies to maintain funds to pay for the abandonment of their pipelines; and
  • taking, under certain circumstances, any action it considers necessary respecting an unintended or uncontrolled release of oil, gas or any other commodity from a pipeline.

New liability measures include:

  • reinforcing the “polluter pays” principle;
  • confirming that liability of pipeline companies is unlimited if an unintended or uncontrolled release of oil, gas or any other commodity is a result of fault or negligence;

establishing liability limits, without proof of fault or negligence, at no less than $1 billion for companies that operate pipelines with capacity to transport at least 250,000 barrels of oil per day and at an amount prescribed by regulation for companies that operate any other pipelines;

  • requiring that pipeline companies maintain the financial resources necessary to pay the applicable liability limits; and
  • requiring pipeline companies to remain responsible for their abandoned pipelines.

In addition, Bill C-46 allows the Governor in Council to establish, in certain circumstances, a pipeline claims tribunal to examine and adjudicate compensation claims for damage caused by an unintended or uncontrolled release of oil, gas or any other commodity from a pipeline. Other anticipated federal policy development includes enhanced involvement of Aboriginal communities in pipeline safety operations and further NEB guidance on best available technologies.

Bill C-46 will place a new, significant onus on pipeline companies to ensure that: (a) operations do not result in releases; and (b) if such releases occur, necessary financial resources to meet any liability exist. Accordingly, pipeline companies must assess their safety and financial obligations to ensure they meet legislated requirements once Bill C-46 becomes law.

2. Publish What You Pay – Ottawa Enhances Financial Transparency for Oil and Gas Companies

On December 16, 2014, the Government of Canada gave Royal Assent to the Extractive Sector Transparency Measures Act, sweeping legislation which establishes new mandatory reporting standards for extractive companies. Its focus is payments made to foreign and domestic governments at all levels. The purpose of these new requirements is to improve transparency within the natural resources industry and to achieve alignment with similar measures set out in the European Union and the United States. Key aspects of the new legislation include who is required to report, what must be reported, and the scope of compliance.

Reporting is now required for any entity engaged in the commercial development of oil, gas or minerals in Canada or elsewhere, including exploration and extraction and the acquisition or holding of permits, licenses, leases or other authorizations for such purpose and that either:

  • is listed on a stock exchange in Canada; or
  • has a place of business, does business or has assets in Canada and, for at least one of its two most recent financial years, meets at least two of the following three thresholds:
    • the company has at least CDN $20 million in assets;
    • the company has at least CDN $40 million in revenue; and/or
    • the company employs an average of at least 250 employees.

The Act requires affected entities to report certain payments respecting the commercial development of oil, gas or minerals during a financial year that exceed the amount prescribed by regulation. If no amount is prescribed, then the threshold amount is CDN $100,000 and includes payments to all levels of government, domestically and internationally of the following nature, either monetary or “in kind”:

  • taxes, other than consumption taxes and personal income taxes;
  • royalties;
  • fees, including rental fees, entry fees and regulatory charges as well as fees or other consideration for licences, permits or concessions;
  • production entitlements;
  • bonuses, including signature, discovery and production bonuses;
  • dividends, other than dividends paid as ordinary shareholders; and
  • infrastructure improvements payments.

The Act does not specifically include “Aboriginal government” in the definition of Payees. However, section 29 clarifies that reporting to an Aboriginal government will be required two years after the Act is brought into effect by Order in Council.

Turning to compliance, the Canadian Government may require the provision of any information and documents, including a list of projects for the commercial development of oil, gas or minerals in which the entity has an interest and the nature of that interest, an explanation of the treatment of the payment by the entity, a statement of any policies that the entity has implemented for the purpose of compliance with the proposed legislation and the results of an audit of its report.

In the event of non-compliance with the reporting requirements, the Canadian Government may impose corrective measures. In addition, any person or entity would be liable to a fine of not more than $250,000 for the following:

  • failing to comply with the reporting standards or any corrective measures;
  • knowingly making false or misleading statements or providing false or misleading information; or
  • structuring payments or any other financial obligations or gifts, whether monetary or in kind, that relate to its commercial development of oil, gas or minerals, with the intention of avoiding the requirement to report.

The Act grants no exemptions. It instead includes a broad due diligence defence against liability, if the person or entity can establish that it “exercised due diligence to prevent” the commission of the offence. The new legislation will significantly increase the complexity and depth of financial reporting requirements for the Canadian oil and gas industry – as well as the risks of non-compliance and reputational damage.

3a No Change? The Absence of Federal Climate Change Policy in 2014 Is A Key Regulatory Development

Notwithstanding Prime Minister Harper’s suggestions in late 2013 that a national climate change regime would be forthcoming, the absence of federal legislation on climate is one of the most important policy developments of 2014. Perhaps as important are the activities Canadian provinces take independently of the federal government, outlined in greater detail below.

3b All Change? – Provinces Move Forward On Climate Change Policy

On October 20, 2014 the British Columbia government introduced new legislation to control greenhouse gas (“GHG”) emissions from industrial operations. Bill 2, the Greenhouse Gas Industrial Reporting and Control Act is a critical change in the province’s approach to GHGs and more closely aligns BC with the Alberta approach. The bill proposes intensity-based emission standards, and the broadening of alternative compliance mechanisms to include credits from offsets, payments to technology funds, and earned credits.

In Alberta, at the end of 2014, the provincial government extended the four key regulations that set out Alberta’s intensity-based greenhouse gas regulation program – the Specified Gas Emitters Regulation, the Specified Gas Reporting Regulation, the Administrative Penalty Regulation, and the Climate Change and Emissions Management Fund Administration Regulation – to June 2015. Until the change, all four regulations were set to expire on December 31, 2014.

The Alberta regulatory regime has been in place since 2007 and provides the framework for the reduction of greenhouse gas emissions intensity levels from large industrial emitters. Alberta requires facilities that emit more than 100,000 tonnes of GHGs a year to reduce emissions intensity by 12 per cent. Companies may choose to pay $15 per tonne for every tonne of emissions over their required reduction into the Climate Change and Emissions Management Fund.

In addition to being necessary to maintain its regulatory framework, the Alberta Government states that the extension until 2015 is to “ensure the smooth transition from the current strategy to the new framework expected be in place in the new year”. The Alberta Government further indicates that it is “exploring options to address climate change”. There are no further details on what those options include.

In 2014, provinces moved forward on cross-border policy development. In November, 2014 Ontario and Québec issued a Memorandum of Understanding agreeing to collaborate on “concerted climate change actions”. This will likely include harmonizing data collection and greenhouse gas reporting requirements, exploring the use of market based mechanisms in Ontario, sharing knowledge and promoting the transition to a low carbon economy through initiatives such as setting a price on carbon and adopting cleaner fuel standards. Ontario and Québec have agreed to increase collaboration with the Canadian Government as well as provincial and territorial governments. The Ontario-Québec Memorandum of Understanding does not create legally binding obligations on either province and may be terminated on two months’ notice.

In December, 2014 the governments of Ontario, Québec and British Columbia, together with the government of California, issued a Joint Statement on Climate Change. The result was an agreement to collaborate on mid-term GHG emissions reductions to maintain momentum toward 2050 targets. The December announcement follows on from the California Air Resources Board and Québec Ministry of Sustainable Development holding the first joint action of GHG allowances. The joint Québec-California program permits companies to trade carbon allowances across jurisdictions to comply with GHG emission limits.

In a federal election year with plunging oil prices, climate change legislation at the national level will likely remain elusive. However, provinces have clearly stepped into the climate change space. Whether this creates a jurisdictional collision course or simply a stopgap until the federal government enters into the legislative fray remains to be seen. One thing is certain. It will be essential for Canadian oil and gas companies to understand and respond to the impacts of climate change regulation, whether at the provincial, federal or ultimately both levels of government.

4. Finally LNG? British Columbia’s Introduction of an LNG Tax Regime

On October 21, 2014, the British Columbia Government introduced Bill 6, the Liquefied Natural Gas Income Tax Act. The bill, which creates BC’s first liquefied natural gas (“LNG”) tax regime, is viewed by policy-makers and industry alike as critical for the progress of LNG in Canada. Specifically, the bill provides clarity for project proponents to reach a final investment decision. Under Bill 6, BC’s new tax regime will take effect on January 1, 2017.

BC’s proposed LNG tax essentially has two parallel, but different, rates of taxation. A lower tax rate will apply if an LNG operator has losses and can claim depreciation for costs it incurs in developing its LNG facilities. A higher tax rate will apply when there are no losses or depreciation.

The lower tax rate applies as follows:

  • when commercial LNG production begins, an operator will pay a 1.5% tax on “net operating income”; and
  • no federal depreciation or capital cost allowance is recognized. There is a special deduction from a capital investment account. This account includes all costs associated with constructing the LNG plant.
  • The higher tax rate applies as follows:
  • if there is no capital investment account and no losses to be claimed, a higher rate of tax will apply. This rate is currently 3.5%; and
  • any taxes paid under the higher rate can be deducted as a credit in determining tax exposure under the second rate.

The new BC LNG tax applies on a project by project basis. It applies even if a project operator or participant is not a resident of, or permanently established in, Canada. Project proponents may not be subject to federal or provincial income tax, yet still captured by the LNG tax regime. We anticipate more regulatory detail on the LNG tax in 2015, particularly respecting administrative and enforcement measures and the prescribed rate for adjusted capital investment account deductions.

5. LNG Redux? More Regulations from the OGC

On July 21, 2014, the British Columbia Oil and Gas Commission (“OGC”) enacted the new Liquefied Natural Gas Facility Regulation (“Regulation”). This provides a new regulatory framework for LNG facilities and updates LNG-related provisions previously in the BC Pipeline and Liquefied Natural Gas Facility Regulation. The OGC has also issued version 1.0 of its Liquefied Natural Gas Facility Permit Application and Operations Manual (“LNG Facility Manual”), which provides guidance for applicants seeking to construct an LNG facility. The Regulation is limited to LNG facility sites only, and not upstream aspects of natural gas extraction, production and transportation.

The Regulation covers a wide scope of technical requirements for LNG facilities:

  • the LNG facility permit application process, through the construction, operation, decommissioning and reclamation phases; and
  • notice and reporting requirements for all project applicants and permit holders during various project phases.

The regulation further empowers the OCG to make individual facility-specific decisions based on the technical details set out in project applicants’ reports and sets out overarching occupational health and safety program requirements, including emergency response planning.

One of the complexities of the new LNG framework is the OGC’s discretion to exempt an LNG facility permit holder from one or more provisions of the Regulation on a case-by-case basis. Although an LNG project proponent may successfully apply for, and receive an exemption, the OGC retains the ability to impose conditions on that exemption. It therefore remains to be seen how widely the OGC will grant exemptive relief to LNG facility permit holders.

Turning to the LNG Facility Manual, it sets out an overview of the current provincial LNG scheme, as well as detailed guidelines for the rules and procedures set forth in the Regulation. More specifically, it addresses LNG facility life cycle matters including water use, engineering and geotechnology.

The Regulation and the LNG Facility Manual establish an overview of the LNG approval regime in British Columbia. They provide guidance to LNG facility proponents and permit holders on a variety of regulatory and technical issues. Despite this additional guidance, areas of uncertainty remain within British Columbia’s LNG regulatory system. These questions will undoubtedly emerge on a case by case project basis. So too, will challenges to the OCG’s newly released framework for LNG development.

6. Under Water? The BC Water Sustainability Act Receives Safe Passage

On May 20, 2014, the BC Water Sustainability Act (the “WSA”) received Royal Assent. The WSA is a major reworking of BC’s water protection, management and regulation. Key elements of the WSA include:

  • eliminating a distinction between the surface water and groundwater under the old Water Act – the first time that BC has extended the regulatory regime for surface water to groundwater;
  • non-domestic users of groundwater must apply for a license if they plan to divert or use groundwater;
  • groundwater users will be prioritized on the same “first in time, first in right” basis as surface water users currently are under the Water Act, with the exception of a super-priority for “essential household uses”;
  • current groundwater users will be required to transition to the WSA regime by applying for, and obtaining, a water-use license;
  • domestic users of groundwater are not required to obtain a water license or pay annual water rental fees;
  • the quick-licensing procedures for certain classes of applications, primarily small scale domestic and irrigation use, have been retained under the WSA;
  • existing licenses granted under the Water Act will be grandfathered into the new regime under the WSA; and
  • the WSA increases the provincial government’s ability to regulate water use during times of scarcity.

Water Sustainability Plans are a critical portion of the WSA. Under the Act the BC government has broad powers to develop and enforce such plans. A further change to the rules is the ability for the development of Water Sustainability Plans to be delegated to groups other than the provincial government, which is intended to encourage community involvement.

The WSA retains the general rule from the Water Act that where water is diverted, it must be put to a “beneficial use”. This term was not defined in the Water Act. Instead, the WSA defines “beneficial use” as using water “as efficiently as practicable” and in accordance with any applicable regulations.

Turning to timing, the WSA sets a default 30 year review period for all water licenses. The new review period will apply to existing licenses. There are three exceptions to the default review period:

  • licences issued for a power purpose or a storage purpose related to a power purpose;
  • licences issued under the Industrial Development Act; and
  • licences reviewed or issued following a review under the 1998 Water Use Plan Guidelines.

The WSA retains the Water Act’s offences and enforcement measures. However, it grants discretion to the Comptroller of Water Rights to impose administrative monetary penalties on persons who have contravened the WSA, breached a term or condition of a water license, or failed to comply with an order under the WSA. Administrative penalties offer an alternative to ticketing or criminal prosecution and allow the WSA to be enforced without having to establish liability in court. Persons receiving administrative monetary penalties are entitled to notice, a hearing, and the ability to appeal the decision of the hearing to the Environmental Appeal Board. The amount of the administrative monetary penalties will be established by regulation.

7. Matters Under Consultation – Changes To First Nations Engagement in Alberta

2014 brought a major development in Alberta’s approach to consultation with First Nations. The Alberta government released the final version of its Consultation Guidelines in July 2014 to clarify the First Nation consultation processes. Alberta’s Consultation Guidelines outline activities in various sectors, including pipelines and petroleum, natural gas and oilsands that require consultation.

The Consultation Guidelines’ primary effect is the identification of anticipated levels of consultation for various activities within each industry sector, and the timelines within which consultation is expected to take place for each of these activities. The guidelines provide additional clarity on the roles and responsibilities for each of the parties involved in First Nation consultation processes in Alberta, specifically government, project proponents and First Nations. The Consultation Guidelines highlight the following three goals:

  • stakeholders gaining a better understanding of First Nations’ concerns regarding potential adverse impacts of a project on the exercise of treaty rights and traditional uses;
  • substantially addressing these concerns through a meaningful process; and
  • developing positive working relations.

The 2014 guidelines are only a starting point. Stakeholders will need to be aware of, and rigorously comply with, their respective duties to consult as well as recent Supreme Court of Canada decisions on First Nations consultation and emerging law at the lower court levels.

8. How Far, AER? Alberta Energy Regulator Expands Its Jurisdiction

In 2014, the Alberta Energy Regulator (“AER”) – the entity responsible for providing “the efficient, safe, orderly and environmentally responsible development of energy resources in Alberta” – implemented the third and final phase of its mandate under the Responsible Energy Development Act (“REDA”).

Under the prior legislative framework for oil and gas development in Alberta, there were several decision-makers operating under various statutes as follows:

  • Alberta Environment and Sustainable Resource Development (“ESRD”) granted surface leases to companies to develop on public lands and regulated reclamation and remediation under the Public Lands Act;
  • the Energy Resources Conservation Board (“ERCB”) granted licences and approvals for oil and gas wells and facilities as well as regulated most aspects of those facilities including construction, operations and abandonment;
  • both the ERCB and ESRD granted licences and approvals respecting air, land and water impacts; and
  • Alberta Energy had a policy setting role as well as responsibility for the sale of oil and gas rights for the 80% of oil and gas resources in Alberta owned by the province.

Under REDA, Alberta Energy’s role in the disposition of oil and gas rights is unchanged. The mandates of ESRD and the ERCB were combined into a single regulator known as the AER with the ERCB dissolved. 2014 ushered in an expansion of the AER’s jurisdiction under REDA as follows:

  • the AER now has authority over various provisions in the Public Lands Act, the Environmental Protection and Enhancement Act and the Water Act to the extent that those provisions relate to “energy resources activities”, specifically oil and gas operations and coal mining, but not power generation or electricity transmission and distribution; and
  • Crown surface dispositions and environmental approvals will now be obtained under the single umbrella of the AER.

Respecting procedural rule changes, it is now within the AER’s discretion to disregard Statements of Concern (“SOC”) filed under REDA under circumstances set out in section 6.1 of the AER’s Rules of Practice. This includes circumstances where the AER determines that the concern has been adequately dealt with or addressed through a hearing or other proceeding under any other enactment or by a decision on another application. Previously, all persons who could establish that they may be directly and adversely affected by the regulator’s disposition of an application were granted standing.

Industry stakeholders will need to monitor closely the AER’s practices to determine whether the regulator continues to apply the “directly and adversely affected” test as its predecessor did. The practical implications for AER hearings – including application delay – may be significant.

9. Plus tard, Couillard? Emergence of New Oil and Gas Policy in Québec

Québec has a long history of oil and gas exploration dating back to the 1950s. In the 1970s, the Parti Québécois government established a government entity, société québécoise d’initiatives pétrolières (“SOQUIP”) charged with oil and gas exploration to increase Québec’s energy independence. After a period of unsuccessful exploration, SOQUIP was disbanded and exploration ceased. As the combination of hydraulic fracturing and horizontal drilling opened up new reservoirs, there was renewed interest in Québec’s Utica shale. The Québec Oil and Gas Association (“QOGA”) was created to encourage dialogue in Québec about the potential of the province’s emerging oil and gas industry.

Since 2005, over 30 modern shale gas wells have been drilled. Several companies, notably Questerre, Junex and Lone Pine have operations and land holdings in Québec. In 2013, the Parti Québécois government imposed a five-year ban on fracking in the St. Lawrence Lowlands, the region between Montreal and Québec City, until a strategic environmental assessment on shale gas development was completed.

The Québec Environmental Review Board review indicated that the risks outweighed the benefits of fracking. In late 2014, Québec Premier Couillard stated that given the findings of the review board, his government would not support fracking at this time. Premier Couillard did not close the door to fracking in the future, however, and said his government is not opposed to developing the province’s energy resources.

The Québec oil and gas industry is facing a new policy framework under Premier Couillard. On November 7, 2014, the Minister of Energy and Natural Resources and the Minister Responsible for Plan Nord announced the beginning of a consultation process on Québec’s new energy policy set to be released in Fall 2015.

The Québec Government will publish four documents intended to initiate and encourage discussions on the new energy policy. The first document, entitled “Contexte, défis et vision” (“Context, Challenges and Vision”) sets out the framework for the consultation process. The other documents will address the issues of: (i) renewable energy; (ii) efficiency and energy innovation; and (iii) fossil fuels. Public roundtable meetings will be held in January, March and May 2015 on these topics.

10. Fracking in Fredericton – New Brunswick Places a Moratorium on Hydraulic Fracturing

Shale gas and the method used to extract it – hydraulic fracturing or fracking – prompted a series of high profile protests and galvanized the 2014 New Brunswick provincial election. During the campaign, Liberal Premier Gallant promised to impose a moratorium on the practice “until the risks to the environment, health and water are fully understood”.

On December 18, 2014 the New Brunswick Minister of Natural Resources introduced Bill 9, An Act to Amend the Oil and Natural Gas Act to the Legislative Assembly of New Brunswick. Bill 9 will create a moratorium on all forms of hydraulic fracking in the province of New Brunswick, irrespective of whether the process uses water or another substance to extract natural gas from subsurface shale rock. The Bill will also put an end to any fracking projects currently underway in the Province, as no “grandfathering” of projects will be permitted outside of the moratorium.

The moratorium will continue in place until the following five conditions are met:

  • “social licence” for hydraulic fracking is established through consultations between fracking corporations and the community;
  • further information on the impacts on air, health and water prior to the development of a regulatory regime for fracking in New Brunswick;
  • establishment of a plan to mitigate impacts on public infrastructure and to address issues such as waste water disposal;
  • the Province establishes a process to fulfill its First Nations consultation obligation; and
  • a royalty structure ensures that the benefits of fracking are maximized for residents of the Province.

There are currently several companies exploring for shale gas in New Brunswick, most notably SWN Resources Canada. These activities will be permitted to continue under the moratorium, provided that no fracking activity on test wells is undertaken. New Brunswick is the fourth province to create a moratorium on fracking. The others are Québec, Nova Scotia and Newfoundland and Labrador.