In 2015 politics drove policy.  With new federal and Alberta governments, last year ushered in unprecedented changes for the Canadian oil and gas industry.  There is more to come.  Greenhouse gas regulation and a revised royalty regime are poised to be two of the sector’s leading business challenges in 2016 - along with stubbornly low price - as energy companies determine the impact to their bottom lines.

There are significant transitions happening to Canada’s energy economy.  Pipelines remain elusive.  M&A activity is nascent and waiting for further price and policy clarity.  International oil supply, buoyed by an end of year U.S. policy shift to permit crude exports, continues to be robust.  Green energy and renewable sources will play a larger role in the country’s energy mix. As the year progresses, companies with strong balance sheets and a low cost of capital are likely to be some of the biggest winners in 2016.

Canada’s oil and gas sector looks ahead to not only the implementation of provincial carbon initiatives, but also the federal government pursuing its own climate change agenda.  This involves new international obligations arising from the 2015 United Nations Climate Change Conference as well as a commitment to set national emissions targets – and coordinate with existing provincial ones.  2016 will therefore be a watershed year for energy companies navigating the shoals of carbon policy and economic transition. Changes are expected to be rapid and multi-dimensional, effects complicated. 

Our list of the top 10 oil and gas legislative, regulatory and policy changes in 2015 is set out below.  The list could have been much longer, and several important developments, such as passage of the federal Extractive Sector Transparency Measures Act, did not make the cut.  In a year dominated by political transition, there was a clear pivot to new administrations’ policies and their impacts into 2016, with none more significant than climate change.

1. Hot Air? The Paris Agreement

From November 30 to December 12, 2015, 195 nations attended the 2015 United Nations Climate Change Conference in Paris, France. The Conference resulted in a landmark agreement (“Paris Agreement”) to reduce global carbon output.

The key aspects of the Paris Agreement are:

  1. a goal to limit global warming to “well below” 2 degrees Celsius. The aim is to “achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century” – in other words, net carbon emissions to be zero;
  2. national pledges to cut greenhouse gas emissions in the 2020s;
  3. a plan to make countries pledge deeper emissions cuts in future, with refinements every five years;
  4. wealthier nations to provide funding to poorer ones – “mobilising” $100 billion a year until 2025, and more thereafter; and   
  5. a plan to monitor progress and hold countries to account, including a global “stock-take” in 2023, and every five years thereafter, to assess progress toward the aims of the agreement and to encourage countries to make deeper pledges.

The Paris Agreement will become binding if ratified by at least 55 countries, representing at least 55 per cent of global greenhouse emissions.  Binding ratification is widely expected.  The most important result of the agreement for Canada’s oil and gas industry will likely be further federal and provincial legislative changes aimed at reducing emissions and addressing climate change. 

Many of the provinces have already instituted climate legislation and it is expected that the federal government will following an ambitious timetable, introducing legislation later this year.  Borden Ladner Gervais LLP previously discussed the potential impacts of the 2015 federal election on energy policy at New Energy? Trudeau Unveils Cabinet, Mix of Newcomers and Veterans in Key Portfolios, and Is The Oil and Gas Industry Ready? Canadians Elect Liberal Majority Government.  Trudeau government proposals to watch include phasing out fossil fuel subsidies, issuing “Green Bonds” for carbon reducing infrastructure, and creating a $2 billion fund to support projects aimed at cutting emissions.         

2. Acclimatized Yet? Alberta’s Climate Change Plan

On November 22, 2015 Alberta Premier Rachel Notley announced a comprehensive new climate change plan. It is a broadly based carbon tax - impacting both producers and consumers - and responds to recommendations of the Climate Change Advisory Panel (“Panel”) the Premier appointed last summer.  Premier Notley’s announcement draws from the Panel’s report, but does not specifically endorse all of the Panel’s conclusions. Borden Ladner Gervais LLP has commented extensively on the new framework and its impacts at Temperature Check: Alberta Makes Big Move on Carbon Emissions,Alberta Premier Notley Tips her Climate Change Hand, All Change — Alberta Overhauls Climate Policy, Ushers In Sweeping New Requirements, and Big Changes Coming to Alberta’s Electricity Market – The Winners and Losers?.   

Carbon Pricing

In what is labelled the “backbone” of the new climate change strategy, Alberta will replace the old “large-emitters tax” and phase in a $30 per tonne economy-wide carbon pricing system, to be implemented in a two-step process. Carbon pricing will be applied across all sectors, starting at $20 per tonne on January 1, 2017 and increasing to $30 per tonne on January 1, 2018. The carbon price will be adjusted thereafter to keep pace with prices and growth, and the levels set in other jurisdictions.

Alberta’s carbon pricing system is stated to be “revenue neutral” with all capital reinvested into pollution reduction measures in Alberta, including clean research and technology, green infrastructure like public transit, financing the transition to renewable energy, and efficiency programs to reduce energy use. Premier Notley has indicated that once the Alberta economy recovers, her government will consider using climate revenues to relieve public debt.

Oil Sands Emission Limits

Alberta’s climate change plan will introduce an overall oil sands emissions limit. Oil sands currently generate roughly 70 megatonnes of carbon a year. The plan will set a legislated overall carbon emissions limit of 100 megatonnes with provision for new upgrading and co-generation. This cap allows for an increase in current emissions for economic growth, with innovation and technology expected to help reduce the carbon output per barrel in the future. 

There is still uncertainty as to how the oil sands emission cap will operate, with potential options involving grandfathering and pro rata reductions.  Additional clarity is expected on how and whether the cap will apply on a facilities basis, for example, at or after facility approval. Borden Ladner Gervais LLP will be closely monitoring these implementation details as they unfold in 2016.

Methane Emission Reductions

Alberta’s climate change plan proposes a 45% reduction in methane emissions from oil and gas operations by 2025. The provincial government expects to reach this level by applying additional emission design standards to new Alberta facilities and developing a 5-year voluntary Joint Initiative on Methane Reduction and Verification.

The Joint Initiative will include Alberta industry, environmental groups, and Indigenous communities. It will be tasked with taking action on venting and fugitive emissions from existing facilities, including enhanced measurement and reporting requirements. The Alberta Energy Regulator (“AER”), in collaboration with Alberta Energy and Alberta Environment and Parks, will lead the implementation of new methane standards.

Alberta’s climate change regime is a framework only, with further details and implementation in 2016.  Issues to watch over the next year include who are the oil patch winners and losers, whether carbon has been accurately “priced”, clarity respecting total emissions reductions and coordination with federal and other provincial government policy.

3. Errors and Emissions? Carbon Pricing Elsewhere In Canada

In 2015, Alberta was not alone in redesigning its climate regime.  Quebec, Ontario and Manitoba have recently adopted cap-and-trade systems and are expected to coordinate with California through the Western Climate Initiative.  Federal climate proposals - on the heels of the Paris Agreement - will not be far behind.


In February, 2015, the Ontario government released a climate change discussion paper outlining four options for a carbon pricing system.  The province chose cap-and-trade, and last year enacted enabling legislation: Bill 185, or the Environmental Protection Amendment Act (Greenhouse Gas Emissions Trade). Ontario’s cap-and-trade program is set to start in 2017, and will initially involve auction of intra-provincial emission allowances, with plans to ultimately integrate with the Quebec and California systems.

British Columbia

In British Columbia, the provincial government continues to prefer a carbon tax regime to a cap-and-trade system. In May, 2015, Premier Christy Clark appointed a Climate Leadership Team (“CLT”) with the mandate to provide recommendations to government on a new Climate Leadership Plan. The CLT released its report on November 27, 2015 with 32 recommendations.

The CLT recommended that B.C. “build on the success of the carbon tax by establishing a new, innovative fiscal policy that helps mitigate impacts on emission-intensive, trade-exposed sectors while putting a higher price on pollution.”   In response, the government noted that the current carbon tax of $30/per tonne was frozen until 2018 in order to “allow other jurisdictions to catch up to British Columbia” and that B.C. “would only consider an increase in the carbon tax under a regime where emission-intensive, trade-exposed industries are fully protected from any carbon tax increase.”  It plans to consult in January 2016 on the recommendations and possible actions.


The majority of Canada’s economy is, or will soon be, subject to a provincially determined carbon price. The federal government also promises to price carbon. In 2016, a key national policy issue is whether Canada’s carbon pricing architecture can be reconciled. Ensuring consistent price signals across the Canadian economy will be critical not just for the oil and gas sector, but the country as a whole. A coordinating meeting between federal, provincial and territorial governments is set for the first quarter of this year. The country’s increasingly patchwork system of climate policy - absent sufficient and workable integration - creates risk of burdens, disproportionate benefits and barriers to investment.

4. Royal Treatment? Royalty Review Announced, To Be Implemented in 2017

In 2015 the Alberta government established the Royalty Review Panel. The existing royalty structure is based on a double sliding scale for well production rates and commodity prices. The program has a minimum rate of 5% and a maximum rate of 36% for natural gas and 40% for oil.  The Panel’s stated objective is to optimize the return of energy sector profits to Albertans while supporting continued industry investment, economic diversification, and responsible development. Alberta’s Energy Minister has promised that any increased government revenue that results from changes to the royalty framework will go to Alberta’s Heritage Savings Trust Fund. 

Alberta royalty reviews have a turbulent history. The Progressive Conservatives previously established an increased government take in 2007 that became effective in 2008. This coincided with - like today - a significant downturn in commodity price.  The impacts of the 2007 royalty review were compounding the effects of falling demand, capital flight and reduced investor confidence.  In 2010 the Alberta government rolled back royalty rates to current levels.

Changes to Alberta’s royalty regime create potential uncertainty. Exploration and production companies with diversified asset bases can redirect dollars outside of Alberta.  There are abundant tight oil and shale gas investment opportunities in the U.S., among other places, with appealing tax regimes.  Policies resulting in new operational costs have impacts on investment and drilling.    Ensuring a competitive royalty, credit and incentive structure – even relative to Saskatchewan and British Columbia – therefore remains critical.    

The release of the Royalty Review Panel’s report is expected in January, 2016. The Alberta government indicates that no changes to fees will be implemented before 2017.  Many industry players have nonetheless cited the royalty review as creating uncertainty and impediments to accurate pricing for potential oil patch transactions.  It therefore remains to be seen in 2016 whether the review’s release facilitates or hinders potential transactions in Alberta’s beleaguered energy sector.

5. Tax to the Max? New Federal and Provincial Tax Increases

In 2015, Alberta’s NDP government introduced Bill 2, An Act to Restore Fairness to Public Revenue, which increased corporate taxes from 10% to 12%, effective July 1, 2015. Alberta was previously the jurisdiction with the lowest corporate tax rates in Canada. After the change, there are seven other provinces and territories with lower or equal corporate tax rates. British Columbia’s 11% corporate tax rate is now the country’s lowest. These changes are predicted to impact Alberta’s ability to attract investment in 2016.  Borden Ladner Gervais LLP provided insight on the NDP government’s first budget at Alberta Bound? Province Releases Budget, Projects $6.1 Billion Deficit for 2015-16.

Alberta’s new tax structure increases the top combined federal and provincial tax rate on eligible and ineligible dividends. Tax rates on eligible dividends will increase from 19.3% in 2014 to 21% in 2015, and 26.2% in 2016. Ineligible dividends will increase from 29.4% in 2014 to 30.8% in 2015 and 35.7% in 2016.

For 2015, corporate income tax will be prorated based on the number of days in the corporation’s taxation year that are before July 1, to which the prior 10% rate will apply, and the number of days after and including July 1, to which the new 12% rate will apply. In 2016, the 12% rate will apply for the full year. For many oil and gas companies the new taxation regime represents a significant new operating cost, the impacts of which will unfold in the upcoming years. 

6. What Lurks Beneath? AER Obtains New Authority to Issue Subsurface Orders

In February, 2015 AER Bulletin 2015-05 announced changes to section 11.104 of the Oil and Gas Conservation Rules. These changes grant the AER authority to issue new instruments referred to as “Subsurface Orders”.  Under this regime, the AER may now suspend and vary its default rules - especially relevant for spacing, target areas, allowables and production rates. 

Bulletin 2015-05 is a new power to regulate subsurface areas in respect of tight oil and gas reserve development.  The AER quickly employed its new authority for the Montney-Lower Doig zone and appears ready to do so over a broader geographic area.  It reinforces the AER’s intent to address development through a life-cycle approach that takes into account overall trends in down-spacing and stakeholder input. Many in the oil and gas industry consider Subsurface Orders as a positive development creating regulatory efficiencies.  However, there is also risk that they become a mechanism to implement politically-driven decisions absent procedural safeguards.

Bulletin 2015-05 dove-tails with the AER’s 2015 play-based regulation (“PBR”) proposal.  The latter is a policy initiative to address the cumulative effects of unconventional resource developments.  The AER implemented PBR through a pilot project involving the Duvernay shale formation near Fox Creek.  Like PBR, the effects of Bulletin 2015-05 in 2016 are far from certain.  As Bulletin 2015-05 is further implemented, it remains to be seen whether new Subsurface Orders impact - directly or indirectly - surface activities. 

What appears to be clear, however, is that it will be the AER issuing any new subsurface orders.  The Alberta government, which previously suggested it might redesign the province’s energy regulator, changed tack at the end of 2015 to confirm that it would not be dramatically altering the AER’s structure or scope.  Borden Ladner Gervais LLP addressed the development of the AER and the potential for a divided regulator at Separation Anxiety – Is a Divided Alberta Energy Regulator Around The Corner? and AER Now Responsible for the Environmental Assessment Process for Energy Resource Activities.  Any lurking changes over subsurface regulation in 2016 are likely to be ones of policy, rather than jurisdiction.

7. Pipe Down?  Pipeline Policy in 2015

2015 was a tough year for pipelines.  From the Obama administration’s November 6, 2015 rejection of Keystone XL, to delays in Kinder Morgan and TransCanada’s applications moving through the National Energy Board process and numerous Federal Court of Appeal challenges, there was little progress in Canadian pipeline development. Complicating pipeline policy further were elections in 2015 that ushered in administrations in Edmonton and Ottawa ostensibly less friendly to energy infrastructure development than their predecessors. Northern Gateway, for example, continues to face legal, social licence and political headwinds, including the Trudeau government’s proposed moratorium on oil tanker traffic off of B.C.’s North Coast. 

Passage of the federal Pipeline Safety Act was a major 2015 policy initiative.  It implemented a suite of measures to strengthen incident prevention, preparedness and response, and liability and compensation. These include:

  1. enshrining in law the “polluter pays” principle;
  2. implementing absolute, “no fault” liability ($1 billion in the case of companies operating major oil pipelines);
  3. requiring companies operating pipelines to hold a minimum level of financial resources in case of an incident;
  4. establishing new statutory causes of action for both fault and absolute liability claims and a limitation period of three and not more than six years; and
  5. providing the federal government with the ability to pursue pipeline operators for the costs of environmental damages in way they could not before.

Procedurally, the Pipeline Safety Act gave further powers to the NEB, including the ability to:

  1. direct any company operating a pipeline to reimburse government institutions for costs incurred in taking actions respecting a release; and
  2. order pipeline companies to remain responsibility over, and to maintain funds to pay for, the abandonment of their pipelines.

Between 2012 and the spring of 2015, the Harper government implemented its resource development proposals through the Pipeline Safety Act, the Economic Action Plan 2015 Act, and amendments to the National Energy Board Act, and theCanadian Environmental Assessment Act, among other legislation. The Conservatives’ legislative agenda intended to facilitate oil and gas extraction and new energy infrastructure. Examples included streamlining the federal regulatory process toward a “one project, one review” system and setting timelines for pipeline hearings and assessments.

While in opposition, the federal Liberals did not support changes to the National Energy Board Act that facilitated pipeline development, stating that it denied stakeholders’ participatory rights and undermined environmental protections.  The Liberals further stated that the Pipeline Safety Act, as passed in 2015, did not provide sufficient safeguards or levels of pipeline operators’ liability.  Scrutiny of both statutes - as well as procedurally streamlining aspects of the Canadian Environmental Assessment Act - is therefore likely in 2016.

8. Higher Standards? Canadian Securities Administrators Amend National Instrument 50-101 Standards of Disclosure for Oil and Gas Activities

Reporting issuers engaged in oil and gas activities are required to provide annual disclosure of reserves and resources other than reserves. Recognizing the importance of this type of disclosure, in 2015 the Canadian Securities Administrators - which includes securities regulators from each of Canada’s ten provinces and three territories - amended the Standards of Disclosure for Oil and Gas Activities to clarify the procedure for, and disclosure obligations of, reporting issuers. The amendments resulted in changes including:

  1. disclosure under an alternative securities regime, such as the U.S. regime, are permitted, so long as it is comparable to the Canadian Oil and Gas Evaluation (“COGE”) handbook, has a scientific basis, and is based on reasonable assumptions;
  2. definitions from the COGE handbook for securities disclosure purposes are imported and refined, and the concept of “production group” is removed;
  3. clearer guidance is provided for disclosure of contingent resources data and prospective resources data in annual filings;
  4. principle-based requirements are provided to describe the standard, methodology and meaning of a publicly disclosed oil and gas metric;
  5. clarification of the concept of marketability in the reporting of oil and gas volumes; and
  6. clarification of what constitutes abandonment and reclamation costs.

The amendments will likely be beneficial to the oil and gas industry. They promote improved disclosure of resources other than reserves and associated metrics.  Furthermore, the amendments provide increased flexibility for oil and gas issuers that operate and report in different jurisdictions and recover product types not previously recognized. 

9. Gas Accelerator? New CCA Rules for LNG Plants

As part of British Columbia’s “Canada Starts Here: BC Jobs Plan” launched in 2011, the B.C. government set a goal of having three liquefied natural gas (“LNG”) facilities in operation by 2020.  On February 19, 2015, Canada’s Department of Finance announced a proposal to increase the capital cost allowance (“CCA”) rates for property acquired for use in LNG facilities in Canada. Specifically, the Department amended the Income Tax Regulations to allow for accelerated Class 47 CCA from a rate of 8% to a rate of 30% per year for capital properties used in conjunction with LNG facilities.

Key aspects of the new tax treatment include:

  1. equipment and structures used for natural gas liquefaction will generally be included in Class 47 (CCA rate of 8%);
  2. the accelerated CCA takes the form of an additional 22% allowance that will bring the CCA rate up to 30% for Class 47 property used in Canada in connection with natural gas liquefaction; 
  3. property eligible for the additional allowance in respect of Class 47 will be comprised of equipment that is part of a facility that liquefies natural gas, including controls, cooling equipment, compressors, pumps, storage tanks and ancillary equipment, pipelines used exclusively to transport liquefied natural gas from the facility and related structures;
  4. equipment used exclusively for regasification will not be eligible for the additional allowance; and
  5. an additional allowance will bring the CCA rate up to 10% for buildings that are part of facilities that are used to liquefy natural gas.

The new rules apply to eligible property acquired after February 19, 2015 and before 2025.  It is welcome news for LNG proponents, as the increased deductions should materially improve LNG project economics.  Final LNG investment decisions will be an important industry development to watch in 2016, with a narrowing number of viable economic projects expected.  The new CCA rules may well be a positive factor supporting LNG companies’ final investment decisions.

10. Crude Awakening? End of U.S Oil Export Ban

At the end of December 2015, President Obama signed a bill lifting the United States’ 40-year ban on oil exports.  The U.S government introduced crude export restrictions in the mid-1970s as a response to the energy crisis following an OPEC oil embargo.  Washington eased the limits on oil imports and ordered an export ban. The prior rules allowed U.S. oil exports to Canada as an exception.

As a result of the country’s shale oil boom, the energy supply picture in the U.S. is remarkably different today than it was 40 years ago.  So are the implications for the Canadian oil and gas industry. Ending the ban could therefore benefit Canadian producers. 

It may now be easier to transport Canadian crude oil to Asian markets.  Canadian companies need a re-export permit to ship crude to the Gulf Coast and then export it to Asia via the Panama Canal.  The U.S. policy change on exports would likely remove that obstacle.  There would therefore be fewer U.S. regulatory burdens for a Canadian producer who wants to sell into Asia and cannot transit through a pipeline to the Canadian west coast. 

There may also be an additional demand for Canadian heavy oil to reach U.S refineries to replenish U.S. crude sent overseas.  This may help address the light oil glut in the U.S. mid-continent that has driven down benchmark North American prices in relation to international prices. A further factor for Canada’s oil and gas producers is the low probability that U.S. supplies will compete with Canadian exports, given the different grades of crude. 

In what has been a very challenging year for Canada’s oil and gas sector, a ray of optimism arrived at the end of 2015 from – of all places – the same U.S. President that denied Keystone XL.  The President’s decision to lift the export ban, among the significant policy changes in 2015, suggests an equally unpredictable 2016.