2016 was the year of carbon pricing. The Alberta Government ushered in sweeping legislative changes that spanned from broadly-based carbon levies to a specific cap on oil sands emissions. In 2016, no industry was affected more than power generation. Through dramatic policy changes, that sector is now facing a "30 by 30" target (30% of electricity used in Alberta being generated from renewable sources by 2030), significant market restructuring and the Province's first clean power procurement.

Alberta energy policy became clearer in 2016. From Alberta's Royalty Review to the Alberta Energy Regulator's (AER) position on Liability Management Rating (LMR) the oil and gas industry now knows better what it must comply with. The policy pronouncements and political promises of 2015 became formed – and legislated – in 2016.

Alberta was not alone in policy development. The Federal Government entered into the climate change fray with ratification of the Paris Agreement and a pan-Canadian benchmark for carbon pricing. Further federal policy to watch in 2017 will include recommendations on the future of the National Energy Board and a potential thaw on foreign investment into the oil sands. At the Provincial level, British Columbia released its long-awaited Climate Leadership Plan and Québec restructured its petroleum exploration and development regime.

Then there is Donald Trump. The 2016 U.S. election results, both Congressional and Presidential, will have significant implications for Canada's energy sector. Energy security and affordability, rather than carbon reduction, are likely to be key themes of a Trump Administration. The Trudeau Government's climate change strategy increasingly appears out of step with those of President-elect Trump, to the potential detriment of Canada's energy sector.

Our list of the top 10 energy legislative, regulatory and policy changes in 2016 is set out below. The list could have been much longer, and several important developments, such as the AER's consideration of Play-Based Regulation or enhanced SAGD application requirements, did not make the cut. The energy sector is at least a little clearer than it was entering into 2016. Even commodity price and the prospect of new pipelines to tidewater are improving – for now. Across the country, 2017 is shaping up to be the year of implementation and cautious optimism.

1. Broken Levy? Alberta Ushers in New Carbon Levy Legislation, Regulations

A cornerstone of Alberta's climate policy in 2016 is the carbon levy, which became effective on January 1, 2017. The levy is a $20/tonne price on carbon emissions, rising to $30/tonne effective January 1, 2018. It is expected to raise $2.4-billion annually when fully implemented.

The carbon levy applies to purchases of all fossil fuels that produce greenhouse gas (GHG) emissions when combusted and will be applied as a price per tonne. BLG commented in the Globe and Mail on the Alberta Government's June 2016 introduction of the Climate Leadership Implementation Act in Will a carbon levy make Alberta less competitive? The devil's in the details. The Act was a high level framework, with significant details to follow.

On November 3, 2016, the Alberta Government released the highly anticipated Climate Leadership Regulation (the Regulations), which provides further information on how the carbon levy will be implemented and administered in Alberta. The release of the Regulations establishes better, but not perfect, clarity in respect of the steps that Alberta businesses must take to ensure compliance.

The Regulations offer further details respecting, among other matters, exemptions from the carbon levy and the fuel supply chain activities and stages which trigger levy payment. However, there remain a number of unanswered questions. In 2017, businesses will need to implement the carbon levy. Registration, licensing and exemption requirements must be considered. The Alberta Government has indicated that compliance will be strictly enforced, with no extensions granted.

2. Capped Out? Alberta Introduces 100 Megatonne Cap on Oil Sands Emissions

On November 1, 2016, the Government of Alberta introduced Bill 25 – the Oil Sands Emissions Management Act. It establishes a cap on GHG emissions in the oil sands sector. Oil sands facilities were previously regulated under the Specified Gas Emitters Regulation (SGER). The SGER framework broadly operated on an individual facility's historical emissions per tonne of GHGs, per barrel produced, or the operation's efficiency. Oil sands operations currently emit roughly 70 Megatonnes (Mt) per year.

The Oil Sands Emissions Management Act establishes an annual 100Mt emissions limit on oil sands. It is brief and lacks details. There are no monitoring, enforcement or penalty provisions. The actual implementation of the cap is another challenge. The application of the Oil Sands Emissions Management Act exemptions is not entirely clear. It does not, for example, distinguish between mineable oil sands sites and in situ sites.

The Oil Sands Emissions Management Act does not provide any further guidance as to whether the existing projects' emissions are grandfathered, and if so, how it will be allocated among existing oil sands sites. It is also debatable whether there may be a need to segregate between mines and in situ sites for the purposes of the allocation. Without established criteria, such allocation will likely be contentious.

Further, if indeed the 70 Mt per year will be grandfathered, it is not clear how the remaining 30Mt will be allocated to new oil sands projects. Owners of approved projects that received no allocation, if they are not allowed to operate, may argue that their mineral rights have been expropriated. For further details please see BLG's assessment of the Oil Sands Emissions Management Act in Alberta Government Introduces Legislation Mandating Cap on Greenhouse Gas Emissions from the Alberta Oil Sands.

3. Bidder End? Alberta To Hold First Competitive Renewable Power Procurement

Alberta will hold its initial renewable power procurement in 2017. It will be the first of many procurements, as the Alberta Government has committed to provide the financial support required for 5,000 MW of renewable capacity to be added in Alberta by 2030. BLG previously discussed this initiative in further detail in Alberta Announces the Terms for its Initial 400 MW Renewable Electricity Procurement and Alberta's First Competitive Power Procurement Begins.

The Alberta competitive procurement begins in Q1 of 2017, will be for 400 MW, and will be executed in a three-stage competitive process with winning projects subject to a 2019 in-service date. The procurement will result in winning bidders receiving financial support in the form of a 20-year Renewable Electricity Support Agreement (RESA) with the Alberta Electric System Operator (AESO). The key financial support in the RESA will be an indexed renewable energy certificate (REC) which, in essence, is a contract for differences linked to the Alberta power pool price for electricity.

RECs will be automatically adjusted so that when pool prices rise, the support to be paid falls. If the pool price rises above the bidder's strike price, the bidder must pay the difference to the Alberta Government. The intent is that successful bidders will not bear the Alberta pool price risk over the term of their RESA but, in return, will forego windfall profits in times of high pool prices. The RESA is the key agreement upon which developers will seek financing for their renewable projects. Successful bidders will ultimately be determined on the economics of their respective projects – and on a fuel-neutral basis – with wind, solar, hydro or other renewables all able to participate.

4. At Capacity? Alberta Government Announces New Capacity Market For Power

Generation in Alberta is currently competitive, with generators themselves determining the form of energy they will convert into electricity to offer into the Alberta power pool. If dispatched, the generators are paid the competitively determined power pool price for the hour in which they are delivering their electricity into the grid. The Alberta power pool is now "energy only" in that the generators are paid based on the electricity they produce and solely on the power pool price. However, on November 23, 2016, the Alberta Government announced the introduction of the Province's first capacity market. BLG previously commented on this announcement on The Resource in Alberta To Cap Electricity Rates And Bring In A Capacity Market.

Alberta's electricity market is moving to two separate markets – one in which generators compete to sell electricity, and another where generators compete for payments to keep generation capacity available to generate electricity when it is required. Generators will have one stream of revenue for capacity and another stream of revenue for the electricity that they sell in the market. Like the Pennsylvania, Jersey, Maryland (PJM) Market, Alberta will have both an energy and a capacity market.

Transition to a capacity market should not impact the Province's first renewable power procurement in 2017. The capacity market will not be in place until after 2019, when the successful renewable projects from the first procurement must already be in service. Future procurements may require changes to the extent that a renewable project may be eligible for capacity payments. However, renewable project developers in the first procurement should achieve the revenue sufficiency, certainty and stability needed to finance projects under the RESAs, and not from any capacity payment.

The AESO will plan, determine, approve and administer contracts to procure the capacity required to meet Alberta's electricity demands according to the following timetable:

  • 2017 – Stakeholder engagement to determine design;
  • 2018 – Incorporation of design into ISO rules, contracts and/or legislation as required;
  • 2019 – First procurement begins; and
  • 2020/21 – First contracts awarded.

Gas-fired power project developers are welcoming the revenue certainty that the new capacity market offers. There are a number of gas-fired projects permitted in Alberta, and it is expected that other projects will be initiated and expedited by developers so that they can be ready in time to participate in a 2019 procurement. It is also expected that owners of the coal plants being phased out by 2030 will pursue coal-to-gas conversion projects. Renewable projects, like large hydro or renewable projects paired with energy storage, may also have capacity value.

5. Version 2.0? The AER Establishes a 2.0 Liability Management Rating Requirement, But Offers Some Flexibility

On July 8, 2016, the AER issued Bulletin 2016-21 Revision and Clarification on Alberta Energy Regulator's Measures to Limit Environmental Impacts Pending Regulatory Change to Address the Redwater Decision (Bulletin 2016-21). Bulletin 2016-21 clarifies and revises the interim rules outlined in the AER's Bulletin 2016-16 where the AER took measures in response to the Alberta Court of Queen's Bench's decision in Redwater Energy Corporation (Re), 2016 ABQB 278 (Redwater). BLG discussed Bulletin 2016-16 and the Redwater decision in The Alberta Energy Regulator Reacts to the Redwater Decision – Who Suffers?

Liability management rating or LMR refers to the ratio by which an AER licensee's liabilities exceed its assets. Prior to Redwater, if a licensee's deemed liabilities exceed its deemed assets, plus any previously provided security deposits (including facility-specific security deposits), the licensee has an LMR below 1.0 and would be required to provide the AER with a security deposit for the difference. Under AER Bulletin 2016-16, and as a condition of transferring existing AER licences, approvals, and permits, the regulator required all transferees to demonstrate that they have an LMR of 2.0 or higher immediately following the transfer.

Bulletin 2016-21 introduces a new way for a licence transferee to meet the conditions for transferring an AER licence, approval or permit. Specifically, a licensee can demonstrate to the AER "by other means" that it meets its obligations throughout the life cycle of a project with an LMR of less than 2.0. It is not clear what the full scope of "other means" to satisfy the AER is. Licensees can already achieve an LMR of 2.0 or higher by posting security, addressing existing abandonment obligations or transferring other assets.

Bulletin 2016-21 clarifies that the AER may consider contextual factors in considering approval of pending and future licence transfers. It may also allow transfers where a transferee demonstrates it can meet its obligations notwithstanding that it has an LMR of less than 2.0. This clarification could provide some relief to stakeholders. It suggests that the AER can take a more flexible approach in considering transfers on a case-by-case basis.

Another important clarification in Bulletin 2016-21 is that the AER appears to be assessing transactions that are already in progress on a case-by-case basis. Bulletin 2016-21 expressly encourages licensees with transactions in progress to contact the AER to arrange a review of its specific circumstances. This is welcome news for licensees whose licences have been approved but have not yet acquired assets, as a requalification or delay in the issuance of the new licence may be able to be avoided.

6. Royal Pardon? Alberta Announces New Royalty Framework

On January 29, 2016, Premier Notley announced Alberta's new royalty framework. The framework adopted recommendations from the Royalty Review Advisory Panel Report. BLG undertook an in-depth analysis on the implications of the new royalty framework in Thoughts from the Trenches: Incentivizing Producers and Thoughts from the Trenches: Keeping Service Providers Lower for even Longer.

Premier Notley ushered in a new royalty framework for oil and gas producers drilling in 2017 and beyond, that is intended to provide the same internal rate of return as if the wells had been drilled in 2016, subject to meeting or exceeding the average industry costs of drilling. Unlike the old structure, the new royalty framework will be harmonized across crude oil, liquids and natural gas.

Furthermore, all existing oil and gas wells and those drilled in 2016 will pay royalties under the old framework for the next 10 years. It is expected they will be grandfathered in to the new framework thereafter. All costs oil sands projects are able to deduct when paying their royalties will also now be publicly disclosed.

The old royalty structure for crude oil, liquids and natural gas incorporated elements of a "revenue minus costs" (RMC) model. The new framework permanently adopts a proxy RMC structure. The average drilling cost for any new well will be estimated by proxy using a Drilling and Completion Cost Allowance formula, based on vertical depth and horizontal length (C*).

Companies planning to drill a well have an initial flat royalty rate of 5% for early production revenue until they reach payout for the drilling and completion costs, when cumulative revenue equals C*. Companies will move from the low initial royalties to higher posted royalties. Commodity prices of various hydrocarbon streams, using a price function formula system, will determine elevated post-payout royalty rates. The price function calculated over the remaining life of the well will vary the post-payout royalty rate that companies will pay.

Once hydrocarbon production from the well drops below a certain rate, called the Maturity Threshold, the well will be classified as mature. This results in a downward adjustment to the royalty rates in proportion to declining production rates. This structure recognizes the higher per-unit fixed costs involved with keeping a well running.

The proxy for costs will be calibrated each year to accommodate the realities and changes of the energy business. The Alberta Capital Cost Index will likely be set to 100 in 2017, and allowed to float depending on changes in industry costs. Companies will be required to report their actual capital costs along with other mandatory well information to the AER to serve as statistical inputs to calculate the Capital Cost Index for the subsequent year.

The Alberta Government further required that the new drilling cost index will provide information on the average costs of drilling and prices, production volumes, and the allowable costs used to determine royalty payments. This information, as well as the Alberta Capital Cost Index, is provided to the public on a continuing basis to provide transparency of the expenses and royalty revenues the Alberta public might expect.

The new royalty framework is structured with a pricing function formula that encourages innovation by crude oil, liquids, and natural gas explorers and producers. Applying the average industry costs of drilling to the pricing formula is expected to encourage innovation. The policy behind the new Alberta royalty framework is essentially that driving lower costs through innovation results in higher rates of return. Furthermore, it anticipates that companies will continue to seek innovation and technology advancements to lower costs below the industry average each year. Market conditions in 2017 will be critical to whether these expectations ultimately materialize.

7. B.C. Budding? Province Introduces GHG Strategy, Supports Emerging Technology

On August 19, 2016, the B.C. Government released its Climate Leadership Plan (CLP). The CLP sets out 21 strategic actions to assist B.C. in reducing its GHG emissions and promote the use of clean energy and technology. The key aspect of the CLP is to reduce B.C.'s GHG emissions by 25 Mt per year. BLG previously addressed the CLP in greater detail in British Columbia's Climate Leadership Plan.

The CLP targets six key areas: (i) natural gas; (ii) transportation; (iii) forestry and agriculture; (iv) industry and utilities; (v) construction; and (vi) the public sector. Respecting natural gas, the B.C. Government is introducing a strategy to reduce upstream methane emissions by 45% in three phases:

Legacy Phase — Targets extraction and processing facilities built before 2015, and will include:

  • a 45% reduction of fugitive and vented emissions by 2025 (estimated at an annual reduction of 1 million tonnes for 2025); and
  • a midpoint check in fall 2020 to determine progress towards this target, establish what happens if the target is not met, and make adjustments if necessary.

Transition Phase — Offers incentives to drive emissions reductions for facilities built between 2015 and 2018. Incentives will include:

  • a Clean Infrastructure Royalty Credit Program to help stimulate investments in new technology to convert current infrastructure to less carbon intensive machinery; and
  • a new offset protocol to further encourage innovative projects that reduce methane emissions.

Future Phase — Will establish standards to guide the development of projects after the Transition Phase. These include:

  • developing and enforcing standards to reduce methane emissions for all applications; and
  • making leak detection and repair mandatory, with protocols to be developed and enforced in line with other jurisdictions.

One of the most contentious issues has been the B.C. Government's decision not to increase the carbon tax by $10 per tonne per year beginning in 2018. However, it chose to hold the tax at $30 per tonne of carbon dioxide equivalent emissions, which has been the rate in place since 2012. With a B.C. election scheduled for May 2017, the intersection of energy infrastructure, climate policy – and politics – will continue to be front and centre in the new year.

8. Québec Libre? The Petroleum Resources Act Liberalizes Petroleum Exploration and Development

On December 10, 2016, the Québec National Assembly passed Bill 106: An Act to implement the 2030 Energy Policy and to amend various legislative provisions (Bill 106). BLG discussed the Québec legislative changes in Québec Passes New Legislation Governing Clean Energy and Oil and Gas Exploration. Bill 106 enacts or amends various pieces of legislation relating to clean energy and oil and gas exploration in the Province. Most notably – and controversially – Bill 106 enacts the Petroleum Resources Act, which sets out a comprehensive new regime governing petroleum exploration and development in Québec.

This represents a paradigm shift in Québec with respect to oil and gas development, setting out a modern regime that has significant implications for stakeholders. Before Bill 106, Québec did not have a legislative framework dedicated for oil and gas development. Oil and gas licences were awarded using a free-entry system similar to how mining rights are awarded in Canada.

The enactment of the Petroleum Resources Act allows for the development of hydrocarbons in Québec using a licensing and authorization regime. It sets out a comprehensive approach for the issuance of exploration, production and underground reservoir licences, replacing the Mining Act reservoir use provisions. The Petroleum Resources Act establishes a special liability regime for licensees. It further provides means for community involvement, environmental quality approvals and remediation assurances.

The Petroleum Resources Act will significantly alter how petroleum exploration and development in Québec occurs. While many of the details of the regime will be implemented through regulations that have yet to be introduced, Québec is signaling that it is open for increasing exploration and production while striving for responsible hydrocarbon development by involving community stakeholders, providing for environmental impact reviews, and requiring financial assurances for well closure and site restoration.

9. Carbon Dating? Federal Government Requires National Carbon Pricing by 2018

In October 2016, the Federal Government achieved two major climate change milestones – ratification of the Paris Agreement and a 2018 implementation date for a pan-Canadian benchmark on carbon pricing. These both address prior commitments, and raise outstanding legal and policy issues. BLG discussed the new Federal Government policy in The New Federal Carbon Pricing Policy – Roadmap to a Pan-Canadian Energy Strategy?

Key aspects of the Federal Government's pan-Canadian benchmark for carbon pricing are:

  1. All jurisdictions must have carbon pricing in place by 2018. Provinces and territories will have flexibility in deciding how they implement carbon pricing – for example direct price or cap-and-trade. The Federal Government will provide a pricing system for Provinces and territories that do not adopt one of those two systems by 2018.
  2. The establishment of benchmarks for pricing carbon emissions. The initial price will be a minimum $10 per tonne of carbon pollution in 2018 and will rise $10 a year to reach $50 per tonne in 2022.
  3. For provinces opting for a cap-and-trade system, the number of available pollution permits will decrease every year, based on both emission cuts through to 2022 (equal or greater to what would be achieved by a direct price) and a 2030 target equal or greater to federal levels.
  4. The overall approach will be reviewed in 2022 to ensure that it is effective and to confirm future price increases. The review will account for actions by other countries.
  5. Revenues from carbon pricing remain in Provinces and territories of origin.
  6. The carbon initiative is one of the tools Canada will put in place to reach or exceed its objective of reducing its emissions by 30% below 2005 levels.

Several potential concerns arise from the new federal policy, including:

  • the Federal Government's October 2016 announcement does not specify the mechanism by which the a price on carbon will be enforced;
  • there is limited clarity on how two different pricing methods – carbon tax and cap-and-trade – may be consistently measured for compliance purposes;
  • small and mid-sized oil and gas producers have indicated that a new federal carbon cost will impact their competitiveness because energy majors can more easily price a carbon tax into the cost of their operations;
  • carbon tax and cap-and-trade systems have potentially negative impacts on certain industries' ability to be competitive, with emission-heavy and trade-sensitive industries particularly vulnerable;
  • it is unclear how imported carbon products are affected. In a province that imports fuel, the impact of carbon pricing might be less than in a province that produces fuel, leading to competitive advantages.

In addition to matters of policy, there are also emerging legal questions. The Federal Government indicates that for those provinces that do not have a carbon regime, it will essentially impose one. The Federal Government has sufficient jurisdiction to apply a tax. But there are limits, as shown by the Supreme Court of Canada's 1982 Reference Re Proposed Federal Tax [1982] 1 S.C.R. 1004 decision which struck down federal laws on natural gas exports as interfering with provincial ownership of resources. Provinces without a carbon regime, notably Saskatchewan, may therefore seek judicial relief on jurisdictional and constitutional grounds.

In 2017 there will be a number of critical issues respecting the alignment of provincial and federal policies. Not least is how the Federal Government's climate framework will mesh with the U.S. pivot away from carbon pricing under President-elect Donald Trump.

10. Trump Bump? Will the New Administration Impact Trudeau Climate Initiatives

The 2016 U.S. election results have significant implications for Canada's energy sector. President-elect Trump's policies on energy issues – such as support for Keystone XL or a diminishing role for the U.S. Environmental Protection Agency – are swiftly emerging. His proposed Cabinet selections of Exxon CEO Rex Tillerson as Secretary of State, and former Texas Governor Rick Perry as Secretary of Energy, subject to Senate confirmation, further indicate a friendlier approach to fossil fuels. BLG's overview of the 2016 U.S. election's impacts to Canada can be found in The Historic 2016 United States Elections: Canada and the United States — Forward Together.

President-elect Trump's expected pivot away from President Obama's focus on climate change will have knock-on effects in Canada. One example is the Trudeau Government's climate change strategy. Canada's proposed national carbon price of $50 a tonne by 2022 now appears to be out of step with the U.S. With the incoming President's stated hostility towards international agreements, there is a strong potential for a U.S. exit from the Paris Agreement, and little appetite for a harmonized North American carbon regime.

President-elect Trump's energy policy, and its implications for Canada, will likely be furthered by a Republican-held Congress. A significant block of Republicans in the House of Representatives have supported not only the Keystone XL Pipeline, but also a friendlier regulatory framework for oilfield services industries, as well as domestic oil and gas exploration, and production companies. It was the U.S. Congress, after all, that recently lifted a 40-year ban on crude exports.

President-elect Trump's proposed tax cuts and business-friendly agenda may well extend to the energy sector and have strong Congressional support. Of particular interest in 2017 will be whether economic incentives to the U.S. oil and gas industry impact the competitive position of high cost Canadian producers – perhaps now even higher through federal and provincial carbon taxes – and the extent to which greater market access to the U.S. refiners makes a Trump win beneficial to Canada.

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