Canada has significant shale oil and gas resources and, according to the International Energy Agency, Canada and the US account for virtually all the shale gas produced commercially in the world.
Shale plays in Canada
Some of the most promising Canadian shale fields are just beginning to be developed. For instance, the Horn River Basin in north-eastern British Columbia is thought by some to contain up to 529 TCF of reserves of natural gas, 133 TCF of which is thought to be recoverable. Other prominent shale plays are the Montney, Liard Basin and Cordova Embayment in British Columbia, the Colorado in Alberta, the Bakken in Saskatchewan, the Utica Shale in Quebec, and the Horton Bluff in the Canadian Maritimes.
Canada’s National Energy Board (NEB) anticipates Canadian shale gas development will grow from 1.9 billion cubic feet per day (BCFD) in 2013 to up to 3.5 BCFD by 2016. The NEB anticipates annual drilling activity in the Montney and Horn River Basin shales to increase to between 500 and 900 wells by 2020. To provide context, in July 2009, 234 horizontal wells were producing from the Montney Shale.
The Triassic-aged Montney formation is a mature shale and tight gas play spread over approximately 29,000km2 in British Columbia and Alberta. The British Columbia portion of the Montney is located south of the Horn River Basin, near Dawson Creek, while the Alberta portion is located in the north-western part of Alberta, near Grande Prairie. The Montney underlies the Doig formation, and some call it the Montney/Doig.
It is estimated that the Montney holds one of the largest unconventional resources in the world, with 449 TCF of natural gas, 14 billion barrels of natural gas liquids and 1.1 billion barrels of oil, and annual production estimated to be 3.3–4.4 BCFD by 20201.
The Montney is divided into four distinct intervals: upper, middle, middle-lower and lower. The upper Montney, with nearly 90 per cent of the exploration activity to date, and lower Montney, are considered the most prolific2. The Montney is not a pure shale gas play, as it consists of a blend of low-permeability sandstone, siltstone and shale. While most of the historical development has occurred on the eastern side of the Montney, the western side is now attracting interest from exploration and production companies3.
The Montney lies at a depth of 2,000–2,500m (6,600–8,200 ft)4. It is comparable to other North American shales such as the Fayetteville Shale, the Woodford Shale and the Barnett Shale. The Montney shale thickness averages over 290m (950 ft) and it has an average porosity of 6 per cent5.
Geologists have known about the Montney formation for many years. However, it was largely ignored until advances in horizontal drilling and multi-stage hydraulic fracturing technology, combined with a high market price for natural gas, encouraged its exploration and development.
The Montney holds substantial resource potential and opportunities for future growth. Operators have spent over C$2 billion since 2005 acquiring mineral rights in the Montney6. Land sales set records several years ago. At a mid- July 2008 auction of the British Columbia government’s oil and gas rights, records were broken when buyers collectively paid C$610 million for rights to drill in the Montney area, including C$157 million for a single parcel.
Approximately 3,000 wells were drilled in the Montney until April 2014. Wells generally produce 3-5 million cubic feet per day (MMCFD) on start-up, but are typically followed by rapid declines to long-lived lower production rates. Recoverable gas volumes from the Montney are typically in the 20 per cent range7. Some analysts believe that the recovery factor in the Montney could be much higher at up to 50 per cent.
Horn River Basin
The Horn River Basin is a Devonian-aged shale. It encompasses approximately 11,400km2 (4,400km2) in north-eastern British Columbia and runs north to Fort Liard in the southern Northwest Territories. The accompanying Cordova Embayment straddles the north-eastern corner of British Columbia and the Northwest Territories8.
The Horn River Basin has been drilled with over 300 wells, and the adjacent Cordova Embayment with about 340 wells, of which 40 have targeted shale gas9. The Horn River Basin is estimated to hold up to 133 TCF of recoverable gas, with annual production predicted to be between 1.5 and 2.5 BCFD by 2020.
The Muskwa, Otter Park and Evie members are subunits of the Horn River Basin, and the Horn River Basin is sometimes referred to as the Ootla/Muskwa Shale10. It lies at a depth of 2,370–4,053m (7,800–13,300 ft) and is comparable to the Haynesville shales at a depth of 3,200–4,100m (10,500– 13,500 ft). In terms of thickness and porosity, the Horn River Shale is 110–176m (360–580 ft) thick and has a porosity of 4 per cent.
The Liard Basin is about 9,400km2 (3,600 square miles) and is situated to the west of the Horn River Basin11. It has been drilled with approximately 500 wells, some of which are thought to be among the best shale gas wells in the world.
The Colorado Group is found throughout southern Alberta and Saskatchewan. It includes the Medicine Hat and Milk River shale sandstones, which for over 100 years have been producing natural gas, as well as the Second White Speckled Shale, which has produced natural gas for decades. In some places, the Colorado Shale is approximately 200m thick, with potential to produce gas from five zones. Shale from the Colorado Group produces through thick sand beds, making it a hybrid gas shale like the Montney. The gas is from biogenic rather than thermogenic origins. This means it has a very low potential for natural gas liquids and is underpressured, which is more difficult to hydraulically fracture. Colorado Group shales are sensitive to water, which also makes them sensitive to fluids used during hydraulic fracturing. As an alternative, operators use nitrogen or mixtures of propane and butane as fracturing carrier fluids.
The total volume of gas in the Colorado Group is difficult to estimate given the wide lateral extent of the shale, the variability of the reservoir and the absence of publicly available analyses. However, there could be at least several trillion cubic metres (one hundred TCF) of gas in place. As of 2009, only about 3 MMCFD was being produced out of a few dozen shallow wells in the Wildmere area of Alberta. Typically, only vertical wells are drilled for the Colorado Shale because of the rock conditions.
The Ordovician-aged Utica Shale is among the oldest and most widespread shales in North America. The Utica is found from Pennsylvania to New York to Quebec. It can be divided into the Utica deep and Utica shallow. The deep Utica extends from northern New York to Pennsylvania. The shallow Utica is located in Quebec, with the best prospects lying within a corridor along the St Lawrence River between Montreal and Quebec City.
While there is currently no commercial production, Quebec’s Utica Shale has historically attracted significant attention from exploration and production companies. Estimates in the shallow Utica Shale in Quebec range from 18 TCF to 40 TCF of natural gas if fully developed.12 The Utica Shale averages 150m (500 ft) in thickness with a porosity of 3.5 per cent.
Horton Bluff Group
The Horton Bluff Group of the Canadian Maritimes was deposited in the Early Mississippian period about 360 million years ago. The silica content in the Frederick Brook Shale of the Horton Bluff Group in New Brunswick averages 38 per cent; however, the clay content is also high, averaging 42 per cent. The pay zone appears to be over 150m (492 ft) thick, sometimes exceeding 1km (3,280 ft) in New Brunswick.13
An independent analysis indicates 67 TCF of free gas in place in the Frederick Brook Shale of the Sussex/Elgin sub-basins of southern New Brunswick.14 Another independent analysis indicates 69 TCF of gas is present on the Windsor land block in Nova Scotia.15 Few shale wells have been drilled in New Brunswick or Nova Scotia.
Other Canadian shale gas plays include:
- Canal Shale, Devonian, Northwest Territories
- Duvernay Shale, late Devonian, west-central Alberta
- Exshaw Shale, Devonian-Mississippian, Alberta and north-east British Columbia
- Fernie Shale, Jurassic, west-central Alberta and north-east British Columbia
- Gordondale Shale, early Jurassic, north-east British Columbia
- Klua/Evie Shale, middle Devonian, north-east British Columbia
- Nordegg/Gordondale Shale, late Jurassic, Alberta and north-east British Columbia
- Poker Chip Shale, Jurassic, west-central Alberta and north-east British Columbia
- Wilrich/Buckinghorse/Garbutt/Moosebar Shale, early Cretaceous, west-central Alberta and north-east British Columbia.
Ownership of land and mineral rights
In Western Canada, the surface and mineral rights may be owned by private individuals or entities or by the provincial or the federal Crown.
In 1670, King Charles II of England granted a charter to what is now known as the Hudson’s Bay Company, giving it extensive rights to ownership, trading and government in what was then called Rupert’s Land. This vast area extended from east of Winnipeg to the Rocky Mountains. In 1867, the Dominion of Canada was formed; in 1870, the Hudson’s Bay Company surrendered to the Dominion this land which then became known as the Northwest Territories. In exchange for the surrendered land, the company became entitled to 1/20th of the ‘fertile belt’ or habitable portion of Western Canada.
The Dominion government then arranged for the new territories to be surveyed into townships of 36 sections each. Each section contained approximately 259 ha (640 acres or 1 square mile) and was subdivided into four quarter-sections of approximately 65 ha (160 acres). The Dominion Lands Act then operated to convey to and vest ownership in the surface and subsurface in 1/20th of such lands in the Hudson’s Bay Company.
To encourage settlement and railroad construction, the Dominion government also gave land to settlers and railway companies. Up to 1887, mineral rights were included with surface rights in such land grants. After that, no new mineral grants were issued. In 1905, Alberta and Saskatchewan became provinces. In 1930, the power to grant both surface and mineral rights was transferred from the Dominion government to the government of Alberta.
In Alberta, the provincial government (also known as the Crown) owns 81 per cent of the province’s mineral rights or about 5.37 million ha. The remaining 19 per cent are ‘freehold’ mineral rights, owned either by individuals and companies (such as the successors to the Hudson’s Bay Company, early settlers and railways) or by the government of Canada as national parks or military bases, or on behalf of First Nations.
Alberta now leases, but will not sell, the mineral rights it owns. Title to surface rights, however, may be acquired from the province by application to the Department of Environment and Sustainable Resource Development (ESRD).
Alberta Energy issues mineral leases for subsurface tracts owned by the province. These leases are acquired through a competitive bid auction held every two weeks, with the highest bidder winning the parcel. Prior to offering mineral rights, the province may perform a general assessment to identify major surface or environmental concerns. This may result in the attachment of an addendum to the public offering notice, which reflects a surface or environmental concern that could then affect surface access.
A Crown lease is for an initial five-year primary term, but if the lands are proven productive, it can be continued indefinitely. A parcel may be proven productive by drilling, production, mapping or being included in a production unit. The money paid for leases goes into provincial coffers. There is no requirement for lessees to provide any work commitments.
The process for acquiring mineral rights in British Columbia is similar to that for Alberta. British Columbia was a British Colony that joined Canada in 1871. The mineral rights are owned privately in only about 4 per cent of the province, the other 96 per cent being held by the Provincial Crown.
Land grants from the province to settlers and others have not included mineral rights. This is because British Columbia issues mineral agreements to the oil and gas industry through public auctions, with the highest bid being granted an agreement entitling exploration and development for a term of three to ten years. The tenure may be renewed or extended indefinitely through further exploration or production. There is generally no requirement to make any work commitments to hold lands.
All petroleum located under Nova Scotia lands is by legislation deemed to be vested in the Crown. There are no freehold petroleum rights in Nova Scotia. Lands may be nominated by industry at any time. Usually, this results in a competitive Call for Exploration Proposals. The Nova Scotia Department of Energy reviews the requested parcel(s) and may modify the original parcel size and configuration in consultation with the company that made the nomination.
Public notice of the proposed grant is then given through a Call for Exploration Proposals, posting in industry media and through direct mailings.
The Call for Exploration Proposals remains open for a minimum of 60 days. Applicants submit a bid based on a work commitment, information sufficient to judge their technical and financial capability, and evidence of past experience in exploration. Petroleum rights are then granted to the applicant submitting the best work commitment, providing all other criteria have been met.
The exclusive right to explore is conveyed by an Exploration Agreement, which is a contractual agreement between the applicant and the Minister of Energy. For a conventional petroleum right, at least one well must be drilled in the initial three-year period. Two renewals of three years each are available for lands that continue to be explored. A lease may be issued by the Minister of Energy in response to the filing of an acceptable development programme. The lease is for ten years, with further renewals available upon particular terms and conditions.
However, on September 30, 2014, the Nova Scotia government introduced into the legislature a law which prohibits ‘high-volume hydraulic fracturing’ of on-shore shale formations until it has conducted more research and gained a better understanding of the province’s shale resources.
In New Brunswick, all oil and natural gas resources are also owned by the province. Sales of rights to explore petroleum, and natural gas rights, are held four times a year. The process is similar to that in Nova Scotia where a company nominates lands, which then triggers the Ministry of Natural Resources to publish a tender notice. Bidding is left open for 60 days. A licence to search may be granted to the company with the greatest work commitment, entitling the holder to explore and produce for a three-year non-renewable term. The licence may be converted at any time to a five-year lease, thus entitling the lessee to produce the resources. A lease may be extended indefinitely by production.
In New Brunswick, the government has also banned hydraulic fracturing, thereby stopping all efforts to develop New Brunswick’s shale basins, which are some of the thickest in North America.
Rights, licences and approvals
The NEB regulates certain aspects of the energy industry in Canada, including the construction and operation of inter-provincial and international pipelines, the export and import of oil and natural gas, and oil and gas activities in the Northwest Territories and certain offshore basins. It is an independent federal regulatory agency that reports through the federal Minister of Natural Resources to the Parliament of Canada. Although the NEB has a role, most regulatory activity is at the provincial level through provincial departments, boards or commissions.
In Alberta, the Alberta Energy Regulator (AER) issues permits, licences and other regulatory approvals for the development of upstream oil and gas activities. A Geophysical Exploration Approval is required for seismic activities, and a Licence of Occupation, Mineral Surface Lease or Miscellaneous Lease is needed to access the surface of public lands. For private lands, either an agreement with the landowner or a Right of Entry Order from the Surface Rights Board is required. Operators must be registered with the AER and hold a Business Associate Code to be issued a well, facility or pipeline licence. Additional regulatory approvals are needed for injection and disposal wells, oilfield waste management facilities, flaring, pipelines, roads and other linear disturbances. The AER has also issued numerous regulatory directives covering such things as equipment requirements, measurement, record keeping, reporting, emergency response, inspections, setbacks, noise, well spacing, reservoir and pool development, stakeholder notification and consultation, and equity issues such as common carrier, common processor and rateable take matters. The AER’s directives are largely mandatory.
In September 2014, the AER recognised that its regulatory framework needed to evolve to meet the challenges of developing unconventional oil and gas resources and it proposed a new risk-based and play-focused regulatory pilot project. Instead of approving development on a well-by-well or pipeline-by-pipeline basis, all the operators in a field are required to apply for one collective regulatory approval that authorises, under several pieces of legislation, all the wells, pipelines and facilities for the entire field. This unprecedented level of cooperation among numerous companies will also require them to develop joint risk management plans and undertake joint stakeholder engagement throughout the life cycle of the field’s development.
The AER has also issued a directive on hydraulic fracturing, setting out new provisions to manage risks associated with hydraulic fracturing operations. The provisions include requirements for operators to undertake an assessment of the risks of inter-well-bore communication between the well they want to hydraulically fracture and offsetting wells. Operators also have to develop a risk management plan that allows for the monitoring of offset wells during such operations and provide a response plan in the event of any inter-well-bore communication. The directive protects potable groundwater supplies by prohibiting hydraulic fracturing shallower than 100m below the potable groundwater horizon or within 200m of a water well. Fracturing is also prohibited within 100m of the top of the bedrock.
The British Columbia Oil and Gas Commission (OGC) oversees oil and gas activities within British Columbia, from exploration and development to drilling and decommissioning. Public safety and environmental issues are also a part of the OGC’s mandate. British Columbia’s Oil and Gas Activities Act provides a results-based, singlewindow regulatory framework for regulatory approvals for the industry. Under it, the OGC may issue permits that would otherwise be issued by other government agencies and departments.
Since the hydrocarbon resources in the Horn River Basin and other British Columbia shale plays are believed to be quite substantial, the OGC is preparing for the drilling and production boom that is expected to support numerous liquefied natural gas (LNG) export projects on British Columbia’s west coast. That being said, operators in these resource plays face several constraints, including low gas prices, the short drilling season due to the weather and terrain, the lack of existing infrastructure (pipelines and roadways), produced carbon dioxide and emerging water supply issues.
Access to much of north-eastern British Columbia’s hydrocarbon resources is limited to the winter months (December to March). As the ground thaws in the spring, it is unable to sustain the weight of the drilling equipment. Both workers and production equipment must therefore be removed before the spring break-up commences. In turn, a short drilling season places limitations on the amount of gas that can be produced in the area. However, improvements in technology can effectively extend the drilling season in northern climates. The ability to drill multiple horizontal wells (8–20 well bores) from a single well pad can increase production during the drilling season and improve project economics for companies operating in the region.
The lack of existing infrastructure, such as pipelines or roadways, is also a limiting factor. Without sufficient pipeline capacity to move gas to markets, much of British Columbia’s resources remain shut in. As the area develops, additional pipelines will be required to tie into major export trunk lines and to supply gas to the various LNG projects.
Establishment of a local entity
Several different investment vehicles are available in Canada, each with its own advantages and disadvantages. Tax, liability and other issues are usually the main drivers in selecting the best vehicle and must always be carefully considered.
Incorporation may be undertaken under the federal laws of Canada or provincially under the laws of a province. Generally, incorporation in Canada is a simple and quick process consisting of filing various incorporating forms, paying a fee and registering with various taxation and other authorities. Capitalisation is a matter of choice, and private corporations’ capital and financial information is not shared with the public. Generally, a corporation in Canada has the power of a natural person. A federally or provincially incorporated corporation must be registered in each province and territory where it carries on business.
At least 25 per cent of the federal corporation’s directors must be Canadian residents. If there are three or fewer directors, at least one must be a Canadian resident. Some provinces’ corporation laws also include residency requirements.
A flow-through entity, such as an unlimited liability company, is commonly used for US investors for US tax reasons.
The use of partnerships and joint ventures is common in Canada, especially in the oil and gas industry. A detailed partnership or joint venture agreement is customary. Limited partnerships are often used to permit tax deductions for the limited partners while still providing limited liability protection.
There is little State participation in Canada, and no requirement for the State to obtain an interest in a shale project. However, as most mineral resources are owned by the Crown, it can be said that the State ‘participates’ in shale plays through the collection of Crown royalties.
Taxes and royalties
In Alberta, the province has created a Shale Gas New Well Royalty Rate of 5 per cent to encourage new exploration, development and production from Alberta’s shale gas resources. To qualify, the well must produce shale gas, have no production prior to May 1, 2010 and be drilled into Crown lands. This reduced royalty rate is available for 36 production months. Alberta also has a Horizontal Gas New Well Royalty Rate and a Coal Bed Methane New Well Royalty Rate, each at 5 per cent, for horizontal (non-shale) and coalbed methane wells.
Alberta Energy (AE) administers collection of a freehold mineral tax on production of petroleum and natural gas, including production from shale resources, not owned by the province. The tax ensures that private mineral owners contribute to Alberta’s infrastructure and regulatory costs.
In 2003, British Columbia introduced a series of royalty programmes to ensure that its fiscal regime was competitive with other jurisdictions and that it encouraged development of the province’s natural gas resources. Since then, royalty rates have been introduced to encourage marginal and ultramarginal natural gas wells and credits created for deep gas exploration, summer drilling and infrastructure development.
British Columbia has also created a net profit royalty programme to stimulate the development of high-risk and high-cost oil and gas resources that are not economic under other royalty programmes. Interested parties have to apply to the Ministry of Energy, Mines and Petroleum Resources to access the royalty. The programme requires an investment of at least C$50 million over five years. This includes seismic, road building and drilling, but not land acquisition. The net profit royalty programme allows a net profit royalty to be paid on approved projects, beginning with a royalty rate of 2 per cent of gross revenue while a project is in the prepayout phase and then increasing as the project pays out and becomes profitable.
Foreign currency and investment
The federal Investment Canada Act establishes requirements for non-Canadians who wish to acquire control of an existing Canadian business or to establish a new unrelated business in Canada either to provide notice to Investment Canada or obtain Investment Canada’s approval. The purpose of the Act is to encourage non-Canadians to invest in Canada so as to contribute to economic growth and employment opportunities and to provide for the review of significant investments in Canada by non-Canadians in order to ensure such benefit to Canada.
The thresholds for transactions that are subject to review are C$5 million for direct investments and C$50 million for indirect transactions. However, investors from the World Trade Organisation (WTO) member countries benefit from higher thresholds. New thresholds for review for WTO member investors become effective on January 1 of every year. The threshold for review for WTO investors is C$369 million for the year 2015.
The National Security Review of Investments Regulations (the Regulations) prescribe the various time periods within which the Minister of Energy and/or the Governor in Council must take actions to trigger a national security review, to conduct the review and, after the review, to order measures to protect national security in respect of the reviewed investments. The Regulations also provide a list of investigative bodies with which confidential information can be shared and that may use that information for the purpose of their own investigations.
Guidelines for investments by State-owned enterprises
The minister has issued guidelines for investments by State-owned enterprises (SOEs) to inform investors of certain procedures that will be followed for the review and for monitoring provisions of the Act where the investors are SOEs. An SOE is an enterprise that is owned, controlled or influenced, directly or indirectly, by a foreign government. In their applications for review, non-Canadian investors, including SOEs, are required to identify their owners, including any direct or indirect State ownership or control. It is federal policy to ensure that the governance and commercial orientation of SOEs are considered in determining whether reviewable acquisitions of control in Canada by an SOE are of net benefit to Canada.
Investors must also demonstrate their strong commitment to transparent and commercial operations. The minister determines whether a reviewable acquisition of control by an SOE is of ‘net benefit’ to Canada. The burden of proof is on the foreign investor to demonstrate to the satisfaction of the minister that a proposed investment is likely to be of net benefit to Canada. The minister examines, among other things, the corporate governance and reporting structure of the non-Canadian investor, including whether the non- Canadian adheres to Canadian standards of corporate governance such as commitments to transparency and disclosure, independent members of the board of directors, an independent audit committee, equitable treatment of shareholders and adherence to free market principles.
The minister also assesses the effect of the investment on the level and nature of economic activity in Canada, including the effect on employment, production and capital levels in Canada. The examination also covers how the non-Canadian investor is owned and the extent to which it is controlled by a state or its conduct and operations are influenced by a state.
Specific undertakings related to these issues may assist to supplement a non-Canadian’s plans for the Canadian business. Examples of undertakings that have been used in the past include appointment of Canadians as independent members of the board of directors, employment of Canadians in senior management positions, incorporation of the business in Canada and the listing of securities of the acquiring company or the Canadian business being acquired on a Canadian stock exchange.
Whether transactions require notification or review
The minister has also issued guidelines to assist investors in determining whether various transactions involving the acquisition of interests in oil and gas properties are subject either to notification or review under the Act. The acquisition of a working interest in a property on which only exploration activities are conducted is not treated as the acquisition of an interest in a ‘business’, and is not subject either to notification or review. However, the acquisition of a working interest in a property that contains recoverable reserves will usually be treated as the acquisition of an interest in a ‘business’, and may be subject either to notification or review, depending on the size of the interest being acquired and the asset size of the business.
With respect to oil and gas properties, the relationship among the participants in a particular field or well will ordinarily constitute a joint venture. If the interest being acquired, combined with any existing interest owned by the investor in the property, does not exceed 50 per cent, there is no acquisition of control and the transaction is not subject to the Act. However, if the minority interests being acquired represent all or substantially all of the oil and gas business of the vendor, there will be an acquisition of control of the vendor’s business.
A royalty interest or a net profit royalty is not considered a voting interest or an asset used in carrying on the Canadian business. Therefore, the acquisition of a royalty or net profit interest will not ordinarily be treated as the acquisition of control of a business.
Each property or well governed by a separate operating agreement is treated as a separate business. Therefore, if the investor is acquiring a package of interests in separate properties and there is no acquisition of a majority working interest in at least one of those properties, there will be no acquisition of control of any business, notwithstanding the value of the investment.
Each set of properties subject to a unitisation or pooling agreement is treated as one Canadian business. Therefore, where an investor is acquiring working interests in one or more properties that are the subject of a unitisation or pooling agreement, they may acquire a majority interest in one or more of the properties without being subject to the Act, so long as their overall holdings will not constitute a majority of the interests in the unit or pool.
Assessing the value of an entity
Where control of an entity is acquired, its value is assessed on all its assets, as shown on the audited financial statements of the entity for its most recent fiscal year (i.e. book value). With respect to the acquisition of a controlling interest in an oil and gas property or unit, the ‘entity’ is the joint venture between the participants on the property or unit. Financial statements are not ordinarily prepared in relation to the activities of the joint venture. Therefore, to determine the asset value of the joint venture, it is necessary to aggregate the value of the individual interests in the joint venture.
Environmental protection and socio-economic development
Businesses in Canada are subject to federal, provincial, territorial and municipal environmental regulation. Federal and provincial governments both have jurisdiction over environmental matters, and their environmental statutes and regulations at times overlap. Despite efforts to harmonise environmental standards throughout the country, businesses must consider the potential impact of environmental regulation undertaken by all levels of government in multiple jurisdictions. Many Canadian environmental statutes provide for substantial maximum fines and other penalties for violations.
Federally, the Canadian Environmental Protection Act 1999 (CEPA) regulates the introduction, marketing, use and disposal of toxic substances in Canadian commerce. CEPA includes broad enforcement powers. Regulations under CEPA govern, among other things, the import and manufacture of substances new to Canada, and the import and export of hazardous waste. Hence, CEPA is used to regulate the chemicals used in hydraulic fracturing and the export of oilfield waste out of Canada.
The federal Fisheries Act prohibits, among other things, the deposit of a deleterious substance in any water where fish may be present. It also prohibits the harmful alteration, disruption or destruction of fish habitat. Hence, drilling and production fluids used in shale gas developments cannot be discharged into fishery waters, and roads, seismic lines and pipelines must be constructed so as to avoid harm to fish habitat. Other federal environmental legislation of importance to shale developers includes the Navigation Protection Act, the Hazardous Products Act, the Migratory Birds Convention Act, the Species at Risk Act and the Transportation of Dangerous Goods Act.
Canadian Environmental Assessment Act, 2012
Certain large-scale projects must also satisfy the requirements of the Canadian Environmental Assessment Act, 2012 (CEAA). CEAA applies to projects listed in a regulation, which for oil and gas projects includes projects proposed in wildlife and bird sanctuaries, projects with power plants of 200 MW or more, certain large projects involving sour gas and LNG projects. If CEAA applies, then proponents of such projects are prohibited from acting in a way that may cause an environmental effect in connection with their project. This applies until:
- the Canadian Environmental Assessment Agency (the Agency) decides, after undertaking an environmental screening of the designated project, that no environmental assessment (EA) is required, or
- the Agency decides, after considering an EA study, that the proponent complies with the conditions set out in a decision issued by the Minister of Environment that the project is not likely to cause significant adverse environmental effects, or
- the federal Cabinet decides that any likely adverse environmental effects are justified.
Under CEAA, certain designated projects are automatically subject to an EA, while other designated projects are subject, at least at first, to screening. Designated projects automatically subject to an EA include those regulated by the NEB and those made subject to an EA by future regulations or ministerial order. All other designated projects are subject to a screening. Under a screening, the proponent has to submit a project description to the Agency. If the Agency considers it complete, a summary of the project description is posted to the CEAA internet site, and the public has 20 days in which to provide comments. Within 45 days after the posting, the Agency must decide if an EA is required. The Agency undertakes a screening-level assessment of the designated project to guide its decision.
For designated projects for which an EA is required, the Agency must post notice of the commencement of the EA on the CEAA internet site. Within 365 days from the initial posting, a decision must be issued as to whether the designated project is likely to cause significant adverse effect on federal jurisdiction. The decision may include conditions whereby mitigation measures and follow-up programmes are set out. The conditions must be directly linked or necessarily incidental to the exercise of a federal power or performance of a federal duty that enables the designated project to be carried out. To get to the stage of issuing a decision, the Agency requires the proponent of a designated project to collect information and undertake an EA study. A draft of the study must be made available by the Agency for public comment. After taking into account any public comments, the Agency finalises the study and provides it to the minister who then issues the decision as to whether the project is likely to cause significant adverse effect on matters of federal jurisdiction. If likely to cause such an effect, the decision is then sent to the federal Cabinet to decide if the significant adverse effects are justified.
Provincial and territorial regulation
Canada’s ten provincial and three territorial governments are also very active in the area of environmental regulation. Generally speaking, these regulatory regimes employ both a standards-based system (i.e. specified emission criteria) and an objectives-based system (i.e. prevention of adverse effects).
An example is Alberta’s Environmental Protection and Enhancement Act (EPEA), which provides a framework for the undertaking of project EAs, the issuance of approvals and other environmental permits, the prevention and remediation of pollution and various requirements to decommission, remediate and restore well, pipeline and facility sites.
First Nations have special legal rights in Canada. In 1982, existing aboriginal and treaty rights were recognised and affirmed in Section 35(1) of the Constitution Act 1982. The courts continue to clarify the nature of existing aboriginal and treaty rights and, as a consequence, define the legal relationships between the federal government, the provinces and First Nations. Specifically, government decisionmakers have legal obligations to consider and potentially accommodate claimed aboriginal rights and title which might be impacted by government decisions.
Moreover, decision-makers are required to consult where decisions or actions could potentially infringe upon aboriginal rights, including title or treaty rights. No infringements can be justified without consultation occurring. In short, governments are legally required to consult with First Nations and seek to address their concerns before impacting on claimed or proven aboriginal rights, including title or treaty rights.
Historically, as part of the process to make peace with the Indian tribes, the federal Crown entered into treaties whereby certain blocks of land were reserved for individual First Nations bands. The bands were also granted various rights to unoccupied Crown lands, including the right to hunt, fish and trap. Present-day oil and gas grants by the Crown to industry commonly involve or affect these lands and therefore the Crown has a legal duty to consult and accommodate the bands’ rights in granting land rights and regulatory permits to the industry.
The government of Alberta’s First Nations Consultation Guidelines on Land Management and Resource Development describe Alberta’s policy to consult with First Nations where land management and resource development on Crown land have the potential to adversely impact on First Nations’ rights and traditional uses. The duty to consult rests with the Crown. However, as manager of the consultation process, Alberta has delegated some procedural aspects of its duty to the project proponents. The guidelines require proponents to consult with First Nations in accordance with the policy.
Domestic supply and export
In Canada, both the federal government and some provincial governments have enacted gas export regulatory requirements.
The NEB regulates, among other things, the export and import of natural gas. Under the National Energy Board Act, a licence is required from the NEB to export natural gas. The NEB may issue the licence if it is satisfied that the quantity of gas to be exported does not exceed the surplus remaining in Canada after due allowance has been made for the reasonably foreseeable requirements for use in Canada, having regard to the trends in the discovery of gas in Canada.
The NEB has historically used a market-based procedure (MBP) to review natural gas export licence applications. The MBP was founded on the premise that the marketplace will generally operate in a way such that Canadian requirements for natural gas will be met at fair market prices. The MBP had two parts. The first component was a public hearing, which included:
- a complaints procedure allowing Canadian natural gas users the opportunity to examine the application and complain to the NRB if they could not purchase gas on similar terms and conditions, including price
- an export–import assessment
- consideration of any other public interest matters.
The second part was an ongoing monitoring of markets to identify those that were malfunctioning or where there was doubt about the ability of Canadians to meet their future energy requirements at fair market prices.
In June 2012, amendments to the Act were passed which affected the NEB’s review of gas export applications. As a result of amendments, the MBP is no longer in effect. Hearings for gas export licences are no longer mandatory, and when reviewing an application for a licence, the NEB can only consider whether the quantity to be exported is surplus to Canadian needs, taking into account trends in discovery of the resource. For natural gas export applications filed since the NEB Act was amended, the NEB has utilised a written public notice and comment process in place of an oral public hearing and the complaints procedure.
For gas to be exported out of Alberta, a gas export permit must first be obtained from the AER under the Gas Resources Preservation Act. Such permits are easily obtained. The AER uses the permit as a mechanism to collect statistical information on gas exports.
Outside of the United States, Canada is essentially the only other nation with significant shale gas production. Although some of the most promising shale gas fields are just beginning to be developed, the resource potential is large. A stable and experienced regulatory regime and a predictable financial environment is leading to continued interest in Canada’s shale gas resources.