Canada: Peeling Back The Layers Of LNG Development – A Primer On The Regulatory Framework For LNG Projects In B.C.

In an increasingly competitive global market for natural gas, the race to export liquefied natural gas (LNG) to Asia is on. With LNG attracting a premium price in Asia, Canada is vying with the United States, Australia, Russia, East Africa and the Middle East to rapidly build the infrastructure required to move LNG to key markets in Japan, Korea, Taiwan, China and India. By positioning the LNG industry in British Columbia (B.C.) as a key driver for economic and jobs growth over the next few years, the B.C. government is sending a clear message – the time to act is now.

Not long ago, declining supplies of conventional natural gas meant that the North American marketplace was focused on LNG imports from other jurisdictions. However, the advancement of technologies for recovering shale gas (natural gas produced from the fractures, pore spaces and physical matrix of shales) and horizontal drilling, as well an increase in hydraulic fracturing, have shifted the market to LNG exports. Based on 2013 data from the Energy Information Administration (EIA) agency of the U.S. Department of Energy, recoverable shale gas in Canada is estimated to be 573 trillion cubic feet (Tcf), which ranks Canada fifth in the world in terms of estimated shale gas reserves behind China (with an estimated 1,115 Tcf of recoverable shale gas), Argentina (802 Tcf), Algeria (707 Tcf) and the United States (665 Tcf).

B.C. is particularly well-suited to unconventional gas production, with shale being the most commonly occurring sedimentary rock in the northeast part of the province. In the wake of the commercial success of shale gas plays in the United States, the nascent LNG industry in B.C. is attracting significant interest from investors as an economically feasible venture. The big shale plays in B.C. are Montney (which straddles the border between northeastern B.C. and northwestern Alberta), Horn River, Liard and the Cordova Embayment. A recent provincial-federal report titled The Ultimate Potential for Unconventional Petroleum from the Montney Formation of British Columbia and Alberta (released in November 2013) revealed that the Montney formation contains 449 Tcf of marketable natural gas, more than double previous estimates. The report is the first time that recoverable unconventional oil and gas potential in the Montney basin has been evaluated. On the basis of this evaluation, Montney represents one of the largest natural gas basins in the world.

However, as LNG project proponents are discovering, there are many layers of policy and regulation underlying the development of the LNG industry. This article will examine the current policy and regulatory framework for the development of LNG projects in B.C., as well as consider some of the challenges facing project proponents.

Current Policy Setting

In June 2013, the B.C. government established a new Ministry of Natural Gas Development, which is tasked with implementing provincial strategies for natural gas and LNG. The cornerstone of B.C.'s LNG policy, titled Liquefied Natural Gas: A Strategy for B.C.'s Newest Industry (the LNG Strategy), was released in February 2012 as an accompanying strategy to the provincial government's overall natural gas strategy, British Columbia's Natural Gas Strategy: Fuelling B.C.'s Economy for the Next Decade and Beyond. The LNG Strategy sets out a goal of achieving three LNG facilities by 2020, based on three priorities: (i) keeping B.C. competitive in the global LNG market; (ii) maintaining B.C.'s leadership in climate change and clean energy; and (iii) keeping energy rates affordable for families, communities and industry. To foster the growth of B.C.'s LNG industry, the provincial government continues to shape the policy landscape by adjusting incentives to grow new markets in Asia, focusing on LNG-related job opportunities and training, promoting the use of natural gas and ensuring efficiency in environmental assessment review processes. As of November 2013, there are 12 proposals for LNG projects in B.C. at various stages of development, three of which have received export licences from the National Energy Board (natural gas and LNG use different units of measurement – gas reserves and production are usually measured by volume, whereas gas that is converted into LNG is measured by weight):

  • A 20-year licence was granted to Kitimat LNG (Apache Canada Ltd. and Chevron Canada) in October 2011, which authorizes Kitimat LNG to export 10 million tonnes of LNG per year (which is the approximate natural gas equivalent of 468 Bcf).
  • A 20-year export licence was approved for the Douglas Channel Energy project in February 2012 (BC LNG Export Co-operative LLC: LNG Partners [Texas] and Haisla Nation), which authorizes BC LNG to export 1.8 million tonnes of LNG per year (which is the approximate natural gas equivalent of 84.5 Bcf).
  • A 25-year export licence was issued to LNG Canada (Shell Canada Ltd., PetroChina Company Limited, Korea Gas Corp [KOGAS], Mitsubishi Corporation) in February 2013, which authorizes LNG Canada to export 24 million tonnes of LNG per year (which is the approximate natural gas equivalent of 1,180 Bcf).

As of November 2013, there are six other applications for long-term LNG export licences before the National Energy Board (NEB): (i) Pacific NorthWest LNG Ltd. (PETRONAS, Progress Energy Canada Ltd. and Japan Petroleum Exploration Co.) requesting an export volume of 19.68 million tonnes of LNG per year for 25 years; (ii) WCC LNG Ltd. (Imperial Oil Resources Limited and ExxonMobil Canada Ltd.) requesting an export volume of 30 million tonnes of LNG per year for 25 years; (iii) Prince Rupert LNG Exports Limited (BG Group) requesting an export volume of 21.6 million tonnes of LNG per year for 25 years; (iv) Woodfibre LNG Export Pte. Ltd. (Woodfibre Natural Gas Limited, part of the Pacific Oil & Gas Group) requesting an export volume of 2.1 million tonnes per year for 25 years; (v) Jordan Cove LNG L.P. (Veresen Inc.) requesting an export volume of 9 million tonnes per year for 25 years (this application is for the export of natural gas from Canada to the United States to supply Veresen's proposed Jordan Cove LNG project in Oregon); and (vi) Triton LNG Limited Partnership (AltaGas Ltd. and Idemitsu Canada Corporation) requesting an export volume of 2.3 million tonnes per year for 25 years.

As an added incentive, in September 2013, the B.C. government announced the allocation of $115.8 million in royalty credits under the Infrastructure Royalty Credit Program (which has been in place since 2004) for energy companies to construct roads or build pipelines in support of natural gas production in B.C.'s northeast. Oil and gas companies must fund and complete the entire construction project before they are eligible to recover up to 50% of their costs through the program.

Statutory Framework for LNG Projects in B.C.

On paper it seems straightforward enough – extract natural gas from B.C.'s abundant shales in the northeast of the province, transport it to the B.C. coast, convert it into liquid form and place it on a tanker for delivery to key export markets. The reality is that the permitting process for the construction and operation of LNG facilities and upstream infrastructure is a complex affair that entails a multitude of approvals at all stages of the project. Set out below is an overview of the key approvals that would typically be required for a major project such as an LNG project.

  • Federal Environmental Assessment Approval: If a proposed LNG facility meets the thresholds under the federal Regulations Designating Physical Activities, a federal environmental assessment may be required. The Canadian Environmental Assessment Act, 2012 provides the framework for the federal environmental assessment process, and the main regulator is the Canadian Environmental Assessment Agency. The focus of the federal process is on assessing potentially adverse environmental effects that are within the federal jurisdiction, including fish and fish habitat, other aquatic species, migratory birds, federal lands, effects that cross provincial or international boundaries, and impacts on Aboriginal peoples. A federal environmental assessment process can be expected to take between 24 and 36 months to complete from the time a project description is submitted, but delays may occur if the project proponent is required to submit further information or legislated timelines are extended by the minister to enable interjurisdictional cooperation or because of project-specific circumstances.
  • Provincial Environmental Assessment Approval: In B.C., the primary environmental assessment legislation is the Environmental Assessment Act and the main regulator is the B.C. Environmental Assessment Office (EAO). If a project meets the thresholds set out in the B.C. Reviewable Projects Regulation, a provincial environmental assessment will be triggered that will focus on the potential environmental, economic, social, heritage and health effects of the development of the project. The provincial process is carried out in three phases: (i) pre-application phase, in which the proponent provides basic information about the project; (ii) application review phase; and (iii) environmental assessment certificate decision. Depending on the technical complexity of the project and consultation requirements, the pre-application stage typically takes 12 to 18 months to complete. The application review stage is governed by legislated timelines, so the EAO has six months to review the application once it has been accepted. Following review, the EAO will refer its report and recommendations to the Minister of Environment and Minister of Natural Gas Development for review, and they will have 45 days to make a decision on whether or not to certify the project (the ministers may extend the time limit if needed). By their nature, federal and provincial regulatory processes overlap. To clarify roles and responsibilities, as well as to avoid a duplication of efforts, the federal and B.C. governments have entered into the Canada-British Columbia Agreement on Environmental Assessment Cooperation (2004). In addition, B.C. and the federal government also have in place a Memorandum of Understanding on the Substitution of Environmental Assessments to help facilitate a single review process whereby both provincial and federal environmental assessments are required.
  • LNG Export Licence: If the proponent plans to export LNG from Canada, a licence from the NEB under the National Energy Board Act authorizing the export will be required. In order to grant an export licence, the NEB must be satisfied that the quantity of gas to be exported does not exceed the surplus remaining after due allowance has been made for the reasonably foreseeable requirements for use in Canada.

Depending on the project design and required infrastructure, LNG projects will require additional permits from the federal and provincial agencies that have jurisdiction over various aspects of the development of the project:

  • PNG Tenures: As they relate to upstream activities, the majority of sub-surface petroleum and natural gas (PNG) rights in B.C. are owned by the government. By entering into a tenure agreement with the province, private parties can develop these resources. Governed by the Petroleum and Natural Gas Act (PNG Act), PNG tenures provide time-limited rights intended to facilitate the sustainable and efficient development of PNG resources. A PNG lease, which is acquired either through a competitive auction process or by conversion from permits or drilling licences, is the only form of tenure that gives a right of production. Once tenure has been issued, the tenure holder must apply to the B.C. Oil and Gas Commission (the Commission) for permits to conduct activities related to the exploration and development of PNG resources and to build related facilities (which could also trigger a provincial environmental assessment).
  • Permits for Oil and Gas Activities: The Commission regulates oil and gas activities in B.C. under the Oil and Gas Activities Act. Oil and gas activities refer to the exploration, development, processing and storage of oil and gas as well as the construction and operation of pipelines and roads. B.C. has a "single window" approach to the regulation of oil and gas activities, meaning that the Commission has broad authority to regulate oil and gas activities under a wide variety of legislation, including the Oil and Gas Waste Regulation, Environmental Management Act, Heritage Conservation Act, Land Act, Forest Act and Water Act. Additional permits for water and waste management for LNG facilities may also be required under the Water Act and Waste Discharge Regulations. As part of the provincial environmental assessment process, an Archaeological Impact Assessment (AIA) and Heritage Resources Inventory and Assessment will be required under the Heritage Conservation Act. If archaeological or culturally significant resources exist at the project site, the AIA will confirm this and recommend mitigation measures.
  • Land Use Permits and Road Access: Land use permits may be required under the B.C. Land Act from the Ministry of Forests, Lands and Natural Resources Operations. Other land tenures will also be required, including rights-of-way and leases. If required, permits to access public and industrial roads and to transport dangerous goods can be obtained from the B.C. Ministry of Transportation under applicable legislation, including the Transportation Act and the Industrial Roads Act.
  • Marine Terminal and Shipping: If a project includes a marine terminal, completion of the Technical Review Process of Marine Terminal Systems and Transshipment Sites (TERMPOL) may be required, which focuses on shipping routes in Canadian waters as they relate to cargo handling between vessels, or off-loading from ship to shore or vice versa. The findings of a TERMPOL review may be used by the federal Minister of Transport to inform decisions on shipping routes under the Canada Shipping Act.
  • Other Permits: In addition to the various provincial permits outlined above, other permits under federal legislation may be required for project activities, including (i) Fisheries Act authorizations; (ii) Navigable Waters Protection Act (NWPA) approvals to construct the various project components that would impact navigation; (iii) permits for the disposal of excavated or dredged material at sea under the Canadian Environmental Protection Act, 1999; and (iv) any permits required under the Species at Risk Act. It should be noted that in 2012, the federal government introduced significant changes to environmental legislation through its omnibus budget implementation bills C-38 and C-45, including important changes to the Fisheries Act (shifting the focus from habitat protection to fisheries protection) and NWPA (which is expected to be replaced by a new Navigation Protection Act (NPA) in April 2014). With the new fisheries protection provisions of the Fisheries Act coming into force on November 25, 2013 and the introduction of the NPA in April 2014, project stakeholders should be mindful of any potential impacts of these amendments on project planning and development.

First Nations Consultation

Consultation with stakeholders, including First Nations, is legally required for the development of major resource projects in Canada. Section 35 of Canada's Constitution, which recognizes and protects Aboriginal rights and treaty rights, has spawned a modern body of case law that Aboriginal people, governments and proponents must all navigate to successfully develop resource projects. One of the key concepts to emerge from the landmark Haida and Taku River cases in 2004 is the doctrine of the Crown's "duty to consult" Aboriginal peoples. The Crown has a duty to consult with and, where appropriate, accommodate Aboriginal peoples whenever the Crown (i) has knowledge (real or constructive) of the potential existence of an Aboriginal or treaty right or interest and (ii) contemplates conduct that might adversely affect it (such as issuing project approvals). The duty to consult is easily triggered, but the level of consultation required will depend on the strength of the particular Aboriginal right or claim and the potential impacts a particular project may have on the Aboriginal interest. As a result, the scope of the duty to consult will be assessed on a case-by-case basis. Within the context of major resource projects, the duty to consult will usually be triggered at the start of the regulatory review process. While the duty to consult rests with the Crown, the procedural aspects of this legal obligation are often delegated to the project proponent. This means that the proponent must be proactive in engaging with potentially affected First Nations and discussing their concerns in a meaningful way. The duty to consult is an ongoing obligation throughout the life of a project.

If it is determined that the project will have impacts on the local First Nations community, the Crown and project proponent may be required to accommodate Aboriginal rights or interests. At law, accommodation can include mitigating, minimizing or avoiding adverse effects of project activities on Aboriginal interests. A common business practice that has evolved in various industries across Canada is the negotiation of so-called impact and benefit agreements (IBAs) between project proponents and First Nation groups. IBAs aim to provide benefits to the local Aboriginal community and may include training and business opportunities, profit sharing, equity participation and other economic incentives.

The proposed LNG projects in B.C. are located primarily around the Prince Rupert and Kitimat areas on the north coast of the province, which also intersect with the traditional territories of several First Nations in the region. The success of LNG projects – including not only the construction of the LNG facilities but also the production of shale gas upstream and the construction of pipelines to transport shale gas – will depend very much on the support of affected First Nations. An early success story is the agreement reached in February 2013 by the province of British Columbia, the Pacific Trail Pipelines Limited Partnership (a partnership between Apache Canada Ltd. and Chevron Canada Ltd.), and the First Nations Group Limited Partnership (FNLP, a consortium of 15 northern Aboriginal groups) for the proposed 463-kilometre Pacific Trail Pipeline project that will transport natural gas to the proposed Kitimat LNG plant for export. The benefits agreement will provide up to $200 million in benefits to FNLP members whose traditional territories will be affected by the construction and operation of the Pacific Trail Pipeline.

Key Issues for LNG in B.C.

By implementing policies to encourage the growth of LNG in the province, the B.C. government is signalling its commitment to facilitate the success of B.C.'s LNG industry in the global market. As LNG projects advance, there are a number of issues to keep an eye on:

  • LNG Export Tax Rates: The B.C. government is expected to finalize the details of its export tax regime for the LNG sector before the end of 2013 and introduce it into the legislature in early 2014. The government hopes the regime will generate $100 billion over 30 years for a provincial prosperity fund. Faced with stiff competition, the B.C. government is under pressure not to price Canadian natural gas out of a very competitive global market. The formula for a competitive export tax will need to take into account natural gas prices, development costs and profitability. B.C.'s Minister of Natural Gas Development, Rich Coleman, has indicated that the tax will apply strictly to LNG exports and will not increase royalties on gas production from drilling in northeast B.C. Minister Coleman has also indicated that the tax will have some flexibility to respond to market dynamics, which could suggest a tax rate that is tied to gas prices.
  • First Nations: If Aboriginal concerns are not properly addressed or the Crown's duty to consult has not been satisfied, project approvals could face legal challenges resulting in delays and increased costs. To move LNG development forward, there is pressure on governments, energy companies and First Nations to resolve issues quickly in order to clear a path for exporting LNG. B.C. is a particularly challenging environment in which to negotiate, given the number of unresolved land claims, overlapping claims and extensive history of litigation. First Nations are being asked to make important decisions about major energy projects that may permanently change their relationship to their traditional way of life. Effective risk management of LNG projects must include meaningful engagement with affected First Nations, which will help to avoid confrontation and resistance to project development by local communities.
  • Air Quality: A key environmental concern is the impact of the LNG industry on air quality, particularly in Kitimat, which is already home to an aluminum smelter and is the proposed location for four LNG plants, an oil refinery and a crude oil export facility. The provincial government has announced funding for the Kitimat Air Shed Impact Assessment Project (expected to be completed by spring 2014) to examine the impact of cumulative emissions of existing and proposed industrial activities in the Kitimat air shed area, which is considered a constrained air shed due to its topography. Since the operation of LNG facilities will require significant amounts of electricity and companies are looking at generating power by burning natural gas, the study will also examine the impact of emissions from gas-turbine-powered electrical generation facilities and will focus on the sulphur dioxide and nitrogen dioxide emissions from these facilities. The results of the study will guide regulatory and policy developments for future industrial development in the region.
  • The Carbon Question: B.C. has set an emissions reduction target of 33% below 2007 levels by 2020. Even before LNG is transported, regasified into natural gas and consumed overseas, the extraction, transportation and liquefaction of natural gas already represent a carbon-intensive process. With its plan to have at least three LNG facilities in operation by 2020, the B.C. government will be hard pressed to meet its emissions reduction target as the development of LNG pushes this goal out of reach. To address concerns about B.C.'s growing carbon footprint, the provincial government has committed to having "the cleanest LNG facilities in the world" in terms of life cycle greenhouse gas emissions. The B.C. government continues to weigh its policy options as it considers how to reconcile its legislated emission reduction targets with its ambitious LNG development plans.

After peeling back the many layers of LNG development in B.C., the various regulatory drivers and issues currently shaping the LNG industry are revealed. LNG issues must also be considered within the larger context of the Western Canadian energy market, in particular its interaction with issues arising from the development of oil export infrastructure and how the cumulative impacts of natural gas activities are changing the landscape in northern B.C. Given the myriad issues involved in getting an LNG project off the ground, the race to export LNG will need to be run as more of a marathon than a sprint to the finish line.

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