Report of the Committee on the Science-Based Assessment of Offshore Oil and Gas Exploration and Development in the Eastern and Central Arctic

2.1 The Nunavut Agreement and related federal acts

The creation of Nunavut on April 1, 1999 was an outcome of the largest Aboriginal land claims agreement in Canadian history, the Nunavut Land Claims Agreement, also known as the Nunavut Agreement, between the Government of Canada and the Inuit of the Nunavut Settlement Area (Figure 1).^{Footnote 5} The Nunavut Agreement was formally adopted on July 9, 1993.

The Nunavut Agreement sets the foundation for Inuit participation in "decision-making concerning the use, management and conservation of land, water and resources, including the offshore."^{Footnote 6} Provisions with respect to resource development, including the role of co-management boards, apply mostly to projects that take place, in whole or in part, within the Nunavut Settlement Area. However, some provisions also apply to projects within the Outer Land Fast Ice Zone, an area of Baffin Bay and Davis Strait adjacent to the Nunavut Settlement Area, or to 2 distinct zones beyond the Nunavut Settlement Area.^{Footnote 7}

Many of the provisions related to the management of resource development in the Nunavut Settlement Area are enshrined in 2 federal acts: the Nunavut Planning and Project Assessment Act^{Footnote 8} and the Nunavut Waters and Nunavut Surface Rights Tribunal Act. These acts set out the powers, functions, objectives and duties of the Institutions of Public Government^{Footnote 9}. The Nunavut Planning and Project Assessment Act is particularly relevant to oil and gas development as it formally establishes the regulatory processes through which project proposals requiring authorization^{Footnote 10} are reviewed in respect of land use conformity and environmental impact assessment.^{Footnote 11}

Source: Map of the Nunavut Settlement Area, Schedule 3-1, Nunavut Land Claim Agreement.

Text alternative for Figure 1: Nunavut Settlement Area

Figure 1 is a map that depicts the boundaries of the Nunavut Settlement Area established in the Nunavut Land Claim Agreement. As shown on the map, the Nunavut Settlement Area is separated in 2 areas, Area A and Area B. Area A covers a portion of the Arctic Islands and mainland of the Eastern Arctic and adjacent marine areas. Area B covers the Belcher Islands, associated islands and adjacent marine areas in Southeastern Hudson Bay.

Another important feature of the Nunavut Agreement is the granting of title to Inuit of about 356,000 square kilometres of land. These Inuit Owned Lands include 150 parcels for which Inuit hold title to both the surface and subsurface ("Subsurface Inuit Owned Lands") and 944 parcels for which the Crown owns the minerals, oil, and gas ("Surface Inuit Owned Lands"). The only Inuit Owned Lands parcels in which there may be oil and gas potential are in the Norwegian Bay area (onshore) in the southeastern part of the Sverdrup Basin.

2.2 Federal acts and regulations

There are 2 general areas of federal responsibility for oil and gas, regulating operations and administering rights. These are covered, respectively, under the Canada Oil and Gas Operations Act, which applies to all operations that take place in Nunavut, and the Canada Petroleum Resources Act, which applies only to frontier lands.^{Footnote 14} Several other acts and regulations are also applicable to oil and gas operations.

2.2.1 The Canada Oil and Gas Operations Act and the Canada Energy Regulator

The Canada Oil and Gas Operations Act governs the exploration and drilling for and the production, conservation, processing and transportation of oil and gas in Nunavut, onshore and offshore, and the adjacent continental shelf (and the overlying water). It also applies to the waters adjacent to Yukon and the Northwest Territories as well as Pacific and Atlantic waters not under a federal-provincial joint-management arrangement (Figure 2). The act is intended "to promote safety, protection of the environment, the conservation of oil and gas resources, and joint production agreements."^{Footnote 15} Under the Frontier and Offshore Regulatory Renewal Initiative, the Canada Oil and Gas Operations Act regulations^{Footnote 16} pertaining to geophysical operations, exploration and development drilling, and the construction, certification and operation of production facilities are being modernized and will be amalgamated into Framework Regulations. The Canada Energy Regulator^{Footnote 17} regulates all oil and gas activities in areas to which the Canada Oil and Gas Operations Act applies. For the nearly 6 decades before the Canada Energy Regulator came into existence in August 2019 when the Canadian Energy Regulator Act became law, the National Energy Board oversaw energy companies and projects in Canada.

Notes: The Canada Energy Regulator regulates oil and gas activities in the Nunavut Area, Canada's waters in the Arctic, Pacific and Atlantic offshore areas not subject to a federal-provincial accord, and activities that transect provincial and territorial borders.

Text alternative for Figure 2: Canada Energy Regulator Areas of Jurisdiction

Figure 2 depicts the areas of jurisdiction of the Canada Energy Regulator over oil and gas work or activities. Hudson Bay, Nunavut and offshore areas in the Arctic, and the Pacific offshore are all regulated by the Canada Energy Regulator under the Canada Oil and Gas Operations Act. The Northwest Territories mainland is regulated by the government of the Northwest Territories' regulator. Onshore areas in the Inuvialuit Settlement Region are regulated by the Canada Energy Regulator under the Oil and Gas Operations Act. The Norman Wells Proven Area in the Northwest Territories is regulated by the Canada Energy Regulator under the Canada Oil and Gas Operations Act. The Canada-Newfoundland and Labrador Offshore Petroleum Board regulates all offshore areas off the coast of Newfoundland and Labrador, The Canada-Nova Scotia Offshore Petroleum Board regulates all offshore areas surrounding Nova Scotia. The Canadian Quebec Joint Accord Area, located in the Gulf of Saint Lawrence, is under the jurisdiction of the Canada Energy Regulator. Pipelines regulated by the Canada Energy Regulator under the Canada Energy Regulator Act are also depicted on the map and are located in southern parts of Nova Scotia, Quebec, Ontario, Manitoba and Saskatchewan. Most of the Canada Energy Regulator regulated pipelines are located all over Alberta and extend to the Norman Wells Proven Area in the Northwest Territories. There are also Canada Energy Regulator regulated pipelines in British Columbia. The Canada Energy Regulator also regulates the pipeline for the Ikhil gas well under the Oil and Gas Operations Act. The pipeline is located in the Inuvialuit Settlement Region, in the northwestern part of the Northwest Territories.

Environmental assessment

Any oil and gas project within the Nunavut Settlement Area that requires authorization under the Canada Oil and Gas Operations Act is subject to an environmental screening process carried out by the Nunavut Impact Review Board. An assessment under the Impact Assessment Act is required for an oil and gas activity that is authorized under the Canada Oil and Gas Operations Act and is a designated project outside the Nunavut Settlement Area. Environmental assessments for pipeline projects in the North and offshore crossing a territorial and provincial boundary fall under the Canadian Energy Regulator Act.

Review of offshore drilling

In December 2011, the National Energy Board^{Footnote 18} released "The Past is Always Present – Review of Offshore Drilling in the Canadian Arctic – Preparing for the Future."^{Footnote 19} The National Energy Board consulted extensively with northern stakeholders and industry representatives during this review and examined the best available information on the hazards, risks and safety measures associated with offshore drilling in the Canadian Arctic. As an outcome of the review, the National Energy Board identified key filing requirements that companies applying to drill in Canada's Arctic waters would have to meet, providing greater regulatory clarity. The complete set of filing requirements is contained in the companion document to the review, "Filing Requirements for Offshore Drilling in the Canadian Arctic."^{Footnote 20} As part of the review, the National Energy Board also re-affirmed Canada's "Same Season Relief Well Policy", which requires that an applicant for an offshore drilling authorization "demonstrate, in its Contingency Plan, the capability to drill a relief well to kill an out-of-control well during the same drilling season."^{Footnote 21} Alternatively, an applicant could demonstrate that its proposed alternative method(s) to kill a blowout would meet or exceed the intended outcome of the Same Season Relief Well Policy (the Same Season Relief Well Equivalency determination.) The Canada Energy Regulator maintained these requirements.

2.2.2 The Canada Petroleum Resources Act and the administration of rights

Issuance of licences

Under the Canada Petroleum Resources Act, licences are issued to allow for the exploration, development, and production of petroleum with respect to all frontier lands. The issuance of oil and gas licences under the Canada Petroleum Resources Act follows a transparent, competitive process.^{Footnote 22} The process for an exploration licence normally commences with a call for nominations by Crown-Indigenous Relations and Northern Affairs Canada that allows the Department to gauge the level of commercial interest to explore on frontier lands. Next, Crown-Indigenous Relations and Northern Affairs Canada may issue a call for bids, which is a formal invitation to companies to participate in an auction of the lands. During this stage, Crown-Indigenous Relations and Northern Affairs Canada assesses the bids on a single bid criterion – the total amount a company commits to invest exploring the licence area. The Minister of Crown-Indigenous Relations and Northern Affairs Canada may issue an oil and gas licence to the company with the highest bid.

The administration of the Canada Petroleum Resources Act is divided between Crown-Indigenous Relations and Northern Affairs Canada and Natural Resources Canada. Crown-Indigenous Relations and Northern Affairs Canada is responsible for the administration of the act north of its administrative boundary with Natural Resources Canada shown in Figure 3. The map also shows the existing significant discovery licences in Nunavut. More detailed maps are provided in Annex 3.

Text alternative for Figure 3: Canada Petroleum Resources Act: Minister of Crown-Indigenous Relations Canada Jurisdiction

Figure 3 is a map showing the position of exploration licences and significant discovery licences issued in the Arctic (Beaufort Sea, Arctic Islands and Eastern Arctic) within Crown-Indigenous Relations and Northern Affairs' jurisdiction. Exploration licences are all located in the Beaufort Sea. Significant discovery licences are located in majority in the Beaufort Sea, in the same area as the exploration licences, and in the Arctic Islands. One significant discovery licence is located in Eastern Arctic, east of Baffin Island. The map also depicts the location of oil and gas pipelines in Northern British Columbia, Alberta, and in the Northwest Territories.

There are 3 types of oil and gas licence issued under the Canada Petroleum Resources Act:

Exploration licence

The exploration licence grants the exclusive right to the licence holder to explore for and to develop oil and gas resources in the licence area. The exploration licence has a fixed, 9-year term that may not be renewed. The holder of an exploration licence is required to submit a refundable work deposit, which may be forfeited if the licence holder does not meet its obligations to drill an exploration well within the term of the licence.

Significant discovery licence

When exploration results in a significant discovery, that is, if the licence holder drills an exploration well and proves that it has commercial potential, an application can be made for a Significant Discovery Declaration from the Canada Energy Regulator. Upon receiving a Significant Discovery Declaration, the holder of an exploration licence can apply to Crown-Indigenous Relations and Northern Affairs Canada for a significant discovery licence for the area of the discovery. The significant discovery licence, like the exploration licence, grants the licence holder the exclusive right to explore for and develop oil and gas resources within the licence area. However, the term of the significant discovery licence is in perpetuity.

Production licence

The final type of licence is the production licence. A production licence grants an exclusive right to the licence holder to develop and produce oil and gas resources in the licence area. The term of a production licence is 25 years but may be extended as long as there is ongoing production. A full process map for rights issuance is provided in Annex 4.

Canada Petroleum Resources Act Review

On May 30, 2016, the Minister's Special Representative, Mr. Rowland Harrison, Q.C., finalized the Review of the Canada Petroleum Resources Act. The purpose of the Review was:

"to conduct a comprehensive review of the operations of the Canada Petroleum Resources Act, to engage with aboriginal groups, stakeholders and other interested parties as appropriate, and to provide recommendations as to whether potential amendments should be made to the Act as it applies to the Arctic offshore."

The Review concluded that while the scheme of the Canada Petroleum Resources Act is robust and should be maintained, the role of the act should be clarified. Harrison proposed 10 recommendations to the act to better reflect today's understanding of the technical and regulatory challenges in Canada's Arctic waters.

Benefits plans

A benefits plan is a statutory requirement under the Canada Oil and Gas Operations Act and the Canada Petroleum Resources Act. An operator engaged in the exploration and drilling for, and (or) the production and transportation of, oil and gas in Nunavut and the adjacent continental shelves is required to submit a benefits plan to the Minister of Crown-Indigenous Relations and Northern Affairs Canada for approval.^{Footnote 23}

Section 5.2(1) of the Canada Oil and Gas Operations Act defines a benefits plan as a

"plan for the employment of Canadians and for providing Canadian manufacturers, consultants, contractors and service companies with a full and fair opportunity to participate on a competitive basis in the supply of goods and services used in any proposed work or activity referred to in the benefits plan."

While the Canada Oil and Gas Operations Act does not provide any detail on what constitutes a benefits plan, guidelines^{Footnote 24} prepared by the federal government specify that a benefits plan should include a project description as well as the operator's strategies for training and employment, procurement and contracting, and monitoring and reporting. The guidelines also outline the main principles, along with corresponding objectives, that an operator engaged in an oil and gas work or activity on frontier lands is expected to follow.

A benefits plan should ensure that Inuit and other Northern residents and businesses are provided an opportunity to participate in and benefit directly from oil and gas work or activities on Northern frontier lands. An operator is encouraged to develop and implement training and employment strategies as well as business and procurement processes that maximize Northern benefits.

Royalties

Federal frontier lands are subject to a generic royalty regime authorized under the Canada Petroleum Resources Act and prescribed through the Frontier Lands Petroleum Royalty Regulations.^{Footnote 25} While the federal government collects royalties, Inuit are entitled^{Footnote 26}, under Article 25 of the Nunavut Agreement, to a percentage of revenue from all projects in which the resource is within the Nunavut Settlement Area or the Outer Land Fast Ice Zone. Inuit would be the sole beneficiary of resource revenue from production on Subsurface Inuit Owned Lands.^{Footnote 27}

2.3 Devolution

Nunavut's regulatory environment will be further developed as the Government of Canada transfers responsibility for administration and control of public (Crown) land and resource management to the Government of Nunavut. This process, known as devolution, will allow Nunavummiut to make decisions on how public lands and resources are used and developed. On August 15, 2019, the parties signed an agreement-in-principle which will now serve as a guide for the negotiation of a final devolution agreement in Nunavut. These negotiations were still ongoing when this report was prepared.

The agreement-in-principle's chapter on administration of oil and gas resources sets out the framework for the transfer of responsibility for oil and gas management in the onshore, which will be detailed in the final Devolution Agreement. This will include a coordination and cooperation agreement between the Parties with respect to onshore and offshore oil and gas resources, particularly in areas where oil and gas resources straddle or potentially straddle the onshore and offshore. The signing of a Devolution Agreement will also allow, upon the written request of the Government of Nunavut, for the start of negotiations for an offshore agreement with respect to management, decision making, and resource revenue sharing.

4.1 Addressing the Nunavut Impact Review Board's recommendations: Government of Nunavut Action Plan Discussion Paper

The Government of Nunavut has actively participated in the various stages of the Strategic Environmental Assessment and has substantial interest in respecting sustainable development in and around Nunavut, from environmental, socio-economic, cultural, and other vantage points. In the Government of Nunavut Action Plan Discussion Paper, an analysis of the Strategic Environmental Assessment and an Action Plan to address Nunavut Impact Review Board's recommendations are presented to set out priorities as guided by the results of the Strategic Environmental Assessment.

It is important to note that priorities could vary depending on several factors such as the priorities of partners, stakeholders and the communities. The Government of Nunavut is sharing the Action Plan for the purpose of discussions, hoping that some high priority action items could be delivered by the relevant partners and stakeholders. Initial comments are provided on the quality of the completed Strategic Environmental Assessment and the overall success in achieving its objectives. The Action Plan also sets out the priority of each of the recommendations, as well as the likely timeline and potential partners that would be involved. The actions are separated into the key topic areas below:

• spill prevention and response
• benefits regime and compensation
• scenario development
• sensitive areas, species at risk, and areas of importance for Inuit
• building a strong knowledge base
• regional planning, policy, and community engagement
• project mitigation, impact assessment, and monitoring

The implementation of this action plan is subject to the approval of the partners, engagement and consultation with the affected communities, availability of federal funding and collaboration between stakeholders.

5.1 History of exploration and production

Hydrocarbon (oil and gas) exploration in the Eastern and Central Arctic began with seismic surveying in the early 1960s^{Footnote 36} and the drilling of the first well at Resolute Bay in 1963. Altogether, 150 exploration boreholes were drilled:

• 146 in the Arctic Islands
• 3 in Davis Strait
• 1 in Foxe Basin^{Footnote 37}

One hundred and twenty-five of the holes in the Arctic Islands were in the Sverdrup Basin^{Footnote 38}, resulting in 19 hydrocarbon discoveries:

• 9 of gas
• 7 of oil and gas
• 3 of oil^{Footnote 39}

Two of the 3 holes drilled in Davis Strait in 1980 were in the Saglek Basin^{Footnote 40}, Hekja O–71 and the nearby Ralegh N–18. The Hekja O–71 well, 80 kilometres east of Loks Land, an island at the mouth of Frobisher Bay, discovered the Hekja field, with 2.3 Tcf^{Footnote 41} of gas. The Ralegh N–18 well, drilled to the north of Hekja, and Gjoa G–37, drilled just outside the Saglek Basin, were unsuccessful. All of the discoveries are subject to significant discovery licences.^{Footnote 42}

The only production to date has been from the Bent Horn oil field on Cameron Island. Between 1985 and 1996, 1 to 3 tankers of oil were shipped to a refinery in Montreal or Europe every summer, for total production of 2.8 million barrels.^{Footnote 43}

5.2 Reports prepared for the Five-Year Review

At the request of Crown-Indigenous Relations and Northern Affairs Canada, the Geological Survey of Canada prepared 2 reports on the oil and gas resources in the Eastern and Central Arctic. The first report "Resource Assessments of Northern Offshore Canadian Sedimentary Basins, 1973 to 2020"^{Footnote 44} (the Resource Assessment) covers all of the Canadian Arctic offshore, including the waters adjacent to Yukon and the Northwest Territories and areas of the Eastern and Central Arctic^{Footnote 45} subject to the moratorium. It presents brief descriptions of the geology of 8 sedimentary basins^{Footnote 46},^{Footnote 47}, the seismic surveys and drilling carried out, and the results of resource assessments of oil and gas in each basin.

The second report, "Northern Nunavut Hydrocarbon Prospectivity Study"^{Footnote 48} (the Prospectivity Report), builds on the Resource Assessment to provide an overview of the prospectivity^{Footnote 49} of hydrocarbon resources in the offshore^{Footnote 50} areas of the Eastern and Central Arctic^{Footnote 51}, including 3 sedimentary basins not described in the first report. For each of the 10 basins that have at least some probability of containing hydrocarbons (Figure 5), the report describes several aspects related to the prospectivity, including the geology and petroleum systems^{Footnote 52}, past exploration, previous studies, previous resource estimates, the level of confidence in previous estimates, and future work that might be done with respect to the basins and the level of effort that would be required to do that work. The basins described in the report can be grouped into 3 areas:

Baffin Bay and Davis Strait

• Saglek Basin lies offshore Baffin Island, south of Cumberland Sound and extending along the coast of Labrador as far south as about 56°N.
• Baffin Margin^{Footnote 53} is present along the coast of Baffin Island extending south as far as Cumberland Sound. It includes a number of sub-basins.
• Lancaster Sound, Baffin Fan^{Footnote 54} occupies Lancaster Sound and the adjacent area of Baffin Bay.

Source: Prospectivity Study; dashed lines and stars have been added – note that the locations of these are approximate.

Text alternative for Figure 5: Sedimentary Basins in Nunavut

Figure 5 is a depiction of sedimentary basins in Nunavut. A portion of the boundary (approximate) between Nunavut and the Northwest Territories is shown by the dashed line (the north-south portion follows the 110⁰W line of longitude.). The Drake and Hecla gas fields are shown by stars near the left margin, near the boundary between Nunavut and the Northwest Territories, (Hecla is on the left) and the Hekja field is shown by the star below the "S" of Saglek Basin. The various areas depicted on the map are the following: the Deformed Franklinian Belt, which extends from Ellesmere Island to Melville Island between the Arctic Platform to the south and the Sverdrup Basin to the north; the Sverdrup Basin, which underlies the northern and central parts of the Arctic Islands, north of the Deformed Franklinian Belt; the Arctic Margin, north of the Sverdrup Basin, extending from Banks Island to Ellesmere Island; the Baffin Fan occupies Lancaster Sound and the adjacent area of Baffin Bay; the Alpha Ridge, located north of the Arctic Margin; the Lincoln Sea Basin, located north of Greenland and the Arctic Islands; the Lomonosov Ridge located west of the Lincoln Sea Basin and north of the eastern portion of the Alpha Ridge; the Baffin Margin, located in between Baffin Island, Ellesmere Island, Devon Island and Greenland; the Foxe Basin, located between Baffin Island and Melville Peninsula; the Saglek Basin lies offshore Baffin Island, south of Cumberland Sound and extending along the coast of Labrador as far south as about 56°N, and the Arctic Platform that covers the southern Arctic Islands, parts of northern Baffin Island and extends onto the northern mainland.

5.3 Previous resource assessments

The previous resource assessments vary in quality and detail. According to the Prospectivity Report: "Older assessments predicted the size of the resource in a sedimentary basin, but did not predict where those resources might be found. Newer assessments from the Geological Survey of Canada make qualitative predictions on the location of resources but not their size." Figure 6 shows that on the basis of the previous assessments, most of the potential oil and gas resources are in the Sverdrup Basin, Baffin Margin and Arctic Margin.

Notes: Assessments for some basins include areas that are west of 110°W, thus are in the Northwest Territories. Assessments for Sverdrup Basin, Deformed Franklinian Belt and Arctic Platform include significant onshore resources. Baffin Margin excludes the Saglek Basin and the Baffin Fan. There are no separate previous assessments for Saglek Basin and Baffin Fan. "Barrels oil equivalent" (BOE) includes oil and gas; one barrel of oil is deemed to have the same amount of energy content as 6,000 cubic feet of gas.

Text alternative for Figure 6. Range of mean estimates of recoverable BOE from existing resource assessments of sedimentary basins of the Eastern and Central Arctic.

Figure 6 is a bar graph illustrating the range of mean estimates of recoverable barrels of oil equivalent from existing resource assessments of the 9 sedimentary basins located in Central and Eastern Arctic that have at least some probability of containing hydrocarbons. The bar graph shows that the Canadian portion of the Lomonosov ridge contains none or few recoverable barrels of oil equivalent. The Lincoln Sea Basin as approximately a range of mean estimates of recoverable barrels of 1,000 to 2,000 million barrels of oil equivalent. The Arctic Margin as approximately a range of mean estimates of recoverable barrels of oil equivalent of 3,000 to 8,000 million barrels of oil equivalent. The Sverdrup Basin as approximately a range of mean estimates of recoverable barrels of oil equivalent of 5,000 to 16,000 million barrels of oil equivalent. Lancaster Sound as approximately a range of mean estimates of recoverable barrels of oil equivalent of 1,000 to 4,000 million barrels of oil equivalent. The Baffin Margin as approximately a range of mean estimates of recoverable barrels of oil equivalent of 3,000 to 10,000 million barrels of oil equivalent. The Franklinian Deformed Belt as approximately a range of mean estimates of recoverable barrels of oil equivalent of 2,000 to 3,000 million barrels of oil equivalent. The Arctic Platform as approximately a range of mean estimates of recoverable barrels of oil equivalent of 2,000 to 3,000 million barrels of oil equivalent. The bar graph shows that Foxe Basin contains none or few recoverable barrels oil equivalent.

5.4 Hydrocarbon potential

The Prospectivity Report identifies 6 areas considered to have the highest potential for large oil or gas resources. All are "underlain by relatively young sediments and either have discoveries or geological conditions that are considered favourable for hydrocarbon accumulations." The 2 basins with at least 1 discovery are the Sverdrup Basin in the central Arctic Islands between Melville and Ellef Ringnes islands and the Saglek Basin off southeastern Baffin Island.

Other areas with high potential include:

• the Baffin Margin between Cumberland Sound and Lancaster Sound
• Lancaster Sound and the Baffin Fan at the mouth of Lancaster Sound
• the rifted Arctic Margin along the northwest side of the Arctic Islands
• the Lincoln Sea north of Ellesmere Island

All these areas are discussed in the following sections; the descriptions are based closely on the Prospectivity Study.^{Footnote 55}

Four areas are considered to have lower hydrocarbon potential. The Foxe Basin was not buried deeply and lacks prolific source rocks needed to generate oil and gas.^{Footnote 56} Hydrocarbon generation in the Arctic Platform and Deformed Franklinian Belt would have occurred a long time ago and subsequent tectonic events have likely reduced the potential for preserved hydrocarbon pools. Because the Lomonosov Ridge has also seen major tectonic events, uplift and erosion, there is a reduced chance that significant hydrocarbon pools remain. These areas are not discussed further. Annex 6 shows the areas with high, medium and low hydrocarbon potential.

5.5 The Sverdrup Basin

Measuring about 1,300 kilometres along a northeast-southwest axis by up to 400 kilometres wide, the Sverdrup Basin is one of Canada's largest petroliferous basins. It encompasses a sequence of sedimentary rocks up to 13 kilometres thick. Although most of the basin lies within Nunavut, a small part at the western end, which holds 20 percent of the resources^{Footnote 57}, is in the Northwest Territories. Most of the basin is well explored, however, undiscovered potential remains deeper in the basin.^{Footnote 58} Twenty-nine percent of the total resources of the basin are onshore and not subject to the moratorium.

Most of the 19 oil and gas discoveries are in a belt stretching from southwestern Ellef Ringnes Island to the Sabine Peninsula on Melville Island (see Figure 3 and the top figure of Annex 3). The discoveries include 2 of the largest undeveloped conventional gas fields in Canada, the Drake field on the east side of the Sabine Peninsula (with half of the resources onshore) and the Hecla field on the west side within the Northwest Territories. These fields hold approximately half of the discovered gas in the Sverdrup Basin, with an estimated 6 to 10 Tcf of recoverable gas.^{Footnote 59} There are also smaller gas fields to the north and northeast.

The Cisco oil field, just west of Lougheed Island, is the largest oil field discovered in the Arctic Islands, with an estimated 584 million barrels of oil.

5.6 The Saglek Basin

Previous resource assessments did not include a stand-alone assessment of the Saglek Basin. However, work done by the Geological Survey of Canada in the last decade provides insights into the resource potential of the basin. Jauer et al. (2014) interpreted a high potential fairway^{Footnote 60} in the area in which the Hekja and Ralegh wells were drilled. They estimated that the Gudrid structure^{Footnote 61} to the east of the Ralegh N-18 well "could potentially contain ten times as much petroleum as found in the Hekja O-71 discovery based on the estimated size of the closure."^{Footnote 62} If so, this would be a world class deposit containing up to 23 Tcf of gas.

In the Prospectivity Report, Dewing et al. had a different interpretation. They stated that the "estimate of a field ten times the size of Hekja seems overly optimistic" and "would be at the very upper end of what might be expected" in that geologic setting. They further noted that "untested targets are likely to be in the size range of other discoveries along the eastern Canadian margin" which range from 2.2 to 2.7 Tcf of gas. One or more such fields in the Gudrid structure combined with the 2.3 Tcf of gas at Hekja would be a substantial resource that may be large enough to warrant development.

Further work is required to resolve the uncertainty and clarify the potential gas resources in the Gudrid structure as well as other settings in the Saglek Basin. The Prospectivity Report described work that could be done, including reprocessing the older vintage seismic from the original field tapes and carrying out new high quality seismic surveys using longer streamers and with sound sources tuned for better penetration.^{Footnote 63} Other work could include:

• new age dating of cuttings samples from drill holes
• more detailed seafloor imaging
• sampling seeps, either from the surface or at the seafloor
• low temperature thermochronology studies

Follow-up drilling would ultimately be necessary to determine whether significant quantities of gas are present.

5.7 Areas with high potential but which are untested by drilling

5.8 Summary

The Prospectivity Report summarizes the potential of several sedimentary basins and the need for further work and new resource assessments. These basins have the potential to host significant hydrocarbon resources, with estimates of discovered and undiscovered resources ranging up to 15,869 million barrels of oil equivalent for the Sverdrup Basin. The development of these resources could yield important revenue for Nunavut once a co-management regime is in place for the region and a revenue sharing agreement is established between the territory and the Government of Canada.

Although the Sverdrup Basin has the highest potential to host significant hydrocarbon resources, "there have been major advances in geological knowledge in the eastern Arctic (Saglek Basin, Baffin Margin, Baffin Fan) since the last hydrocarbon resource assessments were done in those areas. New hydrocarbon resource assessments in the Eastern Arctic would incorporate new knowledge about the Baffin Fan and Saglek Basin, and would revise the estimates of resource potential in these areas."

On the basis of information in the Prospectivity Report, it is the opinion of the committee that new studies and resource assessments in Baffin Bay and Davis Strait should be done as soon as possible. Priority should be given to further work to resolve questions related to the potential gas resources in the part of the Saglek Basin east of the Hekja field. The demonstration of the potential for significant resources could lead to the preparation of detailed development scenarios. The committee also views the Drake gas field as a priority for future work.

6.1 Sverdrup/Drake

Based on prior studies, the combined fields of Drake and Hecla (in the Northwest Territories) and a few other nearby fields in the Sverdrup Basin have significant resources of gas that may warrant production. Proposals were made in previous decades to transmit the gas from these fields, which include both onshore and offshore portions, by pipeline to Bridport Inlet on the south shore of Melville Island where it would be processed into liquefied natural gas and sent to markets in specialized ships.

6.2 Saglek/Hekja

There is a gas resource subject to a significant discovery licence at the Hekja field in southern Davis Strait off Frobisher Bay. The Geological Survey of Canada has indicated that a structure to the east of Hekja may host much larger gas resources, but data on this is inconclusive. New seismic surveys and drilling would be required to determine whether resources exist. If resources are present in economic amounts, gas could be produced from Hekja and the nearby area and transmitted by subsea pipeline to a plant on Loks Land (Island) or the nearby Baffin Island mainland for processing into liquefied natural gas. The liquefied natural gas would be sent to markets in specialized ships.

6.3 Low-carbon methods to produce liquefied natural gas or hydrogen

Producing gas and converting it to liquefied natural gas could involve the use of electricity from renewable energy sources or small modular nuclear reactors, the capture and storage of the carbon emissions or a combination of these approaches. An integrated approach of this type may be necessary to meet government climate policy requirements at the time of development.^{Footnote 66}

Another option not previously proposed for production in these basins would be to convert the gas into hydrogen through a process called reforming or by a different chemical process. The hydrogen gas would be liquefied or converted into a solid compound (for example a hydride) or other product such as ammonia and shipped to markets. The advantage of producing hydrogen is that the product of its combustion is water, little or no greenhouse gases would be emitted. Both the production of hydrogen using the techniques described above and the ultimate use of the hydrogen may be consistent with Canada's net-zero emissions requirement.

6.4 Potential timeline for development

When considering the possibility of future development, it is necessary to understand when this development might occur and the economic and climate conditions that might prevail at that time.

In a report prepared for the Strategic Environmental Assessment, Nunami Stantec^{Footnote 67} estimated that the "full life cycle of a hypothetical oil and gas project in Davis Strait or Baffin Bay could be in the range of 45 to 80 years from the start of seismic exploration, through exploration drilling to production and eventual decommissioning." That part of the process beginning with the first call for nominations up to the point the first gas is produced could take 30 to 35 years.

6.5 Potential benefits from natural gas

The Government of Nunavut is the largest public sector employer in the territory. The mineral exploration and mining sector, which employs over 900 Nunavummiut yearly, is the largest industry. Fishing, sealing, and tourism are growing sectors of the economy that also bring important sources of income for Nunavummiut.^{Footnote 68}

The energy industry, if managed properly, can bring revenue and spark local economic development. Natural gas development creates the potential for new funding and investment in the region, contributing to overall increases in institutional capacity. The industry could also bring training and employment opportunities for Nunavut communities, local infrastructure investments, and the development of emergency response capacity. Energy projects that use natural gas are also better for the environment than those using coal or oil.

Another benefit of natural gas development could be energy security, reducing dependence on imported diesel while lowering energy costs. This is important for communities that are isolated and have very few options for affordable heat and power. While no natural gas project has occurred in Nunavut, ongoing initiatives in other jurisdictions show advancement in domestic energy security in addition to generating permanent jobs for residents and cost savings in fuel and heating. For example, the experiences in the Inuvialuit Settlement Region have highlighted the social and economic benefits of producing energy within the region. The Inuvialuit Petroleum Corporation has plans to develop a previously discovered natural gas well on the Tuktoyaktuk Peninsula and process it into liquefied natural gas for distribution to Inuvialuit communities in a project known as the Inuvialuit Energy Security Project.^{Footnote 69} This ongoing initiative could advance domestic energy security in addition to generating revenues from global market exports.

6.6 Information required

Work to determine if production from Saglek Basin, Baffin Shelf and the Sverdrup Basin might be viable would include, but not be limited to, the following:

• The studies and other work described in the Prospectivity Study to show whether there is good potential for additional gas resources:
  • in the Saglek Basin, especially in the vicinity of the Hekja field
  • on the Baffin Shelf to the north of Hekja
• Updating of resource assessments for all of Nunavut.
• An analysis to show whether the technology that could be used to produce and process gas in accordance with the scenarios and the Government of Canada climate change policy requirements. Such technology could potentially include:
  • renewable energy sources to produce electricity for operations
  • small modular nuclear reactors to produce electricity for operations
  • carbon capture and storage to capture any greenhouse gas(es) (GHG) emitted (if gas is used to provide the power for production and processing)
• An analysis of the potential demand for the liquefied natural gas, hydrogen or other products described in the scenarios and an analysis of economic factors of potential projects.
• An analysis of the potential benefits of the project to Nunavummiut and other Canadians, including royalties, benefit plans and (or) socio-economic agreements, fees and rents for use of Inuit Owned Lands (for onshore operations), and employment and business opportunities.
• Reports from consultations and other sources that show that such a project is socially and culturally acceptable.
• An overview of socio-economic impacts and benefits from other northern producing regions:
  • Northwest Territories
  • Newfoundland
  • Norway
  • Alaska
  • Russia

In addition to the requirements in this list, consultations with officials from the Inuvialuit Regional Corporation and the Government of the Northwest Territories would need to be held with respect to the possibility of developing the Hecla gas field in conjunction with the Drake operation.

Regulatory framework

All oil and gas activities in Canada's offshore are subject to a rigorous environmental and regulatory regime. Canada has recently modernized its regime to ensure that local and indigenous participation are fully part of the impact assessment process. Other modernization aspects included strengthening safety requirements for the oil and gas industry and mandating the evaluation of impacts projects could have on climate policy requirements.

The Nunavut Agreement sets the foundation for Inuit participation in "decision-making concerning the use, management and conservation of land, water and resources, including the offshore". Many of the provisions that relate to the management of resource development in the Nunavut Settlement Area are enshrined in 2 federal acts which set out the powers, functions, objectives, and duties of the Institutions of Public Government. The Nunavut Planning and Project Assessment Act is particularly relevant to oil and gas development as it formally establishes the regulatory processes through which project proposals requiring authorization are reviewed in respect of land use conformity and environmental impact assessment.

A benefits plan, including provisions for local training and employment, is required for any offshore oil and gas project proposal. Further, under the Canada Petroleum Resources Act, any royalties from an oil and gas offshore development project would flow to the Government of Canada, with a percentage paid to Inuit for a project in the Nunavut Settlement Area or the Outer Land Fast Ice Zone. However, after a Devolution Agreement has been signed, Nunavut would be the beneficiary of royalties from onshore projects. An offshore agreement would have the potential to add royalties for Nunavut that could be invested in territorial needs such as housing, health, education and infrastructure development.

Climate change commitments

Since the signing of the Paris Agreement, the Government of Canada has made significant commitments in its fight against climate change. The initial measures were set out in the Pan-Canadian Framework on Clean Growth and Climate Change, followed by a strengthened climate plan in 2020. The Prime Minister announced on April 22, 2021, that Canada's greenhouse gas emissions target under the Paris Agreement is 40 to 45 percent below 2005 levels by 2030. Subsequently, the Canadian Net-Zero Emissions Accountability Act, which formalizes Canada's target of net-zero emissions by 2050, became law. Since that time, the Government of Canada has made further commitments, including some relating specifically to the oil and gas sector. These include capping greenhouse gas emissions from the sector at current levels and reducing them at a pace and scale needed to achieve net-zero emissions by 2050. As well as joining the Global Methane Pledge and committing to reduce oil and gas sector methane emissions by at least 75 percent below 2012 levels by 2030.

Strategic environmental assessment for Baffin Bay and Davis Strait

From 2017 to 2019, the Nunavut Impact Review Board carried out a Strategic Environmental Assessment for Baffin Bay and Davis Strait looking at potential impacts and benefits that offshore oil and gas development could have on the region. This work included the participation of Nunavut Tunngavik Incorporated, the Qikiqtani Inuit Association, and the Government of Nunavut as well as 3 rounds of consultations with the communities of the Qikiqtani Region that could be impacted by development. The Nunavut Impact Review Board's final report highlights knowledge gaps and work required to ensure the appropriate balance between environmental stewardship and economic development for Nunavut.

In its final Strategic Environmental Assessment report, the Nunavut Impact Review Board shared 79 recommendations and concluded that the moratorium should remain in place for Baffin Bay and Davis Strait until the key issues set out in the report can be addressed, a process expected to take at least 10 years. The Government of Nunavut developed a draft "Action Plan Discussion Paper" to address the Nunavut Impact Review Board's report and recommendations and to categorize and prioritize action items. Although the Strategic Environmental Assessment dealt only with the effects of oil and gas development in Baffin Bay and Davis Strait, some of the findings and recommendations may be applicable to other parts of the Eastern and Central Arctic.

Hydrocarbon potential and basin prospectivity

At the request of the committee, the Geological Survey of Canada wrote 2 reports on potential oil and gas resources in the Eastern and Central Arctic. The report on the "Northern Nunavut Hydrocarbon Prospectivity Study" assessed the potential of ten sedimentary basins. It concluded that:

• 4 of the basins were unlikely to have significant resources
• 4 have good potential on the basis of what is known of their geology but have not been tested by drilling
• 2 basins, the Sverdrup and the Saglek Basins, have good potential as indicated by discovered resources

There are 19 discovered oil and (or) gas fields in the Sverdrup Basin and 1 gas field in the Saglek Basin. The report described work that could be useful in further assessing the potential in the Saglek Basin near the area of the Hekja gas field and in the Baffin Margin to the north. Drilling would ultimately be required to confirm whether more resources are present.

Proposal for scenarios for the Sverdrup and Saglek Basins

Detailed scenarios should be developed for:

• the exploration for and production of gas from the Saglek Basin and Baffin shelf
• the exploration for and production of oil and gas in the Sverdrup Basin
• the processing of gas from those areas into liquefied natural gas or hydrogen (including products made from hydrogen)

Producing gas and converting it to liquefied natural gas could involve the use of electricity from renewable energy sources or small modular nuclear reactors, the capture and storage of the carbon emissions or a combination of these approaches. The conversion of the gas into hydrogen, an option not previously proposed for production from these basins, would be done through a process called reforming or by a different chemical process. An integrated approach of this type may be necessary to meet government climate policy requirements at the time of development. The exact scenarios to be developed are subject to future discussion and decisions amongst partners and stakeholders.

Future projects could generate institutional capacity, infrastructure, and employment in the territory in the coming years. Local energy projects have the potential to create new investment opportunities in the region and to meet local energy demands.

Objective

• To provide protection to active Arctic offshore licence holders for the duration of the moratorium, pending a decision by the Government of Canada on next steps.
• To complement the policy intent of the moratorium and to suspend further capital investment while providing protection to active licence holders and to preserve their rights.
• To respond to the interests of territorial governments and to respect the rights of Northern Indigenous peoples regarding future oil and gas and economic development potential in the offshore.
• To establish a path forward for the strategic management of Arctic offshore oil and gas in collaboration with partners.

Annex 2: Sovereignty and the United Nations Convention on the Law of the Sea

Natural gas used in new technologies to reduce emissions

Over the last few years, the energy industry has developed methods to provide new sources of clean energy in order to reduce greenhouse gases (GHG). The development of energy resources in Nunavut could include technologies to produce liquefied natural gas, implement carbon capture and storage^{Footnote 76}, and produce hydrogen, all of which could lead to lower GHG emissions. The stacking of many approaches may be required to reduce global emissions in the long term.

Natural gas converted to liquefied natural gas

While still emitting GHG when it is combusted, natural gas is a cleaner source of energy than diesel or coal. Liquefied natural gas is natural gas that has been converted to liquid form to reduce its volume by 600 times to make it more amenable to shipping and storage. To produce liquefied natural gas, natural gas is cooled to -162 degrees Celsius. Liquefied natural gas that is inadvertently released quickly vaporizes as it warms, rises, and disappears into the atmosphere leaving no residue behind. Liquefied natural gas is colourless, odourless, non-toxic, non-corrosive, and non-flammable. When put through the regasification process to convert it back to natural gas, liquefied natural gas can be used for residential heating, electricity and cooking, while commercial uses for natural gas include electricity, heating and fuelling commercial vehicles.

Liquefied natural gas used in the place of diesel fuel in Nunavut would have lower GHG emissions and may support a transition to the full use of renewable energy in Nunavut. However, the carbon dioxide (CO₂) emissions from natural gas will still contribute to climate change. Other concerns are the "fugitive emissions" of methane that escape into the atmosphere during exploration, production and transportation of natural gas.

Carbon capture and storage in Arctic countries

The introduction of carbon capture and storage facilities by several Arctic countries has been part of their net-zero strategy to reduce GHG emissions. The research and development for carbon capture and storage, which may also include the utilization and conversion of CO₂, has grown in the past decades. Several studies have demonstrated that carbon capture and storage can provide a solution toward the decarbonization of the economy. A United Nations Educational, Scientific and Cultural Organization (UNESCO) Science Report (2021) describes research published in 2016 in which scientists from Denmark, Iceland, France, Australia, UK and USA reported an effective attempt to dispose of CO₂ permanently as environmentally benign carbonate minerals in subsurface basaltic rocks (Matter et la., 2016). For 2 years, 95 percent of the anthropogenic CO₂ injected in a storage formation was mineralized by CarbFix in Iceland.^{Footnote 77} Iceland is not the only Arctic country that has used carbon capture and storage to reduce CO₂ emissions into the atmosphere. Norway's state enterprise Gassnova has worked closely with industry to show that carbon capture and storage can be done safely on a large scale.^{Footnote 78}

Hydrogen energy infrastructure

Hydrogen is a growing fuel source in the global market that could help provide Nunavut with a clean energy source. The production of hydrogen at scale could be used as an energy source for residential heating and flexible power generation. Hydrogen production can come from a variety of sources that include natural gas, natural gas with carbon capture, utilization and storage, and renewables. The combination of carbon capture, utilization and storage (or carbon capture and storage) with natural gas or coal is the most cost-effective way to produce hydrogen. As the raw material in the process, natural gas is considered an essential source of energy for the future. The interest in the use of hydrogen has resulted in a classification based on the origin and production technique. Each method of hydrogen production varies in its carbon intensity, which is also called its carbon footprint. The hydrogen production types are assigned a colour as shown in the following figure.

Text alternative for Figure 1: Hydrogen colours spectrum showing different GHG footprints for different hydrogen technologies

The following table offers information on the hydrogen colour spectrum based on the origin and production technique and on the different greenhouse gas emission footprints for each of them. The colour spectrum for hydrogen that is produced via electricity is green, purple/pink and yellow. Hydrogen that is produced with electricity uses a technology called electrolysis. The feedstock, or electricity source, for green hydrogen is wind, solar, hydro, geothermal or tidal. The greenhouse gas emission footprint for green hydrogen is minimal. The feedstock, or electricity source, for purple/pink hydrogen is nuclear. The greenhouse gas emission footprint for purple/pink hydrogen is minimal. The feedstock, or electricity source, for yellow hydrogen is mixed-origin grid energy. The greenhouse gas emission footprint for yellow hydrogen is medium. The colour spectrum for hydrogen that is produced via fossil fuels is blue, turquoise, grey, brown and black. The technology used to produce blue hydrogen is natural gas reforming with carbon capture, utilization and storage. The feedstock, or electricity source, for blue hydrogen is natural gas or coal. The greenhouse gas emission footprint for blue hydrogen is low. The technology used to produce turquoise hydrogen is pyrolysis. The feedstock, or electricity source, for turquoise hydrogen is natural gas. The greenhouse gas emission footprint for turquoise hydrogen is solid carbon (by-product). The technology used to produce grey hydrogen is natural gas reforming. The feedstock, or electricity source, for grey hydrogen is natural gas. The greenhouse gas emission footprint for grey hydrogen is medium. The technology used to produce brown hydrogen is gasification. The feedstock, or electricity source, for brown hydrogen is brown coal (ignite). The greenhouse gas emission footprint for brown hydrogen is high. The technology used to produce black hydrogen is gasification. The feedstock, or electricity source, for black hydrogen is black coal. The greenhouse gas emission footprint for black hydrogen is high.

The type of production is based on the existing energy and resources available in the country, as well as policies that include decarbonization and economic growth. Nunavut could use technologies based on reforming the available natural gas, such as the blue or grey processes described above, to produce hydrogen, a fuel that releases no emissions when burned. Not only would this provide a secure and clean fuel for residential and commercial uses in the territory, it may also be possible to export the hydrogen to other markets.