Exploration and production snapshots: Canada has been saved
Exploration and production snapshots: Canada
Outsized resources looking for new markets
With the largest oil reserves in North America, Canada likely holds promising opportunities for large and small companies for decades to come. To achieve its potential, however, the Canadian oil and gas industry will need to overcome regulatory and political hurdles, expand pipeline infrastructure, and increase investment in new technology.
Americas exploration and production (E&P) snapshots
In this series, Americas E&P Snapshots, Deloitte profiles the region’s major countries, their hydrocarbon endowments, the historical context of the industry in each country, and the new opportunities that seem to be taking shape. Each country report concludes with considerations for the future and an assessment of the country’s attractiveness for new investment in the E&P sector.
The series includes profiles of the following countries:
How we got here: Highlights from historical oil and gas development
Canada contains the largest oil resources in North America and ranks third globally after Venezuela and Saudi Arabia.1 While much of that oil is found in (and produced from) massive Albertan oil sands deposits, the country also produces significant volumes from conventional and unconventional reservoirs, as well as off the eastern coast of Nova Scotia and Newfoundland and Labrador (figure 1). Additionally, the country produces significant volumes of natural gas, mainly in the Western Canadian Sedimentary Basin (figure 2). Similar to the United States, and distinct from many Latin American countries, the above-ground risks appear limited, though still present. Pressures from environmental groups2 and some First Nations3 can partially offset the benefits from a well-established legal system and predictable government take (e.g., royalties, taxes, credits, and incentives) as the country balances a range of stakeholder interests. However, the lack of export capacity to markets other than the United States and opposition to large-scale energy infrastructures has proven a challenging hindrance to Canada’s oil and gas industry growth potential and competitiveness.4
Figure 1. Liquids production by theme
Figure 2. Natural gas production by theme
Source: Rystad Energy UCube Database5
Source: Rystad Energy UCube Database6
Canada upstream in brief
Unlike much of Latin America but like the United States, Canada does not currently have a national oil company (NOC), as Petro-Canada was privatized in 1991 and later merged with Suncor in 2009.7 Also, unlike Latin America and like the United States, Canada has not historically limited foreign investment in oil and gas—standing in stark contrast to countries like Brazil and Mexico.
One element of Canadian oil and gas that stands out is the country has limited privately owned mineral rights—roughly 11 percent countrywide, though it can vary substantially. For example, freeholds are limited to only 10 percent of land in Alberta, whereas in Manitoba 75 percent of mineral rights are private.8 The majority of Canada’s mineral rights are held and administered by the provincial governments acting on behalf of the Crown, and the government take varies.9
Large producers in the country include US majors like ExxonMobil and Chevron, regional integrated companies like Husky and Suncor, and independents and pure-play E&Ps (figure 3). Despite not having an NOC, domestic firms represent roughly three-quarters of total production. Canadian Natural Resources Limited, often referred to as CNRL, comprises almost 10 percent of that total on a barrel of oil equivalent basis.10 The largest producers typically have significant oil sands exposure, but this does not apply across the board. For example, Crescent Point Energy focuses on the Viking and Bakken plays among others in Saskatchewan.11 Similarly, Husky has invested in a number of offshore oil and gas projects. This means that unlike Argentina or Brazil, industry activity (and future interest) is not driven by a single play or basin (see Key plays to watch section). This variety, along with the established industry footprint and business and regulatory standards, opens up opportunities for smaller firms to compete.
However, like many countries in Latin America and unlike the United States, even though Canada is a large producer of oil and gas, domestic demand is limited. The country exports roughly 3.3 million barrels a day of liquids and imports only 600,000 barrels per day. This means the country’s net exports are equivalent to half of its production.12 Similarly, Canadian net natural gas exports to the United States averaged 6 billion cubic feet per day over the last year, more than a third of total production.13 These export levels seem to indicate that companies active in the region are focused heavily on the export market and midstream infrastructure could be key to project development. It also likely means that there is large demand for condensate and natural gas liquids for diluent, allowing for export of bitumen produced from the oil sands.
One risk that impacts Canadian producers directly is that while costs are incurred in Canadian dollars, most crude oil is priced in US dollars. It is true that this impacts E&Ps in many countries, but because significant crude and other petroleum products are exported to the United States directly, both US currency and overall economic growth can pose potential upsides and downsides—particularly for oil sands and offshore projects with long producing lives. The relative strength of US dollars versus Canadian over the last five years benefited companies operating in Canada, offsetting in part the decline in commodity prices.
Main events and milestones
Key plays to watch
The oil sands represent the single largest source of Canadian oil production.31 They are composed of sand, water, clay, and a thick, viscous oil commonly referred to as bitumen. This bitumen does not flow easily and is usually pumped after being heated or diluted. While oil sands are found around the world (along with other types of very heavy oil), the most developed deposits are in Alberta.32 There are two primary methods to extract bitumen. The first, surface mining, dates back to the 1960s. Mining usually has a large aerial footprint and requires physically collecting and separating bitumen from the other material, somewhat akin to processing mineral ore. The second method, referred to as in-situ production, started in the 1980s as a means to produce deeper oil sands deposits. It has a smaller surface footprint and can extract otherwise unobtainable resources. In-situ production often uses steam-assisted gravity drainage (SAGD), though there are other production methods including cyclic-steam simulation and conventional well production.33 Over time, in-situ production has grown at a faster rate than mining, with current production levels split evenly.34 As of 2018, seven major projects represent more than half of all production, four of which use surface mining (figure 4).
Figure 4. Top seven projects represent 60% of oil sands total production
Sources: Canadian National Energy Board,35 Daily Oil Bulletin36
Despite large in-place resources, oil sands face a number of challenges. First, they can be costly to develop and, unlike other high-capex projects, have relatively high ongoing operating costs, sometimes exceeding $20 per barrel despite significant reductions since the oil price decline post-2014.37 Total cost of supply estimates range from $45 to $85 per barrel (in WTI terms) depending on the project type, including the cost of upgrading the bitumen or blending it with diluent for export.38 Second, the heavy oil produced by the oil sands trades at a significant discount to lighter, sweeter crudes. Western Canadian Select, a regional heavy crude blend, has traded at a $20 per barrel discount since the beginning of 2017 to both lighter Canadian blends and the US benchmark, West Texas Intermediate.39 Third, oil sands projects can be energy intensive and face heightened carbon dioxide emissions scrutiny. Alberta has implemented a greenhouse gas emissions limit for oil sands projects, combined with a carbon tax. While current emission levels are far from the 100 million metric tons per year limit, these projects are long-lived and the regulatory environment can shift.40 Last, oil sands, much like deepwater projects, lack the flexibility of shale. Once a project is sanctioned, adjusting the investment and production levels based on the commodity price cycle can be difficult.
Canadian oil sands production has more than doubled over the last 10 years and currently represents roughly half of the country’s output.41 This is unlikely to change in the near-term, despite challenges from new project sanctions. With long development lead times and multi-decadal production plateaus, the oil sands could continue to represent the majority of production even with few new projects coming online.
Atlantic East Coast offshore oil and gas
Canadian offshore oil and gas is immature relative to that of the United States and Mexico, both of which have extensive developments in the Gulf of Mexico. Canada’s offshore basins produce over 220,000 barrels per day (bbl/d) of oil, mainly from Hibernia in the Jeanne D’Arc Basin off the coast of the island of Newfoundland, and nearly 150 million cubic feet per day from the Sable Island and Panuke projects offshore of Nova Scotia (figures 5 and 6).42 With the Sable Island project undergoing planned decommissioning starting in 2018,43 offshore natural gas production could decline by up to 60 percent. In comparison, the US Gulf of Mexico is closer to 1.6 million bbl/d of oil and 3 billion cubic feet per day (bcfd)44 from thousands of structures, including more than 40 floating production platforms.45
Figure 5. Three projects produce virtually all offshore liquids
Figure 6. Only three offshore natural gas projects currently online
Source: Rystad Energy UCube Database46
Source: Rystad Energy UCube Database47
Canada’s limited number of offshore projects does not reflect a lack of resources. The Hibernia field has produced over a billion barrels of oil since the taps were turned on in 1997, and the field could produce for an additional 15 to 20 years.48 Some of the challenges offshore operators face include high capital costs, long project lead times, a lack of infrastructure, inclement weather (including potential sea ice impacts),49 and limited access to major markets. These issues tend to be particularly acute outside of Newfoundland and Labrador, and Nova Scotia. Despite a number of exploration campaigns since the late 1970s, there has been negligible production in the Canadian Beaufort Sea, north of the Yukon and Northwest Territories, and in Baffin Bay, between Nunuvut and Greenland, despite some positive exploration results. 50, 51
In the near-term, Canadian offshore production is expected to increase as ExxonMobil ramps up production at its standalone Hebron project that reached first oil at the end of 2017.52 Additionally, Husky expects to reach first oil at its West White Rose Project by 2022.53 The longer-term picture is more mixed as there are no other offshore projects expected to be sanctioned in the next five years,54 though there are substantial contingent resources located farther offshore the island of Newfoundland in the Flemish Pass and Orphan Basins.55 Provinces like Newfoundland and Labrador have announced plans to review regulations, improve recovery, and incentivize new exploration wells, which could spur future investment and production.56 Those changes, in combination with higher oil and gas prices, could spark renewed investment in offshore projects. Still, all of these basins will likely remain technically challenging and projects could be difficult to commercialize.
Major shale plays
The Western Canadian Sedimentary Basin covers parts of Manitoba, Saskatchewan, Alberta, British Columbia, and the Northwest Territories. It includes plays like the Duvernay, which are predominantly shale, as well as others like the Bakken, Cardium, and Montney, which are composed of shale, tight, and conventional formations.57 These represent a small portion of total Canadian production compared to the oil sands, but they are growing at a rapid pace. Shale production achieved a roughly 30 percent compound growth rate in the last 10 years. More importantly, despite the substantial decline in oil prices, the growth trend continued (figures 7 and 8). The Montney currently produces the most oil and gas.58 Additionally, it contains the most gas resources at 449 trillion cubic feet; however, the Duvernay’s long-term liquids potential is likely larger. The Canadian National Energy Board estimated the play holds 3.4 billion barrels of oil and condensate, in addition to 6.3 billion barrels of natural gas liquids and 77 trillion cubic feet of natural gas.59
Figure 7. Shale liquids production by play
Figure 8. Shale natural gas production by play
|Source: Rystad Energy UCube Database60||Source: Rystad Energy UCube Database61|
However, despite ample resource potential, Canada is unlikely to catch up to US unconventional production levels due to a lack of access to non-US international markets. This can be seen in realized low prices, which, due to transportation costs, is more apparent in natural gas than oil. For example, the AECO spot price in Alberta traded at $1.61 per million BTU from January to April 2018, compared to $2.94 at Henry Hub during the same period.62 Moreover, due to significant Canadian price volatility, producers saw negative gas prices in September and October 2017,63 and the outlook for 2018 is bearish.64 These differentials have increased in recent years and could persist due to saturated North American energy markets. While other Canadian projects may face similar pricing challenges, the significant natural gas volumes and shorter investment cycle of shale development could leave operators more exposed.
Two challenges would need to be overcome to maintain (or increase) the country’s significant unconventional production growth. First, new transport infrastructure would likely need to be built. That includes not only oil and gas pipelines in Canada, but also in the United States, where much of the commodities are consumed. New liquefied natural gas (LNG) export terminals on both sides of the border could play a role in alleviating the natural gas oversupply as well. Currently LNG development is moving forward in the United States, with proposed Canadian projects slower to move into a committed development phase. Second, Canadian shale development has been slower than the rate in the United States. Over the last year, on average there have been close to 800 US horizontal drilling rigs deployed, compared to less than 200 in Canada—the latter varying substantially with the seasons.65 This rig disparity is evident in the production volumes. For example, the largest Canadian unconventional play, the Montney, produces over 300,000 bbl/d of oil and 6 bcfd of gas, whereas its US equivalent, the Permian (including legacy conventional) produces closer to 3 million bbl/d of oil and 9 bcfd of gas. Increased activity in Canada could lead to further economies of scale through better procurement, pad drilling, and asset optimization. Combined with stronger pricing and access to export markets, higher productivity, and lower costs, Canadian shale could more than compete with US plays.
Other onshore plays
Onshore production, excluding oil sands and shale plays, still accounts for roughly 30 percent of Canada’s oil and gas production, almost exclusively from the Western Canadian Sedimentary Basin.66 This includes some formations being produced by legacy vertical wells, as well as more recent horizontal ones. While these plays lack the visibility of plays like Duvernay and Montney, significant recoverable volumes remain that will likely produce for decades to come.67
In the case of oil, three things stand out: the prominence of Alberta, importance of heavy oil, and the decline in production (figure 9). In 2017, Alberta represented almost three-quarters of Canada’s onshore, conventional production (excluding shale and oil sands), with Saskatchewan comprising the bulk of the balance. In Alberta, like the country overall, heavy oil has risen from 20 to 30 percent of conventional onshore production over the last decade. Two decades ago, it was closer to 10 percent. And over time, production has declined modestly, averaging 3 percent per year, which has been more than offset by oil sands growth.68
Like oil and NGLs, most non-shale natural gas is produced in Alberta. However, unlike oil, little gas is produced in Saskatchewan, and unconventional sources like tight formations and coalbed methane comprises almost 20 percent of total production (figure 10). Gas production declines have been both more consistent and steeper, averaging almost 10 percent per year. Shale overtook other onshore production in 2016, with the former continuing to increase as the latter drops. Still, conventional, tight, and coalbed gas account for 40 percent of the country’s production.69
Figure 9. Conventional liquids production by province
Figure 10. Conventional natural gas production by province
|Source: Rystad Energy UCube Database70||Source: Rystad Energy UCube Database71|
At current decline rates, conventional oil production could drop by 40 percent over the next decade and conventional gas production could be halved. While higher commodity prices could spur new investment, it seems it will be difficult to arrest the decline, let alone grow production. However, even after factoring in declines in conventional production, these resources could still represent a significant portion of the country’s production. These fields may not attract the attention of the majors, but smaller independents and private oil and gas companies are expected to continue to exploit these potentially low-cost brownfield opportunities.
Recent significant changes
Compared to the energy reforms in Mexico, corruption investigation in Brazil, or hyperinflation in Venezuela, Canada’s economic and geopolitical landscape appears quite tame. This perhaps reinforces the stereotype of the country that inspired what has been referred to as the most boring headline ever written, “Worthwhile Canadian initiative.”72 However, over the last five years the currency declined by 20 percent, coinciding with the fall in global oil prices.73 Furthermore, the more environmentally focused Liberal Party under Justin Trudeau will likely scrutinize oil and gas activity to a greater degree than his conservative predecessor, Stephen Harper, who hails from the resource-rich province of Alberta.
One issue, in particular, is the Paris Accord. Canada’s nationally determined contribution is to reduce 2030 greenhouse gas emissions by 30 percent below 2005 levels.74 Combined with regional opposition to large pipeline projects and a carbon tax and oil sands production cap, future regulatory shifts could adversely affect natural resource-focused industries. However, the country has a long history of oil and gas projects, from upstream to downstream, meaning future changes are more likely to be incremental than sweeping.
More important for the near term will likely be decisions around pipeline permitting and trapped oil and gas.75 Recently, British Columbia has attempted to block the expansion of the Trans Mountain Pipeline, causing a dispute with Alberta and requiring the federal government to intervene directly to acquire the pipeline development rights from Kinder Morgan.76 This could be a bellwether for the country’s midstream industry and indicative of the future of oil and gas exports, which could require pipeline expansions at the very least and, more likely, the construction of new pipeline systems. This issue is acutely problematic for the nascent LNG industry, which has yet to sanction a single project, in part due to transport barriers. A proposed British Columbia tax break would likely help these projects, but access to gas would likely be more critical to LNG project success.77 The East Coast has perhaps been more accommodative with Newfoundland and Labrador moving to spur future investment and production; but, if future projects cannot access markets, success could be limited.
Looking to the future
Canada’s expansive resources will likely provide opportunities for both large and small companies for decades. The country contains a number of shale, tight, and conventional plays, as well as major oil sands and offshore capital projects. Shale production, in particular, has expanded rapidly, with more moderate growth seen offshore and in oil sands projects. This has offset declines in lower profile conventional, tight, and coalbed methane fields. However, a lack of investment, low global commodity prices, wide regional differentials, and lack of access to export markets could hinder future growth. While a particularly acute issue for shale gas (and potential LNG exports), it has weighed on other plays and projects as well.
Rystad Energy projects that Canadian oil, condensate, and NGL production will reach over 5.4 million bbl/d by 2020, over 10 percent above 2017 levels, with natural gas telling a similar story.84 To meet or exceed those projections, companies would need to overcome current regulatory and political hurdles to expand pipelines. Increasing investment in new technology and other infrastructure to reduce future project costs could be key as well. Additionally, provincial governments have adjusted taxes and regulations to incentivize development. But commodity prices will likely need to rise to support further capex spend, which may need to grow from $29 to $38 billion to support Canada’s current production trajectory.85 All of this is promising, as the resource and the companies are there and, ultimately, the barriers seem surmountable.
1 “Statistical review of world energy 2017,” BP, https://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy/downloads.html, accessed March 15, 2018.
2 Shawn McCarthy, “Environmental groups take aim at Alberta oil sands emissions,” Globe and Mail, March 25, 2017, https://www.theglobeandmail.com/news/alberta/environmental-groups-take-aim-at-alberta-oil-sands-emissions/article23852627/, accessed March 15, 2018.
3 Tom Flanagan, “Not all First Nations oppose oil and gas development,” Globe and Mail, March 24, 2017, https://www.theglobeandmail.com/report-on-business/rob-commentary/not-all-first-nations-oppose-oil-and-gas-development/article30922185/, accessed March 15, 2018.
4 Dan Healing, “Oil and gas spending drop linked to competitiveness gap with the United States,” City News, February 28, 2018, http://toronto.citynews.ca/2018/02/28/statistics-canada-says-oil-and-gas-spending-set-to-fall-for-4th-year-in-a-row/, accessed March 15, 2018.
5 Rystad Energy, UCube database, accessed February 16, 2018.
7 “Suncor, Petro-Canada announce merger,” CBC News, March 23, 2009, http://www.cbc.ca/news/business/suncor-petro-canada-announce-merger-1.805258, accessed April 23, 2018.
8 “Freehold mineral rights in Alberta, Alberta Department of Agriculture and Forestry, May 9, 2018, http://www1.agric.gov.ab.ca/$department/deptdocs.nsf/all/ofa16605/$file/freeholdnew.pdf?OpenElement, accessed June 13, 2018.
9 Cameron C. Wyatt, “Mineral rights in Canada,” Pipeline News, November 10, 2015, http://www.pipelinenews.ca/opinion/columnists/mineral-rights-in-canada-1.2102451, accessed April 19, 2018.
10 Rystad Energy, UCube database, accessed April 20, 2018.
11 Areas of operation, Crescent Point Energy, http://www.crescentpointenergy.com/operations/areas, accessed April 20, 2018.
12 “Exports and imports of crude oil and equivalent products,” Statistics Canada, May 9, 2018, https://www150.statcan.gc.ca/n1/daily-quotidien/180509/cg-c003-eng.htm, accessed June 13, 2018.
13 “Canadian imports and exports of natural gas,” Statistics Canada, May 29, 2018, https://www150.statcan.gc.ca/n1/daily-quotidien/180529/cg-b003-eng.htm, accessed June 13, 2018.
14 Company reported production, SEDAR database, https://www.sedar.com/issuers/issuers_en.htm, accessed June 14, 2018.
15 Richard Bott, “Evolution of Canada’s oil and gas industry,” Canadian Center for Energy Information, 2004, http://www.energybc.ca/cache/oil/www.centreforenergy.com/shopping/uploads/122.pdf, accessed February 7, 2018.
18 Ron Babiy, “Norman Wells Field – a long history of oil production in the Central Mackenzie Valley,” GeoConvention, 2013, https://www.geoconvention.com/archives/2013/460_GC2013_Norman_Wells_Field.pdf, accessed February 8, 2018.
19 Ashley Clarke, “Atlantic Canada’s offshore fields,” Natural Resources, December 2013, http://www.naturalresourcesmagazine.net/wp-content/uploads/2013/12/v14N1-offshorereview.pdf, accessed February 13, 2018.
20 Wallis Snowdon, “Leduc No. 1: Seven decades ago, a single oil well changed Alberta history,” CBC News, February 13, 2017, http://www.cbc.ca/news/canada/edmonton/leduc-oil-discovery-anniversary-oil-boom-history-1.3980331, accessed February 7, 2018.
21 Steve Jenkinson, “Oilsands timeline: Origins of the oilsands,” Calgary Herald, September 25, 2017, http://calgaryherald.com/business/local-business/oilsands-timelines-origins-of-the-oilsands, accessed February 7, 2018.
22 “Exploration history,” Nova Scotia Petroleum Board, https://callforbids.cnsopb.ns.ca/2007/01/exploration_history.html, accessed February 7, 2018.
23 “Energy history in Alberta,” Alberta Energy, http://www.energy.alberta.ca/About_Us/1133.asp, accessed February 7, 2018.
24 “Petro Canada,” Government of Alberta, http://www.history.alberta.ca/EnergyHeritage/oil/energy-crises-political-debates-and-environmental-concerns-1970s-1980s/provincial-federal-confrontations/1970-to-1981/petro-canada.aspx, accessed February 13, 2018.
25 Clarke, “Atlantic Canada’s offshore fields.”.
26 “History of the oil sands,” Regional aquatics monitoring program, Alberta, http://www.ramp-alberta.org/resources/development/mining.aspx, accessed February 8, 2018.
27 Petro-Canada Public Participation Act, Statutes of Canada 1991, c.10. http://laws-lois.justice.gc.ca/eng/acts/P-11.1/FullText.html.
28 “Cohasset Panuke,” Canada-Nova Scotia Offshore Petroleum Board, https://www.cnsopb.ns.ca/offshore-activity/offshore-projects/cohasset-panuke, accessed February 13, 2018.
29 “Exploration and production of shale and tight resources,” Natural Resources Canada, http://www.nrcan.gc.ca/energy/sources/shale-tight-resources/17677, accessed February 13, 2018.
30 Rystad Energy, UCube database, accessed February 16, 2018.
32 “What are oil sands?” Canadian Association of Petroleum Producers, https://www.capp.ca/canadian-oil-and-natural-gas/oil-sands/what-are-oil-sands, accessed March 15, 2017.
33 Rick Morgan, “Athabasca oil sands: A premier world energy reserve and resource,” Discovery Digest, May 21, 2015.
34 “Mining versus in-situ: A look at how energy companies are shifting their priorities,” Oil Sands, July 18, 2016, http://www.oilsandsmagazine.com/news/2016/7/18/mining-versus-in-situ-how-energy-companies-are-shifting-their-priorities, accessed March 15, 2017.
35 Oil sands production data 2010–2016, National Energy Board, https://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2017lsnds/index-eng.html, accessed June 19, 2018.
36 Oil sands 2017 production, Daily Oil Bulletin, https://secure.junewarren-nickles.com/login/?pub=NAV_BROWSE&continue=http%3a%2f%2fwww.oilsandsnavigator.com%2f, accessed June 19, 2018.
37 Tracy Johnson, “Oilsands players hammer down costs, but is it enough?” CBC, October 27, 2016, http://www.cbc.ca/news/business/costs-down-oilsands-1.3824106, accessed March 27, 2018.
38 “Canadian oil sands supply costs and development projects (2016–2036),” Canadian Energy Research Institute, February 2017, https://www.ceri.ca/assets/files/Study_163_Full_Report.pdf, accessed March 27, 2018.
39 Canadian crude prices converted to US dollars using 1.26 to 1 conversion, “Commodity news,” GMP FirstEnergy and Petroleum Services Association of Canada, https://www.psac.ca/business/gmpfirstenergy/, accessed April 10, 2018.
40 “Capping oil sands emissions,” Alberta Government, https://www.alberta.ca/climate-oilsands-emissions.aspx, accessed April 10, 2018.
41 Rystad Energy, UCube database, accessed February 16, 2018.
43 “Sable Offshore Energy Project decommissioning phase activities,” ExxonMobil, http://soep.com/wp-content/uploads/2017/11/WP02353_SableOpenHouseDisplays.pdf, accessed April 10, 2018.
44 “Outer continental shelf oil and gas production,” US Bureau of Ocean Energy Management, April 2, 2018, https://www.data.boem.gov/Production/OCSProduction/Default.aspx, accessed April 10, 2018.
45 “Platform structures query,” US Bureau of Ocean Energy Management, April 10, 2018, https://www.data.boem.gov/Platform/PlatformStructures/Default.aspx, accessed April 10, 2018.
46 Rystad Energy, UCube database, accessed February 16, 2018.
48 “Hibernia celebrates 20 years since first oil,” CBC News, November 17, 2017, http://www.cbc.ca/news/canada/newfoundland-labrador/20th-anniversary-of-hibernia-1.4406683, accessed April 10, 2018.
49 “Ice management,” Hibernia, http://www.hibernia.ca/ice.html, accessed April 10, 2018.
50 “Oil and gas exploration and development activity forecast: Canadian Beaufort Sea 2013–2028,” LTLC Consulting and Salmo Consulting, March 2013, March 2013, https://www.beaufortrea.ca/wp-content/uploads/2012/03/NCR-5358624-v4-BREA_-_FINAL_UPDATE_-_EXPLORATION_AND_ACTIVITY_FORECAST-__MAY_2013.pdf, accessed April 10, 2018.
51 “Greenland: Cairn Energy encounters oil and gas shows in Baffin Bay Basin well,” Energy-pedia, September 21, 2010, https://www.energy-pedia.com/news/greenland/cairn-energy-encounters-oil-and-gas-shows-in-baffin-bay-basin-well, accessed April 10, 2018.
52 Geoff Bartlett, “First oil pumped at Hebron offshore platform,” CBC News, http://www.cbc.ca/news/canada/newfoundland-labrador/hebron-first-oil-1.4422476, accessed April 10, 2018.
53 “West White Rose Project,” Husky Energy, http://wwrp.huskyenergy.com/Project_overview, accessed April 10, 2018.
54 Rystad Energy, UCube database, accessed February 16, 2018.
55 Marc Charest, “Discoveries in Newfoundland and Labrador’s Flemish Pass and East Orphan Basins,” Discovery Digest, April 2, 2016.
56 “‘We can wait no longer’: Newfoundland unveils plans to double oil production by 2030,” Financial Post, February 20, 2018, http://business.financialpost.com/commodities/energy/n-l-unveils-plan-for-faster-cheaper-offshore-oil-and-gas-development, accessed April 10, 2018.
57 Sona Mlada, “Challenges in the low commodity environment,” Oil and Gas Financial Journal, April 22, 2016, http://www.ogfj.com/articles/print/volume-13/issue-4/features/canada-shale.html, accessed April 10, 2018.
58 Rystad Energy, UCube database, accessed February 16, 2018.
59 Nia Williams, “Duvernay field in Alberta holds Canada's biggest shale oil reserves: NEB,” BNN, September 26, 2017, https://www.bnn.ca/duvernay-field-in-alberta-holds-canada-s-biggest-shale-oil-reserves-neb-1.867409, accessed April 10, 2018.
60 Rystad Energy, UCube database, accessed February 16, 2018.
62 Henry Hub and AECO year to date prices, with AECO prices converted to US dollars using 1.26 to 1 conversion, GMP FirstEnergy and Petroleum Services Association of Canada, https://www.psac.ca/business/gmpfirstenergy/, accessed April 10, 2018.
63 Geoffrey Morgan, “Natural gas prices are so bad in Alberta producers are having to pay customers to take it,” Financial Post, October 12, 2017, http://business.financialpost.com/commodities/canadian-natural-gas-prices-enter-negative-territory-amid-pipeline-outages, accessed April 12, 2018.
64 Tara Weber, “Low prices expected to continue plaguing Canadian natural gas producers in 2018,” BNN, December 28, 2017, https://www.bnn.ca/low-prices-expected-to-continue-plaguing-canadian-natural-gas-producers-in-2018-1.954042, accessed April 12, 2018.
65 North America rotary rig count, Baker Hughes, http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother, accessed April 12, 2018.
66 Rystad Energy, UCube database, accessed February 16, 2018.
67 “Canada’s energy future 2017 supplement: Conventional, tight and shale oil production,” National Energy Board, January 2018, https://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2017cnvntnll/index-eng.html?=undefined&wbdisable=true, accessed July 3, 2018.
68 Rystad Energy, UCube database, accessed April 19, 2018.
72 “Worthwhile Canadian initiative,” The New Republic, May 5, 1986, https://newrepublic.com/article/127231/worthwhile-canadian-initiative, accessed April 20, 2018.
73 Canadian to US dollars exchange rate, XE, https://www.xe.com/currencycharts/?from=CAD&to=USD&view=10Y, accessed April 20, 2018.
74 Canada, Climate Action Tracker, November 7, 2017, http://climateactiontracker.org/countries/canada.html, access April 20, 2018.
75 Allison McNeely and Kevin Orland, “‘I'm not crazy about Canada’: Investors bail on trapped oil as pipeline problems worsen,” Financial Post, February 22, 2018, accessed April 20, 2018.
76 “Canada’s Trudeau says oil pipeline will be built,” Reuters, April 19, 2018, https://www.reuters.com/article/us-kinder-morgan-cn-pipeline-trudeau/canadas-trudeau-says-oil-pipeline-will-be-built-idUSKBN1HQ2OW, accessed April 20, 2018.
77 Henning Gloystein and Julie Gordon, “British Columbia tax breaks boost LNG Canada as FID looms,” Reuters, March 22, 2018, https://www.reuters.com/article/us-kinder-morgan-cn-pipeline-trudeau/canadas-trudeau-says-oil-pipeline-will-be-built-idUSKBN1HQ2OW, access April 20, 2018.
78 “Canada country analysis,” US Energy Information Administration, November 10, 2015, https://www.eia.gov/beta/international/analysis.cfm?iso=CAN, accessed February 14, 2018.
80 “Technically recoverable shale oil and shale gas resources: Canada,” US Energy Information Administration, September 2015, https://www.eia.gov/analysis/studies/worldshalegas/pdf/Canada_2013.pdf, accessed February 14, 2018.
81 “Market Snapshot: Value of Canada’s net energy exports declined again in 2016,” National Energy Board, April 5, 2017, https://www.neb-one.gc.ca/nrg/ntgrtd/mrkt/snpsht/2017/04-01vlcndntnrgxprts-eng.html, accessed February 14, 2018.
82 Rystad Energy NasWellCube Database, accessed February 14, 2018.
83 “Energy fact book 2016–2017,” Natural Resources Canada, https://www.nrcan.gc.ca/sites/www.nrcan.gc.ca/files/energy/pdf/EnergyFactBook_2016_17_En.pdf, accessed April 20, 2018.
84 Rystad Energy, UCube database, accessed April 23, 2018.