Canadian Natural Resources Profile
Canadian Natural Resources Limited (Canadian Natural) operates as a Canadian based senior independent energy company.
The company engages in the acquisition, exploration, development, production, marketing and sale of crude oil, natural gas and NGLs. The company’s principal core regions of operations are western Canada, the U.K. sector of the North Sea and Offshore Africa.
The company operates and maintains a large working interest in a majority of the prospects in which it participates. The company’s business approach is to maintain large project inventories and production diversification among each of its products: SCO, natural gas, light and medium crude oil and NGLs, bitumen (thermal oil), primary heavy crude oil and Pelican Lake heavy crude oil. SCO from the oil sands mining and upgrading operations in northern Alberta accounted for 33% of 2022 annual production. Natural gas, primarily produced in Alberta, British Columbia and Saskatchewan, accounted for 27% of 2022 annual production. Light and medium crude oil and NGLs represented 11% of 2022 annual production, and were produced from Alberta, British Columbia, Saskatchewan and Manitoba, as well as from the company’s North Sea and Offshore Africa operations. Also produced from Alberta and Saskatchewan were bitumen (thermal oil), which accounted for 20% of 2022 annual production, primary heavy crude oil which accounted for 5% of 2022 annual production, and Pelican Lake heavy crude oil, which accounted for 4% of 2022 annual production.
The company’s Midstream assets, primarily consisted of two operated pipeline systems (ECHO and Pelican Lake), and a 50% working interest in an 84 megawatt cogeneration plant at Primrose, provide infrastructure supporting the company’s heavy crude oil and bitumen operations. Midstream assets also include a 50% equity interest in the North West Redwater Partnership.
In addition, the company installs renewable energy sources at remote locations, where appropriate.
The company has 20 year transportation agreements to ship 94,000 bbl/d of crude oil on the Trans Mountain Pipeline Expansion (‘TMX’) that will provide waterborne access to international markets. Construction of the TMX was approximately 80% complete as of March 10, 2023. Trans Mountain Corporation has announced that the TMX targets mechanical completion by the end of 2023 and for the pipeline to be in service in the first quarter of 2024.
Canadian Natural has approximately 0.53 million net acres attributed to the North America properties, which are expected to expire by December 31, 2023.
Northeast British Columbia
The northeast British Columbia region holds a significant portion of the Montney formation and provides exploration and development opportunities in combination with significant controlled infrastructure. The exploration strategy focuses on comprehensive evaluation through two dimensional seismic, three dimensional seismic and targeting economic prospects close to existing infrastructure.
This region also includes the Septimus, Umbach/Nig and Townsend Montney natural gas assets with owned natural gas processing capacity, as well as dedicated third party natural gas processing capacity.
The southern portion of this region encompasses the company’s BC Foothills assets where natural gas is produced from the deep Mississippian and Triassic aged reservoirs in this highly structural area.
Northwest Alberta
This region is located west of Edmonton, Alberta along the border of British Columbia and Alberta and provides a premium land base in the deep basin, multi-zone, liquids-rich natural gas and light oil fairway. Northwest Alberta has a significant Montney and Spirit River land base, and provides exploration and development opportunities in combination with an extensive portfolio of owned and operated infrastructure. In this region, the company produces liquids rich natural gas from multiple, often technically complex horizons, with formation depths ranging from 700 to 4,500 meters. Locations are identified with two dimensional and three dimensional seismic to predict channel and shoreface fairways. The southwest portion of this region also contains significant Foothills assets with natural gas produced from the deep Mississippian and Triassic aged reservoirs.
Northern Plains
This region starts just south of Edmonton, Alberta and extends north to Fort McMurray, Alberta and from northwest Alberta into western Saskatchewan. Over most of the region, both sweet and sour natural gas reserves are produced from numerous productive horizons at depths up to approximately 1,500 meters. In the southwest portion of the region, light crude oil and NGLs are also encountered at slightly greater depths. The company targets low-risk exploration and development opportunities in this area.
Near Lloydminster, Alberta, reserves of primary heavy crude oil (averaging 10°-14° API) and natural gas are produced through conventional vertical, slant and horizontal well bores from a number of productive horizons at depths up to 1,000 meters. The energy required to flow the heavy crude oil to the wellbore in this type of heavy crude oil reservoir comes from solution gas. The crude oil viscosity and the reservoir quality will determine the amount of crude oil produced from the reservoir. A key component to maintaining profitability in the production of heavy crude oil is to be an effective and efficient producer. The company continues to control costs by holding a dominant position that includes a significant land base and an extensive infrastructure of batteries and disposal facilities.
In this region, the company’s holdings of primary heavy crude oil production are the result of Crown land purchases and acquisitions. The company’s 100% owned ECHO Pipeline system is also located in this region. The ECHO Pipeline has a capacity of up to 78,000 bbl/d, which enables the company to transport its own production volumes at a reduced production cost. This pipeline enhances the company’s ability to control the full spectrum of costs associated with the development and marketing of its heavy crude oil.
Included in the northern part of this region, approximately 200 miles north of Edmonton, Alberta are the company’s holdings at Pelican Lake. These assets produce Pelican Lake heavy crude oil from the Wabasca formation with gravities of 12°-17° API. Production expenses are low due to the absence of sand production and its associated disposal requirements, as well as the gathering and pipeline facilities in place. The company has the major ownership position in the necessary infrastructure, roads, drilling pads, gathering and sales pipelines, batteries, gas plants and compressors, to ensure economic development of the large crude oil pool located on the lands, including the 100% owned and operated Pelican Lake Pipeline and three major oil batteries with a capacity of 85,000 bbl/d. The company is using an EOR scheme through polymer flooding to increase the ultimate recoveries from the field.
Production of bitumen (thermal oil) from the 100% owned Primrose and Wolf Lake fields located near Bonnyville, Alberta, involves processes that utilize steam to increase the recovery of the bitumen. The processes employed by the company are CSS, SAGD and steamflood. These recovery processes inject steam to heat the bitumen deposits, reducing the viscosity and thereby improving its flow characteristics. There is also an infrastructure of gathering systems and a processing plant at Wolf Lake with capacity of 140,000 bbl/d. The company holds a 50% interest in a co-generation facility capable of producing 84 megawatts of electricity. The company continues to optimize the CSS, and steamflood processes which results in significant improvements in well productivity and in ultimate bitumen recovery.
The company has two 100% owned thermal SAGD facilities in the Kirby area located near Lac La Biche, Alberta with infrastructure and total plant processing capacity of 80,000 bbl/d.
The company has a 100% interest in the operating thermal SAGD assets at Jackfish. In 2022, the company further consolidated development opportunities for the Jackfish and Kirby assets with the purchase of the remaining 50% interest in the undeveloped Pike lands located adjacent to Jackfish. The infrastructure at Jackfish consists of three processing plants and gathering systems that have a combined capacity of 120,000 bbl/d.
Southern Plains and Southeast Saskatchewan
The Southern Plains region is principally located south of the Northern Plains region to the United States border and extending into western Saskatchewan.
Reserves of natural gas, NGLs and light and medium crude oil are contained in numerous productive horizons at depths up to 2,300 meters. This region is one of the more mature regions of the Western Canadian Sedimentary Basin and requires continual operational cost control through efficient utilization of existing facilities, flexible infrastructure design and consolidation of interests where appropriate.
The Southeast Saskatchewan area is located in the southeastern portion of the province extending into Manitoba and produces primarily light sour crude oil from multiple productive horizons found at depths up to 2,700 meters.
Oil Sands Mining and Upgrading
Horizon: The company owns a 100% working interest in its Horizon oil sands leases which are located about 70 kilometers north of Fort McMurray, Alberta. In 2021, the company completed an acquisition of a 5% net carried interest on an existing Company oil sands lease from which Horizon production is derived.
The oil sands resource at Horizon Oil Sands is found in the Cretaceous McMurray Formation, which is further subdivided into three informal members: lower, middle and upper. Most of Horizon’s oil sands resource is found within the lower and middle McMurray Formation at depths ranging from 50 to 100 meters below the surface.
Horizon Oil Sands, which is accessible by private road and private airstrip, includes surface oil sands mining, bitumen extraction, bitumen upgrading and associated infrastructure. Mining of the oil sands is done using conventional truck and shovel technology. The ore is then processed through extraction and froth treatment facilities to produce bitumen, which is upgraded on-site into SCO. The SCO is transported from the site by pipeline to the Edmonton area for distribution. Two on-site cogeneration plants with a combined design capacity of 180 megawatts provide power and steam for operations.
The company received project sanction by the Board of Directors in February 2005, authorizing management to proceed with Phase 1 of Horizon with a design capacity of 110,000 bbl/d. First SCO production was achieved during 2009.
In 2014, the company completed the Phase 2A coker plant tie-in, followed by the Phase 2B expansion in 2016. In 2017, the company completed the Phase 3 expansion bringing total production capacity to approximately 250,000 bbl/d.
In 2018, the company acquired the Joslyn oil sands project, adding to the company’s total oil sands mining and upgrading reserves. This incorporation of the Joslyn leases (now, Horizon South) to the mine plan will allow mining to continue south of the previously existing Horizon leases with opportunity for further cost optimizations.
AOSP: In 2017, the company acquired a combined direct and indirect 70% interest in AOSP which is an oil sands mining and upgrading joint venture located in Alberta, Canada. The company operates AOSP’s mining and extraction assets, which are located in the Athabasca region near Fort McMurray, Alberta, and include the Muskeg River and Jackpine mines. Shell operates the Scotford Upgrader, including the Quest project, which is located near Fort Saskatchewan, northeast of Edmonton, Alberta and utilizes LC FINING technology to efficiently hydrocrack residuum to high-quality fuel oils and transportation fuels.
Bitumen is produced from the oil sands deposits using conventional truck and shovel technology. The ore is then processed through extraction and froth treatment facilities to produce bitumen. Diluted bitumen blend from the Muskeg River and Jackpine mines is transported to the Scotford Upgrader on the third party owned Corridor Pipeline where the bitumen is upgraded into Premium Albian Synthetic crude oil, Albian Heavy Synthetic crude oil and Vacuum Gas Oil and, in certain circumstances, other heavy blends. Diluent is transported from the Scotford Upgrader back to the Muskeg River mine through the combined Corridor Pipeline transport system. A long term off-take agreement is in place with Shell to purchase Vacuum Gas Oil at market rates, as well as agreements to sell volumes of Premium Albian Synthetic and Albian Heavy Synthetic from the Scotford Upgrader at market rates.
Gross production capacity of the combined AOSP mines is approximately 320,000 bbl/d of bitumen. Shell obtained the Joint Review Panel Approval along with other associated approvals in 2013 for a 100,000 bbl/d expansion of the Jackpine Mine and in 2019 the remaining major application approvals were obtained.
The United Kingdom North Sea
Through its wholly owned subsidiary, CNR International (U.K.) Limited, formerly Ranger Oil (U.K.) Limited, the company has operated in the North Sea for over 40 years and has developed a significant database, extensive operating experience and an experienced staff. In 2022, the company produced from 8 crude oil fields.
The northerly fields are centered around the Ninian field where the company has a 100% operated working interest. The central processing facility is connected to other fields, including the Strathspey, Columba and Lyell fields where the company operates with working interests of 91.6% to 100%.
In the central portion of the North Sea, the company holds a 100% operated working interest in the T-block (comprising the Tiffany, Toni and Thelma fields).
The company receives tariff revenue from third parties for the processing of crude oil and natural gas through certain processing facilities.
The decommissioning activities at the Banff and Kyle fields commenced in the second quarter of 2020 with cessation of production occurring in June of 2020. The decommissioning activities are targeted to be substantially completed by 2024.
The company commenced abandonment of the Ninian North Platform in 2017. Dismantling and disposal of the platform topsides was completed in 2021, and jacket removal and dismantling was completed in 2022. These decommissioning activities are targeted to be substantially complete in 2023.
In 2022, the prevailing regulatory and economic conditions and increasingly challenging commercial outlook in the United Kingdom led the company to assess the viability of its North Sea operations. Following a detailed review of its development plans, the company determined that the Ninian, Columba, Lyell and Strathspey fields are no longer economic and de-booked associated crude oil and natural gas reserves as of December 31, 2022, and is accelerating the decommissioning and abandonment of these fields.
Offshore Africa
CÔte d’Ivoire
The company owns interests in two licenses offshore CÔte d’Ivoire. The first is a 58.7% operated working interest in the Espoir field in Block CI-26 which is located in water depths ranging from 100 to 700 meters. Production from East Espoir commenced in 2002 and from West Espoir in 2006. Crude oil from the East and West Espoir fields is produced to a dedicated FPSO with the associated natural gas delivered onshore for local power generation through a subsea pipeline.
The second is a 57.6% operated working interest in the Baobab field, located in Block CI-40, which is eight kilometers south of the Espoir facilities and located in water depths ranging from 1,000 to 1,400 meters. Production from the Baobab field commenced in 2005. Crude oil from the Baobab field is produced to a dedicated FPSO with the associated natural gas delivered onshore via a subsea pipeline tied into the Espoir infrastructure.
South Africa
In 2012, the company completed the conversion of its 100% owned oil sub-lease in respect of Block 11B/12B (the ‘Block’) off the southeast coast of South Africa into an exploration right for petroleum for this area. The company has a 20% non-operated working interest in the Block, having divested a 50% interest in the exploration right in a farm-out transaction in 2013 and an additional 30% interest in two separate farm out transactions in 2018. In 2018, the operator re-entered the suspended Brudpadda exploration well on the Block and subsequently announced the discovery of natural gas and condensate from that prospect. In 2020, the operator completed the drilling and testing of the Luiperd exploratory well on the Block and subsequently announced the discovery of natural gas and condensate on that prospect. In 2022, the operator, on behalf of the exploration rights holders, submitted an application to the State to convert the exploration right to a production right, and is preparing a development plan for the Block. Additional cash payments will be due to the company after the grant of a production right and establishment of commerciality.
History
The company was incorporated under the laws of the province of British Columbia in 1973. It was formerly known as AEX Minerals Corporation and changed its name to Canadian Natural Resources Limited in 1975.
