The Company drilled a total of 295 net crude oil and natural gas wells in the nine months ended September 30, 2022 compared to 168 in the comparable period in 2021, an increase of 127 net wells over this time period.
North America E&P liquids production, excluding thermal in situ, averaged 228,239 bbl/d in Q3/22, comparable to Q2/22 and an increase of 10% over Q3/21. The increase over Q3/21 primarily reflects strong drilling results and acquisitions, partially offset by natural declines.
- Primary heavy crude oil production averaged 68,933 bbl/d in Q3/22, increases of 4% and 8% from Q2/22 and Q3/21 levels respectively, reflecting strong drilling results, partially offset by natural field declines.
- Operating costs(1) in the Company’s primary heavy crude oil operations averaged $21.30/bbl (US$16.32/bbl) in Q3/22, a decrease of 7% from Q2/22 levels, primarily due to lower fuel costs, partially offset by higher trucking costs.
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CNRL Wells Drilled 2022
Canadian Natural has one of the largest land bases of Clearwater rights at approximately 940,000 net acres, on which the Company drilled 14 net horizontal multilateral Clearwater wells in the Smith area in Q3/22, bringing the total Clearwater wells drilled and on production year to date to 33 net wells. The Company’s total Clearwater production in September 2022 averaged approximately 12,300 bbl/d, an increase of approximately 8,400 bbl/d from the beginning of 2022.
Pelican Lake production averaged 50,051 bbl/d in Q3/22, decreases of 2% and 7% from Q2/22 and Q3/21 levels respectively, demonstrating the low decline nature of this long life asset and the continued success of this world class polymer flood.
- Operating costs at Pelican Lake averaged $8.89/bbl (US$6.81/bbl) in Q3/22, an 11% increase from Q2/22 levels, primarily as a result of higher power costs.
North America light crude oil and NGL production averaged 109,255 bbl/d in Q3/22, comparable to Q2/22 and up 23% from Q3/21 levels as a result of strong drilling results and acquisitions, partially offset by natural field declines.
- Operating costs in the Company’s North America light crude oil and NGL areas averaged $16.68/bbl (US$12.78/bbl) in Q3/22, an increase of 10% from Q2/22 levels, primarily due to higher power costs.
- At Wembley, the Company brought a 3 well pad on production in July 2022 at a capital efficiency(2) of approximately $6,000/BOE/d. October 2022 monthly production from these wells averaged approximately 2,000 bbl/d of liquids and 7 MMcf/d of natural gas.
- At Gold Creek, the Company brought a 2 well pad on production in September 2022 at a strong capital efficiency of approximately $4,300/BOE/d, with strong October 2022 monthly average production of approximately 2,100 bbl/d of liquids and 16 MMcf/d of natural gas.
Canadian Natural’s long life low decline thermal in situ assets averaged 243,393 bbl/d in Q3/22, decreases of 3% and 2% from Q2/22 and Q3/21 levels respectively, primarily reflecting planned maintenance activities at Jackfish in Q3/22 and the low decline nature of these assets.
- Thermal in situ operating costs averaged $15.63/bbl (US$11.97/bbl) in Q3/22, a decrease of 17% from Q2/22 levels primarily reflecting lower natural gas costs, partially offset by higher power costs.
As a result of continued strong execution, the Company remains on track to add targeted production of approximately 7,000 bbl/d in 2023, as per the capital update released on August 4, 2022. Capital efficiencies target to average approximately $8,000/bbl/d on Steam Assisted Gravity Drainage (“SAGD”) pads and approximately $10,000/bbl/d on cyclic steam stimulation (“CSS”) pads.
- At Kirby, the Company is progressing, as budgeted, with a 3 SAGD pad development and is targeting to begin steam injection on the first pad in Q1/23, with ramp up to full production capacity in Q3/23.
- At Primrose, the Company completed drilling of two CSS pads on time and on costs. These two pads are targeted to come on production in Q3/23.
CNRL Wells Drilled Since 2020 (Click for Access)
Canadian Natural has been piloting solvent enhanced oil recovery technology on certain of its thermal in situ assets with an objective to increase bitumen production, reduce the Steam to Oil Ratio (“SOR”), reduce GHG intensity and realize high solvent recovery. This technology has the potential for application throughout the Company’s extensive thermal in situ asset base.
- The Company is progressing with engineering and design of a commercial scale solvent SAGD pad development at Kirby North, which is targeted to commence solvent injection in early 2024.
- The Company’s solvent pilot in the Primrose steam flood area began solvent injection in November 2021 with plans to continue for approximately two years to achieve targeted SOR and GHG intensity reductions of 40% to 45%, with solvent recovery greater than 70%. The Company is seeing positive operating results to date, including SOR reductions of approximately 50%.
Canadian Natural achieved record quarterly North America natural gas production in Q3/22, averaging approximately 2,117 MMcf/d, an increase over Q2/22 and a 25% increase over Q3/21 levels. The increase from Q2/22 primarily reflects the impact of strong drilling results, partially offset by natural field declines and planned turnaround activities in Q3/22. The increase from Q3/21 primarily reflects strong drilling results and acquisitions, partially offset by natural field declines.
- North America natural gas operating costs averaged $1.13/Mcf in Q3/22, a 2% decrease from Q2/22 levels, reflecting the Company’s continuous focus on cost control.
Based on the midpoint of the Company’s previously updated production guidance, Canadian Natural’s diversified natural gas sales points includes the equivalent use of approximately 41% of its natural gas production in its operations, with approximately 37% exported to other North American markets and sold internationally and the remaining 22% sold at AECO/Station 2 pricing.
- The Company’s diversified sales points drove strong realized natural gas pricing averaging $6.51/Mcf in Q3/22, which is above the AECO monthly benchmark price.
Canadian Natural has approximately 1.5 million net acres of Montney rights, providing the Company with significant high value growth opportunities. Montney natural gas production represents approximately 41% of the Company’s total natural gas production, with October 2022 Montney production averaging approximately 866 MMcf/d of natural gas with 45,300 bbl/d of liquids. The Company continues to utilize its efficient low cost drill-to-fill strategy to maximize value.
- At Nig, the Company brought a 6 well pad on production inQ3/22 at a top tier capital efficiency of approximately $2,700/BOE/d. October 2022 monthly production from these wells averaged approximately 55 MMcf/d of natural gas and 3,200 bbl/d of liquids, exceeding budgeted rates and maximizing existing facility capacity.
- At Townsend, the Company brought a 2 well pad on production in July 2022 at a strong capital efficiency of approximately $4,800/BOE/d. Production from these wells continues to be strong, with average October 2022 monthly production of approximately 20 MMcf/d of natural gas.
The Company’s world class Oil Sands Mining and Upgrading assets continue to deliver safe and reliable production of SCO, averaging 487,553 bbl/d in Q3/22. Production increased by 37% and 4% from Q2/22 and Q3/21 levels respectively, primarily reflecting strong operational performance following the planned turnaround activities completed at Horizon and Scotford in Q2/22.
- Approximately 50% of Canadian Natural’s total liquids production is comprised of high value SCO from its Oil Sands Mining and Upgrading assets, which captured a strong price premium to WTI of US$8.87/bbl in Q3/22, driving strong SCO average realized pricing of $120.91/bbl and generating significant free cash flow for the Company.
- Top tier operating costs were realized in Q3/22, averaging $22.35/bbl (US$17.12/bbl) of SCO, a decrease of 34% from Q2/22 levels and an increase of 13% from Q3/21 levels. The decrease from Q2/22 primarily reflects increased volumes due to the completion of planned turnaround activities in Q2/22 as well as lower natural gas and diesel costs in Q3/22. The increase from Q3/21 primarily reflects higher energy costs.
At Horizon, the reliability enhancement project is progressing as planned and targets to extend the major maintenance cycle from once per year to once every second year, increasing the SCO production capacity by approximately 5,000 bbl/d in 2023, increasing to approximately 14,000 bbl/d in 2025.
- The Company is progressing on detailed design work of the 750t/hr commercial unit for the In-Pit Extraction Plant (“IPEP”) that will provide dry stackable tailings directly in the mine-pit, targeting to reduce GHG emissions and tailings ponds in the future.
Subsequent to Q3/22, the Company’s Oil Sands Mining and Upgrading assets experienced unplanned outages at both Horizon and Scotford upgraders during the month of October 2022, resulting in a Q4/22 targeted production range of 450,000 bbl/d to 460,000 bbl/d of SCO.
- At Horizon, piping and mechanical repairs in the Primary Upgrading area have been completed and the Company will be enhancing its piping integrity and maintenance programs to support safe and reliable operations.
At Scotford, piping repairs in the hydrotreater area were completed by the operator. The Company is working closely with the operator to understand the learnings and the opportunity to enhance the integrity program accordingly.
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