Resource News

Canadian Natural Resources Limited Announces 2021 Third Quarter Results

Commenting on the Company's third quarter 2021 results, Tim McKay, President of Canadian Natural (TSX: CNQ) (NYSE: CNQ) stated "Our diverse product mix is a competitive advantage, as we can allocate capital to the highest return projects, without being reliant on any one commodity. Our effective and efficient operations combined with disciplined capital allocation generates significant free cash flow, which delivers substantial shareholder returns through our sustainable dividend and ongoing share repurchases. Our world class long life low decline assets, which have low maintenance capital requirements relative to the size and quality of the assets, delivered top tier Q321 operational and financial results with average production volumes of approximately 1,238 MBOEd achieved in the quarter, representing increases of 11% and 8% over Q320 and Q221 levels respectively. Our strong operational results during Q321 delivered robust quarterly adjusted funds flow of approximately $3.6 billion. After our disciplined capital program and dividend, the Company generated quarterly free cash flow of approximately $2.2 billion.

Environmental, Social and Governance ("ESG") performance remains a priority. We continue to invest in technologies and innovations designed to improve our environmental performance and reduce our environmental footprint. As previously announced, the Oil Sands Pathways initiative to achieve net zero greenhouse gas emissions by 2050 is an unprecedented initiative by the Canadian energy industry. Canadian Natural and Pathways alliance members are developing several technology pathways that when implemented will strengthen our leading ESG performance through meaningful emissions reductions while maintaining jobs in the oil sands sector and creating thousands of new construction and permanent jobs in the energy and cleantech industries. Collaboration with the federal and Alberta governments on this initiative will be critical for Canada to achieve its climate goals."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added "During the third quarter of 2021 our robust business model delivered strong net earnings of over $2.2 billion and adjusted net earnings of approximately $2.1 billion. Our diversified portfolio of world class assets combined with effective and efficient operations in a strong commodity price environment, allowed us to continue to enhance returns to shareholders by repurchasing shares and reducing debt at a faster rate than originally targeted. The Company's balance sheet continues to be a priority and was further strengthened during the quarter with ending net debt at approximately $15.9 billion, a reduction of approximately $2.3 billion compared to Q2/21. We remain on track to meet our full year 2021 capital investment target of approximately $3.48 billion.

Our commitment to returns to shareholders has been significant totaling $3.1 billion year to date through dividends and share repurchases. Subsequent to quarter end the Board of Directors has approved a 25% increase to our quarterly dividend to $0.5875 per share, payable on January 5, 2022. The increased dividend clearly demonstrates the confidence that the Board of Directors have in the sustainability of our business model, the strength of our balance sheet and the Company's effective and efficient operations supported by our robust, long life low decline asset base and associated low maintenance capital requirements. With this increase, 2022 will mark the 22nd consecutive year of dividend increases for the Company, and this 25% increase from our previous quarterly dividend is in excess of our historical dividend compound annual growth rate of 20% over the last 22 years.

Effective July 1, 2021 our free cash flow allocation policy authorized management to increase returns to shareholders through accelerated share repurchases under the Company's Normal Course Issuer Bid ("NCIB") by targeting the repurchase of approximately 1% of shares outstanding per quarter. This policy further states that once the Company reaches an absolute debt level of $15 billion, currently targeted to occur in Q4/‍21, 50% of free cash flow will be targeted to share repurchases, with the remaining 50% of free cash flow allocated to further strengthen our balance sheet. Per this policy, the Company repurchased approximately 12 million shares in the quarter and year-to-date as of November 3, 2021 we have repurchased a total of approximately 21.5 million shares for approximately $940 million. Subsequent to quarter end, and as an enhancement to the free cash flow allocation policy, the Board of Directors has authorized management to target absolute debt at levels below $15 billion (approximately 1.0 times debt to EBITDA in the current price environment). To the extent debt is below $15 billion, such amount will be available for strategic growth/acquisition opportunities."

QUARTERLY HIGHLIGHTS


Three Months Ended
Nine Months Ended
($ millions, except per common share amounts)Sep 30
2021

Jun 30
2021

Sep 30
2020

Sep 30
2021

Sep 30
2020
 
Net earnings (loss)$2,202
$1,551
$408
$5,130
$(1,184)
Per common share- basic$1.87
$1.31
$0.35
$4.33
$(1.00)

- diluted$1.86
$1.30
$0.35
$4.32
$(1.00)
Adjusted net earnings (loss) from operations (1)$2,095
$1,480
$135
$4,794
$(932)
Per common share- basic$1.78
$1.25
$0.11
$4.05
$(0.79)

- diluted$1.77
$1.24
$0.11
$4.04
$(0.79)
Cash flows from operating activities$4,290
$2,940
$2,070
$9,766
$3,444
Adjusted funds flow (2)$3,634
$3,049
$1,740
$9,395
$3,492
Per common share- basic$3.08
$2.57
$1.47
$7.94
$2.96

- diluted$3.07
$2.56
$1.47
$7.91
$2.96
Cash flows used in investing activities$721
$719
$643
$2,088
$2,195
Net capital expenditures, excluding net acquisition costs (3)$881
$957
$771
$2,646
$2,030
Net capital expenditures, including net acquisition costs (3)
$1,011
$1,285
$771
$3,104
$2,030
Daily production, before royalties

 
 
 
 
Natural gas (MMcf/d)1,708
1,614
1,362
1,640
1,421
Crude oil and NGLs (bbl/d)952,839
872,718
884,342
934,873
914,859
Equivalent production (BOE/d) (4)1,237,503
1,141,739
1,111,286
1,208,285 
1,151,693 

 

Footnotes 1 through 3 describe non-GAAP financial measures that the Company considers key in evaluating its performance. Derivations of these measures are discussed in the "Advisory" section of this press release.
(1)Adjusted net earnings (loss) from operations demonstrates the Company's ability to generate after-tax operating earnings from its core business areas.
(2)Adjusted funds flow demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
(3)Net capital expenditures provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget.
(4)A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

  • Net earnings of $2,202 million and adjusted net earnings from operations of $2,095 million were realized in Q3/21, significant increases from Q2/21 net earnings of $1,551 million and adjusted net earnings from operations of $1,480 million, primarily as a result of higher realized pricing and effective and efficient operations.

  • Cash flows from operating activities were $4,290 million in Q3/21, increases from $2,070 million in Q3/20 and $2,940 million in Q2/21.

  • The strength of our balanced asset base, supported by safe, effective and efficient operations generates significant free cash flow over the long-term, making Canadian Natural's business unique, robust and sustainable.

    • Canadian Natural has a diverse asset base underpinned by low maintenance capital requirements and effective and efficient operations that delivers significant free cash flow.

    • Canadian Natural generated strong quarterly adjusted funds flow of $3,634 million in Q3/‍21, a significant increase from Q2/21 levels of $3,049 million, primarily the result of higher realized pricing and effective and efficient operations.

    • Reflecting the strength of our effective and efficient operations and our high quality, long life low decline asset base, Canadian Natural generated strong quarterly free cash flow of $2,195 million in Q3/21, after dividend payments of $558 million and net capital expenditures of $881 million, excluding acquisitions.

  • Returns to shareholders year to date in 2021 have been significant, as Canadian Natural has returned approximately $3.1 billion by way of dividends and share repurchases up to and including November 3, 2021.

    • Share repurchases for cancellation during Q3/21 per the free cash flow allocation policy, totaled 11,984,400 shares or 1% of common shares outstanding at a weighted average price of $42.26 per share. Share repurchases for cancellation in 2021 up to and including November 3, 2021 total 21,464,400 common shares at a weighted average price of $43.77 per share.

    • Subsequent to quarter end the Board of Directors has approved a 25% increase to our quarterly dividend to $0.5875 per share, payable on January 5, 2022. The increased dividend clearly demonstrates the confidence that the Board of Directors have in the sustainability of our business model, the strength of our balance sheet and the Company's effective and efficient operations supported by our robust, long life low decline asset base and associated low maintenance capital requirements.

      • With this increase, 2022 will mark the 22nd consecutive year of dividend increases for the Company, and this 25% increase from our previous quarterly dividend is in excess of our historical dividend compound annual growth rate of 20% over the last 22 years.

  • Canadian Natural executed on our commitment to further strengthen our balance sheet with strong financial results in Q3/‍21, reducing net debt by approximately $2.3 billion from Q2/21 levels, while net debt has decreased by approximately $5.8 billion over the last 12 months ended September 30, 2021. In Q3/21 the Company executed on the following:

    • On August 16, 2021 the Company repaid the US$500 million 3.45% notes originally due November 15, 2021.

    • The Company repaid $500 million on its $2,650 million term credit facility due February 2023.

      • Subsequent to quarter end the Company repaid an additional $1,000 million, which reduced the facility balance to $1,150 million as at November 3, 2021.

  • Effective July 1, 2021 our free cash flow allocation policy authorized management to increase returns to shareholders through accelerated share repurchases under the Company's NCIB by targeting the repurchase of approximately 1% of shares outstanding per quarter. This policy further states that once the Company reaches an absolute debt level of $15 billion, currently targeted to occur in Q4/‍21, 50% of free cash flow will be targeted to share repurchases, with the remaining 50% of free cash flow allocated to further strengthen our balance sheet. Per this policy, the Company repurchased approximately 12 million shares in the quarter and year to date as of November 3, 2021 we have repurchased a total of approximately 21.5 million shares for approximately $940 million. Subsequent to quarter end, and as an enhancement to the free cash flow allocation policy, the Board of Directors has authorized management to target absolute debt at levels below $15 billion (approximately 1.0 times debt to EBITDA in the current price environment). To the extent debt is below $15 billion, such amount will be available for strategic growth/acquisition opportunities.

  • In Q3/21 the Company continued its focus on safe, effective and efficient operations averaging quarterly production volumes of 1,237,503 BOE/d, increases of 11% and 8% from Q3/20 and Q2/21 levels respectively. The increases from prior periods are primarily as a result of robust natural gas production and strong Oil Sands Mining and Upgrading performance after completion of planned turnaround activities.

    • The Company delivered strong natural gas performance in Q3/21 with corporate natural gas production of 1,708 MMcf/d, an increase of 6% from Q2/21 levels. The increase from Q2/21 levels primarily reflects reinstated production volumes from the Pine River Gas Plant, acquisitions, and strong drilling results, partially offset by natural field declines.

      • Corporate natural gas operating costs in Q3/21 averaged $1.17/Mcf, a decrease of 2% from Q2/21 levels.

    • Strong quarterly liquids production volumes averaged 952,839 bbl/d in Q3/21, increases of 8% and 9% from Q3/20 and Q2/21 levels respectively, primarily due to Canadian Natural's effective and efficient operations and planned turnaround activities completed in prior periods.

  • Canadian Natural's North America E&P liquids production, including thermal in situ, averaged 454,888 bbl/d during Q3/21, decreases of 8% and 5% from Q3/20 and Q2/21 levels respectively. The decreases from Q3/20 and Q2/21 levels were primarily due to natural field declines, planned turnaround activities at Jackfish and lower NGL production volumes largely due to third-party outages in the quarter.

    • North American E&P liquids, including thermal in situ, operating costs averaged $13.33/bbl (US$10.58/bbl) in Q3/21, an increase of 4% from Q2/21 levels. The increase in operating costs from Q2/21 was primarily due to increased energy costs and lower production volumes.

  • Canadian Natural's thermal in situ production averaged 248,113 bbl/d in Q3/21, decreases of 14% and 4% from Q3/20 and Q2/21 levels respectively. The decrease in thermal in situ production during Q3/21 compared to Q3/20 and Q2/21 was primarily due to planned turnaround activities at Jackfish and natural field declines.

    • Thermal in situ assets operating costs averaged $12.24/bbl (US$9.71/bbl) in Q3/21, an increase of 4% from Q2/21 levels. The increase in operating costs from Q2/21 was primarily due to increased energy costs and lower production volumes due to planned turnaround activities.

  • The Company's world class Oil Sands Mining and Upgrading assets averaged quarterly production of 468,126 bbl/‍d of Synthetic Crude Oil ("SCO") in Q3/21, increases of 34% and 29% from Q3/20 and Q2/21 levels respectively and comparable to the record average quarterly production volumes achieved in Q1/21. Strong Q3/21 production performance was due to the Company's focus on continuous improvement, effective and efficient operations as well as planned turnaround activities completed during prior periods.

    • Following recently completed maintenance and turnaround activities across the Oil Sands Mining and Upgrading assets, top tier performance and utilization resulted in industry leading operating costs. During the first nine months of 2021, as a result of the successful completion of the Scotford turnaround and expansion in 2020, the Company increased sales volumes by over 20,000 bbl/d of SCO.

    • Operating costs from the Company's Oil Sands Mining and Upgrading assets were strong and remain top tier averaging $19.86/bbl (US$15.76/bbl) of SCO during Q3/21, a decrease of 22% from Q2/21 levels. The decrease from Q2/21 was primarily due to strong production volumes, the Company's culture of continuous improvement and planned turnaround activities completed during the prior period.

    • Oil Sands Mining and Upgrading continue to be top tier with production volumes for October 2021 of approximately 477,000 bbl/d of SCO.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural's production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO (herein collectively referred to as "crude oil") and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company's shareholders.

Underpinning this asset base is the Company's long life low decline production, representing approximately 81% of our total liquids production in Q3/21, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of long life low decline production comes from Canadian Natural's top tier thermal in situ oil sands operations and the Company's Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations, results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.

In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for our shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.

Canadian Natural's balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.

Drilling Activity
Nine Months Ended Sep 30

 2021 
2020
(number of wells)
Gross

Net

Gross

Net 
Crude oil 130

127

43

37
Natural gas 50

40

25

21
Dry 1

1

-

- 
Subtotal 181

168

68

58
Stratigraphic test / service wells 405

336

426

372 
Total 586

504

494

430 
Success rate (excluding stratigraphic test / service wells)  

99% 
 

100% 

 

  • The Company's total crude oil and natural gas drilling program of 168 net wells for the nine months ended September 30, 2021, excluding stratigraphic/service wells, represents an increase of 110 net wells from the same period in 2020, consistent with the 2021 capital budget.

North America Exploration and Production

Crude oil and NGLs - excluding Thermal In Situ Oil Sands








Three Months Ended

Nine Months Ended


Sep 30
2021


Jun 30
2021


Sep 30
2020


Sep 30
2021


Sep 30
2020
 
Crude oil and NGLs production (bbl/d)
206,775

219,763

206,974

212,565

212,064 
Net wells targeting crude oil
55

22

-

116

30 
Net successful wells drilled
54

22

-

115

30 
Success rate
98%

100%

-%

99%

100% 

 

  • Canadian Natural's North America E&P crude oil and NGL production volumes, excluding thermal in situ averaged 206,775 bbl/d in Q3/21, comparable with Q3/20 levels. Production volumes decreased by 6% from Q2/21 levels primarily due to lower NGL production volumes largely as a result of third-party outages and natural field declines.

    • Primary heavy crude oil production averaged 63,891 bbl/d in Q3/21, decreases of 10% and 3% from Q3/20 and Q2/21 levels respectively, primarily due to natural field declines, partially offset by strong drilling results and increased development activity in 2021.

      • Operating costs in the Company's primary heavy crude oil operations averaged $19.51/bbl (US$15.48/bbl) in Q3/21, comparable to Q2/21 levels.

      • At the Company's Clearwater play at Smith, the 6 net horizontal multilateral wells brought onstream in the first half of 2021 continue to perform well, with current production rates totaling over 1,800 bbl/d.

        • - The additional 6 net horizontal multilateral wells that were targeted to be onstream in Q4/21 are now on production with current volumes totaling approximately 2,100 bbl/d, exceeding the targeted rate of 2,000 bbl/d.

    • Pelican Lake production in Q3/21 averaged 53,923 bbl/d, decreases of 4% and 2% from Q3/20 and Q2/21 levels respectively. The production decreases reflect the low decline nature of this long life low decline asset and the continued success of the Company's world class polymer flood.

      • The Company continues to focus on safe, effective and efficient operations, realizing low operating costs in Q3/21 at Pelican Lake, averaging $5.90/bbl (US$4.68/bbl), a decrease of 14% from Q2/21 levels. The operating cost decrease from Q2/21 levels was primarily due to Canadian Natural's culture of continuous improvement.

    • North America light crude oil and NGL production averaged 88,961 bbl/d in Q3/21, an increase of 12% from Q3/20 levels and a decrease of 10% from Q2/21 levels. The increase from Q3/20 was primarily due to strong drilling results, acquired production over the past 12 months and development activities. The decrease from Q2/21 was primarily due to lower NGL production volumes, which impacted the quarter by approximately 8,400 bbl/d and natural field declines, offset by strong light crude oil drilling results.

      • Operating costs in the Company's North America light crude oil and NGL areas averaged $16.19/bbl (US$12.85/bbl) in Q3/21, an increase of 13% from Q2/21 levels. The increase in Q3/21 was primarily the result of increased energy costs and decreased NGL production volumes.

      • The Company continues to advance its high-value Montney light crude oil development plan at Wembley.

        • - 13 net wells were onstream in Q3/21 with 5 additional net wells targeted to be onstream in Q4/21.

        • - Construction of a new crude oil battery was completed ahead of schedule and below budgeted costs.

        • - The project now targets to exit 2021 with total production rates of more than 10,000 bbl/d of liquids and 30 MMcf‌/‌d of natural gas, representing an increase of over 1,500 bbl/d of liquids and approximately 2 MMcf/d of natural gas.

        • - The Company is targeting strong well capital efficiencies of approximately $6,800/BOE/d.

Thermal In Situ Oil Sands








Three Months Ended

Nine Months Ended


Sep 30
2021


Jun 30
2021


Sep 30
2020


Sep 30
2021


Sep 30
2020
 
Bitumen production (bbl/d)
248,113

258,551

287,978

257,993

243,193 
Net wells targeting bitumen
-

4

-

7

6 
Net successful wells drilled
-

4

-

7

6 
Success rate
-%

100%

-%

100%

100% 

 

  • Canadian Natural's thermal in situ production averaged 248,113 bbl/d in Q3/21, decreases of 14% and 4% from Q3/20 and Q2/21 levels respectively. Changes in thermal in situ production during Q3/21 compared to Q3/20 and Q2/21 were primarily due to planned turnaround activities at Jackfish and natural field declines.

    • Thermal in situ assets operating costs averaged $12.24/bbl (US$9.71/bbl) in Q3/21, an increase of 4% from Q2/21 levels. The increase in operating costs from Q2/21 was primarily due to increased energy costs and lower production volumes due to planned turnaround activities.

  • Solvent enhanced oil recovery technology is being piloted by the Company with an objective to increase bitumen production, reduce the Steam to Oil Ratio ("SOR"), reduce greenhouse gas ("GHG") intensity and have high solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.

    • Results at Kirby South from our on-going two year pilot of this technology were positive, showing SOR and GHG intensity reductions of 45% through the piloted process, consistent with the targeted range, as well as solvent recoveries of approximately 85%, confirming the viability of this technology. As a result, the Company is progressing with engineering and design of a commercial scale SAGD pad development at Kirby North.

    • As previously announced, a second solvent injection pilot intended to further validate this technology commenced in October 2021, in the steam flood area of Primrose. The Company's second pilot consists of 9 net wells, 5 producers and 4 injectors. The second pilot targets to operate for a two year period with targeted SOR and GHG intensity reductions of 40 to 45% and solvent recoveries of greater than 70%.

North America Natural Gas








Three Months Ended

Nine Months Ended


Sep 30
2021


Jun 30
2021


Sep 30
2020


Sep 30
2021


Sep 30
2020

Natural gas production (MMcf/d)
1,698

1,594

1,340

1,626

1,393 
Net wells targeting natural gas
9

9

9

40

21
Net successful wells drilled
9

9

9

40

21 
Success rate
100%

100%

100%

100%

100% 

 

  • North America natural gas production was strong in Q3/21 averaging 1,698 MMcf/d, increases of 27% and 7% from Q3/20 and Q2/21 levels respectively. The increase from Q3/20 was primarily the result of acquired production in Q4/20 and strong drilling results, partially offset by natural field declines. The increase from Q2/21 levels primarily reflects reinstated production volumes from the Pine River Gas Plant, acquisitions, and strong drilling results, partially offset by natural field declines.

    • North America natural gas operating costs in Q3/21 averaged $1.14/Mcf, comparable with Q2/21 levels.

  • As part of the 2021 budget, in the liquids-rich Montney area, the Company targets to utilize facility capacity through its drill-to-fill strategy adding low cost, high value liquids rich natural gas production volumes.

    • At Septimus, production additions from the 5 net well pad completed in June 2021, brought the facility to full capacity of 150 MMcf/d of natural gas and 9,000 bbl/d of liquids. As a result of the strong performance of this pad, the facility is targeted to remain at full capacity into early 2022.

      • Operating costs at Septimus remained strong in Q3/21, averaging $0.25/Mcfe, a decrease of 22% from Q2/21 levels. The decrease in operating costs was primarily the result of the Company's drill to fill strategy and maximizing operational and cost efficiencies in the quarter.

  • Production at Townsend of 284 MMcf/d of natural gas was achieved in Q3/21, an increase of 7% over Q2/21 levels.

    • Due to a recent BC court decision, all development activities at Townsend have been temporarily suspended with 9 wells that are awaiting facilities and pipeline permit approvals. Capital has been redeployed into our deep inventory of natural gas opportunities in northwest Alberta with similar strong drill-to-fill capital efficiencies and production volume profiles.

International Exploration and Production



Three Months Ended

Nine Months Ended


Sep 30
2021


Jun 30
2021


Sep 30
2020


Sep 30
2021


Sep 30
2020
 
Crude oil production (bbl/d)













 
North Sea
16,294

16,458

21,220

17,557

25,186 
Offshore Africa
13,531

16,239

17,537

13,882

16,977 
Natural gas production (MMcf/d)
 

 

 

 

  
North Sea
2

4

5

3

14 
Offshore Africa
8

16

17

11

14 
Net wells targeting crude oil
1.9

1.0

-

4.9

1.0 
Net successful wells drilled
1.9

1.0

-

4.9

1.0 
Success rate
100%

100%

-%

100%

100% 

 

  • International E&P crude oil production volumes averaged 29,825 bbl/d in Q3/21, decreases of 23% and 9% from Q3/20 and Q2/21 levels respectively. The fluctuations in production from prior periods primarily reflects planned maintenance activities and natural field declines.

    • Crude oil operating costs increased from prior periods primarily due to lower production volumes as a result of planned maintenance activities in the North Sea and Offshore Africa. Increased costs from prior periods also reflects the timing of liftings from various fields that have different cost structures in addition to fluctuations in the Canadian dollar.

    • During Q3/21 the Company completed the planned turnaround at the Ninian Central platform in the North Sea. The planned maintenance activities at Espoir in Offshore Africa were completed subsequent to quarter end. Targeted production impacts are included in the Company's annual 2021 budgeted production volume range.

North America Oil Sands Mining and Upgrading



Three Months Ended

Nine Months Ended


Sep 30
2021


Jun 30
2021


Sep 30
2020


Sep 30
2021
 
Sep 30
2020
 
Synthetic crude oil production (bbl/d) (1) (2)
468,126

361,707

350,633

432,876

417,439 

 

(1)SCO production before royalties and excludes production volumes consumed internally as diesel.
(2)Consists of heavy and light synthetic crude oil products.

  • The Company's world class Oil Sands Mining and Upgrading assets averaged strong quarterly production of 468,126 bbl/‍d of SCO in Q3/21, increases of 34% and 29% from Q3/20 and Q2/21 levels respectively and comparable to the record average quarterly production volumes achieved in Q1/21. Strong Q3/21 production performance was due to the Company's focus on continuous improvement, effective and efficient operations as well as planned turnaround activities completed during prior periods.

    • Following recently completed maintenance and turnaround activities across the Oil Sands Mining and Upgrading assets, top tier performance and utilization resulted in industry leading operating costs. During the first nine months of 2021, as a result of the successful completion of the Scotford turnaround and expansion in 2020, the Company has increased sales volumes by over 20,000 bbl/d of SCO.

    • Operating costs from the Company's Oil Sands Mining and Upgrading assets were strong and remain top tier averaging $19.86/bbl (US$15.76/bbl) of SCO during Q3/21, a decrease of 22% from Q2/21 levels. The decrease from Q2/21 was primarily due to strong production volumes, the Company's culture of continuous improvement and planned turnaround activities completed during the prior period.

    • Oil Sands Mining and Upgrading continue to be top tier with production volumes for October 2021 of approximately 477,000 bbl/d of SCO.

MARKETING


Three Months Ended
Nine Months Ended

Sep 30
2021

Jun 30
2021

Sep 30
2020

Sep 30
2021

Sep 30
2020
 
Crude oil and NGLs pricing









WTI benchmark price (US$/bbl) (1)$70.55
$66.06
$40.94
$64.85
$38.30
WCS heavy differential as a percentage of WTI (%) (2)19%
17%
22%
19%
36%
SCO price (US$/bbl)$68.98
$66.49
$38.61
$63.31
$35.11
Condensate benchmark pricing (US$/bbl)$69.22
$66.39
$37.55
$64.58
$35.10
Average realized pricing before risk management (C$/bbl) (3)$68.06
$61.20
$40.14
$60.53
$28.91
Natural gas pricing

 
 
 
 
AECO benchmark price (C$/GJ)$3.36
$2.70
$2.03
$2.95
$1.96
Average realized pricing before risk management (C$/Mcf)$4.13
$3.17
$2.31
$3.59
$2.19 

 

(1)West Texas Intermediate ("WTI").
(2)Western Canadian Select ("WCS").
(3)Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.

  • Crude oil prices continue to improve with WTI averaging US$70.55/‍bbl in Q3/21, increases of 72% and 7% from Q3/20 and Q2/21 levels respectively. The increase in WTI from comparable periods primarily reflects increased demand, the continuation of agreements by OPEC+ to maintain the majority of production cuts implemented in 2020 and the strengthening of the global economy.

    • As at November 2, 2021 for crude oil, annual WTI pricing of US$69.22/bbl is currently 76% higher than 2020 levels and the annual WCS heavy oil differential, currently at approximately a 19% discount to WTI, is in line with average historical levels.

  • Natural gas prices continue to improve with AECO averaging $3.36/GJ in Q3/21, increases of 66% and 24% from Q3/20 and Q2/21 levels respectively. The increase in natural gas prices from the comparable periods primarily reflects lower storage levels and increased NYMEX benchmark pricing.

  • Market egress has improved as Enbridge's Line 3 pipeline replacement began operations on October 1, 2021, increasing incremental transportation throughout the month of October.

    • November 2021 is expected to be the first full month of incremental crude oil transportation of approximately 370,000 bbl/d on Enbridge's Line 3 pipeline, increasing crude oil egress from western Canada.

  • Improved performance at the North West Redwater ("NWR") Refinery continues to increase local demand for heavy crude oil.

  • Construction on the 590,000 bbl/d Trans Mountain Expansion targets an on stream date in early 2023, on which Canadian Natural has committed 94,000 bbl/d.

FINANCIAL REVIEW

The Company continues to implement proven strategies including its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural's adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and related flexible capital expenditure program, all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.

  • The Company's strategy to maintain a diverse portfolio, balanced across various commodity types, averaged quarterly production of 1,237,503 BOE/‍‍d in Q3/21, with approximately 99% of total production located in G7 countries.

  • In Q3/‍21, reflecting the strength of our effective and efficient operations and our high quality, long life low decline asset base, Canadian Natural generated robust quarterly free cash flow of $2,195 million, after dividend payments of $558 million and net capital expenditures of $881 million, excluding acquisitions.

  • Returns to shareholders year to date in 2021 have been significant, as Canadian Natural has returned approximately $3.1 billion by way of dividends and share repurchases up to and including November 3, 2021.

    • Share repurchases for cancellation during Q3/21 per the free cash flow allocation policy, totaled 11,984,400 shares or 1% of common shares outstanding at a weighted average price of $42.26 per share. Share repurchases for cancellation in 2021 up to and including November 3, 2021 total 21,464,400 common shares at a weighted average price of $43.77 per share. 

    • Subsequent to quarter end the Board of Directors has approved a 25% increase to our quarterly dividend to $0.5875 per share, payable on January 5, 2022. The increased dividend clearly demonstrates the confidence that the Board of Directors have in the sustainability of our business model, the strength of our balance sheet and the Company's effective and efficient operations supported by our robust, long life low decline asset base and associated low maintenance capital requirements.

      • With this increase, 2022 will mark the 22nd consecutive year of dividend increases for the Company, and this 25% increase from our previous quarterly dividend is in excess of our historical dividend compound annual growth rate of 20% over the last 22 years.

  • Canadian Natural executed on our commitment to further strengthen our balance sheet with strong financial results in Q3/‍21, reducing net debt by approximately $2.3 billion from Q2/21 levels, while net debt has decreased by approximately $5.8 billion over the last 12 months ended September 30, 2021.

    • On August 16, 2021 the Company repaid the US$500 million 3.45% notes originally due November 15, 2021.

    • During Q3/21 the Company repaid $500 million on its' $2,650 million term credit facility due February 2023.

      • Subsequent to quarter end the Company repaid an additional $1,000 million, which reduced the facility balance to $1,150 million as at November 3, 2021.

  • As at September 30, 2021, the Company had undrawn revolving bank credit facilities of approximately $5.0 billion. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $6.2 billion. At September 30, 2021, the Company did not have any funds drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

  • Effective July 1, 2021 our free cash flow allocation policy authorized management to increase returns to shareholders through accelerated share repurchases under the Company's NCIB by targeting the repurchase of approximately 1% of shares outstanding per quarter. This policy further states that once the Company reaches an absolute debt level of $15 billion, currently targeted to occur in Q4/‍21, 50% of free cash flow will be targeted to share repurchases, with the remaining 50% of free cash flow allocated to further strengthen our balance sheet. Per this policy, the Company repurchased approximately 12 million shares in the quarter and year-to-date as of November 3, 2021 we have repurchased a total of approximately 21.5 million shares for approximately $940 million. Subsequent to quarter end, and as an enhancement to the free cash flow allocation policy, the Board of Directors has authorized management to target absolute debt at levels below $15 billion (approximately 1.0 times debt to EBITDA in the current price environment). To the extent debt is below $15 billion, such amount will be available for strategic growth/acquisition opportunities.

  • During Q3/21, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States, which expire August 2023, replacing the Company's previous base shelf prospectuses which would have expired in August 2021. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE HIGHLIGHTS

Canada and Canadian Natural are well positioned to deliver responsibly produced energy that the world needs through leading ESG performance. Canadian Natural's culture of continuous improvement provides a significant advantage and results in continued improvement in the Company's environmental performance.

2020 Stewardship Report

Canadian Natural published its 2020 Stewardship Report to Stakeholders in August 2021, which is available on the Company's website at https://www.cnrl.com/report-to-stakeholders. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint. Canadian Natural outlined its pathway to lower carbon emissions and its journey to achieve its goal of net zero GHG emissions in the oil sands. Highlights from the Company's 2020 report are as follows:

  • Canadian Natural's corporate GHG emissions intensity continues to improve, decreasing by 18% from 2016 to 2020, a material reduction in emissions intensity.

  • The Company reduced methane emissions in its North American E&P segment by 28% from 2016 to 2020.

  • The Company continues to improve corporate total recordable injury frequency ("TRIF") in 2020, with a TRIF of 0.21 in 2020 compared to 0.50 in 2016. The Company's TRIF is down 58% since 2016, while man-hours have increased over this time period.

  • Canadian Natural is one of the largest owners of Carbon Capture and Storage ("CCS") and sequestration capacity in the oil and natural gas sector globally through projects at Horizon, the Company's 70% owned Quest CCS facility located at Scotford, and its 50% working interest in the NWR Refinery. As part of our comprehensive GHG emissions reduction strategy, our CCS projects include carbon dioxide ("CO2") storage in geological formations, the use of CO2 in enhanced oil recovery techniques and injection of CO2 into tailings. Gross carbon capture capacity through these projects combined is approximately 2.7 million tonnes of CO2 annually, equivalent to taking approximately 576,000 cars off the road per year.

  • The Quest Carbon Capture, Utilization and Storage ("CCUS") (70% Company ownership) facility captures and stores approximately 1.1 million tonnes of CO2 per year, the equivalent of removing approximately 235,000 cars off the road annually. In May 2020 Quest reached the milestone of 5 million tonnes of stored carbon dioxide, equal to the emissions from approximately 1.25 million cars.

    • At Horizon, annual capture capacity is approximately 0.4 million tonnes of CO2 from the hydrogen plant, the equivalent of removing approximately 85,000 cars off the road annually.

    • At the NWR Refinery, captured CO2 is delivered to the Alberta Carbon Truck Line for enhanced oil recovery and permanent storage in central Alberta. At full capacity, approximately 1.2 million tonnes of CO2 per year is targeted to be captured, the equivalent of removing approximately 256,000 cars off the road annually.

  • The Company continues to increase the level of third party verified direct GHG emissions and indirect energy use.

    • The Company targets to increase the total corporate level of third party verification of GHG emissions to 95% in 2021, an increase of 9% from 2020 levels of 87%.

  • In 2020 the Company planted its one millionth tree at AOSP and its one and a half millionth tree at Horizon, reclaiming land and contributing to increased carbon capture.

Oil Sands Pathway to Net Zero Initiative

On June 9, 2021 Canadian Natural together with oil sands industry participants formally announced the Oil Sands Pathways to Net Zero initiative. Canadian Natural and these companies operate approximately 90% of Canada's oil sands production. The goal of this unique alliance, working collectively with the federal and Alberta governments, is to achieve net zero GHG emissions from oil sands operations by 2050 to help Canada meet its climate goals, including its Paris Agreement commitments and 2050 net zero aspirations.

  • This collaborative effort follows welcome announcements from the Government of Canada and the Government of Alberta of important support programs for emissions-reduction projects and infrastructure. Collaboration between industry and government will be critical to progressing the Oil Sands Pathways to Net Zero vision and achieving Canada's climate goals.

  • The Pathways vision is anchored by a major CCUS trunkline connected to a carbon sequestration hub to enable multi-sector 'tie-in' projects for expanded emissions reductions. The proposed CCUS system will involve significant collaboration between industry and government, which is similar to the Longship/Northern Lights project in Norway as well as other CCUS projects in the Netherlands, UK and USA.

  • The Pathways initiative is ambitious and will require significant investment on the part of both industry and government to advance the research and development of new and emerging technologies.

  • The companies involved look forward to continuing to work with governments and to engage with Indigenous and local communities in northern Alberta, to make this ambitious, major emissions-reduction vision a reality so those communities can continue to benefit from Canadian resource development.

Government Support for Carbon Capture, Utilization and Storage

The Government of Canada has recognized the important role of carbon capture, utilization and storage projects for the oil sands sector to continue contributing to Canada's economic growth while working towards climate objectives. Canadian Natural is a leader in CCUS and GHG reduction projects and sees many opportunities for industry to advance investments in CCUS projects. Details of the proposed government programs to support CCUS are important and the Company looks forward to continuing to provide input as government finalizes its plans.

ENVIRONMENTAL TARGETS

  • As previously announced in August 2021, Canadian Natural has committed to new environmental targets as follows:

    • 50% reduction in North America E&P, including thermal in situ, methane emissions by 2030, from a 2016 baseline.

    • 40% reduction in thermal in situ fresh water usage intensity by 2026, from a 2017 baseline.

    • 40% reduction in mining fresh river water usage intensity by 2026, from a 2017 baseline.

  • In 2018, Canadian Natural was one of the first oil companies to announce an aspirational goal of achieving net zero emissions in its oil sands operations.

  • Through the Company's participation in the Oil Sands Pathways to Net Zero Initiative with our industry partners and collaboration with the federal and Alberta governments, the Company is further refining its goal by targeting to achieve net zero emissions in its oil sands operations by 2050.

  • The Company is currently working through the details with members of the net zero initiative alliance to advance key milestones to be achieved over the next decade as we accelerate related projects through the Pathways initiative.

ADVISORY

Special Note Regarding Forward-Looking Statements

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses, and other targets provided throughout this press release and the Company's Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Oil Sands Pathway to Net Zero Initiative, the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, the North West Redwater bitumen upgrader and refinery, construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market, the development and deployment of technology and technological innovations, and the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.

In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of effects of the novel coronavirus ("COVID-19") pandemic and the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+")) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil and natural gas and NGLs prices including due to actions of OPEC+ taken in response to COVID-19 or otherwise; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities (including production curtailments mandated by the Government of Alberta); government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses.

The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this press release or the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this press release or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.

Special Note Regarding non-GAAP Financial Measures

This press release includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings (loss) from operations, adjusted funds flow and net capital expenditures. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP financial measures. The non-GAAP financial measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP financial measures to evaluate its performance. The non-GAAP financial measures should not be considered an alternative to or more meaningful than net earnings (loss), cash flows from operating activities, and cash flows used in investing activities as determined in accordance with IFRS, as an indication of the Company's performance. The non-GAAP financial measure adjusted net earnings (loss) from operations is reconciled to net earnings (loss), as determined in accordance with IFRS, in the "Financial Highlights" section of this press release and the Company's MD&A. Additionally, the non-GAAP financial measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the "Financial Highlights" section of the Company's MD&A. The non-GAAP financial measure net capital expenditures is reconciled to cash flows used in investing activities, as determined in accordance with IFRS, in the "Net Capital Expenditures" section of the Company's MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the "Liquidity and Capital Resources" section of the Company's MD&A.

Adjusted net earnings (loss) from operations is a non-GAAP financial measure that represents net earnings (loss), as determined in accordance with IFRS, as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for the after-tax effects of certain items of a non-operational nature. The Company considers adjusted net earnings (loss) from operations a key measure in evaluating its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. Adjusted net earnings (loss) from operations may not be comparable to similar measures presented by other companies.

Adjusted funds flow is a non-GAAP financial measure that represents cash flows from (used in) operating activities, as determined in accordance with IFRS, as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to North West Redwater Partnership ("NWRP"), and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Adjusted funds flow may not be comparable to similar measures presented by other companies.

Net capital expenditures is a non-GAAP financial measure, as determined in accordance with IFRS, that represents cash flows used in investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, the repayment of NWRP subordinated debt advances, abandonment expenditures including the impact of government grant income under the provincial well-site rehabilitation programs, and the settlement of long-term debt assumed in acquisitions. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. Net capital expenditures may not be comparable to similar measures presented by other companies.

Free cash flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders, and to repay debt.

Adjusted EBITDA is a non-GAAP financial measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for interest, taxes, depletion, depreciation and amortization, stock based compensation expense (recovery), unrealized risk management gains (losses), unrealized foreign exchange gains (losses), and accretion of the Company's asset retirement obligation. The Company considers adjusted EBITDA a key measure in evaluating its operating profitability by excluding non-cash items.

Debt to adjusted EBITDA is a non-GAAP ratio that is derived as the current and long-term portions of long-term debt, divided by the 12 month trailing Adjusted EBITDA, as defined above. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.

Special Note Regarding Currency, Financial Information and Production

This press release should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2021 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2020. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2021 and the Company's MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout the Company's MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2020, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A.

CONFERENCE CALL

Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2021 Third Quarter Earnings Results on Thursday, November 4, 2021 before market open.

A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, November 4, 2021.

The conference call will also be webcast and can be accessed on the home page our website, www.cnrl.com.

The North American conference call number is 833-670-0711 and the international conference call number is 001-236-714-2926. You will also be required to enter the following passcode 5782073 for the call. When prompted, please record your name and company name.

An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, November 18, 2021. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 5782073.

Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.

CANADIAN NATURAL RESOURCES LIMITED
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8
Phone: 403-514-7777 Email: ir@cnrl.com
www.cnrl.com

TIM S. MCKAY
President

MARK A. STAINTHORPE
Chief Financial Officer and Senior Vice-President, Finance

JASON M. POPKO
Manager, Investor Relations

Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/101987

News Provided by Newsfile via QuoteMedia

Imperial declares first quarter 2023 dividend

Imperial Oil Limited (TSE: IMO, NYSE American: IMO) today declared a quarterly dividend of 44 cents per share on the outstanding common shares of the company, payable on April 1, 2023, to shareholders of record at the close of business on March 3, 2023.

This first quarter 2023 dividend compares with the fourth quarter 2022 dividend of 44 cents per share.

News Provided by Business Wire via QuoteMedia

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Imperial announces fourth quarter 2022 financial and operating results

  • Quarterly net income of $1,727 million and cash flow from operating activities of $2,797 million
  • Upstream production of 441,000 gross oil-equivalent barrels per day during fourth quarter, driven by continued strength at Kearl and Cold Lake, and higher production at Syncrude
  • Maintained strong refining capacity utilization, achieving best ever quarterly utilization of 101 percent
  • Returned more than $2.1 billion to shareholders in the fourth quarter, including successful completion of substantial issuer bid
  • Declared first quarter dividend of 44 cents per share
  • Approved $720 million project to construct largest renewable diesel facility in Canada
  • Announcing company-wide goal to achieve net zero (Scope 1 and 2) by 2050 in operated assets

Imperial (TSE: IMO) (NYSE American: IMO) :

Imperial reported estimated net income in the fourth quarter of $1,727 million and cash flow from operating activities of $2,797 million, compared to net income of $2,031 million and cash flow from operating activities of $3,089 million in the third quarter of 2022. Fourth quarter results reflected strong operating performance across all business segments and robust diesel crack spreads, which were offset by lower upstream realizations. Full-year estimated net income was $7,340 million with cash flow from operating activities of $10,482 million.

"Our financial results this past year are the strongest in company history, driven by record operating performance across our assets," said Brad Corson, chairman, president and chief executive officer. "Throughout 2022 our operations remained focused on ensuring a stable supply of energy products to Canadian and global markets, supporting continued economic growth and capturing significant value for our shareholders."

Upstream production in the fourth quarter averaged 441,000 gross oil-equivalent barrels per day, bringing full-year production to 416,000 gross oil-equivalent barrels per day. At Kearl, quarterly total gross production averaged 284,000 barrels per day, in-line with the asset's previous record quarterly production set in the fourth quarter of 2020. Kearl's second half production was the highest in the asset's history, fully recovering from early 2022 cold weather impacts, bringing full-year production to 242,000 total gross barrels per day. At Cold Lake, quarterly gross production averaged 141,000 barrels per day with annual production of 144,000 barrels per day, the highest full-year production since 2018. At Syncrude, quarterly production increased to 87,000 gross barrels per day following the completion of its planned turnaround in the third quarter of 2022, with full-year production of 77,000 barrels per day representing the highest annual production in Syncrude history.

In the Downstream, throughput in the fourth quarter averaged 433,000 barrels per day with capacity utilization of 101 percent, the highest quarterly utilization in company history, as Imperial continues to maximize production to meet Canadian demand. Full-year throughput averaged 418,000 barrels per day with capacity utilization of 98 percent, the highest full-year utilization in company history. Fourth quarter petroleum product sales averaged 487,000 barrels per day, with annual petroleum product sales averaging 475,000 barrels per day.

During the quarter, Imperial returned $2,145 million to shareholders, through dividend payments, accelerated completion of the company's annual normal course issuer bid program and successful completion of the company's $1.5 billion substantial issuer bid program in December. Throughout 2022, the company returned over $7 billion to its shareholders. "Imperial continued delivering on its long-standing commitment by returning record cash to shareholders in 2022 through our reliable and growing dividend and industry-leading share repurchase programs," said Corson.

In January, Imperial announced it will further help Canada achieve its net zero goals by approving a $720 million renewable diesel project located at the company's Strathcona Refinery near Edmonton. The project will be the largest of its kind in Canada, designed to produce more than one billion litres of renewable diesel annually primarily from locally sourced feedstocks and could help reduce greenhouse gas emissions by about 3 million metric tons per year, as determined in accordance with Canada's Clean Fuel Regulations. Site preparation and initial construction work is underway with renewable diesel production expected to start in early 2025, subject to regulatory approvals.

As part of the company's efforts to provide solutions that lower the greenhouse gas emissions intensity of our operations and provide lower life-cycle emissions products to our customers, Imperial is implementing a company-wide goal to achieve net zero emissions (Scope 1 and 2) by 2050 in its operated assets through collaboration with government and industry partners. Successful technology development and supportive fiscal and regulatory frameworks will be needed to achieve this goal. This work builds on Imperial's previously announced net-zero goal for operated oil sands as part of the Pathways Alliance initiative, as well as the company's 2030 emission intensity reduction goal for operated oil sands. The company plans to achieve its net zero goal by applying oil sands recovery technologies that use less steam, implementing carbon capture and storage and implementing efficiency projects including the use of lower carbon fuels at its operations.

"We continue to make progress on advancing lower-carbon solutions that support our journey to net zero, including our strategic growth investment in the Strathcona Renewable Diesel project," said Corson. "This project will create jobs for the local economy, help our customers reduce their emissions and further enhance Imperial's low-carbon product offering."

Fourth quarter highlights

  • Net income of $1,727 million or $2.86 per share on a diluted basis, up from $813 million or $1.18 per share in the fourth quarter of 2021.
  • Cash flows from operating activities of $2,797 million, up from $1,632 million in the same period of 2021. Cash flows from operating activities excluding working capital 1 of $2,452 million, up from $1,648 million in the same period of 2021.
  • Capital and exploration expenditures totaled $488 million, up from $441 million in the fourth quarter of 2021.
  • The company returned $2,145 million to shareholders in the fourth quarter of 2022, including $211 million in dividends paid and $1,934 million in share repurchases, through its normal course issuer bid and completion of the $1,500 million substantial issuer bid program in December.
  • Production averaged 441,000 gross oil-equivalent barrels per day, compared to 445,000 gross oil-equivalent barrels per day in the same period of 2021. Adjusting for the sale of XTO Energy Canada, which closed in the third quarter of 2022, production increased by 11,000 gross oil-equivalent barrels per day compared to the same period in 2021.
  • Total gross bitumen production at Kearl averaged 284,000 barrels per day (201,000 barrels Imperial's share), in-line with the asset's previous record quarterly production set in the fourth quarter of 2020 and up from 270,000 barrels per day (191,000 barrels Imperial's share) in the fourth quarter of 2021.
  • Gross bitumen production at Cold Lake averaged 141,000 barrels per day, compared to 142,000 barrels per day in the fourth quarter of 2021.
  • The company's share of gross production from Syncrude averaged 87,000 barrels per day, up from 79,000 barrels per day in the fourth quarter of 2021.
  • Refinery throughput averaged 433,000 barrels per day, up from 416,000 barrels per day in the fourth quarter of 2021. Capacity utilization reached 101 percent, the highest quarterly utilization in company history, up from 97 percent in the fourth quarter of 2021, as the company continues to maximize production to meet Canadian demand.
  • Petroleum product sales were 487,000 barrels per day, compared to 496,000 barrels per day in the fourth quarter of 2021.
  • Chemical net income of $41 million in the quarter, compared to $64 million in the fourth quarter of 2021. Lower income was primarily driven by lower polyethylene margins.
  • Approved $720 million project to construct largest renewable diesel facility in Canada. The project, located at Imperial's Strathcona Refinery near Edmonton, is designed to produce more than one billion litres of renewable diesel annually, primarily from locally sourced feedstocks and could help reduce greenhouse gas emissions by about 3 million metric tonnes per year, as determined in accordance with Canada's Clean Fuel Regulations. Site preparation and initial construction work is underway with renewable diesel production expected to start in early 2025, subject to regulatory approvals.
  • Announcing company-wide goal to achieve net zero (Scope 1 and 2) by 2050 in operated assets, through collaboration with government and industry partners. This builds on Imperial's previously announced net zero goal for operated oil sands as part of the Pathways Alliance initiative, as well as the company's 2030 emission intensity reduction goal for its operated oil sands.
  • The Pathways Alliance entered into a Carbon Sequestration Evaluation Agreement with the Government of Alberta, enabling the Alliance to immediately start a detailed evaluation of its proposed geological storage hub, which would be one of the world's largest carbon capture and storage projects.

____________________
1
non-GAAP financial measure - see attachment VI for definition and reconciliation

Recent business environment

During the COVID-19 pandemic, industry investment to maintain and increase production capacity was restrained to preserve capital, resulting in underinvestment and supply tightness as demand for petroleum and petrochemical products recovered. Across late 2021 and the first half of 2022, this dynamic, along with supply chain constraints, and a continuation of demand recovery, led to a steady increase in oil and natural gas prices and refining margins.

Demand for petroleum and petrochemical products has grown in 2022, with the company's financial results benefiting from stronger prices and margins. Commodity and product prices are expected to remain volatile given the current global economic uncertainty and geopolitical events affecting supply and demand.

The general rate of inflation in Canada and many other countries experienced a brief decline in the initial stage of the COVID-19 pandemic, before starting to increase steadily in 2021 due to imbalanced recoveries between supply and demand in the global economy. The underlying factors include, but are not limited to, supply chain disruptions, shipping bottlenecks, labour constraints, and side effects from monetary and fiscal expansions. Prices for services and materials continue to respond to the fast changing dynamics involving economic growth, overall inflation, commodity markets, and industry activities. The company closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments through efficient project management practices, and general productivity improvements.

Operating results
Fourth quarter 2022 vs. fourth quarter 2021

Fourth Quarter

millions of Canadian dollars, unless noted

2022

2021

Net income (loss) (U.S. GAAP)

1,727

813

Net income (loss) per common share, assuming dilution (dollars)

2.86

1.18

Upstream
Net income (loss) factor analysis
millions of Canadian dollars

2021

Price

Volumes

Royalty

Other

2022

545

(160)

40

(50)

156

531

Price – Lower bitumen realizations were primarily driven by the widening WTI/WCS spread. Average bitumen realizations decreased by $5.68 per barrel generally in line with WCS, and synthetic crude oil realizations increased by $22.68 per barrel.

Volumes – Higher volumes were the result of improved plant performance at Kearl and lower unplanned downtime at Syncrude, partially offset by the absence of XTO Energy Canada production following the divestment in the third quarter of 2022.

Royalty – Higher royalties primarily driven by improved commodity prices.

Other – Favourable foreign exchange impacts of about $160 million, partially offset by higher operating expenses of about $70 million, resulting primarily from higher energy prices.

Marker prices and average realizations

Fourth Quarter

Canadian dollars, unless noted

2022

2021

West Texas Intermediate (US$ per barrel)

82.58

77.04

Western Canada Select (US$ per barrel)

57.00

62.49

WTI/WCS Spread (US$ per barrel)

25.58

14.55

Bitumen (per barrel)

59.85

65.53

Synthetic crude oil (per barrel)

115.22

92.54

Average foreign exchange rate (US$)

0.74

0.79

Production

Fourth Quarter

thousands of barrels per day

2022

2021

Kearl (Imperial's share)

201

191

Cold Lake

141

142

Syncrude (a)

87

79

Kearl total gross production (thousands of barrels per day)

284

270

(a) In the fourth quarter of 2022, Syncrude gross production included about 2 thousand barrels per day of bitumen and other products (2021 - 3 thousand barrels per day) that were exported to the operator's facilities using an existing interconnect pipeline.

Higher production at Kearl was primarily driven by improved plant performance and the absence of extreme cold weather in December 2021.

Downstream
Net income (loss) factor analysis
millions of Canadian dollars

2021

Margins

Other

2022

250

720

218

1,188

Margins – Higher margins primarily reflect improved market conditions.

Other – Improved volumes of about $60 million, favourable foreign exchange impacts of about $60 million, absence of the prior year unfavourable out-of-period inventory adjustment of $60 million, partially offset by higher operating expenses of about $50 million.

Refinery utilization and petroleum product sales

Fourth Quarter

thousands of barrels per day, unless noted

2022

2021

Refinery throughput

433

416

Refinery capacity utilization (percent)

101

97

Petroleum product sales

487

496

Improved refinery throughput in the fourth quarter of 2022 was primarily driven by economic optimization across the downstream supply chain.

Chemicals
Net income (loss) factor analysis
millions of Canadian dollars

2021

Margins

Other

2022

64

(20)

(3)

41

Corporate and other

Fourth Quarter

millions of Canadian dollars

2022

2021

Net income (loss) (U.S. GAAP)

(33

)

(46

)

Liquidity and capital resources

Fourth Quarter

millions of Canadian dollars

2022

2021

Cash flow generated from (used in):

Operating activities

2,797

1,632

Investing activities

(473

)

(399

)

Financing activities

(2,151

)

(955

)

Increase (decrease) in cash and cash equivalents

173

278

Cash and cash equivalents at period end

3,749

2,153

Cash flow generated from operating activities primarily reflects higher Upstream realizations, improved Downstream margins, and favourable working capital impacts.

Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment.

Cash flow used in financing activities primarily reflects:

Fourth Quarter

millions of Canadian dollars, unless noted

2022

2021

Dividends paid

211

188

Per share dividend paid (dollars)

0.34

0.27

Share repurchases (a)

1,934

761

Number of shares purchased (millions) (a)

27.3

17.5

(a) Share repurchases were made under the company's normal course issuer bid program, and substantial issuer bid that commenced on November 4, 2022 and expired on December 9, 2022. Includes shares purchased from Exxon Mobil Corporation concurrent with, but outside of the normal course issuer bid, and by way of a proportionate tender under the company's substantial issuer bid.

The company completed share repurchases under its normal course issuer bid on October 21, 2022.

On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $1.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $72.50 per share, for an aggregate purchase of $1.5 billion and 3.4 percent of Imperial's issued and outstanding shares at the close of business on

October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent.

Full-year 2022 vs. full-year 2021

Twelve Months

millions of Canadian dollars, unless noted

2022

2021

Net income (loss) (U.S. GAAP)

7,340

2,479

Net income (loss) per common share, assuming dilution (dollars)

11.44

3.48

Net income (loss) excluding identified items 1

7,132

2,479

Current year results include favourable identified items 1 of $208 million related to the company's gain on the sale of interests in XTO Energy Canada.

Upstream
Net income (loss) factor analysis
millions of Canadian dollars

2021

Price

Volumes

Royalty

Identified

Items¹

Other

2022

1,395

3,140

(80)

(970)

208

(48)

3,645

Price – Higher realizations were generally in line with increases in marker prices, driven primarily by increased demand. Average bitumen realizations increased by $26.76 per barrel generally in line with WCS, and synthetic crude oil realizations increased by $43.85 per barrel.

Volumes – Lower volumes were primarily the result of downtime at Kearl in the first half of the year, partly offset by higher production at Syncrude and Cold Lake.

Royalty – Higher royalties primarily driven by improved commodity prices.

Identified Items 1 – Current year results include favourable identified items 1 related to the company's gain on the sale of interests in XTO Energy Canada.

Other – Higher operating expenses of about $500 million, primarily from higher energy prices, partially offset by favourable foreign exchange impacts of about $270 million, and higher electricity sales at Cold Lake of about $60 million due to increased prices.

Marker prices and average realizations

Twelve Months

Canadian dollars, unless noted

2022

2021

West Texas Intermediate (US$ per barrel)

94.36

68.05

Western Canada Select (US$ per barrel)

76.28

54.96

WTI/WCS Spread (US$ per barrel)

18.08

13.09

Bitumen (per barrel)

84.67

57.91

Synthetic crude oil (per barrel)

125.46

81.61

Average foreign exchange rate (US$)

0.77

0.80

____________________
1
non-GAAP financial measure - see Attachment VI for definition and reconciliation

Production

Twelve Months

thousands of barrels per day

2022

2021

Kearl (Imperial's share)

172

186

Cold Lake

144

140

Syncrude (a)

77

71

Kearl total gross production (thousands of barrels per day)

242

263

(a) In 2022, Syncrude gross production included about 3 thousand barrels per day of bitumen and other products (2021 - 1 thousand barrels per day) that were exported to the operator's facilities using an existing interconnect pipeline.

Lower production at Kearl was primarily a result of downtime in the first half of the year.

Downstream
Net income (loss) factor analysis
millions of Canadian dollars

2021

Margins

Other

2022

895

2,350

377

3,622

Margins – Higher margins primarily reflect improved market conditions.

Other – Lower turnaround impacts of about $140 million, reflecting the absence of turnaround activities at Strathcona refinery, improved volumes of about $130 million, favourable foreign exchange impacts of about $120 million, absence of the prior year unfavourable out-of-period inventory adjustment of $74 million, partially offset by higher operating expenses of about $190 million.

Refinery utilization and petroleum product sales

Twelve Months

thousands of barrels per day, unless noted

2022

2021

Refinery throughput

418

379

Refinery capacity utilization (percent)

98

89

Petroleum product sales

475

456

Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity.

Improved petroleum product sales in 2022 primarily reflects increased demand.

Chemicals
Net income (loss) factor analysis
millions of Canadian dollars

2021

Margins

Other

2022

361

(110)

(47)

204

Margins – Lower margins primarily reflect weaker industry polyethylene margins.

Corporate and other

Twelve Months

millions of Canadian dollars

2022

2021

Net income (loss) (U.S. GAAP)

(131

)

(172

)

Liquidity and capital resources

Twelve Months

millions of Canadian dollars

2022

2021

Cash flow generated from (used in):

Operating activities

10,482

5,476

Investing activities

(618

)

(1,012

)

Financing activities

(8,268

)

(3,082

)

Increase (decrease) in cash and cash equivalents

1,596

1,382

Cash flow generated from operating activities primarily reflects higher Upstream realizations, improved Downstream margins, and favourable working capital impacts.

Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment, which were partially offset by proceeds from the sale of interests in XTO Energy Canada.

Cash flow used in financing activities primarily reflects:

Twelve Months

millions of Canadian dollars, unless noted

2022

2021

Dividends paid

851

706

Per share dividend paid (dollars)

1.29

0.98

Share repurchases (a)

6,395

2,245

Number of shares purchased (millions) (a)

93.9

56.0

(a) Share repurchases were made under the company's normal course issuer bid program, and substantial issuer bids that commenced on May 6, 2022 and November 4, 2022, and expired on June 10, 2022 and December 9, 2022, respectively. Includes shares purchased from Exxon Mobil Corporation concurrent with, but outside of, the normal course issuer bid, and by way of a proportionate tender under the company's substantial issuer bids.

On June 27, 2022, the company announced that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its then existing share repurchase program. The program enabled the company to purchase up to a maximum of 31,833,809 common shares during the period

June 29, 2022 to June 28, 2023. The program completed on October 21, 2022 as a result of the company purchasing the maximum allowable number of shares under the program.

On May 6, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $2.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on June 15, 2022, with the company taking up and paying for 32,467,532 common shares at a price of $77.00 per share, for an aggregate purchase of $2.5 billion and 4.9 percent of Imperial's issued and outstanding shares at the close of business on May 2, 2022. This included 22,597,379 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent.

On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $1.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $72.50 per share, for an aggregate purchase of $1.5 billion and 3.4 percent of Imperial's issued and outstanding shares at the close of business on

October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent.

During the third quarter of 2022, the company decreased its long-term debt by $1 billion by partially repaying an existing facility with an affiliated company of ExxonMobil.

Key financial and operating data follow.

Forward-looking statements

Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Forward-looking statements can be identified by words such as believe, anticipate, intend, propose, plan, goal, seek, project, predict, target, estimate, expect, strategy, outlook, schedule, future, continue, likely, may, should, will and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to continuing to maximize production to meet Canadian fuel demand; the company's planned renewable diesel complex at Strathcona, including project cost, production estimates, expected sources of feedstock, projections regarding expected reductions in greenhouse gas emissions in comparison to conventional fuels, expected start up in early 2025, and timing of regulatory approvals; the ability for the renewable diesel project to create jobs, help customers reduce emissions and enhance the company's low carbon product offering; continuing to advance lower-carbon solutions supporting the company's journey to net zero; the company's ongoing efforts to provide solutions that lower the greenhouse gas emissions intensity of operations and provide lower life-cycle emissions products to customers; the company-wide goal to achieve net zero emissions (Scope 1 and 2) by 2050 in its operated assets through collaboration with government and industry partners; the company's 2030 emission intensity reduction goal for operated oil sands assets; the impact and ability to apply recovery technologies, carbon capture and storage, and efficiency projects including the use of lower carbon fuels at its operations to achieve lower emissions goals; evaluation of the Pathways Alliance proposed geological storage hub, including the carbon sequestration evaluation agreement with the Government of Alberta; the expectation of commodity and product price volatility; and the continued evolution of inflation and prices for services and materials, its impact on operating and capital cost, and the company's ability to mitigate these costs.

Forward-looking statements are based on the company's current expectations, estimates, projections and assumptions at the time the statements are made. Actual future financial and operating results, including expectations and assumptions concerning demand growth and energy source, supply and mix; production rates, growth and mix across various assets; project plans, timing, costs, technical evaluations and capacities and the company's ability to effectively execute on these plans and operate its assets, including its investment in the renewable diesel complex at Strathcona; the adoption and impact of new facilities or technologies on reductions to GHG emissions intensity, including but not limited to Strathcona renewable diesel, carbon capture and storage including in connection with hydrogen for the renewable diesel project, recovery technologies and efficiency projects and any changes in the scope, terms, or costs of such projects; for renewable diesel, the availability and cost of locally-sourced and grown feedstock and the supply of renewable diesel to British Columbia in connection with its low-carbon fuel legislation; the amount and timing of emissions reductions, including the impact of lower carbon fuels; that any required support from policymakers and other stakeholders for various new technologies such as carbon capture and storage will be provided; performance of third party service providers; receipt of regulatory approvals in a timely manner; refinery utilization; applicable laws and government policies, including with respect to climate change, GHG emissions reductions and low carbon fuels; the ability to offset any ongoing inflationary pressures; capital allocation including shareholder returns, and capital and environmental expenditures; progression of COVID-19 and its impacts on Imperial's ability to operate its assets; and commodity prices, foreign exchange rates and general market conditions could differ materially depending on a number of factors.

These factors include global, regional or local changes in supply and demand for oil, natural gas, and petroleum and petrochemical products and resulting price, differential and margin impacts, including foreign government action with respect to supply levels and prices, the impact of COVID-19 on demand and the occurrence of wars; availability and allocation of capital; the receipt, in a timely manner, of regulatory and third-party approvals, including for new technologies that will help the company meet its lower emissions goals; the results of research programs and new technologies, the ability to bring new technologies to commercial scale on a cost-competitive basis, and the competitiveness of alternative energy and other emission reduction technologies; failure or delay of supportive policy and market development for the adoption of emerging lower emission energy technologies and other technologies that support emissions reductions; political or regulatory events, including changes in law or government policy, environmental regulation including climate change and greenhouse gas regulation, and actions in response to COVID-19; unanticipated technical or operational difficulties; project management and schedules and timely completion of projects; availability and performance of third-party service providers, including in light of restrictions related to COVID-19; environmental risks inherent in oil and gas exploration and production activities; management effectiveness and disaster response preparedness, including business continuity plans in response to COVID-19; operational hazards and risks; cybersecurity incidents, including increased reliance on remote working arrangements; currency exchange rates; general economic conditions; and other factors discussed in Item 1A risk factors and Item 7 management's discussion and analysis of financial condition and results of operations of Imperial Oil Limited's most recent annual report on Form 10-K and subsequent interim reports.

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial Oil Limited. Imperial's actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law.

In this release all dollar amounts are expressed in Canadian dollars unless otherwise stated. This release should be read in conjunction with Imperial's most recent Form 10-K. Note that numbers may not add due to rounding.

The term "project" as used in this release can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

Imperial's company-wide net-zero goal (Scope 1 and 2) by 2050 is backed by a comprehensive approach centered on detailed emission-reduction roadmaps for its major operated assets. Roadmaps may be updated as needed to reflect technology, policy and other developments, including the development and acquisition of major operated assets. Actions needed to advance the company's 2030 greenhouse gas emissions intensity reductions plans are incorporated into its medium-term business plans, which are updated annually. The reference case for planning beyond 2030 is based on the ExxonMobil's Energy Outlook research and publication, which contains demand and supply projections based on assessment of current trends in technology, government policies, consumer preferences, geopolitics, and economic development. Reflective of the existing global policy environment, the Energy Outlook does not project the degree of required future policy and technology advancement and deployment for the world, or Imperial, to meet net-zero goals by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the company's business plans will be updated accordingly.

Individual projects or opportunities may advance based on a number of factors, including availability of supportive policy, technology for cost-effective abatement, company planning process, and alignment with our partners and other stakeholders. The company's plans to reduce emissions are good-faith efforts based on current relevant data and methodology, which could be changed or refined.

Attachment I

Fourth Quarter

Twelve Months

millions of Canadian dollars, unless noted

2022

2021

2022

2021

Net Income (loss) (U.S. GAAP)

Total revenues and other income

14,453

12,312

59,670

37,590

Total expenses

12,174

11,201

50,186

34,307

Income (loss) before income taxes

2,279

1,111

9,484

3,283

Income taxes

552

298

2,144

804

Net income (loss)

1,727

813

7,340

2,479

Net income (loss) per common share (dollars)

2.87

1.18

11.47

3.48

Net income (loss) per common share - assuming dilution (dollars)

2.86

1.18

11.44

3.48

Other Financial Data

Gain (loss) on asset sales, after tax

9

241

43

Total assets at December 31

43,524

40,782

Total debt at December 31

4,155

5,176

Shareholders' equity at December 31

22,413

21,735

Capital employed at December 31

26,593

26,931

Dividends declared on common stock

Total

266

185

932

729

Per common share (dollars)

0.44

0.27

1.46

1.03

Millions of common shares outstanding

At December 31

584.2

678.1

Average - assuming dilution

603.0

689.5

641.5

713.2

Attachment II

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

Total cash and cash equivalents at period end

3,749

2,153

3,749

2,153

Operating Activities

Net income (loss)

1,727

813

7,340

2,479

Adjustments for non-cash items:

Depreciation and depletion

465

545

1,897

1,977

(Gain) loss on asset sales

(3

)

(10

)

(158

)

(49

)

Deferred income taxes and other

281

75

(77

)

91

Changes in operating assets and liabilities

345

(16

)

1,485

363

All other items - net

(18

)

225

(5

)

615

Cash flows from (used in) operating activities

2,797

1,632

10,482

5,476

Investing Activities

Additions to property, plant and equipment

(492

)

(424

)

(1,526

)

(1,108

)

Proceeds from asset sales

18

24

904

81

Additional investments

(6

)

Loans to equity companies - net

1

1

10

15

Cash flows from (used in) investing activities

(473

)

(399

)

(618

)

(1,012

)

Cash flows from (used in) financing activities

(2,151

)

(955

)

(8,268

)

(3,082

)

Attachment III

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

Net income (loss) (U.S. GAAP)

Upstream

531

545

3,645

1,395

Downstream

1,188

250

3,622

895

Chemical

41

64

204

361

Corporate and other

(33

)

(46

)

(131

)

(172

)

Net income (loss)

1,727

813

7,340

2,479

Revenues and other income

Upstream

4,332

4,252

19,764

15,831

Downstream

15,919

14,453

64,985

34,786

Chemical

422

449

1,976

1,758

Eliminations / Corporate and other

(6,220

)

(6,842

)

(27,055

)

(14,785

)

Revenues and other income

14,453

12,312

59,670

37,590

Purchases of crude oil and products

Upstream

1,787

1,712

7,971

7,492

Downstream

13,110

12,980

55,569

29,505

Chemical

260

273

1,330

966

Eliminations

(6,264

)

(6,843

)

(27,128

)

(14,789

)

Purchases of crude oil and products

8,893

8,122

37,742

23,174

Production and manufacturing

Upstream

1,438

1,266

5,491

4,661

Downstream

447

406

1,640

1,445

Chemical

80

65

273

210

Eliminations

Production and manufacturing

1,965

1,737

7,404

6,316

Selling and general

Upstream

Downstream

179

156

653

572

Chemical

23

22

85

90

Eliminations / Corporate and other

55

37

144

122

Selling and general

257

215

882

784

Capital and exploration expenditures

Upstream

364

266

1,128

632

Downstream

94

168

295

476

Chemical

5

2

10

8

Corporate and other

25

5

57

24

Capital and exploration expenditures

488

441

1,490

1,140

Exploration expenses charged to Upstream income included above

1

26

5

32

Attachment IV

Operating statistics

Fourth Quarter

Twelve Months

2022

2021

2022

2021

Gross crude oil and natural gas liquids (NGL) production

(thousands of barrels per day)

Kearl

201

191

172

186

Cold Lake

141

142

144

140

Syncrude (a)

87

79

77

71

Conventional

6

11

8

10

Total crude oil production

435

423

401

407

NGLs available for sale

2

1

1

Total crude oil and NGL production

435

425

402

408

Gross natural gas production (millions of cubic feet per day)

37

121

85

120

Gross oil-equivalent production (b)

441

445

416

428

(thousands of oil-equivalent barrels per day)

Net crude oil and NGL production (thousands of barrels per day)

Kearl

184

179

157

178

Cold Lake

105

119

106

114

Syncrude (a)

77

68

63

62

Conventional

6

11

8

9

Total crude oil production

372

377

334

363

NGLs available for sale

1

1

1

Total crude oil and NGL production

372

378

335

364

Net natural gas production (millions of cubic feet per day)

37

112

83

115

Net oil-equivalent production (b)

378

397

349

383

(thousands of oil-equivalent barrels per day)

Kearl blend sales (thousands of barrels per day)

277

272

236

264

Cold Lake blend sales (thousands of barrels per day)

186

189

188

187

NGL sales (thousands of barrels per day) (c)

1

Average realizations (Canadian dollars)

Bitumen (per barrel)

59.85

65.53

84.67

57.91

Synthetic crude oil (per barrel)

115.22

92.54

125.46

81.61

Conventional crude oil (per barrel)

67.91

70.09

97.45

59.84

NGL (per barrel)

62.07

64.92

35.87

Natural gas (per thousand cubic feet)

5.54

4.92

5.69

3.83

Refinery throughput (thousands of barrels per day)

433

416

418

379

Refinery capacity utilization (percent)

101

97

98

89

Petroleum product sales (thousands of barrels per day)

Gasolines

242

240

229

224

Heating, diesel and jet fuels

180

180

176

160

Lube oils and other products

41

44

47

45

Heavy fuel oils

24

32

23

27

Net petroleum products sales

487

496

475

456

Petrochemical sales (thousands of tonnes)

193

194

842

831

(a) Syncrude gross and net production included bitumen and other products that were exported to the operator's facilities using an existing interconnect pipeline.

Gross bitumen and other products production (thousands of barrels per day)

2

3

3

1

Net bitumen and other products production (thousands of barrels per day)

2

2

3

1

(b) Gas converted to oil-equivalent at six million cubic feet per one thousand barrels.

(c) NGL sales round to 0 in 2021.

Attachment V

Net income (loss) per

Net income (loss) (U.S. GAAP)

common share - diluted (a)

millions of Canadian dollars

Canadian dollars

2018

First Quarter

516

0.62

Second Quarter

196

0.24

Third Quarter

749

0.94

Fourth Quarter

853

1.08

Year

2,314

2.86

2019

First Quarter

293

0.38

Second Quarter

1,212

1.57

Third Quarter

424

0.56

Fourth Quarter

271

0.36

Year

2,200

2.88

2020

First Quarter

(188

)

(0.25

)

Second Quarter

(526

)

(0.72

)

Third Quarter

3

Fourth Quarter

(1,146

)

(1.56

)

Year

(1,857

)

(2.53

)

2021

First Quarter

392

0.53

Second Quarter

366

0.50

Third Quarter

908

1.29

Fourth Quarter

813

1.18

Year

2,479

3.48

2022

First Quarter

1,173

1.75

Second Quarter

2,409

3.63

Third Quarter

2,031

3.24

Fourth Quarter

1,727

2.86

Year

7,340

11.44

(a) Computed using the average number of shares outstanding during each period. The sum of the quarters presented may not add to the year total.

Attachment VI

Non-GAAP financial measures and other specified financial measures
Certain measures included in this document are not prescribed by U.S. Generally Accepted Accounting Principles (GAAP). These measures constitute "non-GAAP financial measures" under Securities and Exchange Commission Regulation G, and "specified financial measures" under National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure of the Canadian Securities Administrators.

Reconciliation of these non-GAAP financial measures to the most comparable GAAP measure, and other information required by these regulations, have been provided. Non-GAAP financial measures and specified financial measures are not standardized financial measures under GAAP and do not have a standardized definition. As such, these measures may not be directly comparable to measures presented by other companies, and should not be considered a substitute for GAAP financial measures.

Cash flows from (used in) operating activities excluding working capital
Cash flows from (used in) operating activities excluding working capital is a non-GAAP financial measure that is the total cash flows from operating activities less the changes in operating assets and liabilities in the period. The most directly comparable financial measure that is disclosed in the financial statements is cash flows from (used in) operating activities within the company's Consolidated statement of cash flows. Management believes it is useful for investors to consider these numbers in comparing the underlying performance of the company's business across periods when there are significant period-to-period differences in the amount of changes in working capital. Changes in working capital is equal to "Changes in operating assets and liabilities" as disclosed in the company's Consolidated statement of cash flows and in Attachment II of this document. This measure assesses the cash flows at an operating level, and as such, does not include proceeds from asset sales as defined in Cash flows from operating activities and asset sales in the Frequently Used Terms section of the company's annual Form 10-K.

Reconciliation of cash flows from (used in) operating activities excluding working capital

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

From Imperial's Consolidated statement of cash flows

Cash flows from (used in) operating activities

2,797

1,632

10,482

5,476

Less changes in working capital

Changes in operating assets and liabilities

345

(16

)

1,485

363

Cash flows from (used in) operating activities excl. working capital

2,452

1,648

8,997

5,113

Free cash flow
Free cash flow is a non-GAAP financial measure that is cash flows from operating activities less additions to property, plant and equipment and equity company investments plus proceeds from asset sales. The most directly comparable financial measure that is disclosed in the financial statements is cash flows from (used in) operating activities within the company's Consolidated statement of cash flows. This measure is used to evaluate cash available for financing activities (including but not limited to dividends and share purchases) after investment in the business.

Reconciliation of free cash flow

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

From Imperial's Consolidated statement of cash flows

Cash flows from (used in) operating activities

2,797

1,632

10,482

5,476

Cash flows from (used in) investing activities

Additions to property, plant and equipment

(492

)

(424

)

(1,526

)

(1,108

)

Proceeds from asset sales

18

24

904

81

Additional investments

(6

)

Loans to equity companies - net

1

1

10

15

Free cash flow

2,324

1,233

9,864

4,464

Net income (loss) excluding identified items
Net income (loss) excluding identified items is a non-GAAP financial measure that is total net income (loss) excluding individually significant non-operational events with an absolute corporate total earnings impact of at least $100 million in a given quarter. The net income (loss) impact of an identified item for an individual segment in a given quarter may be less than $100 million when the item impacts several segments or several periods. The most directly comparable financial measure that is disclosed in the financial statements is net income (loss) within the company's Consolidated statement of income. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The company believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management. Net income (loss) excluding identified items is not meant to be viewed in isolation or as a substitute for net income (loss) as prepared in accordance with U.S. GAAP. All identified items are presented on an after-tax basis.

Reconciliation of net income (loss) excluding identified items

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

From Imperial's Consolidated statement of income

Net income (loss) (U.S. GAAP)

1,727

813

7,340

2,479

Less identified items included in Net income (loss)

Gain/(loss) on sale of assets

208

Subtotal of identified items

208

Net income (loss) excluding identified items

1,727

813

7,132

2,479

Cash operating costs (cash costs)
Cash operating costs is a non-GAAP financial measure that consists of total expenses, less costs that are non-cash in nature, including, Purchases of crude oil and products, Federal excise taxes and fuel charge, Depreciation and depletion, Non-service pension and postretirement benefit, and Financing. The components of cash operating costs include (1) Production and manufacturing, (2) Selling and general and (3) Exploration, from the company's Consolidated statement of income, and as disclosed in Attachment III of this document. The sum of these income statement lines serve as an indication of cash operating costs and does not reflect the total cash expenditures of the company. The most directly comparable financial measure that is disclosed in the financial statements is total expenses within the company's Consolidated statement of income. This measure is useful for investors to understand the company's efforts to optimize cash through disciplined expense management.

Reconciliation of cash operating costs

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

From Imperial's Consolidated statement of Income

Total expenses

12,174

11,201

50,186

34,307

Less:

Purchases of crude oil and products

8,893

8,122

37,742

23,174

Federal excise taxes and fuel charge

563

524

2,179

1,928

Depreciation and depletion

465

545

1,897

1,977

Non-service pension and postretirement benefit

4

10

17

42

Financing

26

22

60

54

Total cash operating costs

2,223

1,978

8,291

7,132

Components of cash operating costs

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

From Imperial's Consolidated statement of Income

Production and manufacturing

1,965

1,737

7,404

6,316

Selling and general

257

215

882

784

Exploration

1

26

5

32

Cash operating costs

2,223

1,978

8,291

7,132

Segment contributions to total cash operating costs

Fourth Quarter

Twelve Months

millions of Canadian dollars

2022

2021

2022

2021

Upstream

1,439

1,292

5,496

4,693

Downstream

626

562

2,293

2,017

Chemicals

103

87

358

300

Corporate / Eliminations

55

37

144

122

Cash operating costs

2,223

1,978

8,291

7,132

Unit cash operating cost (unit cash costs)
Unit cash operating costs is a non-GAAP ratio. Unit cash operating costs (unit cash costs) is calculated by dividing cash operating costs by total gross oil-equivalent production, and is calculated for the Upstream segment, as well as the major Upstream assets. Cash operating costs is a non-GAAP financial measure and is disclosed and reconciled above. This measure is useful for investors to understand the expense management efforts of the company's major assets as a component of the overall Upstream segment. Unit cash operating cost, as used by management, does not directly align with the definition of "Average unit production costs" as set out by the U.S. Securities and Exchange Commission (SEC), and disclosed in the company's SEC Form 10-K.

Components of unit cash operating cost

Fourth Quarter

2022

2021

millions of Canadian dollars

Upstream (a)

Kearl

Cold Lake

Syncrude

Upstream (a)

Kearl

Cold Lake

Syncrude

Production and manufacturing

1,438

673

327

393

1,266

561

315

333

Selling and general

Exploration

1

26

Cash operating costs

1,439

673

327

393

1,292

561

315

333

Gross oil-equivalent production

441

201

141

87

445

191

142

79

(thousands of barrels per day)

Unit cash operating cost ($/oeb)

35.47

36.39

25.21

49.10

31.56

31.93

24.11

45.82

USD converted at the quarterly average forex

26.25

26.93

18.66

36.33

24.93

25.22

19.05

36.20

2022 US$0.74; 2021 US$0.79

Twelve Months

2022

2021

millions of Canadian dollars

Upstream (a)

Kearl

Cold Lake

Syncrude

Upstream (a)

Kearl

Cold Lake

Syncrude

Production and manufacturing

5,491

2,353

1,344

1,563

4,661

1,902

1,117

1,388

Selling and general

Exploration

5

32

Cash operating costs

5,496

2,353

1,344

1,563

4,693

1,902

1,117

1,388

Gross oil-equivalent production

416

172

144

77

428

186

140

71

(thousands of barrels per day)

Unit cash operating cost ($/oeb)

36.20

37.48

25.57

55.61

30.04

28.02

21.86

53.56

USD converted at the YTD average forex

27.87

28.86

19.69

42.82

24.03

22.42

17.49

42.85

2022 US$0.77; 2021 US$0.80

(a) Upstream includes Imperial's share of Kearl, Cold Lake, Syncrude and other.

After more than a century, Imperial continues to be an industry leader in applying technology and innovation to responsibly develop Canada's energy resources. As Canada's largest petroleum refiner, a major producer of crude oil, a key petrochemical producer and a leading fuels marketer from coast to coast, our company remains committed to high standards across all areas of our business.

Source: Imperial

Investor relations
(587) 476-4743

Media relations
(587) 476-7010

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