"As a result of our diversified portfolio, we achieved annual realized natural gas pricing of $6.55/Mcf in 2022, which was approximately 17% above the AECO benchmark price. In addition, our high value synthetic crude oil ("SCO") captured a strong price premium to WTI of US$4.43/bbl, driving strong realized SCO pricing of $117.69/bbl, which on an annual basis represents approximately 46% of our total liquids volumes and generates significant free cash flow for the Company.
"Canadian Natural's diverse portfolio is supported by long life low decline assets which have low risk, high value reserves that require low maintenance capital. This allows us to remain flexible with our capital allocation and maximize value. Total proved reserves increased by 6% to 13.587 billion BOE, replacing 2022 production by 265%. This provides the Company with a 32 year reserve life index ("RLI") and reflects the strength and depth of our assets. We continued to deliver strong total proved finding, development and acquisition ("FD&A") costs, including changes in future development costs, of $8.39/BOE in 2022.
"Canadian Natural is committed to supplying safe, reliable and responsible energy, along with reducing its environmental footprint. In 2022, we announced a new environmental target to reduce corporate scope 1 and 2 absolute GHG emissions by 40% by 2035, in addition to our other robust environmental targets. We have a defined journey to net zero emissions in oil sands operations and are working collaboratively with our industry peers through the Pathways Alliance to achieve this goal. It is important we work together with both federal and provincial governments to achieve climate goals, in an economically feasible manner. We are also an industry leader in abandonment and reclamation activity and through our active program, we have abandoned more than 3,000 wells per year in each of the last two years. At this pace, we would be able to achieve 100% abandonment of our current inventory of inactive wells in approximately 10 years."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added, "The combination of our leading financial results and our top tier asset base provides unique competitive advantages which drive substantial cash flow generation and shareholder returns. Canadian Natural generated approximately $19.8 billion in adjusted funds flow in 2022, resulting in free cash flow of approximately $10.9 billion, after total dividend payments and base capital expenditures excluding net acquisitions and strategic growth capital. We were able to deliver significant returns to shareholders in 2022, totaling approximately $10.5 billion through $5.6 billion in share repurchases and $4.9 billion in dividends, including the special dividend of $1.50 per common share paid in August 2022. This equates to approximately $9.25 per share in direct returns to shareholders in 2022.
"In 2022, the Board of Directors approved two separate raises to our quarterly dividend, for a combined increase of 45%, to $0.85 per common share. Subsequent to year end, the Board of Directors approved a 6% increase to the quarterly dividend to $0.90 per common share from $0.85 per common share, demonstrating the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline asset base. The Company has a leading track record of 23 consecutive years of dividend increases.
"We maintain a strong balance sheet and reduced our net debt by approximately $3.4 billion in 2022, closing the year with approximately $10.5 billion in net debt. In just two years, we have reduced our net debt by $10.7 billion or approximately 50% from the beginning of 2021.
"Subsequent to year end 2022, up to and including March 1, 2023, the Company has returned approximately $0.5 billion to shareholders through the repurchase and cancellation of approximately 6.2 million common shares. Additionally, the Board of Directors has approved the renewal of the Company's Normal Course Issuer Bid ("NCIB"), which states that during the 12 month period commencing March 13, 2023 and ending March 12, 2024, the Company can repurchase for cancellation up to 10% of the public float, subject to TSX approval.
"After reviewing our strong financial position and sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity, and long life low decline nature of our high value reserves, the Board of Directors has enhanced our free cash flow allocation policy to accelerate incremental shareholder returns to 100% of free cash flow when the Company's net debt reaches $10 billion, changed from the previous $8 billion net debt level. These changes reflect the substantial debt reductionover the last two years of approximately $10.7 billion, the increase in our production and reserve base and that our fixed outstanding bonds of approximately $11.4 billion are similar to the $10 billion net debt level in the free cash flow allocation policy. Additionally, with fully committed undrawn bank credit facilities of approximately $5.5 billion, we ensure strong liquidity. Once the Company's net debt reaches $10 billion, the enhanced free cash allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in the year.
"Canadian Natural's operations create long-term value in the areas we operate, through payments to governments, employment, investment in the oil and natural gas sector and returns to shareholders. In 2022, Canadian Natural paid a total of approximately $10.3 billion to Canadian governments in the form of income taxes, property taxes and royalties, an increase of approximately $5.3 billion, or 107%, from 2021 levels. Additionally, our 2022 capital investment of approximately $5.0 billion, excluding acquisitions, was an increase of approximately $1.5 billion, or 44%, from 2021 levels, delivering responsibly produced energy to help meet global energy demand, while creating jobs for Canadians."
HIGHLIGHTS
|
| Three Months Ended |
|
| Year Ended |
|
| ($ millions, except per common share amounts) |
| Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
|
| Dec 31
2022 |
|
| Dec 31
2021 | |
| Net earnings | $ | 1,520 |
| $ | 2,814 |
| $ | 2,534 |
| $ | 10,937 |
| $ | 7,664 |
|
| Per common share | - basic | $ | 1.37 |
| $ | 2.52 |
| $ | 2.16 |
| $ | 9.64 |
| $ | 6.49 |
|
| - diluted | $ | 1.36 |
| $ | 2.49 |
| $ | 2.14 |
| $ | 9.52 |
| $ | 6.46 |
|
| Adjusted net earnings from operations (1) | $ | 2,194 |
| $ | 3,493 |
| $ | 2,626 |
| $ | 12,863 |
| $ | 7,420 |
|
| Per common share | - basic (2) | $ | 1.98 |
| $ | 3.12 |
| $ | 2.24 |
| $ | 11.33 |
| $ | 6.28 |
|
| - diluted (2) | $ | 1.96 |
| $ | 3.09 |
| $ | 2.21 |
| $ | 11.19 |
| $ | 6.25 |
|
| Cash flows from operating activities | $ | 4,544 |
| $ | 6,098 |
| $ | 4,712 |
| $ | 19,391 |
| $ | 14,478 |
|
| Adjusted funds flow (1) | $ | 4,176 |
| $ | 5,208 |
| $ | 4,338 |
| $ | 19,791 |
| $ | 13,733 |
|
| Per common share | - basic (2) | $ | 3.78 |
| $ | 4.66 |
| $ | 3.69 |
| $ | 17.44 |
| $ | 11.63 |
|
| - diluted (2) | $ | 3.73 |
| $ | 4.60 |
| $ | 3.66 |
| $ | 17.22 |
| $ | 11.57 |
|
| Cash flows used in investing activities | $ | 1,262 |
| $ | 1,129 |
| $ | 1,615 |
| $ | 4,987 |
| $ | 3,703 |
|
| Net capital expenditures (1), excluding net acquisition costs and strategic growth capital (3) | $ | 850 |
| $ | 996 |
| $ | 837 |
| $ | 3,956 |
| $ | 3,483 |
|
| Net capital expenditures (1) | $ | 1,317 |
| $ | 1,249 |
| $ | 1,804 |
| $ | 5,471 |
| $ | 4,908 |
|
| Daily production, before royalties |
| |
|
| |
|
| |
|
| |
|
| |
|
| Natural gas (MMcf/d) |
| 2,115 |
|
| 2,132 |
|
| 1,857 |
|
| 2,090 |
|
| 1,695 |
|
| Crude oil and NGLs (bbl/d) |
| 942,258 |
|
| 983,678 |
|
| 1,004,425 |
|
| 933,149 |
|
| 952,404 |
|
| Equivalent production (BOE/d) (4) |
| 1,294,679 |
|
| 1,338,940 |
|
| 1,313,900 |
|
| 1,281,434 |
|
| 1,234,906 | |
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.
(3)Net capital expenditures, excluding net acquisition costs and strategic growth capital, is defined as base capital expenditures.
(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.
ANNUAL HIGHLIGHTS
The strength of Canadian Natural's long life low decline asset base, supported by safe, effective and efficient operations, makes our business unique, robust and sustainable. In 2022, the Company generated strong financial results, including:
Net earnings of approximately $10.9 billion and adjusted net earnings from operations of approximately $12.9 billion in 2022.
Cash flows from operating activities of approximately $19.4 billion in 2022.
Adjusted funds flow of approximately $19.8 billion in 2022.
Free cash flow(1) of approximately $10.9 billion(2) in 2022 after total dividend payments of approximately $4.9 billion and base capital expenditures(3) of approximately $4.0 billion.
Significant returns to shareholders and debt reduction in 2022 are a result of substantial free cash flow generation and the Company's free cash flow allocation policy that states when net debt is below $15 billion, 50% of free cash flow will be allocated to share repurchases and 50% of free cash flow allocated to the balance sheet less strategic growth / acquisition opportunities. Free cash flow for the purpose of the policy is defined as adjusted funds flow less dividends, less base capital.
Returns to shareholders in 2022 were significant, having returned approximately $10.5 billion, comprised of approximately $4.9 billion in dividends and approximately $5.6 billion in share repurchases.
Canadian Natural increased its sustainable and growing quarterly dividend twice in 2022 for a total combined increase of 45% to $3.40 per share annually. The last increase in 2022 was in November, when the Board of Directors approved a 13% increase to our quarterly dividend to $0.85 per common share, which demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline asset base. The Company's leading track record of dividend increases continues, as this increase marked the 23rd consecutive year of dividend increases.
In 2022, the Company repurchased a total of approximately 77.3 million common shares for cancellation at a weighted average price of $72.03 per share for a total of approximately $5.6 billion.
Canadian Natural continues to maintain a strong balance sheet and financial flexibility. The Company reduced net debt(1) by approximately $3.4 billion in 2022, ending the year with approximately $10.5 billion in net debtand significant liquidity(1) of approximately $6.9 billion. The Company executed on a number of initiatives in 2022 to strengthen the Company's financial flexibility, including:
Repaid $1.0 billion of 3.31% medium term notes.
Repaid and cancelled a total of $1.15 billion of non-revolving term credit facilities.
Early repayment of US$1.0 billion of 2.95% debt securities, originally due January 15, 2023.
Repaid through market purchases approximately $0.5 billion of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028.
Concurrently with the release of Canadian Natural's year end results, the Company enhanced its free cash flow allocation policy due to being in a strong financial position and having a sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity, and long life low decline nature of our high value reserves. As a result, the Board of Directors has confidence in the sustainability and resilience of the Company to support accelerating incremental shareholder returns to 100% of free cash flow when the Company's net debt reaches $10 billion, changed from the previous $8 billion net debt level. Once the Company's net debt reaches $10 billion, the free cash allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in the year.
In 2022, the Company continued to focus on safe, effective and efficient operations, delivering record annual average production of 1,281,434 BOE/d, consisting of total liquids production of 933,149 bbl/d and record natural gas production of 2,090 MMcf/d.
Total BOE production increased by 4% from 2021 levels, or 8% on a production per share basis, driven by a 23% increase in annual natural gas production volumes.
As a result of the Company's diversified sale points, we achieved strong annual natural gas realized pricing of $6.55/Mcf in 2022, which was approximately 17% above the AECO benchmark price, maximizing value for shareholders. Approximately 28% of the Company's natural gas production was sold at AECO/Station 2 pricing, and approximately 34% was exported to other North Americanand international markets, capturing higher natural gas prices. Additionally, the Company used the equivalent of approximately 38% of its natural gas production in its operations in 2022.
The Company's high value SCO captured a strong price premium to WTI of US$4.43/bbl in 2022, driving strong annual realized SCO pricing of $117.69/bbl, which on an annual basis represented approximately 46% of total liquids volumes and generated significant free cash flow for the Company.
Subsequent to year end:
The Board of Directors did an annual review of dividend levels and approved a 6% increase to the quarterly dividend to $0.90 per common share, from $0.85 per common share, payable on April 5, 2023 to shareholders of record on March 17, 2023.
The Company returned a total of approximately $1.4 billion to shareholders through approximately $0.9 billion in dividends and $0.5 billion from the repurchase and cancellation of approximately 6.2 million common shares, up to and including March 1, 2023.
The Board of Directors approved the renewal of the Company's NCIB, which states that during the 12 month period commencing March 13, 2023 and ending March 12, 2024, the Company can repurchase for cancellation up to 10% of the public float (determined in accordance with the rules of the TSX), subject to TSX approval.
QUARTERLY HIGHLIGHTS
In Q4/22, the Company generated strong financial results, including:
Net earnings of approximately $1.5 billion and adjusted net earnings from operations of approximately $2.2 billion in Q4/22.
Cash flows from operating activities of approximately $4.5 billion in Q4/22.
Adjusted funds flow of approximately $4.2 billion in Q4/22.
Free cash flow of approximately $2.5 billion in Q4/22 after total dividend payments of approximately $0.8 billion and base capital expenditures of approximately $0.9 billion.
Returns to shareholders in Q4/22 of approximately $1.6 billion, comprised of approximately $834 million in dividends and approximately $746 million in share repurchases.
In Q4/22, the Company repurchased a total of approximately 9.6 million common shares for cancellation at a weighted average price of $77.69 per share for a total of approximately $0.7 billion.
In November 2022, the Board of Directors approved a 13% increase to our quarterly dividend to $0.85 per common share, from $0.75 per common share.
Reduced net debt by approximately $1.9 billion in Q4/22.
Delivered quarterly average production of 1,294,679 BOE/d, consisting of 942,258 bbl/d of liquids and 2,115 MMcf/d of natural gas.
North America E&P liquids production, excluding thermal in situ, averaged 233,371 bbl/d in Q4/22, a 2% increase from Q3/22 levels, reflecting increased drilling activity and acquisitions, partially offset by natural declines and the impact of extreme cold weather in December 2022.
Thermal in situ production averaged 253,188 bbl/d, a 4% increase from Q3/22 levels, reflecting strong production at Jackfish following planned maintenance activities completed in Q3/22, partially offset by natural field declines.
(1) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.
(2) Based on sum of rounded numbers.
(3) Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023 for more details on net capital expenditures.
RESERVES UPDATE
A key differentiator for Canadian Natural is the strength, diversity and balance of our world class, top tier reserves. Strategically assembled and developed over several decades, these assets have a low decline rate as well as low maintenance capital relative to the size and quality of the reserves. The low maintenance capital requirements of our reserves affords the Company significant flexibility when balancing our four pillars of capital allocation to maximize shareholder value.
The Company's reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators ("IQREs"). The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2022 (all reserves values are Company Gross unless stated otherwise).
Total proved reserves increased 6% to 13.587 billion BOE, with reserves additions and revisions of 1.242 billion BOE. Total proved plus probable reserves increased 6% to 18.046 billion BOE, with reserves additions and revisions of 1.563 billion BOE.
Proved developed producing reserves additions and revisions are 491 million BOE, replacing 2022 production by 105%. The proved developed producing BOE reserves life index is approximately 21 years.
Total proved reserves additions and revisions replaced 2022 production by 265%. Total proved plus probable reserves additions and revisions replaced 2022 production by 334%. This includes negative technical revisions as a result of accelerating the cessation of production from two platforms in the North Sea.
In 2022, Canadian Natural continued to achieve strong finding and development costs:
FD&A(1)costs, excluding changes in Future Development Cost ("FDC"), are $4.11/BOE for total proved reserves and $3.26/BOE for total proved plus probable reserves.
FD&A costs, including changes in FDC, are $8.39/BOE for total proved reserves and $7.62/BOE for total proved plus probable reserves.
The net present value of future net revenues, before income tax, discounted at 10%, is approximately $102.3 billion for proved developed producing reserves, approximately $150.9 billion for total proved reserves, and approximately $183.7 billion for total proved plus probable reserves.
(1) Supplementary financial measure. Refer to the "2022 Year End Reserves" section of this interim report.
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 73% of total liquids production in 2022, 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 the Company's long life low decline production comes from its top tier thermal in situ oil sands operations and 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 |
| Year Ended Dec 31 |
|
| | 2022 |
|
| 2021 |
|
| (number of wells) |
| Gross |
|
| Net |
|
| Gross |
|
| Net | |
| Crude oil (1) | | 332 |
|
| 317 |
|
| 154 |
|
| 149 |
|
| Natural gas | | 100 |
|
| 72 |
|
| 62 |
|
| 49 |
|
| Dry | | 1 |
|
| 1 |
|
| 1 |
|
| 1 | |
| Subtotal | | 433 |
|
| 390 |
|
| 217 |
|
| 199 |
|
| Stratigraphic test / service wells | | 530 |
|
| 452 |
|
| 485 |
|
| 393 | |
| Total | | 963 |
|
| 842 |
|
| 702 |
|
| 592 | |
| Success rate (excluding stratigraphic test / service wells) | | |
|
| 99% |
|
| |
|
| 99 % | |
(1)Includes bitumen wells.
- The Company drilled a total of 390 net crude oil and natural gas wells in 2022 compared to 199 in 2021, nearly doubling the number of wells drilled over this time period.
North America Exploration and Production
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands |
|
|
|
|
|
|
|
|
| Three Months Ended |
|
| Year Ended |
|
| | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
| | Dec 31
2022 |
|
| Dec 31
2021 | |
| Crude oil and NGLs production (bbl/d) | | 233,371 |
|
| 228,239 |
|
| 215,628 |
| | 227,953 |
|
| 213,336 | |
| Net wells targeting crude oil | | 71 |
|
| 60 |
|
| 20 |
| | 214 |
|
| 136 |
|
| Net successful wells drilled | | 71 |
|
| 60 |
|
| 20 |
| | 213 |
|
| 135 | |
| Success rate | | 100% |
|
| 100 % |
|
| 100 % |
| | 99% |
|
| 99 % | |
North America E&P liquids production, excluding thermal in situ, averaged 227,953 bbl/d in 2022, an increase of 7% from 2021 levels, reflecting increased drilling activity and acquisitions, partially offset by natural declines and the impact of extreme cold weather in December 2022.
Primary heavy crude oil production averaged 67,699 bbl/d in 2022, an increase of 5% from 2021 levels, reflecting strong results from the Company's horizontal multilateral drilling program, partially offset by natural field declines.
Operating costs(1) in the Company's primary heavy crude oil operations averaged $21.84/bbl (US$16.79/bbl) in 2022, an increase of 13% from 2021 levels, primarily due to higher energy and trucking costs.
In 2022, the Company drilled a total of 127 net horizontal multilateral heavy oil wells, including 52 net wells at Smith in the Clearwater. The Company's Clearwater production averaged approximately 13,000 BOE/d in Q4/22, up by approximately 9,100 BOE/d from the start of the year.
Pelican Lake production averaged 50,333 bbl/d in 2022, a decrease of 7% from 2021 levels, primarily reflecting a temporary injection reduction in Q4/22 and natural field declines. As of February 2023, injection rates have been reinstated and the polymer flood field is targeted to return to its historical low decline rate of approximately 5% in the second half of 2023.
North America light crude oil and NGL production averaged 109,921 bbl/d in 2022, an increase of 16% from 2021 levels as a result of strong drilling results and acquisitions, partially offset by natural field declines.
Operating costs in the Company's North America light crude oil and NGL areas averaged $15.91/bbl (US$12.23/bbl) in 2022, an increase of 4% from 2021 levels, primarily due to higher energy costs.
The Company successfully drilled a total of 32 net Montney and Deep Basin light crude oil wells in 2022.
| Thermal In Situ Oil Sands |
|
|
|
|
|
|
|
|
| Three Months Ended |
|
| Year Ended |
|
| | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
| | Dec 31
2022 |
|
| Dec 31
2021 | |
| Bitumen production (bbl/d) | | 253,188 |
|
| 243,393 |
|
| 263,110 |
| | 252,018 |
|
| 259,284 | |
| Net wells targeting bitumen | | 9 |
|
| 38 |
|
| 1 |
| | 104 |
|
| 8 |
|
| Net successful wells drilled | | 9 |
|
| 38 |
|
| 1 |
| | 104 |
|
| 8 | |
| Success rate | | 100% |
|
| 100 % |
|
| 100 % |
| | 100% |
|
| 100 % | |
Canadian Natural's long life low decline thermal in situ assets produced an average of 252,018 bbl/d in 2022, a decrease of 3% from 2021 levels, demonstrating the long life low decline nature of these assets.
(1) Calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.
(2) Supplementary financial measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release.
The Company remains on track with its pad development plans across its thermal in situ assets, adding production while offsetting natural field declines. The Company targets to achieve capital efficiencies ranging from approximately $8,000/bbl/d to $10,000/bbl/d on its Steam Assisted Gravity Drainage ("SAGD") and cyclic steam stimulation ("CSS") pads.
At Primrose, the Company finished drilling two CSS pads in Q4/22, and targets to bring these pads on production in early Q3/23.
At Kirby, the Company is progressing with the development of four SAGD pads, the first of which began steam injection in late December 2022 and targets to ramp up to full production capacity in Q3/23. The remaining three pads target to ramp up to full production capacity in 2024.
At Jackfish, the Company is currently drilling a SAGD pad, which is targeted to begin steam injection in early Q4/23 and ramp up to full production capacity in 2024.
Canadian Natural has been piloting solvent enhanced oil recovery technology on certain of its thermal in situ assets with an objective to increase bitumen production, reduce the Steam to Oil Ratio ("SOR"), reduce GHG intensity and realize high solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
After a successful solvent pilot at Kirby South, the Company has substantially completed engineering and design of a commercial scale solvent SAGD pad development at Kirby North. The solvent facility site construction and module installations are targeted to begin in Q3/23, followed by solvent injection targeted for Q2/24.
At Primrose, the Company is currently piloting solvent enhanced oil recovery in the steam flood area and is targeting SOR and GHG intensity reductions of 40% to 45%, with solvent recovery greater than 70%. Results to date have been positive and the Company targets to complete the pilot in Q4/23.
| North America Natural Gas |
|
|
|
|
|
|
|
|
| Three Months Ended |
|
| Year Ended |
|
| | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
|
| Dec 31
2022 |
|
| Dec 31
2021 | |
| Natural gas production (MMcf/d) | | 2,105 |
|
| 2,117 |
|
| 1,841 |
| | 2,075 |
|
| 1,680 | |
| Net wells targeting natural gas | | 15 |
|
| 14 |
|
| 9 |
| | 72 |
|
| 49 |
|
| Net successful wells drilled | | 15 |
|
| 14 |
|
| 9 |
| | 72 |
|
| 49 | |
| Success rate | | 100% |
|
| 100 % |
|
| 100 % |
| | 100% |
|
| 100 % | |
Canadian Natural achieved record annual North America natural gas production in 2022, averaging approximately 2,075 MMcf/d, an increase of 395 MMcf/d, or 24%, from 2021 levels, driven by strong drilling results and acquisitions, partially offset by natural field declines and the impact of extreme cold weather in December 2022.
North America natural gas operating costs averaged $1.19/Mcf in 2022, a 3% increase from 2021 levels, primarily reflecting higher energy costs.
The Company's successful natural gas drilling program included 15 net wells in Q4/22, bringing the total drilled in the year to 72 net wells, including 38 net Montney and 34 net Deep Basin wells.
As a result of the Company's diversified sales points, the Company realized strong North American natural gas pricing of $6.51/Mcf in 2022, which is 16% above the 2022 average AECO benchmark price.
International Exploration and Production
|
| Three Months Ended |
|
| Year Ended |
|
| | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
| | Dec 31
2022 |
|
| Dec 31
2021 |
|
| Crude oil production (bbl/d) | | 26,915 |
|
| 24,493 |
|
| 32,281 |
| | 27,233 |
|
| 31,650 |
|
| Natural gas production (MMcf/d) | | 10 |
|
| 15 |
|
| 16 |
| | 15 |
|
| 15 |
|
| Net wells targeting crude oil | | - |
|
| - |
|
| 1.0 |
| | - |
|
| 5.9 |
|
| Net successful wells drilled | | - |
|
| - |
|
| 1.0 |
| | - |
|
| 5.9 |
|
| Success rate | | -% |
|
| - % |
|
| 100 % |
| | -% |
|
| 100 % |
|
International E&P crude oil production volumes averaged 27,233 bbl/d in 2022, a decrease of 14% from 2021 levels, primarily reflecting natural field declines and maintenance activities in 2022.
Primarily as a result of prevailing regulatory and economic conditions in 2022 along with the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, the Company completed an assessment of its North Sea operations and de-booked 65 million BOE of its North Sea total proved reserves and 99 million BOE of its North Sea total proved plus probable reserves, representing approximately 0.5% of the Company's total reserves at December 31, 2022. Additionally, the Company is accelerating the abandonment of two of the platforms in the North Sea.
North America Oil Sands Mining and Upgrading
|
| Three Months Ended |
|
| Year Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
| | Dec 31
2022 |
|
| Dec 31
2021 | |
| Synthetic crude oil production (bbl/d) (1)(2) | | 428,784 |
|
| 487,553 |
|
| 493,406 |
| | 425,945 |
|
| 448,133 | |
(1)SCO production before royalties and excludes production volumes consumed internally as diesel.
(2)Consists of heavy and light synthetic crude oil products.
Canadian Natural continues to focus on safe, reliable and efficient operations of its world class Oil Sands Mining and Upgrading assets to deliver high value SCO. Production averaged 425,945 bbl/d in 2022, a decrease of 5% from 2021 levels, primarily as a result of the previously announced updated Q4/22 targeted production range as well as the impact of extreme cold weather conditions in December 2022.
As a result of extreme cold weather in December 2022, the Company had to complete multiple mining equipment repairs, resulting in reduced rates at Horizon in both December 2022 and January 2023. These events are targeted to impact Q1/23 production by approximately 25,000 bbl/d. Production from the Company's Oil Sands Mining and Upgrading assets averaged approximately 483,000 bbl/d in February 2023.
The Company is progressing with its reliability enhancement project, which is now targeted to be 45 days ahead of our previous schedule. This project targets to extend the major maintenance cycle from once per year to once every second year, increasing the SCO production capacity by approximately 5,000 bbl/d in 2023, increasing to approximately 14,000 bbl/d in 2025.
As a result of the advancement of the reliability enhancement project and the reduced rates in Q1/23, the Company's 2023 thermal and Oil Sands Mining and Upgrading production guidance range remains unchanged.
Approximately 46% of the Company's total liquids production is comprised of high value SCO, which captured a strong price premium to WTI of US$4.43/bbl in 2022, driving strong SCO average realized pricing of $117.69/bbl and generating significant free cash flow for the Company.
Operating costs on the Company's SCO averaged $26.04/bbl (US$20.01/bbl) in 2022, an increase of 25% from 2021 levels as a result of increased energy and maintenance services costs, together with lower production volumes in 2022.
Included in the Company's previously announced 2023 production guidance, planned turnaround schedules for its Oil Sands Mining and Upgrading operations in 2023 include:
A major turnaround at the non-operated Scotford Upgrader is targeted to begin in April 2023 with reduced rates from the mines targeted for approximately 73 days, impacting 2023 annual production by approximately 8,300 bbl/d.
A turnaround at Horizon is targeted to begin in May 2023 with a full plant outage targeted for approximately 28 days, impacting 2023 annual production by approximately 21,600 bbl/d. During this time, the Company is planning to complete tie ins supporting the reliability enhancement project.
The Company is evaluating the detailed design work of the 750t/hr commercial unit for the In-Pit Extraction Plant ("IPEP") that will provide dry stackable tailings directly in the mine-pit, targeting to reduce GHG emissions and tailings ponds in the future.
MARKETING
|
| Three Months Ended |
|
| Year Ended |
|
| | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
|
| Dec 31
2022 |
|
| Dec 31
2021 | |
| Crude oil and NGLs pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| WTI benchmark price (US$/bbl) (1) | $ | 82.62 |
| $ | 91.64 |
| $ | 77.17 |
| $ | 94.23 |
| $ | 67.96 |
|
| WCS heavy differential as a percentage of WTI (%) (2) |
| 31% |
|
| 22 % |
|
| 19 % |
|
| 19% |
|
| 19 % |
|
| SCO benchmark price (US$/bbl) | $ | 86.78 |
| $ | 100.51 |
| $ | 75.39 |
| $ | 98.66 |
| $ | 66.36 |
|
| Condensate benchmark price (US$/bbl) | $ | 83.33 |
| $ | 87.15 |
| $ | 79.10 |
| $ | 93.69 |
| $ | 68.24 |
|
| Exploration & Production liquids realized pricing (C$/bbl) (3)(4) | $ | 69.34 |
| $ | 84.91 |
| $ | 72.81 |
| $ | 90.64 |
| $ | 63.71 |
|
| SCO realized pricing (C$/bbl) (5) | $ | 103.79 |
| $ | 120.91 |
| $ | 88.48 |
| $ | 117.69 |
| $ | 77.95 |
|
| Natural gas pricing |
| |
|
| |
|
| |
|
| |
|
| |
|
| AECO benchmark price (C$/GJ) | $ | 5.29 |
| $ | 5.51 |
| $ | 4.67 |
| $ | 5.28 |
| $ | 3.38 |
|
| Average realized pricing before risk management (C$/Mcf) (4) | $ | 6.39 |
| $ | 6.57 |
| $ | 5.35 |
| $ | 6.55 |
| $ | 4.07 | |
(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.
(4)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.
(5)Pricing is net of blending costs and excluding risk management activities.
Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, thermal in situ bitumen and SCO.
Commodity prices improved in 2022, with WTI averaging US$94.23/bbl, an increase of 39% from US$67.96/bbl in 2021. Crude oil prices increased in the first half of 2022, primarily in response to the impact of the Russian invasion of Ukraine, the OPEC+ decision to adhere to production cut agreements, and an increase in global demand for crude oil due to improved economic conditions as a result of the lessening of COVID-19 restrictions. In the latter part of 2022, crude oil prices softened due to demand concerns related to the temporary reinstatement of COVID-19 restrictions in China, rising interest rates and concerns of a global recession.
SCO benchmark pricing remained strong as a result of strong North American demand for refined products, averaging US$98.66/bbl in 2022, representing a US$4.43/bbl price premium to WTI, relative to a US$1.60/bbl discount to WTI in 2021.
Increased market access from western Canada has resulted in a more balanced market for heavy crude oil, with the WCS heavy oil differential as a percentage of WTI remaining at 19% in 2022, the same percentage as in 2021.
Natural gas prices continued to strengthen in 2022, with AECO averaging $5.28/GJ in 2022, an increase of 56% from 2021 levels, primarily reflecting lower storage levels and increased NYMEX benchmark pricing.
Canadian Natural has diversified sales points to maximize value for our shareholders. Approximately 28% of its natural gas production was sold at AECO/Station 2 pricing, and approximately 34% was exported to other North American and international markets, capturing higher natural gas prices. Additionally, the Company used the equivalent of approximately 38% of its natural gas production in its operations in 2022.
The Company's diversified sales points drove strong annual realized natural gas pricing averaging $6.55/Mcf in 2022, which was 17% above the average AECO benchmark price in 2022.
The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 58,351 BOE/d in 2022 and resulted in strong margins on domestic diesel volumes.
Canadian Natural has been a supporter of incremental pipeline projects to ensure Canadian crude oil and natural gas can access global markets to deliver the most responsible and leading ESG production that the world needs.
Canadian Natural has committed 94,000 bbl/d on the 590,000 bbl/d Trans Mountain Pipeline Expansion. Trans Mountain Corporation anticipates mechanical completion of the pipeline to occur at the end of Q3/23 with commercial service expected to occur late in Q4/23 per its third quarter 2022 press release dated November 29, 2022.
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 flexible capital expenditure program, all support a strong financial position and provide the appropriate financial resources for the near-, mid- and long-term.
Safe, effective and efficient operations combined with our high quality, long life low decline asset base generated annual free cash flow of approximately $10.9 billion after dividend payments of approximately $4.9 billion and base capital expenditures of approximately $4.0 billion (excluding net acquisitions and strategic growth capital, as per the Company's free cash flow allocation policy).
In 2022, Canadian Natural's free cash flow allocation policy stated that when net debt is below $15 billion, 50% of free cash flow will be allocated to share repurchases and 50% of free cash flow to the balance sheet less strategic growth / acquisition opportunities. Free cash flow for the purpose of the policy is defined as adjusted funds flow less dividends, less base capital.
Returns to shareholders were significant in 2022, having returned approximately $10.5 billion, comprised of approximately $4.9 billion in dividends and approximately $5.6 billion in share repurchases.
Canadian Natural increased its sustainable and growing quarterly dividend twice in 2022 for a total combined increase of 45% to $3.40 per share annually. The last increase in 2022 was in November, when the Board of Directors approved a 13% increase to our quarterly dividend to $0.85 per common share, which demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline asset base. The Company's leading track record of dividend increases continues, as this increase marked the 23rd consecutive year of dividend increases.
In 2022, the Company repurchased a total of approximately 77.3 million common shares for cancellation at a weighted average price of $72.03 per share for a total of approximately $5.6 billion.
Canadian Natural continues to maintain a strong balance sheet and financial flexibility. The Company reduced net debt by approximately $3.4 billion in 2022, ending the year with approximately $10.5 billion in net debtand significant liquidity of approximately $6.9 billion. The Company executed on a number of initiatives in 2022 to strengthen the Company's financial flexibility, including:
Repaid $1.0 billion of 3.31% medium term notes.
Repaid and cancelled a total of $1.15 billion of non-revolving term credit facilities.
Early repayment of US$1.0 billion of 2.95% debt securities, originally due January 15, 2023.
Repaid through market purchases approximately $0.5 billion of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028.
Undrawn revolving bank credit facilities totaling approximately $5.5 billion were available at December 31, 2022. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $6.9 billion. At year end, the Company had no amount drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
Concurrently with the release of Canadian Natural's year end results, the Company enhanced its free cash flow allocation policy due to being in a strong financial position and having a sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity, and long life low decline nature of our high value reserves. As a result, the Board of Directors has confidence in the sustainability and resilience of the Company to support accelerating incremental shareholder returns to 100% of free cash flow when the Company's net debt reaches $10 billion instead of the previous $8 billion net debt level. Once the Company's net debt reaches $10 billion, the free cash allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in the year.
Subsequent to year end:
The Company, up to and including March 1, 2023, returned approximately $1.4 billion to shareholders through approximately $0.9 billion in dividends and $0.5 billion from the repurchase and cancellation of approximately 6.2 million common shares.
The Board of Directors approved the renewal of the Company's NCIB, which states that during the 12 month period commencing March 13, 2023 and ending March 12, 2024, the Company can repurchase for cancellation up to 10% of the public float (determined in accordance with the rules of the TSX), subject to TSX approval.
The Board of Directors did an annual review of dividend levels and approved a 6% increase to the quarterly dividend to $0.90 per common share, from $0.85 per common share, payable on April 5, 2023 to shareholders of record on March 17, 2023.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE HIGHLIGHTS
Canada and Canadian Natural are well positioned to deliver affordable, reliable, safe and 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 ongoing enhancements to the Company's environmental performance.
Environmental Targets
Canadian Natural is committed to reducing its environmental footprint and as previously announced, has committed to the following environmental targets:
40% reduction in corporate Scope 1 and Scope 2 absolute GHG emissions by 2035, from a 2020 baseline
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
Canadian Natural is an industry leader in abandonment and reclamation activity and through its active program, the Company has abandoned more than 3,000 wells per year in each of the last two years. At this pace, the Company would be able to achieve 100% abandonment of its current inventory of inactive wells in approximately 10 years.
Pathways Alliance
The six major oil sands companies in the Pathways Alliance ("Pathways"), including Canadian Natural, operate approximately 95% of Canada's oil sands production. The goal of this unique alliance is to support Canada in meeting its climate commitments and position Canada to be the preferred source of crude oil globally. Working collectively with the federal and provincial governments, the Pathways Alliance has a goal to achieve net zero GHG emissions from oil sands operations by 2050 and is pursuing realistic and workable solutions to deliver significant emission reductions.
On January 4, 2023, Pathways reached another milestone as it entered into a Carbon Sequestration Evaluation Agreement with the Government of Alberta, enabling Pathways to conduct a detailed evaluation of the proposed geological storage hub to safely inject and permanently store CO2. Members of Pathways are advancing environmental field programs, engineering design and a subsurface development plan. Ongoing field activity includes a water injection well test at a Manatokan site, which is refining our understanding of storage capability and capacity, and will ensure safe, effective and efficient CO2 sequestration.
The proposed carbon storage hub would be one of the world's largest carbon capture and storage ("CCS") projects and would be connected to a transportation line that would initially gather captured CO2 from an anticipated 14 oil sands facilities in the Fort McMurray, Christina Lake and Cold Lake regions. The plan is to grow the transportation network to include over 20 oil sands facilities, and to accommodate other industries in the region interested in CCS. Stakeholder engagement continues to progress with Indigenous and local communities in northern Alberta related to the Pathways CCS project.
Government Support for Carbon Capture, Utilization and Storage ("CCUS")
Canadian Natural is a leader in CCUS and GHG reduction projects and sees many opportunities for industry to advance investments in CCUS. The Government of Canada has proposed an investment tax credit for CCUS projects for all sectors across Canada. In addition, the Government of Alberta announced its 2023 Budget on February 28, 2023, which includes support for CCUS projects and coordination with federal CCUS initiatives. Together, these are positive approaches whereby industry and governments can co-invest in infrastructure that advances CCUS projects. Decarbonization projects, including CCUS, represents an important opportunity for industry and governments to work together to achieve climate goals and economic objectives while supporting Canada's allies with energy security.
Technology Innovation and Emissions Reduction ("TIER") Regulation
In Q4/22, the Alberta government announced changes to its Technology Innovation and Emissions Reduction Regulation ("TIER"), which became effective January 1, 2023, to align with the federal carbon pricing system.It is encouraging that the federal government review of provincial carbon pricing systems continued to accept the TIER system in Alberta. Moving forward, it will be important to work together to ensure that the TIER system continues to support sustainable, long-term investments in GHG reduction technologies.
Blueberry River First Nations
In January 2023, the British Columbia Government and the Oil & Gas Commission came to a resolution with the Blueberry River First Nations ("BRFN") regarding the impact of resource development on the BRFN lands. Further engagement with government and the regulator is required to gather more information to understand the implementation of its land management framework and the impacts to Canadian Natural going forward. The Company values its relationships with local Indigenous communities, including the Blueberry River First Nations, and meets regularly with communities to build and maintain positive relationships in order to create shared value and mutual benefit from our operations.
British Columbia Royalty Framework
On May 19, 2022, the Government of British Columbia ("BC") announced a new royalty framework, which comes into effect September 1, 2024. The new framework will replace previous drilling incentive programs with a revenue minus costs model similar to other Canadian jurisdictions. New wells will pay a flat royalty rate of 5% until the capital spent on drilling and completions are recovered and then a price sensitive royalty rate between 5% and 40% will apply and will vary based on commodity type. Details of certain cost allowances and reference prices remain to be finalized by the BC government through consultation with stakeholders.
2022 YEAR END RESERVES
Determination of Reserves
For the year ended December 31, 2022, the Company retained Independent Qualified Reserves Evaluators (IQREs), Sproule Associates Limited, Sproule International Limited and GLJ Ltd., to evaluate and review all of the Company's proved and proved plus probable reserves. The evaluation and review was conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.
The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with the IQREs as to the Company's reserves.
Additional reserves information is disclosed in the Company's Annual Information Form.
Summary of Company Gross Reserves
As of December 31, 2022
Forecast Prices and Costs
|
| Light and
Medium
Crude Oil
(MMbbl) |
| Primary
Heavy
Crude Oil
(MMbbl) |
| Pelican Lake
Heavy
Crude Oil
(MMbbl) |
| Bitumen
(Thermal Oil)
(MMbbl) |
| Synthetic
Crude Oil
(MMbbl) |
| Natural Gas
(Bcf) |
| Natural Gas
Liquids
(MMbbl) |
| Barrels of Oil
Equivalent
(MMBOE) | |
| Total Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Developed Producing |
| 122 |
| 96 |
| 207 |
| 540 |
| 6,836 |
| 4,989 |
| 143 |
| 8,775 |
|
| Developed Non-Producing |
| 16 |
| 11 |
| - |
| 140 |
| - |
| 306 |
| 6 |
| 225 |
|
| Undeveloped |
| 93 |
| 73 |
| 55 |
| 2,604 |
| 37 |
| 8,332 |
| 337 |
| 4,587 | |
| Total Proved |
| 231 |
| 179 |
| 262 |
| 3,284 |
| 6,873 |
| 13,627 |
| 486 |
| 13,587 |
|
| Probable |
| 89 |
| 93 |
| 114 |
| 1,901 |
| 535 |
| 8,643 |
| 285 |
| 4,458 | |
| Total Proved plus Probable |
| 320 |
| 272 |
| 376 |
| 5,186 |
| 7,408 |
| 22,270 |
| 772 |
| 18,046 | |
Notes to Reserves:
- Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
- Information in the reserves data tables may not add due to rounding. BOE values and oil and gas metrics may not calculate exactly due to rounding.
- Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates are the 3-consultant-average of price forecasts developed by Sproule Associates Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2022:
|
| 2023 | 2024 | 2025 | 2026 | 2027 |
| Crude Oil and NGL |
|
|
|
|
|
|
| WTI | US$/bbl | 80.33 | 78.50 | 76.95 | 77.61 | 79.16 |
| WCS | C$/bbl | 76.54 | 77.75 | 77.55 | 80.07 | 81.89 |
| Canadian Light Sweet | C$/bbl | 103.76 | 97.74 | 95.27 | 95.58 | 97.07 |
| Cromer LSB | C$/bbl | 104.55 | 98.50 | 95.55 | 96.83 | 98.13 |
| Edmonton C5+ | C$/bbl | 106.22 | 101.35 | 98.94 | 100.19 | 101.74 |
| Brent | US$/bbl | 84.67 | 82.69 | 81.03 | 81.39 | 82.65 |
| Natural gas |
|
|
|
|
|
|
| AECO | C$/MMBtu | 4.23 | 4.40 | 4.21 | 4.27 | 4.34 |
| BC Westcoast Station 2 | C$/MMBtu | 4.08 | 4.28 | 4.11 | 4.16 | 4.23 |
| Henry Hub | US$/MMBtu | 4.74 | 4.50 | 4.31 | 4.40 | 4.49 |
All prices increase at a rate of 2%/year after 2027.
A foreign exchange rate of 0.7450 US$/C$ for 2023 and 0.7650 US$/C$ for 2024, 0.7683 US$/C$ for 2025, 0.7717 US$/C$ for 2026 and 0.7750 US$/C$ after 2026 was used in the year end 2022 evaluation.
- A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet of natural gas to one barrel 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.
- Oil and gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural's performance over time. However, such measures are not reliable indicators of Canadian Natural's future performance and future performance may vary.
- Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.
- Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period.
- Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2023 proved developed producing production forecast prepared by the Independent Qualified Reserves Evaluators.
- Finding, Development and Acquisition ("FD&A") costs excluding changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2022 by the sum of total additions and revisions for the relevant reserves category.
- FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2022 and net changes in FDC from December 31, 2021 to December 31, 2022 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs.
- Abandonment, decommissioning and reclamation ("ADR") costs included in the calculation of the Future Net Revenue (FNR) consist of both the Company's total Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as at December 31, 2022 and forecast estimates of ADR costs attributable to future development activity.
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 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 Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project and 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; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil production, 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, the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+") and inflation) 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, 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; 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 Currency, Financial Information and Production
This press release should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three months and year ended December 31, 2022 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2021. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three months and year ended December 31, 2022 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards ("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.
The following discussion and analysis refers primarily to the Company's financial results for the three months and year ended December 31, 2022 in relation to the comparable periods in 2021 and the third quarter of 2022. In addition, the Company's MD&A details its targeted capital program for 2023. The accompanying tables form an integral part of the Company's MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2021, 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 dated March 1, 2023.
Special Note Regarding non-GAAP and Other Financial Measures
This press release includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position or cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the Company's financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this press release, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022, dated March 1, 2023.
Free Cash Flow
Free cash flow is a non-GAAP financial measure that represents adjusted funds flow adjusted for base 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.
|
| Three Months Ended |
|
| Year Ended |
|
| ($ millions) | | Dec 31
2022 |
|
| Sep 30
2022 |
|
| Dec 31
2021 |
| | Dec 31
2022 |
|
| Dec 31
2021 |
|
| Adjusted funds flow (1) | $ | 4,176 |
| $ | 5,208 |
| $ | 4,338 |
| $ | 19,791 |
| $ | 13,733 |
|
| Less: Base capital expenditures (2) | | 850 |
|
| 996 |
|
| 837 |
| | 3,956 |
|
| 3,483 |
|
| Dividends on common shares | | 834 |
|
| 2,532 |
|
| 558 |
| | 4,926 |
|
| 2,170 |
|
| Free cash flow | $ | 2,492 |
| $ | 1,680 |
| $ | 2,943 |
| $ | 10,909 |
| $ | 8,080 | |
(1)Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.
(2)Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023 for more details on net capital expenditures.
Capital Budget
Capital budget is a forward-looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.
Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
Capital Efficiency
Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($/bbl/d or $/BOE/d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.
CONFERENCE CALL
Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2022 Fourth Quarter and Year End Results on Thursday, March 2, 2023 before market open.
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, March 2, 2023.
Dial-in to the live event:
North America 1-888-886-7786 / International 001-416-764-8658
Listen to the audio webcast:
Access the audio webcast on the home page of our website, www.cnrl.com.
Conference call playback:
North America 1-877-674-7070 / International 001-416-764-8692 (Passcode: 348479#)
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
LANCE J. CASSON
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/156881
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