Canadian Natural Resources Limited Announces 2020 Fourth Quarter and Year End Results

Newsfile Corp.
·61 min read

Calgary, Alberta--(Newsfile Corp. - March 4, 2021) - Commenting on the Company's 2020 results, Tim McKay, President of Canadian Natural (TSX: CNQ) (NYSE: CNQ) stated "The impact of the COVID-19 pandemic effected the very way we conducted our lives and the way we operated our businesses. Through the year we took protocols to protect our stakeholders and would like to thank our employees, contractors, suppliers and shareholders for their support through this challenging year.

Despite the challenges of COVID-19 in 2020, the Company had a strong year operationally and financially as the Company's effective and efficient operations and long life low decline asset base proved their robustness in this challenging year. We were nimble in 2020, quickly lowering capital with minimal impact to annual production as we stayed within the Company's original production guidance range, effectively managing through a volatile commodity price environment and low crude oil demand. This was achieved through the commitment and hard work of our employees, who were rewarded with no economic layoffs due to the impacts of COVID-19. In 2020 the Company generated strong adjusted funds flow while effectively allocating to the Company's four pillars of capital allocation; balance sheet strength, returns to shareholders, resource value growth, and opportunistic acquisitions.

The Company achieved record annual corporate BOE production levels of approximately 1,164 MBOE/d, an increase of 6% or approximately 65,000 BOE/d over 2019 levels. Continued focus on effective and efficient operations and our culture of continuous improvement delivered strong operating cost reductions. As a result, record low annual operating costs of $20.46/bbl (US$15.25/bbl) of Synthetic Crude Oil ("SCO") produced were achieved at the Company's Oil Sands Mining and Upgrading segment, a decrease of $2.10/bbl. Our North America Exploration and Production ("E&P") liquids segment achieved significant operating cost reductions of $1.20/bbl or 10% from 2019 levels.

In 2020, Canadian Natural delivered top tier reserve replacement and finding, development and acquisition ("FD&A") costs, reflecting the strength and depth of the asset base. Total proved reserves grew by 10% to 12.106 billion BOE, of which 58% are high value, zero decline, SCO reserves, resulting in a strong corporate reserve replacement of 361% in 2020. Total proved FD&A costs, including changes in future development costs, were strong at $4.46/BOE.

Environmental, Social and Governance ("ESG") performance remains a top priority and investments to improve our performance and reduce our environmental footprint continue. In 2020 we reduced our corporate Greenhouse Gas ("GHG") emission intensity by 18% and methane emissions by 28%, from 2016 levels. Our safety record is top tier, as corporate total recordable injury frequency ("TRIF") improved to 0.21 in 2020, a reduction of 58% from 2016 levels. Additionally in 2020, the Company reached significant environmental milestones, including the cumulative sequestration at our Quest facility of five million tonnes of CO2 captured from the Scotford Upgrader and the cumulative planting of two and a half million trees at our Oil Sands Mining and Upgrading operations."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added "The resilience and sustainability of our business model was evident in 2020 as annual adjusted funds flow was strong at over $5.3 billion, excluding the provision relating to the Keystone XL pipeline project. Excluding the Painted Pony acquisition costs and the Keystone XL provision, we completely covered our capital program, and dividend, generating approximately $690 million in free cash flow in 2020. Excluding Painted Pony acquisition costs, year end net debt would have decreased by approximately $80 million from 2019 year end levels. Our long life low decline asset base afforded the Company time to be patient in 2020 as we reduced capital, maintained our dividend increase, sustained a robust balance sheet with ample liquidity and opportunistically accessed the debt capital markets at attractive rates.

The sustainability of our free cash flow generation provides the Board of Directors confidence to increase our dividend by 11% to $1.88 per share annually, marking the 21st consecutive year of dividend increases representing a CAGR of 20% since inception. The 2021 capital budget of approximately $3.2 billion drives targeted annual production growth of approximately 61,000 BOE/d, at the mid-point of our production range, from 2020 levels and robust free cash flow generation. At the current 2021 annual strip pricing of approximately US$57 WTI per barrel, the Company targets to generate significant annual free cash flow of approximately $4.9 billion to $5.4 billion, after our capital program and increased dividend. As a result, our balance sheet is targeted to strengthen further in 2021, with year end debt to adjusted EBITDA targeted to improve to approximately 1.2x and debt to book capitalization targeted to improve to approximately 29%, at the mid-point of the targeted free cash flow range. Subsequent to year end, in March 2021 the Board of Directors authorized management, subject to acceptance by the TSX, to repurchase shares under a Normal Course Issuer Bid ("NCIB"), equal to options exercised throughout the coming year, in order to eliminate dilution for shareholders. Our strong financial position, unique long life low decline asset base and effective and efficient operations continue to generate long-term shareholder value."

QUARTERLY HIGHLIGHTS


Three Months Ended


Year Ended


($ millions, except per common share
amounts)

Dec 31
2020


Sep 30
2020


Dec 31
2019


Dec 31
2020


Dec 31
2019


Net earnings (loss)

$

749


$

408


$

597


$

(435

)

$

5,416


Per common share - basic

$

0.63


$

0.35


$

0.50


$

(0.37

)

$

4.55


- diluted

$

0.63


$

0.35


$

0.50


$

(0.37

)

$

4.54


Adjusted net earnings (loss) from operations (1)

$

176


$

135


$

686


$

(756

)

$

3,795


Per common share - basic

$

0.15


$

0.11


$

0.58


$

(0.64

)

$

3.19


- diluted

$

0.15


$

0.11


$

0.58


$

(0.64

)

$

3.18


Cash flows from operating activities

$

1,270


$

2,070


$

2,454


$

4,714


$

8,829


Adjusted funds flow (2)

$

1,708


$

1,740


$

2,494


$

5,200


$

10,267


Per common share - basic

$

1.45


$

1.47


$

2.11


$

4.40


$

8.62


- diluted

$

1.44


$

1.47


$

2.10


$

4.40


$

8.61


Cash flows used in investing activities

$

624


$

643


$

854


$

2,819


$

7,255


Net capital expenditures, excluding net
acquisition costs (3)

$

655


$

771


$

1,056


$

2,701


$

3,904


Net capital expenditures, including net
acquisition costs (3)

$

1,176


$

771


$

1,056


$

3,206


$

7,121








Daily production, before royalties







Natural gas (MMcf/d)

1,644


1,362


1,455


1,477


1,491


Crude oil and NGLs (bbl/d)

927,190


884,342


913,782


917,958


850,393


Equivalent production (BOE/d) (4)


1,201,198



1,111,286



1,156,276



1,164,136



1,098,957


(1) Adjusted net earnings (loss) from operations is a non-GAAP measure the Company utilizes to evaluate its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the "Advisory" section of this press release.

(2) Adjusted funds flow is a non-GAAP measure the Company considers key to evaluate 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. The derivation of this measure is discussed in the "Advisory" section of this press release.

(3) Net capital expenditures is a non-GAAP measure the Company considers a key measure as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. For additional information and details, refer to the net capital expenditures table in the "Advisory" section of this press release.

(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, 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.

ANNUAL HIGHLIGHTS

  • A net loss of $435 million and an adjusted net loss from operations of $756 million were realized in 2020.

  • Cash flows from operating activities were $4,714 million in 2020.

  • In 2020, the Company generated annual free cash flow of $692 million after dividend requirements and capital expenditures, before Painted Pony Energy Ltd. ("Painted Pony") acquisition costs, share repurchases and the provision relating to the Keystone XL pipeline project while managing through mandatory production volume curtailments, a volatile commodity price environment and lower crude oil demand, due to the global pandemic.

    • These results are a clear demonstration of the strength and resiliency of the Company's diverse, high quality, long life low decline asset base and effective and efficient operations that delivered a dividend increase in 2020 and excluding Painted Pony acquisition costs, would have decreased net debt from year ended 2019 levels.

  • Canadian Natural generated strong annual adjusted funds flow of $5,343 million in 2020, excluding the provision relating to the Keystone XL pipeline project of $143 million, fully covering the Company's capital expenditures and dividend that was increased in March 2020.

    • Canadian Natural generated $692 million in free cash flow in 2020, after dividend payments of $1,950 million and net capital expenditures of $2,701 million, excluding Painted Pony acquisition costs, share repurchases and the provision relating to the Keystone XL pipeline project.

  • Canadian Natural maintained a strong financial position in 2020 and would have reduced year ended net debt by $79 million from year ended 2019 levels when excluding Painted Pony acquisition costs.

    • Including Painted Pony acquisition costs, in the second half of 2020 the Company reduced absolute net debt by over $1.5 billion from June 30, 2020 levels.

    • As at December 31, 2020, 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 $5.4 billion. At December 31, 2020, the Company had approximately $0.5 billion drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

    • In 2020, the Company repaid two medium-term notes totaling $1.9 billion.

    • In 2020, the Company successfully accessed both the Canadian and United States debt capital markets. Details are summarized as follows:

      • US dollar denominated debt securities were issued in Q2/20 totaling US$1.1 billion.

      • Canadian dollar denominated medium-term notes were issued in Q4/20 totaling $0.8 billion.

    • In 2020, the Company's $750 million non-revolving term credit facility, originally due February 2021 was increased by $250 million to $1,000 million and extended to February 2022. Subsequent to year end, in Q1/21, the Company has extended the facility to February 2023.

    • In Q2/20 the Company repaid $162.5 million on its $3,250 million non-revolving term loan, relating to the annual amortization requirement. Subsequent to year end, in Q1/21, the Company repaid a further $362.5 million on this facility, reducing the outstanding balance to $2,725 million, and satisfying the required annual amortization of $162.5 million originally due in June 2021.

  • In 2020, the Company achieved record annual production volumes of 1,164,136 BOE/d, an increase of 6% from 2019 levels. The increase was primarily as a result of increased production from the thermal in situ and Oil Sands Mining and Upgrading segments and strong operations from the E&P liquids and natural gas segments.

    • Record annual corporate liquids production of 917,958 bbl/d was achieved in 2020, an increase of 8% from 2019 levels. The increase in 2020 was primarily as a result of the first full year of operatorship and improved performance at Jackfish, increased Kirby North production as the facility reached full capacity in June 2020 and high utilization rates and operational enhancements from the Company's Oil Sands Mining and Upgrading segment.

    • The Company effectively executed on its curtailment optimization strategy in 2020 by utilizing its high quality and flexible asset base to maximize production. The Government of Alberta curtailment program was suspended effective December 1, 2020.

  • The Company's world class Oil Sands Mining and Upgrading assets averaged annual production of 417,351 bbl/d of SCO, an increase of 6% from 2019 levels. The increase from 2019 levels was as a result of high utilization rates and operational enhancements.

    • Record monthly production and high utilization was achieved at the Company's Oil Sands Mining and Upgrading assets in December 2020 of approximately 490,800 bbl/d of SCO, following the completion of planned turnarounds, increased capacity at the Scotford upgrader ("Scotford") and elimination of the mandatory Government of Alberta curtailment program.

    • Record low annual operating costs from the Company's Oil Sands Mining and Upgrading assets were achieved in 2020, averaging $20.46/bbl (US$15.25/bbl) of SCO. Operating costs decreased by 9% or $2.10/bbl from 2019 levels, driven by the Company's continued focus on effective and efficient operations, high reliability and operational enhancements.

  • Canadian Natural's North America E&P annual liquids production averaged 460,443 bbl/d in 2020, an increase of 13% from 2019 levels. The increase was primarily as a result of increased thermal in situ production.

    • Canadian Natural's continued focus on effective and efficient operations was also demonstrated at the Company's North American E&P liquids, including thermal in situ operations, where annual operating costs of $11.21/bbl (US$8.36/bbl) were achieved in 2020, a decrease of 10%, or $1.20/bbl from 2019 levels.

  • Canadian Natural's thermal in situ assets achieved record annual daily production in 2020, averaging 248,971 bbl/d, an increase of 48% over 2019 levels. The record daily production levels in 2020 were primarily as a result of a full year of operatorship of Jackfish and increased production at Kirby North.

    • Record monthly production was achieved at Jackfish in October 2020 reaching approximately 128,600 bbl/d, as a result the Company's curtailment optimization strategy and the ramp up of new pad tie-ins completed in Q4/19.

    • Strong annual operating costs from the Company's thermal in situ assets were achieved in 2020, averaging $9.44/bbl (US$7.04/bbl), a decrease of 13% or $1.39/bbl from 2019 levels. The decrease in operating costs was primarily due to cost savings as a result of operational synergies and higher production volumes, offset by higher fuel costs.

  • North America annual natural gas production was strong in 2020 averaging 1,450 MMcf/d, comparable with 2019 levels. Strong base production, highly economic volumes additions and acquired production in the second half of the year resulted in significant exit rate volumes of 1,624 MMcf/d in December 2020.

    • North America natural gas operating costs in 2020 averaged $1.14/Mcf, a decrease of 2% from 2019 levels, demonstrating the Company's continued focus on effective and efficient operations.

  • The strength of the Company's assets are shown in its ability to generate significant and sustainable free cash flow over the long term, supported by effective and efficient operations, making Canadian Natural's business unique, robust and sustainable. As a result, 2021 adjusted funds flow is targeted to be $10.3 billion to $10.8 billion at an annual WTI level of approximately US$57/bbl, demonstrating the significant torque of the Company's assets to improving commodity prices.

    • 2021 free cash flow is targeted to be robust at $4.9 billion to $5.4 billion, after capital expenditures and increased dividend levels.

    • The Company's 2021 capital program of approximately $3.2 billion, provides a targeted production range of 1,190 MBOE/d to 1,260 MBOE/d, an increase of 5% at the mid-point from 2020 levels.

      • Corporate annual natural gas production is targeted to range between 1,620 MMcf/d to 1,680 MMcf/d in 2021, representing significant growth of over 170 MMcf/d at the mid-point, from 2020 levels.

      • Corporate annual liquids production is targeted to be strong in 2021 ranging from 920,000 bbl/d to 980,000 bbl/d, an increase of approximately 32,000 bbl/d at the mid-point, from 2020 levels.

      • Free cash flow is targeted to be allocated to the balance sheet in the near term resulting in targeted 2021 year ended debt to book capitalization and debt to adjusted EBITDA of approximately 29% and 1.2x respectively, at the mid-point of targeted free cash flow range.

      • 2020 dividends increased 13% from 2019 levels to $1.70 per share. Subsequent to year end, the Company declared a quarterly dividend increase of 11% to $0.47 per share, payable on April 5, 2021. The increase marks the 21st consecutive year of dividend increases, reflecting the Board of Directors' confidence in Canadian Natural's strength and robustness of the Company's assets and its ability to generate significant and sustainable free cash flow.

      • Subsequent to year end, in March 2021 the Board of Directors authorized management, subject to acceptance by the TSX, to repurchase shares under an NCIB, equal to options exercised throughout the coming year, in order to eliminate dilution for shareholders.

RESERVES UPDATE

  • Canadian Natural's crude oil, SCO, bitumen, natural gas and NGL reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators. The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2020 (all reserves values are Company Gross unless stated otherwise).

  • Total proved reserves increased 10% to 12.106 billion BOE with reserves additions and revisions of 1.538 billion BOE. Total proved plus probable reserves increased 12% to 15.925 billion BOE with reserves additions and revisions of 2.099 billion BOE.

    • The strength and depth of the Company's assets are evident as approximately 80% of total proved reserves are long life low decline. This results in a total proved BOE reserves life index of 29.8 years and a total proved plus probable BOE reserves life index is 39.2 years.

      • Additionally, high value, zero decline, SCO is approximately 58% of total proved reserves with a reserve life index of approximately 45 years.

  • Canadian Natural's 2020 performance has once again consistently delivered superior finding and development costs:

    • Finding, Development and Acquisition ("FD&A") costs, excluding changes in Future Development Cost ("FDC"), are $1.91/BOE for total proved reserves and $1.40/BOE for total proved plus probable reserves.

    • FD&A costs, including changes in FDC, are $4.46/BOE for total proved reserves and $3.46/BOE for total proved plus probable reserves.

  • Total proved reserves additions and revisions replaced 2020 production by 361%. Total proved plus probable reserves additions and revisions replaced 2020 production by 493%.

  • Proved developed producing reserves additions and revisions are 1.032 billion BOE, replacing 2020 production by 242%. The proved developed producing BOE reserves life index is 21.2 years.

  • The net present value of future net revenues, before income tax, discounted at 10%, is $80.7 billion for total proved reserves, $98.0 billion for total proved plus probable reserves and $61.4 billion for proved developed producing reserves.

QUARTERLY HIGHLIGHTS

  • Net earnings of $749 million and adjusted net earnings from operations of $176 million were realized in Q4/20, improving over Q3/20 levels as expected. The increases in net earnings and adjusted net earnings are primarily a result of increased volumes from the Oil Sands Mining and Upgrading and Natural Gas segments as well as decreased operating costs from Oil Sands Mining and Upgrading.

  • Cash flows from operating activities were $1,270 million in Q4/20.

  • Canadian Natural generated strong quarterly adjusted funds flow of $1,851 million in Q4/20 excluding the provision relating to the Keystone XL pipeline project of $143 million. Strong adjusted funds flow was driven by the Company's effective and efficient operations and increased high value production.

  • Canadian Natural generated $694 million in free cash flow in Q4/20, after net capital expenditures of $655 million and dividend payments of $502 million in the quarter, excluding Painted Pony acquisition costs and the provision, reflecting the strength of the Company's effective and efficient operations and its high quality, long life low decline asset base.

  • Canadian Natural maintained a strong financial position in Q4/20 and reduced net debt by approximately $432 million, from Q3/20 levels, including Painted Pony acquisition costs.

  • In Q4/20, the Company achieved record quarterly production volumes of 1,201,198 BOE/d, increases of 4% and 8% from Q4/19 and Q3/20 levels respectively. The increase in production from the comparable periods primarily reflected the completion of planned maintenance and turnaround activities combined with continued high utilization rates and operational enhancements in the Oil Sands Mining and Upgrading segment, increased natural gas activity throughout the year and closing of the Painted Pony acquisition in Q4/20.

    • Liquids production was strong in Q4/20 averaging 927,190 bbl/d, comparable to Q4/19 levels and an increase of 5% from Q3/20 levels.

    • Corporate natural gas production was 1,644 MMcf/d in Q4/20, increases of 13% and 21% from Q4/19 and Q3/20 levels respectively.

  • The Company's world class Oil Sands Mining and Upgrading assets recorded strong operational results, high utilization and captured operational enhancements in Q4/20 resulting in average production of 417,089 bbl/d of SCO, increases of 17% and 19% from Q4/19 and Q3/20 levels respectively.

    • Operating costs from the Company's Oil Sands Mining and Upgrading assets are industry leading, averaging $20.20/bbl (US$15.50/bbl) of SCO in Q4/20, decreases of 19% and 15% from Q4/19 and Q3/20 levels respectively, driven by the Company's continued focus on effective and efficient operations and increased production volumes.

  • Canadian Natural's North America E&P liquids production, including thermal in situ, was strong in Q4/20 averaging 475,889 bbl/d, decreasing as expected by 6% and 4% from Q4/19 and Q3/20 levels respectively as the Company optimized production volumes within the mandatory Government of Alberta curtailment program.

    • Canadian Natural's continued focus on delivering effective and efficient operations across its entire asset base was also demonstrated at the Company's North American E&P liquids, including thermal in situ operations, where operating costs of $10.81/bbl (US$8.30/bbl) were achieved in Q4/20, comparable to Q4/19 levels.

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 Synthetic Crude Oil ("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 long life low decline production, representing approximately 80% of the Company's total liquids production in Q4/20, 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 long life low decline, low reserves replacement cost, 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 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



2020

2019


(number of wells)


Gross



Net



Gross



Net

Crude oil


48



42



96



86


Natural gas


34



30



30



19


Dry


-



-



3



3

Subtotal


82



72



129



108


Stratigraphic test / service wells


427



372



519



447

Total


509



444



648



555

Success rate (excluding stratigraphic test / service wells)




100%





97%

  • The Company's total crude oil and natural gas drilling program of 72 net wells for the year ended December 31, 2020, excluding stratigraphic/service wells, represents a decrease of 36 net wells from 2019 levels.

North America Exploration and Production

Crude oil and NGLs - excluding Thermal In Situ Oil Sands










Three Months Ended



Year Ended



Dec 31
2020



Sep 30
2020



Dec 31
2019



Dec 31
2020



Dec 31
2019

Crude oil and NGLs production (bbl/d)


209,710



206,974



247,184



211,472



238,028

Net wells targeting crude oil


5



-



9



35



79

Net successful wells drilled


5



-



9



35



77

Success rate


100%



-



100%



100%



97%

  • Canadian Natural's North America E&P crude oil and NGL annual production volumes, excluding the Company's thermal in situ operations, averaged 211,472 bbl/d in 2020, a decrease of 11% from 2019 levels. The decrease from 2019 reflects natural declines and strategic decisions to limit capital investment.

    • Primary heavy crude oil production averaged 70,279 bbl/d in 2020, a decrease of 14% from 2019 levels. The decrease in production relative to 2019 was due to natural field declines, low commodity prices and the mandatory Government of Alberta curtailment program.

      • Operating costs in the Company's primary heavy crude oil operations in 2020 averaged $17.59/bbl (US$13.11/bbl), a 6% increase from 2019 levels.

    • Pelican Lake production was strong in 2020 averaging 56,535 bbl/d of long life low decline production, a decrease of only 4% from 2019 levels. The decrease from 2019 levels demonstrates Pelican Lake's low decline rate and the continued success of the Company's world class polymer flood.

      • The Company continues to focus on effective and efficient operations, realizing strong operating costs in 2020 at Pelican Lake, averaging $6.03/bbl (US$4.49/bbl), a decrease of 3% from 2019 levels.

    • North American light crude oil and NGL production averaged 84,658 bbl/d in 2020, a decrease of 13% from 2019 levels primarily as a result of natural field declines.

      • Operating costs in the Company's North America light crude oil and NGL areas averaged $14.61/bbl (US$10.89/bbl) in 2020, a decrease of 4% from 2019 levels, as a result of the Company's continued focus on effective and efficient operations.

      • The Company continues to advance its high value Montney light crude oil development plan at Wembley, including 18 net wells targeted in 2021 and construction is underway on the new crude oil battery targeted to be on-stream in October 2021. With the crude oil battery in place the new wells are targeted to be brought on stream at strong capital efficiencies of approximately $9,400 per flowing BOE. This project is targeting to exit 2021 at total production rates of approximately 8,500 bbl/d of liquids and 28 MMcf/d.

Thermal In Situ Oil Sands










Three Months Ended



Year Ended




Dec 31
2020



Sep 30
2020



Dec 31
2019



Dec 31
2020



Dec 31
2019

Bitumen production (bbl/d)


266,179



287,978



259,387



248,971



167,942

Net wells targeting bitumen


-



-



3



6



3

Net successful wells drilled


-



-



3



6



3

Success rate


-



-



100%



100%



100%

  • Canadian Natural's thermal in situ assets achieved record annual daily production in 2020, averaging 248,971 bbl/d, an increase of 48% over 2019 levels. The record daily production levels in 2020 were primarily as a result of a full year of operatorship of Jackfish and increased production at Kirby North.

    • Record monthly production was achieved at Jackfish in October 2020 reaching approximately 128,600 bbl/d, as a result the Company's curtailment optimization strategy and the ramp up of new pad tie-ins completed in Q4/19.

    • Strong annual operating costs from the Company's thermal in situ assets were achieved in 2020, averaging $9.44/bbl (US$7.04/bbl), a decrease of 13% or $1.39/bbl from 2019 levels. The decrease in operating costs was primarily due to cost savings as a result of operational synergies and higher production volumes, offset by higher fuel costs.

    • At Jackfish, the Company achieved annual production of 103,294 bbl/d in 2020, an increase of 102% from 2019 levels. The increase was as a result of the Company's first full year of operatorship of the Jackfish assets and increased production throughout 2020 as a result of new pad tie-ins completed in Q4/19.

    • At Kirby, strong annual production of 61,476 bbl/d was achieved in 2020, an increase of 80% from 2019 levels as Kirby North averaged approximately 42,000 bbl/d in the second half of the year, continuing to produce above facility nameplate capacity.

    • At Primrose, annual production increased by 4% from 2019 levels, averaging 81,991 bbl/d in 2020 as the Company continues to optimize steam cycles.

  • At Kirby South, the Company continues to see positive results from its on-going two year solvent enhanced oil recovery technology pilot. The Company is also developing a second pilot in the steam flood area at Primrose, targeted to begin in the latter half of 2021. The technology targets to increase bitumen production, with a Steam to Oil Ratio ("SOR") reduction of up to 50%, GHG intensity reduction of up to 50% and high solvent recovery. The Company will continue to monitor results of the pilots throughout 2021 as this technology has the potential for application throughout the Company's extensive thermal in situ asset base.

North America Natural Gas










Three Months Ended



Year Ended




Dec 31
2020



Sep 30
2020



Dec 31
2019



Dec 31
2020



Dec 31
2019

Natural gas production (MMcf/d)


1,623



1,340



1,411



1,450



1,443

Net wells targeting natural gas


9



9



4



30



20

Net successful wells drilled


9



9



4



30



19

Success rate


100%



100%



100%



100%



95%

  • North America annual natural gas production was strong in 2020 averaging 1,450 MMcf/d, comparable with 2019 levels. Strong base production, highly economic volumes additions and acquired production in the second half of the year resulted in significant exit rate volumes of 1,624 MMcf/d in December 2020.

    • As identified in May 2020, the Company completed its plan of adding low cost, volume adding opportunities in Q4/20. Results have been highly successful, with stronger than expected exit production rates totaling 69 MMcf/d, for less than $2,000 per flowing BOE, approximately $1,000 per flowing BOE lower than originally estimated.

  • North America natural gas operating costs in 2020 averaged $1.14/Mcf, a decrease of 2% from 2019 levels, demonstrating the Company's continued focus on effective and efficient operations.

  • At Septimus, in the high value liquids rich Montney, the Company drilled eight net wells which came on production in Q4/20 with strong capital efficiencies at approximately $4,800 per flowing BOE. Total current production rates from the wells is strong at approximately 46 MMcf/d and 2,150 bbl/d of NGLs, in-line with expectations.

    • Annual operating costs at Septimus remained strong in 2020, averaging $0.30/Mcfe, comparable to 2019 levels.

  • Subsequent to year end, within our high quality Montney lands at Townsend, six of seven wells were brought on production at strong total rates of approximately 74 MMcf/d, compared to a target of 50 MMcf/d, resulting in a strong capital efficiency of approximately $2,200 per flowing BOE.

International Exploration and Production



Three Months Ended



Year Ended




Dec 31
2020



Sep 30
2020



Dec 31
2019



Dec 31
2020



Dec 31
2019

Crude oil production (bbl/d)










North Sea


17,057



21,220



30,860



23,142



27,919

Offshore Africa


17,155



17,537



18,495



17,022



21,371

Natural gas production (MMcf/d)










North Sea


4



5



25



12



24

Offshore Africa


17



17



19



15



24

Net wells targeting crude oil


-



-



-



1.0



5.5

Net successful wells drilled


-



-



-



1.0



5.5

Success rate


-



-



-



100%



100%

  • International E&P annual crude oil production volumes averaged 40,164 bbl/d in 2020, a decrease of 19% from 2019 levels.

    • In the North Sea, annual crude oil production volumes averaged 23,142 bbl/d in 2020, a decrease of 17% from 2019 levels. The decrease in production in 2020 was primarily a result of the permanent cessation of production from the Banff and Kyle fields and natural field declines.

      • Crude oil operating costs in the North Sea averaged $36.51/bbl (US$27.21/bbl) in 2020, comparable with 2019 levels.

    • Offshore Africa annual crude oil production volumes averaged 17,022 bbl/d in 2020, a decrease of 20% from 2019 levels, primarily due to natural field declines.

      • Offshore Africa crude oil operating costs averaged $13.29/bbl (US$9.91/bbl) in 2020, an increase of 19% from 2019 levels, primarily due to lower volumes on a relatively fixed cost base.

      • Subsequent to quarter end, the Floating Production Storage and Offloading vessel ("FPSO") operator at Espoir reported a serious incident in which two of its employees were fatally injured on January 14, 2021. Operations on the FPSO were immediately suspended and production was shut-in. Late in February 2021 the operator of the FPSO safely resumed operations, and is currently reinitiating production of the field.

    • As previously announced, the operator of the South Africa block 11B/12B, where Canadian Natural has a 20% working interest, has made a significant gas condensate discovery on the Luiperd prospect. This discovery follows the previously announced Brulpadda discovery in 2019. The operator is currently evaluating development scenarios following the successful discovery wells.

North America Oil Sands Mining and Upgrading



Three Months Ended



Year Ended



Dec 31
2020



Sep 30
2020



Dec 31
2019



Dec 31
2020



Dec 31
2019

Synthetic crude oil production (bbl/d) (1) (2)


417,089



350,633



357,856



417,351



395,133

(1) SCO production before royalties and excludes 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 annual production of 417,351 bbl/d of SCO, an increase of 6% from 2019 levels. The increase from 2019 levels was as a result of high utilization rates and operational enhancements.

    • Record monthly production and high utilization was achieved at the Company's Oil Sands Mining and Upgrading assets in December 2020 of approximately 490,800 bbl/d of SCO, following the completion of planned turnarounds, increased capacity at the Scotford and elimination of the mandatory Government of Alberta curtailment program.

    • Record low annual operating costs from the Company's Oil Sands Mining and Upgrading assets were achieved in 2020, averaging $20.46/bbl (US$15.25/bbl) of SCO. Operating costs decreased by 9% or $2.10/bbl from 2019 levels, driven by the Company's continued focus on effective and efficient operations, high reliability, as well as operational enhancements.

      • In 2020 the Company increased annual SCO production by approximately 22,000 bbl/d over 2019 levels and reduced annual operating costs by $183 million, excluding natural gas costs as the Company continues to focus on effective and efficient operations.

  • As part of the 2021 budget, a planned 30 day turnaround at Horizon is scheduled for the month of April. During the shutdown, new incremental operational tankage at the upgrader is coordinated to be tied in.

  • At Scotford no turnaround activities are targeted for 2021. The front end gross capacity was successfully increased by 20,000 bbl/d to 320,000 bbl/d as part of the Q3/20 turnaround activities.

MARKETING


Three Months Ended


Year Ended



Dec 31
2020


Sep 30
2020


Dec 31
2019


Dec 31
2020


Dec 31
2019

Crude oil and NGLs pricing










WTI benchmark price (US$/bbl) (1)

$

42.67


$

40.94


$

56.96


$

39.40


$

57.04

WCS heavy differential as a percentage of
WTI (%) (2)

22%


22%


28%


32%


22%

SCO price (US$/bbl)

$

39.69


$

38.61


$

56.32


$

36.26


$

56.35

Condensate benchmark pricing (US$/bbl)

$

42.54


$

37.55


$

52.99


$

36.97


$

52.84

Average realized pricing before risk
management (C$/bbl) (3)

$

40.56


$

40.14


$

49.60


$

31.90


$

55.08

Natural gas pricing






AECO benchmark price (C$/GJ)

$

2.62


$

2.03


$

2.21


$

2.12


$

1.54

Average realized pricing before risk
management (C$/Mcf)

$

2.94


$

2.31


$

2.64


$

2.40


$

2.34

(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.

  • Canadian Natural has a balanced and diverse product mix with strong expertise in marketing its products. Additionally, flexibility of the Company's production is targeted to be maximized in 2021, as the Government of Alberta suspended the mandatory curtailment production limits as of December 1, 2020.

  • Natural gas prices improved throughout 2020, with AECO averaging $2.12/GJ in the year, an increase of 38% from 2019 levels. The increase in natural gas prices from the comparable period primarily reflects lower WCSB production levels.

  • Market egress will continue to improve in the mid-term as construction is progressing on the Trans Mountain Expansion ("TMX") on which Canadian Natural has 94,000 bbl/d committed capacity. Including the Enbridge Line 3 replacement, Western Canadian egress is targeted to increase by approximately 1.0 MMbbl/d in the mid-term.

    • Enbridge Line 3 continues to progress and is targeted to be on stream in Q4/21.

    • Canadian Natural is committed to approximately 10,000 bbl/d of the targeted 50,000 bbl/d base Keystone export pipeline optimization expansion, which is targeted to be on-stream in the latter half of 2021.

    • TMX construction is on track for a targeted on stream date late in 2022.

    • On January 20, 2021, the presidential permit granted in 2019 on the Keystone XL Pipeline was revoked following the US presidential inauguration.

  • The North West Redwater ("NWR") Refinery reached commercial operations on June 1, 2020 and has a targeted processing capacity of approximately 80,000 bbl/d of diluted bitumen, which will improve heavy oil demand in western Canada, effectively increasing egress out of the WCSB. For more details, please contact the North West Redwater Partnership.

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, achieved annual production of 1,164,136 BOE/d in 2020, with approximately 98% of total production located in G7 countries.

  • In 2020, the Company generated annual free cash flow of $692 million after dividend requirements and capital expenditures, before Painted Pony acquisition costs, share repurchases and the provision relating to the Keystone XL pipeline project while managing through mandatory production volume curtailments, a volatile commodity price environment and lower crude oil demand, due to the global pandemic.

    • These results are a clear demonstration of the strength and resiliency of the Company's diverse, high quality, long life low decline asset base and effective and efficient operations that delivered a dividend increase in 2020 and excluding Painted Pony acquisition costs, would have decreased net debt from year ended 2019 levels.

  • Canadian Natural generated strong annual adjusted funds flow of $5,343 million in 2020, excluding the provision relating to the Keystone XL pipeline project of $143 million, fully covering the Company's net capital expenditures and dividend that was increased in March 2020.

    • Canadian Natural generated $692 million in free cash flow in 2020, after dividend payments of $1,950 million and net capital expenditures of $2,701 million, excluding Painted Pony acquisition costs, share repurchases and the provision relating to the Keystone XL pipeline project.

  • Canadian Natural maintained a strong financial position in 2020 and would have reduced year ended net debt by $79 million from year ended 2019 levels when excluding Painted Pony acquisition costs.

    • Including Painted Pony acquisition costs, in the second half of 2020 the Company reduced absolute net debt by over $1.5 billion from June 30, 2020 levels.

    • As at December 31, 2020, 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 $5.4 billion. At December 31, 2020, the Company had approximately $0.5 billion drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

    • In 2020, the Company repaid $0.9 billion of 2.05% medium-term notes and $1.0 billion of 2.89% medium-term notes in Q2/20 and Q3/20, respectively.

    • In 2020, the Company successfully accessed both the Canadian and United States debt capital markets. Details are summarized as follows:

      • US dollar denominated debt securities were issued in Q2/20 totaling US$1.1 billion, including a US$0.6 billion, 5 year, 2.05% note and a US$0.5 billion,10 year, 2.95% note.

      • Canadian dollar denominated medium-term notes were issued in Q4/20 totaling $0.8 billion, including a $0.5 billion, 3 year, 1.45% note and a $0.3 billion, 7 year 2.50% note.

    • In 2020, the Company's $750 million non-revolving term credit facility, originally due February 2021 was increased by $250 million to $1,000 million and extended to February 2022. Subsequent to year end, in Q1/21, the Company has extended the facility to February 2023.

    • In Q2/20 the Company repaid $162.5 million on its $3,250 million non-revolving term loan, relating to the annual amortization requirement. Subsequent to year end, in Q1/21, the Company repaid a further $362.5 million on the facility, reducing the outstanding balance to $2,725 million, and satisfying the required annual amortization of $162.5 million originally due in June 2021.

    • The Company has approximately $4.6 billion of availability under its United States (US$1.9 billion) and Canadian (C$2.2 billion) base shelf prospectuses, which expire August 2021, allowing the Company to offer these securities for sale from time to time.

  • Returns to shareholders totaled $2,221 million in 2020 by way of dividends and share repurchases.

  • The strength of the Company's assets are shown in its ability to generate significant and sustainable free cash flow over the long term, supported by effective and efficient operations, making Canadian Natural's business unique, robust and sustainable. As a result, 2021 adjusted funds flow is targeted to be $10.3 billion to $10.8 billion at an annual WTI level of approximately US$57/bbl, demonstrating the significant torque of the Company's assets to improving commodity prices.

    • 2021 free cash flow is targeted to be robust at $4.9 billion to $5.4 billion, after capital expenditures and increased dividend levels.

    • The Company's 2021 capital program of approximately $3.2 billion, provides a targeted production range of 1,190 MBOE/d to 1,260 MBOE/d, an increase of 5% at the mid-point from 2020 levels.

      • Corporate annual natural gas production is targeted to range between 1,620 MMcf/d to 1,680 MMcf/d in 2021, representing significant growth of over 170 MMcf/d at the mid-point, from 2020 levels.

      • Corporate annual liquids production is targeted to be strong in 2021 ranging from 920,000 bbl/d to 980,000 bbl/d, an increase of approximately 32,000 bbl/d at the mid-point, from 2020 levels.

      • Free cash flow is targeted to be allocated to the balance sheet in the near term resulting in targeted 2021 year ended debt to book capitalization and debt to adjusted EBITDA of approximately 29% and 1.2x respectively, at the mid-point of targeted free cash flow range.

      • 2020 dividends increased 13% from 2019 levels to $1.70 per share. Subsequent to year end, the Company declared a quarterly dividend increase of 11% to $0.47 per share, payable on April 5, 2021. The increase marks the 21st consecutive year of dividend increases, reflecting the Board of Directors' confidence in Canadian Natural's strength and robustness of the Company's assets and its ability to generate significant and sustainable free cash flow.

      • Subsequent to year end, in March 2021 the Board of Directors authorized management, subject to acceptance by the TSX, to repurchase shares under an NCIB, equal to options exercised throughout the coming year, in order to eliminate dilution for shareholders.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE ("ESG") 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 ESG HIGHLIGHTS

  • Canadian Natural's corporate GHG emissions intensity continues to improve, decreasing by 18% from 2016 to 2020, a material reduction in emissions intensity. These 2020 results include a decrease of 2% from 2019 levels.

  • The Company reduced methane emissions in its North American E&P segment by 28% from 2016 to 2020, which includes a decrease of 14% from 2019 levels.

  • 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 CCS facility captures and stores approximately 1.1 million tonnes of CO2 per year and in May 2020 reached the milestone of 5 million tonnes of stored carbon dioxide. 5 million tonnes of CO2 is equal to the annual 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 from the refinery began to be delivered in March 2020 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 will 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 targeted levels.

  • 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.

  • In 2020 the Company successfully achieved three of our four current environmental targets relating to GHG and methane emissions intensity reductions and reduced fresh water usage, and as a result we plan to update our environmental targets in Q2/21.

  • In September 2020, Canadian Natural published its 2019 Stewardship Report to Stakeholders, 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 aspirational goal of net zero GHG emissions in the oil sands.

  • The Company targets the release of its 2020 Stewardship Report to Stakeholders in Q3/21.

ESG HIGHLIGHTS FROM OUR STEWARDSHIP REPORT RELEASED IN 2020

  • Three of the eight independent directors of our Board are female, achieving the Company's Board gender diversity target of no less than 30% of independent directors.

  • We awarded over $550 million in contracts to more than 150 Indigenous businesses during the period covered by the report.

  • Canadian Natural has invested over $3.7 billion in research and development over the last decade and continues to invest in technology to unlock reserves, become more effective and efficient and reduce the Company's environmental footprint. Many of the Company's technology projects are featured in its 2020 Technology and Innovation Case Studies on the Company's website at https://www.cnrl.com/innovation-case-studies.

  • Oil Sands Mining and Upgrading fresh river water use intensity decreased by 68% from 2012 to 2019.

  • Thermal in situ fresh water use intensity decreased by 61% from 2012 to 2019.

2020 YEAR-END RESERVES

Determination of Reserves

For the year ended December 31, 2020, 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, 2020
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

142

81

216

580

6,870

3,725

98

8,607

Developed Non-Producing

24

12

-

27

-

264

4

111

Undeveloped

149

84

49

1,876

92

5,476

225

3,388

Total Proved

315

177

265

2,483

6,962

9,465

326

12,106

Probable

148

82

130

1,674

534

6,457

174

3,819

Total Proved plus Probable

463

260

395

4,157

7,496

15,922

500

15,925

Notes to Reserves:

  1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.

  2. 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.

  3. Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates were provided by Sproule Associates Limited:

    All prices increase at a rate of 2%/year after 2025.

    A foreign exchange rate of 0.7700 US$/C$ for 2021 and 0.7700 US$/C$ after 2021 was used in the year-end 2020 evaluation.

  4. 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.

  5. 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.

  6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.

  7. 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.

  8. Reserves Life Index is based on the amount for the relevant reserves category divided by the 2021 proved developed producing production forecast prepared by the Independent Qualified Reserves Evaluators.

  9. 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 2020 by the sum of total additions and revisions for the relevant reserves category.

  10. FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2020 and net changes in FDC from December 31, 2019 to December 31, 2020 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs.

  11. 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, 2020 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 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"), 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 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; the continued availability of the Canada Emergency Wage Subsidy ("CEWS") or other subsidies; 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 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 funds flow (previously referred to as funds flow from operations) is a non-GAAP 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, abandonment expenditures and movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation "Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities" is presented in the Company's MD&A.

Net capital expenditures is a non-GAAP measure 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, investment in other long-term assets, share consideration in business acquisitions and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. The reconciliation "Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities" is presented in the Net Capital Expenditures section of the Company's MD&A.

Free cash flow is a non-GAAP 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 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 measure 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.

Debt to book capitalization is a non-GAAP measure that is derived as net current and long-term debt, divided by the book value of common shareholders' equity plus net current and long-term debt. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.

Available liquidity is a non-GAAP measure that is derived as cash and cash equivalents, total bank and term credit facilities, less amounts drawn on the bank and credit facilities including under the commercial paper program. The Company considers available liquidity a key measure in evaluating the sustainability of the Company's operations and ability to fund future growth. See note 9 - Long-term Debt in the Company's consolidated financial statements.

Special Note Regarding Currency, Financial Information and Production

This press release should be read in conjunction with the Company's MD&A and unaudited interim consolidated financial statements for the three months and year ended December 31, 2020 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2019. 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 months and year ended December 31, 2020 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.

The Company's 2021 targeted annual adjusted funds flow and free cash flow are based upon forecasted commodity prices of US$57.28 WTI/bbl, WCS discount of US$11.77/bbl, AECO price of C$2.88/GJ and FX of US$1.00 to C$1.27.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2019, 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

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

The North American conference call number is 1-866-521-4909 and the outside North American conference call number is 001-647-427-2311. Please call in 10 minutes prior to the call starting time.

An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, March 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 1296005.

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

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/76056